e10vk

-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, OgPRlCd1RuTj+3ea3UtDInfNwzky1hoJVQ2xk8kPKeIi8Me2J5OdPvRBvNRf2x54 /L0rYmIbW2+b9Z8wXs6/xg== 0000950134-04-003273.txt : 20040311 0000950134-04-003273.hdr.sgml : 20040311 20040311115921 ACCESSION NUMBER: 0000950134-04-003273 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 13 CONFORMED PERIOD OF REPORT: 20031231 FILED AS OF DATE: 20040311 FILER: COMPANY DATA: COMPANY CONFORMED NAME: ENCORE ACQUISITION CO CENTRAL INDEX KEY: 0001125057 STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311] IRS NUMBER: 752759650 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-16295 FILM NUMBER: 04662171 BUSINESS ADDRESS: STREET 1: 777 MAIN STREET, SUITE 1400 CITY: FORT WORTH STATE: TX ZIP: 76102 BUSINESS PHONE: 8178779955 10-K 1 d12839e10vk.htm FORM 10-K e10vk

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K


þ		ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2003

Encore Acquisition Company

(Exact name of registrant as specified in its charter)


Delaware	001-16295	75-2759650
(State or other jurisdiction of incorporation)	(Commission File Number)	(IRS Employer Identification No.)

777 Main Street Suite 1400 Fort Worth, Texas (Address of principal executive offices)		76102 (Zip Code)

Registrant’s telephone number, including area code:

(817) 877-9955

Securities registered pursuant to Section 12(b) of the Act:


Title of each class		Name of each exchange on which registered

Common Stock		New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:

None

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein and will not be contained, to the best of Registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o

Indicate by check mark whether the registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2) Yes þ No o


Aggregate market value of the voting and non-voting common stock held by non-affiliates of the Registrant as of June 30, 2003 (the last business day of Registrant’s most recently completed second fiscal quarter	$	222,980,532
Number of shares of Common Stock, $0.01 par value, outstanding as of February 27, 2004		30,403,189

DOCUMENTS INCORPORATED BY REFERENCE

Parts of the definitive proxy statement for the Registrant’s annual meeting of stockholders to be held on April 29, 2004 are incorporated by reference into Part III of this report on Form 10-K.

ENCORE ACQUISITION COMPANY

2003 ANNUAL REPORT ON FORM 10-K

TABLE OF CONTENTS


		Page

PART I
Items 1 and 2.	Business and Properties		2
Item 3.	Legal Proceedings		16
Item 4.	Submission of Matters to a Vote of Security Holders		16

PART II
Item 5.	Market for Registrant’s Common Equity and Related Stockholder Matters		17
Item 6.	Selected Financial Data		18
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		19
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		43
Item 8.	Financial Statements and Supplementary Data		48
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		79
Item 9A.	Controls and Procedures		79

PART III
Item 10.	Directors and Executive Officers of the Registrant		79
Item 11.	Executive Compensation		80
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		80
Item 13.	Certain Relationships and Related Transactions		80
Item 14.	Principal Accountant Fees and Services		80

PART IV
Item 15.	Exhibits, Financial Statement Schedules, and Reports on Form 8-K		81
First Amendment to Credit Agreement
Second Amendment to Credit Agreement
Severance Agreement with Morris B. Smith
Stock Purchase Agreement
Subsidiaries of the Company
Consent of Ernst & Young LLP
Consent of Miller and Lents, Ltd.
Rule 13a-14(a)/15d-14(a) Certification
Rule 13a-14(a)/15d-14(a) Certification
Certification Pursuant to 18 U.S.C. Section 1350
Certification Pursuant to 18 U.S.C. Section 1350

This annual report on Form 10-K (the “Report”) contains forward-looking statements, which give our current expectations and forecasts of future events. The Private Securities Litigation Reform Act of 1995 provides a “safe harbor” for forward-looking statements made by or on behalf of Encore Acquisition Company or its subsidiaries. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” for a description of various factors that could materially affect the ability of Encore Acquisition Company to achieve the anticipated results described in the forward looking statements. Certain terms commonly used in the oil and natural gas industry and in this Report are defined at the end of Item 7A, beginning on page 45, under the caption “Glossary of Oil and Natural Gas Terms.” In addition, all production and reserve volumes disclosed in this Report represent amounts net to Encore Acquisition Company.

PART I

Items 1 and 2. Business and Properties

General

Our Business. We are a growing independent energy company engaged in the acquisition, development, exploitation, and production of onshore North American oil and natural gas reserves. Since our inception in 1998, we have sought to acquire high quality assets with potential for upside through low-risk development drilling projects. Our properties are currently located in the Williston Basin of Montana and North Dakota, the Permian Basin of Texas and New Mexico, the Anadarko Basin of Oklahoma, the Powder River Basin of Montana, the Paradox Basin of Utah, and the North Louisiana Salt Basin of Louisiana. During the three years ended December 31, 2003, we invested $134.8 million in acquiring producing oil and natural gas properties and we have invested another $266.5 million on development and exploitation of these properties.

Most Valuable Asset. The Cedar Creek Anticline (“CCA”), in the Williston Basin of Montana and North Dakota, represented 73% of our total proved reserves as of December 31, 2003. The CCA is our most valuable asset today and in the foreseeable future. A large portion of our future success revolves around future exploitation of and production from this property through primary, secondary, and tertiary recovery techniques.

Recent Acquisitions. On March 2, 2004, we entered into a stock purchase agreement to acquire all of the outstanding common stock of Cortez Oil & Gas, Inc., a privately held, independent oil and gas company (“Cortez”), for total consideration of approximately $123.0 million. We intend to fund the acquisition initially with bank debt under our existing credit facility. The oil and natural gas assets to be acquired from Cortez are in the same areas as our producing properties located in the CCA of Montana, the Permian Basin of West Texas and Southeastern New Mexico, and in our Mid Continent area, including the Anadarko and Arkoma Basins of Oklahoma and the Barnett Shale north of Fort Worth, Texas. We expect to close the transaction in the second quarter of 2004.

On July 31, 2003, we completed an acquisition of interests in natural gas properties in North Louisiana for $52.5 million before purchase price adjustments. Subsequent to the initial acquisition, we have purchased additional interests in the properties. The properties are located in the Elm Grove Field in Bossier Parish, Louisiana and are non-operated working interests ranging from 2% to 38% across 1,800 net acres in 15 sections. The properties are substantially all natural gas. For the fourth quarter of 2003, the properties’ average daily production was 8,255 Mcfe.

Drilling. In 2003, we drilled 105 gross operated wells and participated in drilling another 33 gross non-operated wells for a total of 138 gross wells for the year. On a net basis, we drilled 95.7 operated wells and participated in 7.9 non-operated wells in 2003.

Oil and Natural Gas Reserves. In 2003, our reserve growth was achieved through acquisitions, high pressure air injection (“HPAI”) and organically through the drill bit by developing a portion of our inventory of drilling projects that we expect will extend over the next several years. We continue to pursue

high-quality assets and to replenish our drilling inventory through acquisitions. During 2003, we added 20.7 MMBOE of oil and natural gas reserves for finding, development, and acquisition, or FD&A, replacement costs of $7.42 per BOE, which replaced 255% of the 8.1 MMBOE we produced in 2003. Including downward revisions of 3.5 MMBOE, the development program added 14.4 MMBOE (178% of our production) at an average FD&A cost of $6.86 per BOE. Included in our reserve additions are 12.5 MMBOE of HPAI in the CCA of Montana and North Dakota. Our three year average FD&A cost, including revisions, is $5.60 per BOE, with a reserve replacement ratio of 329%.

The following table sets forth our total proved reserves, average daily production and reserve-to-production ratio, or R/ P index, in our principal areas of operation as of December 31, 2003 and for the year then ended.


		Proved Reserves at					Average Daily
		December 31,		Percent			Production for		Percent
		2003		of			2003		of			R/P
		(MBOE)		Total			(BOE/d)		Total			Index

Cedar Creek Anticline(1)			103,601		73	%		13,490		61	%		21.0
Permian Basin(2)			22,424		16	%		4,554		20	%		13.5
Rockies(3)			6,620		5	%		2,935		13	%		6.2
Mid Continent(4)			8,245		6	%		1,239		6	%		11.2

	Total		140,890		100	%		22,218		100	%		17.4

Public Offering. On November 13, 2003, we priced a public offering of 8.0 million shares of our common stock at a price to the public of $20.25 per share. The underwriters also exercised their over-allotment option for an additional 1.06 million shares of common stock, at a price of $20.25 per share, on December 2, 2003, for a total of 9.06 million shares. We used all of the net proceeds to repurchase 6,866,643 shares of our common stock from J.P. Morgan Partners (SBIC), LLC (“J.P. Morgan”) and 2,193,357 shares from Warburg, Pincus Equity Partners L.P. (“Warburg Pincus”) at a price of $19.3775 per share. The 9.06 million shares we purchased were retired upon repurchase. Our total shares outstanding did not change as a result of this offering. Net proceeds from the original offering and the over-allotment option totaled approximately $175.6 million, after deducting underwriting discounts and commissions and the estimated expenses of the offering. After giving effect to the repurchase, J.P. Morgan no longer beneficially owns any of our common stock and Warburg Pincus beneficially owns 24.5% of our common stock.

Business Strategies

Our primary business objective is to maximize internally generated cash flow and shareholder value by executing the following strategies:

• Maintain an Active Low-Risk Development Drilling Program. Our technological expertise, combined with our proficient field operations and reservoir engineering, have allowed us to increase production and reserves on our properties through development drilling, workovers, waterflood enhancements, tertiary projects, and recompletions. Our plan is to maintain an inventory of low-risk

exploitation and development projects that provide us ongoing drilling activity. Each year, we budget a portion of internally generated cash flow to secondary and tertiary recovery projects whose results will not be seen until future years. Our conventional development budget for 2004, exclusive of spending on high pressure air injection, is $93 million.

• Maximize Existing Reserves and Production Through High-Pressure Air Injections. In addition to conventional development drilling, we utilize high-pressure air injection techniques on certain properties to enhance our growth. High-pressure air injection involves utilizing compressors to inject air into previously produced oil and natural gas formations in order to displace remaining resident hydrocarbons and force them under pressure to a common lifting point for production. We believe that the HPAI programs on our CCA properties will generate a higher rate of return than other tertiary processes and can be applied throughout our CCA properties. The zone of our initial focus for HPAI, the Red River U4 zone, is the same zone where HPAI has been successfully implemented by other operators in adjacent areas and on our Pennel unit of the CCA. Response from HPAI investments is not expected until ten to eighteen months from the time of first injection. Our high-pressure air injection budget for 2004 is $34 million.

• Expand Our Reserves, Production, and Drilling Inventory Through a Disciplined Acquisition Program. We will continue to pursue acquisitions of properties with similar upside potential to our current producing properties portfolio. Using the experience of our management team, we have developed and refined an acquisition program designed to increase our reserves and to complement our core properties, while providing upside potential. We have a staff of engineering and geoscience professionals who manage our core properties and use their experience and expertise to target attractive acquisition opportunities. Following an acquisition, our technical professionals seek to enhance the value of the new assets through a proven development and exploitation program. For the year ended 2003, we evaluated over $1 billion of potential acquisitions. We will continue to aggressively evaluate acquisition opportunities in 2004 with the same disciplined commitment to acquire assets that fit our portfolio and continue to create value for our shareholders.

• Focus on Cost Control Through Efficient and Safe Operations. As of December 31, 2003, we operated properties representing approximately 84% of our proved reserves, which allows us to control capital allocation and expenses. Not only do we strive to efficiently operate our properties but we strive to safely operate our properties. The total recordable incident rate (“TRIR”) averaged 2.5 per 200,000 man hours for the industry in 2003. We are very proud to have a perfect TRIR of zero for our employees in 2003.

Challenges to Implementing Our Strategy. We face a number of challenges to implementing our strategy and achieving our goals. Our primary challenge is to generate superior rates of return on our investments in a volatile commodity pricing environment, while replenishing our drilling inventory. Changing commodity prices affect the rate of return on a property acquisition, internally generated cash flow, and, in turn, can affect our capital budget. In addition to the changing commodity price risk, we face strong competition from independents and major oil companies. For more information on the challenges to implementing our strategy and achieving our goals, please read “Factors That May Affect Future Results and Financial Condition” beginning on page 37.

Business Activities

The following table sets forth the net production, proved reserves quantities, and PV-10 values of our properties:

Properties — Principal Areas of Operations



											Proved Reserve Quantities						PV-10
		Net Production 2003									at December 31, 2003						at December 31, 2003

				Natural									Natural
		Oil		Gas		Total					Oil		Gas		Total
		(MBbls)		(MMcf)		(MBOE)		Percent			(MBbls)		(MMcf)		(MBOE)		Amount(5)		Percent

																	(In thousands)
Cedar Creek Anticline(1)			4,723		1,206		4,924		61	%		100,387		19,286		103,601	$	614,428		60	%
Permian Basin(2)			853		4,857		1,662		20	%		11,067		68,138		22,424		230,223		23	%
Rockies(3)			990		490		1,071		13	%		6,123		2,983		6,620		62,263		6	%
Mid Continent(4)			35		2,498		453		6	%		155		48,543		8,245		114,160		11	%

	Total		6,601		9,051		8,110		100	%		117,732		138,950		140,890	$	1,021,074		100	%

(1) Our CCA properties, which produce mainly from porous dolomites drilled on 40 to 80 acre spacing intervals, have longer reserve lives than our other properties because the low permeability level encountered within those producing intervals require a longer time to produce the reserves in place. This results in a lower production decline rate.

(2) Permian Basin includes the Central Permian, Indian Basin and Crockett properties.

(3) Rockies includes the Paradox Basin, Lodgepole and Bell Creek properties.

(4) Mid Continent includes the Elm Grove and Verden Properties.

(5) The pretax present value of estimated future revenues to be generated from the production of proved reserves, net of estimated production and future development costs; using prices and costs as of the date of estimation without future escalation; without giving effect to hedging activities, non-property related expenses such as general and administrative expenses, debt service, and depletion, depreciation, and amortization; and discounted using an annual discount rate of 10%. Giving effect to hedging transactions based on prices current at such dates, our PV-10 value would have been decreased by $23.8 million at December 31, 2003. The Standardized Measure at December 31, 2003 is $736.9 million. Standardized Measure differs from PV-10 because Standardized Measure includes the effect of future income taxes.

Operations

We act as operator of properties representing approximately 84% of our proved reserves at December 31, 2003. As operator, we are able to better control expenses, capital allocation, and the timing of exploitation and development activities of these properties. Our remaining properties are operated by third parties, and, as working interest owners in those properties, we are required to pay our share of the costs of operating, exploiting, and developing them. See “— Properties — Nature of Our Ownership Interests” on page 11. During the years ended December 31, 2003, 2002, and 2001 our approximate costs for development activities on non-operated properties were $5.4 million, $3.4 million, and $9.3 million, respectively. Because the properties purchased in our North Louisiana acquisition in 2003 are all non-operated, we expect our capital costs related to non-operated activities to increase in 2004.

Proved Reserves

Proved developed reserves are proved reserves that are expected to be recovered from existing wells with existing equipment and operating methods. Proved undeveloped reserves are proved reserves that are expected to be recovered from new wells drilled to known reservoirs on acreage yet to be drilled for which

the existence and recoverability of such reserves can be estimated with reasonable certainty, or from existing wells where a relatively major expenditure is required to establish production. Proved undeveloped reserves include unrealized production response from fluid injection and other improved recovery techniques where such techniques have been proved effective by actual tests in the area and in the same reservoir.

The following table sets forth estimated period-end proved reserves for the periods indicated as estimated by Miller and Lents, Ltd., independent petroleum engineers (in thousands except per Bbl and per Mcf amounts):



			As of December 31,

			2003		2002		2001

Oil (Bbls)
	Developed			92,377		93,945		71,639
	Undeveloped			25,355		17,729		19,730

		Total		117,732		111,674		91,369

Natural Gas (Mcf)
	Developed			104,767		82,217		69,941
	Undeveloped			34,183		17,601		5,746

		Total		138,950		99,818		75,687

Combined (BOE)
	Developed			109,838		107,648		83,296
	Undeveloped			31,052		20,662		20,687

		Total(1)		140,890		128,310		103,983

PV-10(2)
	Developed		$	844,873	$	732,823	$	299,383
	Undeveloped			176,201		132,281		60,979

		Total	$	1,021,074	$	865,104	$	360,362

Standardized Measure(3)			$	736,939	$	624,718	$	284,309

Reserve price assumptions
	Oil ($/Bbl)		$	32.55	$	31.20	$	19.84
	Natural gas ($/Mcf)			5.83		4.79		2.57

(1) Volumetric reserves attributed to the net profits interests in our CCA properties were 20,623 MBOE, 16,262 MBOE, and 11,062 MBOE, respectively, at December 31, 2003, 2002, and 2001. See “— Properties — Net Profits Interests” on page 13. The volumes attributed to the net profits interests, which reduce our reserves on a BOE for BOE basis, will fluctuate from period to period primarily based on commodity prices and the level of planned development expenditures.

(2) The pretax present value of estimated future revenues to be generated from the production of proved reserves net of estimated future production and future development costs; using prices and costs as of the date of estimation without future escalation; without giving effect to hedging activities, non-property related expenses such as general and administrative expenses, debt service, and depletion, depreciation, and amortization; and discounted using an annual discount rate of 10%. Giving effect to hedging transactions based on prices current at such dates, our PV-10 value would have been $997.2 million at December 31, 2003, $860.6 million at December 31, 2002, and $364.4 million at December 31, 2001.

(3) Estimated future cash inflows to be generated from the production and sale of proved oil and natural gas reserves, net of estimated future production and development costs, and future income tax expenses discounted at 10% per annum to reflect the timing of future cash flows. Standardized Measure differs from PV-10 because Standardized Measure includes the effect of future income taxes.

There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of exploitation expenditures. The data in the above table represents estimates only. Oil and natural gas reserve engineering is inherently a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured exactly, and estimates of other engineers might differ materially from those shown above. The accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and judgment. Results of drilling, testing, and production, after the date of the estimate, may justify revisions. Accordingly, reserve estimates may vary significantly from the quantities of oil and natural gas that are ultimately recovered.

Future prices received for production and future costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. The PV-10 reserve value shown should not be construed as the current market value of the reserves. The 10% discount factor used to calculate present value, which is mandated by the Securities and Exchange Commission (“SEC”), is not necessarily the most appropriate discount rate. The present value, no matter what discount rate is used, is materially affected by assumptions as to timing of future production, which may prove to be inaccurate. For properties that we operate, future production expenses exclude our share of contractual overhead charges. In addition, the calculation of estimated future costs does not take into account the effect of various cash outlays, including, among other things, general and administrative costs and interest expense.

During the calendar year 2003, we filed estimates of oil and natural gas reserves at December 31, 2002 with the U.S. Department of Energy on Form EIA-23. As required for the EIA-23, this filing reflects only production that comes from our operated wells at year end, and is reported on a gross basis. These estimates come directly from our reserve report that is prepared by Miller and Lents, Ltd., who are independent petroleum engineers.

Production and Price History

The following table sets forth information regarding net production of oil and natural gas, certain price information, and average cost per BOE for each of the periods indicated:



		Year Ended December 31,

		2003		2002		2001

Production:
	Oil (MBbls)		6,601		6,037		4,935
	Natural gas (MMcf)		9,051		8,175		8,078
	Combined (MBOE)		8,110		7,399		6,281
Average Daily Production:
	Oil (Bbls/d)		18,085		16,540		13,519
	Natural gas (Mcf/d)		24,798		22,397		22,130
	Combined (BOE/d)		22,218		20,273		17,208
Average Prices:
	Oil (per Bbl)	$	26.72	$	22.34	$	21.43
	Natural gas (per Mcf)		4.83		3.16		3.73
	Combined (per BOE)		27.14		21.72		21.64



		Year Ended December 31,

		2003		2002		2001

Average Costs per BOE:
	Lease operations expense	$	4.67	$	4.15	$	4.00
	Production, ad valorem, and severance taxes		2.71		2.12		2.20
	General and administrative (excluding non-cash stock based compensation)		1.07		0.83		0.80
	Depletion, depreciation, and amortization		4.13		4.67		5.05

Producing Wells

The following table sets forth information at December 31, 2003 relating to the producing wells in which we owned a working interest as of that date. We also held royalty interests in 2,546 producing wells as of that date. Wells are classified as oil or natural gas wells according to their predominant production stream. Gross wells are the total number of producing wells in which we have an interest, and net wells are determined by multiplying gross wells by our average working interest.



		Oil Wells							Natural Gas Wells

							Average							Average
		Gross			Net		Working		Gross			Net		Working
		Wells			Wells		Interest		Wells			Wells		Interest

Cedar Creek Anticline			565			492		87%		31			8		25%
Permian Basin			1,171			213		18%		367			143		39%
Rockies			309			77		25%		—			—		—
Mid Continent			65			3		5%		222			39		18%

	Total		2,110	(1)		785		37%		620	(1)		190		31%

(1) Our total wells include 906 operated wells and 1,824 non-operated wells.

Acreage

The following table sets forth information at December 31, 2003 relating to acreage held by us. Developed acreage is assigned to producing wells. Undeveloped acreage is acreage held under lease, permit, contract, or option that is not in a spacing unit for a producing well, including leasehold interests identified for exploitation or exploratory drilling. Our undeveloped acreage is concentrated in our CCA, Bell Creek, and Verden properties, which represent 75%, 7%, and 7% of our total undeveloped acreage, respectively. These leases expire at various dates ranging from January 2004 to July 2012, with leases representing $403,000 of cost set to expire in 2004 if not developed.


		Gross		Net
		Acreage		Acreage

Developed acreage			211,219		138,981
Undeveloped acreage			73,896		56,903

	Total		285,115		195,884

Drilling Results

The following table sets forth information with respect to wells drilled during the periods indicated. The information should not be considered indicative of future performance, nor should a correlation be assumed between the number of productive wells drilled, quantities of reserves found, or economic value. We should continue to have good results from drilling because most of our exposure is to infill drilling. Productive wells are those that produce commercial quantities of hydrocarbons, exclusive of their capacity to produce a reasonable rate of return.



		Year Ended December 31,

Development Wells		2003		2002		2001

Productive
	Gross		137.0		109.0		142.0
	Net		103.0		95.3		105.6
Dry
	Gross		1.0		0.0		1.0
	Net		0.7		0.0		1.0

Present Activities

As of December 31, 2003, we had a total of 3 gross (2.9 net) wells that had been spudded and were in varying stages of drilling operations. Also, there were 10 gross (9.8 net) wells that had reached total depth and were in varying stages of completion pending first production.

As of December 31, 2003, we are in the process of expanding the HPAI program to the entire north end of the Pennel Unit. Full field design has been completed and we are ordering necessary tubular, electrical, and compression equipment for the project.

We are in the process of completing the first phase of HPAI in the Little Beaver area on CCA. First injection began in the Little Beaver phase one during December 2003 and phase one and phase two should be completed during 2004.

Delivery Commitments and Marketing

Our oil and natural gas production is principally sold to end users, marketers, refiners, and other purchasers having access to nearby pipeline facilities consistent with industry practices. In areas where there is no practical access to pipelines, oil is trucked to storage facilities. Our marketing of oil and natural gas can be affected by factors beyond our control, the potential effects of which cannot be accurately predicted. For the fiscal year 2003, our largest purchasers included ConocoPhillips, Shell, and Eighty-Eight Oil, which respectively accounted for 28%, 26%, and 11% of total oil and natural gas sales. Management is of the opinion that the loss of any one purchaser would not have a material adverse effect on our ability to market our oil and natural gas production. The sale of approximately 50% of CCA oil is dependant on transportation to markets through the Butte pipeline to Guernsey, Wyoming. Any restrictions on the available capacity for us to transport oil in this pipeline could have a material adverse effect on our price we receive and our oil revenues.

Competition

We compete with major and independent oil and natural gas companies. Some of our competitors have substantially greater financial and other resources than we do. In addition, larger competitors may be able to absorb the burden of any changes in federal, state, provincial, and local laws and regulations more easily than we can, adversely affecting our competitive position. Our competitors may be able to pay more for productive oil and natural gas properties and may be able to define, evaluate, bid for, and purchase a greater number of properties and prospects than we can. Further, these companies may enjoy technological advantages and may be able to implement new technologies more rapidly than we can. Our ability to

acquire additional properties in the future will depend upon our ability to conduct efficient operations, evaluate and select suitable properties, implement advanced technologies, and consummate transactions in this highly competitive environment.

Federal and State Regulations

Compliance with applicable federal and state regulations is often difficult and costly, and non-compliance may result in substantial penalties. The following are some specific regulations that may affect us. We cannot predict the impact of these or future legislative or regulatory initiatives.

Federal Regulation of Natural Gas. The interstate transportation and sale for resale of natural gas is subject to federal regulation, including transportation rates and various other matters, by the Federal Energy Regulatory Commission (“FERC”). Federal wellhead price controls on all domestic natural gas were terminated on January 1, 1992 and none of our natural gas sales are currently subject to FERC regulation. We cannot predict the impact of future government regulation on any natural gas operations.

Although FERC’s regulations should generally facilitate the transportation of natural gas produced from our properties and the direct access to end-user markets, the future impact of these regulations on marketing our production or on our natural gas transportation business cannot be predicted. We do not believe, however, that we will be affected differently than competing producers and marketers.

Federal Regulation of Oil. Sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at market prices. The net price received from the sale of these products is affected by market transportation costs. A significant part of our oil production is transported by pipeline. Under rules adopted by FERC effective January 1995, interstate oil pipelines can change rates based on an inflation index, though other rate mechanisms may be used in specific circumstances. The United States Court of Appeals upheld FERC’s orders in 1996. These rules have had little effect on our oil transportation cost.

State Regulation. Oil and natural gas operations are subject to various types of regulation at the state and local levels. Such regulation includes requirements for drilling permits, the method of developing new fields, the spacing and operations of wells and waste prevention. The production rate may be regulated and the maximum daily production allowable from oil and natural gas wells may be established on a market demand or conservation basis. These regulations may limit production by well and the number of wells that can be drilled.

Federal, State or Native American Leases. Our operations on federal, state or Native American oil and natural gas leases are subject to numerous restrictions, including nondiscrimination statutes. Such operations must be conducted pursuant to certain on-site security regulations and other permits and authorizations issued by the Bureau of Land Management, Minerals Management Service and other agencies.

Environmental Regulations. Various federal, state and local laws regulating the discharge of materials into the environment, or otherwise relating to the protection of the environment, directly impact oil and natural gas exploration, development and production operations, and consequently may impact our operations and costs. Management believes that we are in substantial compliance with applicable environmental laws and regulations. To date, we have not expended any material amounts to comply with such regulations, and we do not currently anticipate that future compliance will have a materially adverse effect on our consolidated financial position or results of operations.

Operating Hazards and Insurance

The oil and natural gas business involves a variety of operating risks, including fires, explosions, blowouts, environmental hazards, and other potential events that can adversely affect our operations. Any of these problems could adversely affect our ability to conduct operations and cause us to incur substantial losses. Such losses could reduce or eliminate the funds available for exploration, exploitation, or leasehold acquisitions or result in loss of properties.

In accordance with industry practice, we maintain insurance against some, but not all, potential risks and losses. We do not carry business interruption insurance. We may not obtain insurance for certain risks if we believe the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable at a reasonable cost. If a significant accident or other event occurs that is not fully covered by insurance, it could adversely affect us.

Employees

We had 119 employees as of December 31, 2003, 50 of which are field personnel. None of the employees are represented by any union. We consider our relations with our employees to be good.

Principal Executive Office

Our principal executive offices are located at 777 Main Street, Suite 1400, Fort Worth, Texas 76102. Our main telephone number is (817) 877-9955.

Available Information

We make available electronically, free of charge through our website (www.encoreacq.com), our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and other items filed with the SEC pursuant to Section 13(a) of the Securities Exchange Act of 1934 as soon as reasonably practicable after we electronically file such material with the SEC. In addition, the public may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 450 Fifth Street, NW, Washington, DC 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC maintains a website (www.sec.gov) that contains reports, proxy and information statements and other information regarding issuers, like us, that file electronically with the SEC.

We have adopted a code of business conduct and ethics that applies to all directors, officers, and employees, including our principal executive officer and senior financial officers. The code of business conduct and ethics is available on our Internet website (www.encoreacq.com). In the event that we make changes in, or provide waivers from, the provisions of this code of business conduct and ethics that the SEC or NYSE require us to disclose, we intend to disclose these events on our website.

The charters of our board of director committees are available on our website. Copies of the code of business conduct and ethics and board committee charters are also available in print upon written request to the Corporate Secretary, Encore Acquisition Company, 777 Main Street, Suite 1400, Fort Worth, Texas 76102.

The information on our website or any other website is not incorporated by reference into this Report.

Properties


	*Nature of Our Ownership Interests*

We own interests in oil and natural gas properties located in Montana, North Dakota, Texas, New Mexico, Oklahoma, Utah, and Louisiana. Substantially all of our PV-10 reserve value at December 31, 2003 was attributable to working interests in oil and natural gas properties. A working interest in an oil and natural gas lease requires us to pay our proportionate share of the costs of drilling and production. The map on the following page depicts the location of our significant properties and the properties we plan to acquire from Cortez. For information on the pending acquisition of Cortez, see “General — Recent Acquisitions” and “Note 14. Subsequent Events (unaudited)” to the consolidated financial statements.

MAP


	*Cedar Creek Anticline Properties — Montana and North Dakota*

The CCA was purchased on June 1, 1999, and we have subsequently acquired additional working interests from various owners. Presently, we operate approximately 99.5% of the CCA properties with an average working interest of approximately 87%.

The CCA is a major structural feature of the Williston Basin in southeastern Montana and northwestern North Dakota. Our acreage is concentrated on the “crest” of the CCA, giving us access to the greatest accumulation of oil in the structure. Our holdings extend for approximately 70 continuous miles across five counties in two states. The gross producing interval on the CCA is approximately 2,000 feet thick, and ranges in depth from approximately 7,000 feet to 9,000 feet.

Since taking over operations, along with subsequent additional acquired interests, we have increased production by 75% on the CCA from 7,807 BOE per day (average for June 1999) to 13,655 BOE per day (average for the fourth quarter 2003). We have accomplished ongoing production growth through a combination of:

• additional acquisition of interests;

• detailed attention to the existing wellbores;

• the addition of strategically positioned new horizontal and vertical wellbores;

• the highly successful application of horizontal re-entry drilling in existing wellbores;

• waterflood enhancements;

• and implementation of our high-pressure air injection program.

In 2003, we drilled 78 gross wells on the CCA, of which 46 were horizontal re-entry wells that both reestablished production from non-producing wells, added additional barrels from existing producing wells and serve as injection wells for secondary and tertiary recovery projects. Including our HPAI project, we incurred $77.6 million of capital projects on the CCA during 2003. The average daily production from the CCA was 13,490 BOE per day for 2003.

Our outlook for sustained production growth on the CCA remains strong. We plan to continue the development of the reserve base through currently identified opportunities and future opportunities resulting from knowledge gained through continued study and the drilling and exploitation efforts ongoing on these properties. We believe that HPAI continues to be our most significant source of sustained production growth on the CCA.

The CCA represents 73% of our total proved reserves as of December 31, 2003. The CCA represents our most valuable asset today and in the foreseeable future. A large portion of our future success revolves around future exploitation and production from these properties.

High-Pressure Air Injection. High-pressure air injection is a tertiary recovery technique that involves utilizing compressors to inject air into oil and natural gas formations in order to displace remaining resident hydrocarbons and force them under pressure to a common lifting point for production.

In 2002 we initiated a HPAI pilot program that injects air into the Red River U4 zone in the Pennel area of the CCA. The Red River U4 zone is the same zone where high-pressure air injection has been successfully implemented by other operators in adjacent areas on the CCA. We have seen positive results from this pilot high-pressure air injection project at Pennel. Based on these results, we are in the process of expanding high pressure air injection to other areas in the CCA. We believe that high-pressure air injection technology can be applied throughout the CCA and that it may yield significant new reserves. We believe that the high-pressure air injection will generate a higher rate of return than other tertiary processes on the CCA.

The pilot project at Pennel continues to perform well with production uplift on target with our original projection. During the second half of 2003 we approved a $25 million project to expand HPAI to the entire north end of the Pennel Unit (“Pennel Phase Two”). Full field design has been completed and we are ordering necessary tubular, electrical, and compression equipment. The Pennel Phase Two expansion should be complete in early 2005.

In the Little Beaver area of the CCA we were able to arrange to purchase our high-pressure air compression services from an offset operator during 2003. This allowed us to implement a HPAI project in Little Beaver, on the south end of the CCA, in less than one year. First injection began in Little Beaver phase one during December 2003 and phase one and phase two should be completed during 2004. Our independent reserve engineers, Miller and Lents, Ltd., booked 12.2 million barrels of proved undeveloped oil reserves associated with high pressure air at year end 2003 related to the Little Beaver unit project. High-pressure air injection contributed to our FD&A cost during 2003.

We believe that much of our acreage in the CCA has potential opportunities for utilizing HPAI recovery techniques at economic rates of return. We continue to evaluate and perform engineering studies on these projects. Over the next several years we plan to implement these development projects initially in the Red River U4 zone of the CCA. Additionally, we have other zones in the CCA that currently produce oil and may provide additional HPAI opportunities. We believe these zones can be most economically evaluated for HPAI opportunities after initiating HPAI in the Red River U4 zone.

Net Profits Interests. A major portion of our acreage position in the CCA is subject to net profits interests (“NPI”) ranging from 1% to 50%. The holders of these net profits interests are entitled to receive a fixed percentage of the cash flow remaining after specified costs have been subtracted from net revenue. The net profits calculations are contractually defined, but in general, net profits are determined after considering operating expense, overhead expense, interest expense, and drilling costs. The amounts of reserves and production calculated to be attributable to these net profits interests are deducted from our reserves and production data, and our revenues are reported net of NPI payments. The reserves and production that are attributed to the NPIs are calculated by dividing estimated future NPI payments (in the case of reserves) or prior period actual NPI payments (in the case of production) by the commodity prices current at the determination date. Fluctuations in commodity prices and the levels of development activities in the CCA from period to period will impact the reserves and production attributed to the NPIs and will have an inverse effect on our reported reserves and production. For the years ended December 31,

2003, 2002, and 2001, we reduced revenue for the payments of the net profits interests by $5.8 million, $2.0 million, and $2.8 million, respectively.


	*Permian Basin Properties — Texas and New Mexico*


	Central Permian — Andrews, Ector, and Pecos Counties, Texas

The Central Permian properties were purchased from Conoco on January 4, 2002. These properties are located in the Permian Basin near Midland, Texas, and include two major operated fields: East Cowden Grayburg Unit and Fuhrman-Nix; and two non-operated fields: North Cowden and Yates. The properties are 94% oil. Production from the Central Permian comes from multiple reservoirs including the San Andres, Grayburg, Glorieta, and Pennsylvanian zones at depths ranging from approximately 4,000 feet to 10,000 feet. We invested $12.2 million in the development drilling of 18 gross wells on the properties in 2003. Average daily production from the Central Permian properties was 2,410 BOE per day in 2003. We see these properties as an area of growth over the next several years.


	Crockett — Crockett County, Texas

The Crockett properties were purchased on March 30, 2000. We have acquired small additional working interests subsequent to the initial acquisition. The properties, located in the southern portion of the Permian Basin of West Texas consist primarily of three field groupings located near the town of Ozona, Texas. We operate approximately 34% of the Crockett properties, and we own a large interest in a significant number of the properties that we do not operate.

Production comes mainly from the Canyon and Strawn Formations. Both formations contain multiple pay intervals, and continued development opportunities remain on these properties. In 2003, an active development drilling program took place on our non-operated properties. In 2003, we invested approximately $3.7 million of development capital on the Crockett properties. Since acquiring these properties, we have increased production 18% from 8,700 Mcfe per day (average daily production for 2000) to 10,288 Mcfe per day (average daily production for 2003). We see these properties as an area of growth over the next couple of years.


	Indian Basin — Eddy County, New Mexico

The Indian Basin properties were purchased on August 24, 2000. We own varied non-operated working interests in these properties (primary area operators are Marathon and ChevronTexaco), whose production is 96% natural gas. Located in the western portion of the Permian Basin in southeastern New Mexico, these properties produce from multiple zones in the Pennsylvanian Formation. In 2003, we invested an insignificant amount of capital in the Indian Basin properties. The average daily production from the Indian Basin properties was 2,573 Mcfe per day for 2003.


	*Rocky Mountain Properties — North Dakota, Montana, and Utah*


	Lodgepole — Stark County, North Dakota

The Lodgepole properties were purchased on March 31, 2000. The properties consist of working and overriding royalty interests in several geographically concentrated fields. Approximately 95% of our interests are non-operated; the largest of which is the Eland Unit in which we own a 26% working interest.

The Lodgepole properties are located in the Williston Basin in western North Dakota near the town of Dickinson, approximately 120 miles from our CCA properties. The Lodgepole properties produce exclusively from the Mississippian-aged Lodgepole Formation, and the Eland Unit is the largest accumulation in the trend. The average production from the Lodgepole properties was 1,817 BOE per day for 2003. In 2003, we invested an insignificant amount of capital in the Lodgepole properties.

The Lodgepole properties produce from reefs with high permeability and thick oil columns. The prolific nature of these reservoirs makes future engineering estimates related to ultimate recovery of

reserves inherently difficult to determine. If the properties’ performance varies significantly from the Miller and Lents, Ltd. estimates of reserves, then our future cash flows could be affected in 2004 and a few years beyond.


	Bell Creek — Powder River and Carter Counties, Montana

The Bell Creek properties, located in the Powder River Basin of southeastern-most Montana, were purchased on November 29, 2000. We operate the seven production units that comprise the Bell Creek properties, each with a 100% working interest. The shallow (less than 5,000 feet) Cretaceous-aged Muddy Sandstone reservoir produces 100% oil. We invested $0.5 million of capital in these properties in 2003. The average daily production from the Bell Creek properties was 314 BOE per day for 2003.


	Paradox Basin — San Juan County, Utah

The Paradox Basin properties, located in southeast Utah’s Paradox Basin, were purchased on August 29, 2002. The properties are divided between two prolific oil producing units: the Ratherford Unit operated by ExxonMobil and the Aneth Unit operated by ChevronTexaco. The working interest and net revenue interest in the Ratherford Unit are 11.1% and 9.7%, respectively, and the working interest and the net revenue interest in the Aneth Unit are 13.4% and 11.4%, respectively. The average net production to us was approximately 804 BOE per day. We believe these properties have horizontal redevelopment, secondary development, and tertiary recovery potential. Our development capital was $0.5 million for 2003.


	*Mid Continent Properties — Oklahoma and Louisiana*


	Elm Grove — Bossier Parish, Louisiana

The Elm Grove properties were purchased on July 31, 2003 for $52.5 million before purchase price adjustments. Subsequent to the initial acquisition, we have purchased additional interests in the properties. The interests in the natural gas properties are located in the Elm Grove Field in Bossier Parish, Louisiana. The acquired properties include non-operated working interests ranging from 2% to 38% across 1,800 net acres in 15 sections. We did not own the properties for an entire year; but the properties averaged 8,255 Mcfe per day in the fourth quarter of 2003. At December 31, 2003, there were two wells currently being drilled and five wells waiting on completion. In 2003, we invested approximately $2.8 million of development capital on the Elm Grove properties. We believe these properties are an area of growth for us.


	Verden — Caddo and Grady Counties, Oklahoma

The Verden properties were purchased on August 24, 2000. We own various operated and non-operated interests in these properties. Located in the Anadarko Basin of central Oklahoma, production is primarily natural gas from the deep (below 15,000 feet) prolific Springer Sands. The development of these properties is driven primarily by other operators where we have a working interest in the properties and share our proportional drilling costs. Therefore, we do not control the timing of future development of the properties. During 2003, we invested $1.6 million of capital in the properties. The average daily production from the Verden properties was 4,088 Mcfe per day for 2003.

Title To Properties

We believe that our title to our oil and natural gas properties is good and defensible in accordance with standards generally accepted in the oil and natural gas industry.

Our properties are subject, in one degree or another, to one or more of the following:

• royalties, overriding royalties, net profit interests, and other burdens under oil and natural gas leases;

• contractual obligations, including, in some cases, development obligations arising under operating agreements, farmout agreements, production sales contracts, and other agreements that may affect the properties or their titles;

• liens that arise in the normal course of operations, such as those for unpaid taxes, statutory liens securing unpaid suppliers and contractors, and contractual liens under operating agreements;

• pooling, unitization and communitization agreements, declarations, and orders; and

• easements, restrictions, rights-of-way, and other matters that commonly affect property.

We believe that the burdens and obligations affecting our properties do not in the aggregate materially interfere with the use of the properties. As indicated under “Net Profits Interests” above, a major portion of our acreage position in the CCA, our primary asset, is subject to net profits interests.


Item 3.	*Legal Proceedings*

We are not currently a party to any material legal proceeding of which we are aware.


Item 4.	*Submission of Matters to a Vote of Security Holders*

There were no matters submitted to stockholders during the quarter ended December 31, 2003.

PART II


Item 5.	*Market for Registrant’s Common Equity and Related Stockholder Matters*

Our common stock, $0.01 par value, is listed on the New York Stock Exchange under the symbol “EAC”. The following table sets forth quarterly high and low sales prices of our common stock for each quarterly period of 2003 and 2002:


	High		Low

2003
Quarter ended December 31	$	25.28	$	19.60
Quarter ended September 30		22.15		17.80
Quarter ended June 30		20.01		17.00
Quarter ended March 31		19.35		16.63
2002
Quarter ended December 31	$	20.40	$	13.51
Quarter ended September 30		17.55		15.00
Quarter ended June 30		17.35		14.60
Quarter ended March 31		15.00		12.40

On February 27, 2004, we had approximately 202 shareholders of record.

Recent Sale and Repurchase of Securities

On November 13, 2003, we priced a public offering of 8.0 million shares of our common stock at a price to the public of $20.25 per share. The underwriters also exercised their over-allotment option for an additional 1.06 million shares of common stock, at a price of $20.25 per share, on December 2, 2003, for a total of 9.06 million shares. We used all of the net proceeds to repurchase 6,866,643 shares of our common stock from J.P. Morgan and 2,193,357 shares from Warburg Pincus at a price of $19.3775 per share. The 9.06 million shares we purchased were retired upon repurchase. Our total shares outstanding did not change as a result of this offering. Net proceeds from the original offering and the over-allotment option totaled approximately $175.6 million, after deducting underwriting discounts and commissions and the estimated expenses of the offering. After giving effect to the repurchase, J.P. Morgan no longer beneficially owns any of our common stock and Warburg Pincus beneficially owns 24.5% of our common stock.

Dividends

No dividends have been declared or paid on our common stock. We anticipate that we will retain all future earnings and other cash resources for the future operation and development of our business. Accordingly, we do not intend to declare or pay any cash dividends in the foreseeable future. Payment of any future dividends will be at the discretion of our Board of Directors after taking into account many factors, including our operating results, financial condition, current and anticipated cash needs, and plans for expansion. The declaration and payment of dividends is restricted by our existing credit agreement, the indenture governing our 8 3/8% notes, and any future dividends may also be restricted by future agreements with our lenders.


Item 6.	*Selected Financial Data*

The following selected consolidated financial data should be read in conjunction with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Item 8. Financial Statements and Supplementary Data” (in thousands except per share and per unit data):



		Year Ended December 31,

		2003			2002			2001			2000			1999

Consolidated Statements of Operations Data:
Revenues(1):
	Oil	$	176,351		$	134,854		$	105,768		$	92,441		$	30,454
	Natural gas		43,745			25,838			30,149			16,509			810

Total revenues		$	220,096		$	160,692		$	135,917		$	108,950		$	31,264

Net income (loss)		$	63,641	(2)	$	37,685		$	16,179	(3)	$	(2,135	)(4)	$	3,005

Net income (loss) per common share:
	Basic	$	2.11		$	1.25		$	0.56		$	(0.09	)	$	0.13
	Diluted		2.10			1.25			0.56			(0.09	)		0.13
Weighted average number of common shares outstanding:
	Basic		30,102			30,031			28,718			22,806			22,687
	Diluted		30,333			30,161			28,723			22,806			22,687
Consolidated Statements of Cash Flows Data:
Cash provided by (used by):
	Operating activities	$	123,818		$	91,509		$	80,212		$	44,508		$	9,759
	Investing activities		(153,747	)		(159,316	)		(89,583	)		(99,236	)		(201,701	)
	Financing activities		17,303			80,749			8,610			49,107			194,972
Production:
	Oil (Bbls)		6,601			6,037			4,935			3,961			1,796
	Natural gas (Mcf)		9,051			8,175			8,078			4,303			180
	Combined (BOE)		8,110			7,399			6,281			4,678			1,826
Average Sales Price:
	Oil ($/Bbl)	$	26.72		$	22.34		$	21.43		$	23.34		$	16.96
	Natural gas ($/Mcf)		4.83			3.16			3.73			3.84			4.50
	Combined ($/BOE)		27.14			21.72			21.64			23.29			17.12
Costs per BOE:
	Lease operations	$	4.67		$	4.15		$	4.00		$	3.99		$	4.60
	Production and severance taxes		2.71			2.12			2.20			3.24			2.97
	General and administrative (excluding non-cash stock based compensation)		1.07			0.83			0.80			0.93			2.22
	Depletion, depreciation, and amortization		4.13			4.67			5.05			4.72			2.89
Reserves:
	Oil (Bbls)		117,732			111,674			91,369			78,910			69,299
	Natural gas (Mcf)		138,950			99,818			75,687			72,970			10,940
	Combined (BOE)		140,890			128,310			103,983			91,072			71,122



	As of December 31,

	2003			2002		2001		2000			1999

Consolidated Balance Sheet Data:
Working capital	$	(52	)	$	12,489	$	1,107	$	(15,275	)	$	5,126
Total assets		672,138			549,896		402,000		343,756			215,571
Total debt		179,000			166,000		79,107		162,045			99,250
Stockholders’ equity		358,975			296,266		269,302		147,811			102,422

(1) For the years ended December 31, 2003, 2002, 2001, 2000, and 1999 we reduced revenue for the payments of the net profits interests by $5.8 million, $2.0 million, $2.8 million, $11.5 million, and $4.4 million, respectively.

(2) Net income for the year ended December 31, 2003 includes a $0.9 million cumulative effect of accounting change, which affects its comparability with other periods presented. See pro forma amounts presented in “Note 2. Summary of Significant Account Policies — New Accounting Standards” to the accompanying consolidated financial statements.

(3) Net income for the year ended December 31, 2001 includes $9.6 million of non-cash compensation expense, $4.3 million of bad debt expense, $1.6 million of impairment of oil and natural gas properties, and a $(0.9) million cumulative effect of accounting change, which affects its comparability with other periods presented.

(4) Net income for the year ended December 31, 2000 includes $26.0 million of non-cash compensation expense, which affects its comparability with other periods presented.


Item 7.	*Management’s Discussion and Analysis of Financial Condition and Results of Operations*

The following discussion and analysis of the consolidated financial condition and results of operations of Encore Acquisition Company should be read in conjunction with the historical financial information provided in the consolidated financial statements and accompanying notes, as well as the business and properties descriptions in Items 1 and 2 of this Report.

Overview

We engage in the acquisition, development, exploitation and production of onshore North American oil and natural gas reserves. We remain determined to execute our business strategy of maintaining an active low-risk development drilling program, maximizing existing reserves and production through high-pressure air injection projects, expanding our reserves and production through a disciplined acquisition program, and cost control through efficient and safe operations.

Our financial results and ability to generate cash depend upon many factors, particularly the price of oil and natural gas. Oil prices remained strong in 2003. The average oil price for the NYMEX futures market was $31.04 and $26.08 per barrel for 2003 and 2002, respectively. The average natural gas price for the NYMEX futures market was $5.50 and $3.36 per MMBTU for 2003 and 2002, respectively. Commodity prices are impacted by many factors that are outside of our control. It is very difficult for us to predict future commodity prices. For this reason, we attempt to mitigate the effect of commodity price risk by hedging.

In 2003, we were able to expand our Mid Continent area by acquiring a non-operated interest in natural gas properties in North Louisiana. We are optimistic both about how well this particular asset, Elm Grove, fits in our portfolio, and by the possibilities of additional acquisitions in the region. Elm Grove complements our existing asset base in many ways. We believe it contains a solid, predictable production base along with a large number of low risk infill drilling opportunities that are currently being exploited.

Also in 2003, we continued to see positive results from our initial high-pressure air injection project at our Pennel unit of the CCA, and have approved expanding it to other areas in the CCA. We began phase one of our second HPAI project in Little Beaver during December 2003 and phase one and phase two

should be completed during 2004. Our independent reserve engineers, Miller and Lents, Ltd., booked 12.2 million barrels of proved undeveloped oil reserves associated with high pressure air at year end 2003 related to the Little Beaver unit project. High pressure air injection contributed to our FD&A cost of $7.42 per BOE during 2003. For the long term, we believe that high-pressure air injection technology can be applied throughout the Cedar Creek Anticline.

2003 Highlights

Our financial and operating results for the year ended December 31, 2003 included the following highlights:

• Oil and natural gas reserves increased 10% to 140,890 MBOE. During 2003, we added 20.7 MMBOE at a FD&A cost of $7.42 per BOE, replacing 255% of the 8.1 MMBOE produced in 2003. Including revisions, the development program added 14.4 MMBOE (178% of our production) at a cost of $6.86 per BOE. Included in our reserve additions are 12.5 MMBOE of high-pressure air volumes. The 12.5 MMBOE represents the first reserves related to our high-pressure air injection program in the Cedar Creek Anticline of Montana and North Dakota. Our three year FD&A costs, including revisions, are $5.60 per BOE with a reserve replacement ratio of 329%. Oil reserves accounted for 84% of total proved reserves, and 78% of proved reserves are proved developed. Our reserve-to-production ratio is 17 years for total proved reserves and 14 years for proved developed reserves.

• Production volumes for the year increased 10% to 8.1 MMBOE (22,218 BOE per day), compared with 2002 production of 7.4 MMBOE (20,273 BOE per day). Oil represented 81% and 82% of our total BOE production in 2003 and 2002, respectively. The increase in production is due to our continued successful development and exploitation program as well as the Elm Grove acquisition.

• Net income for the full year of 2003 increased 69% to $63.6 million, or $2.10 per diluted share, on revenues of $220.1 million. Net income for the year ended December 31, 2003 includes a $0.9 million ($0.03 per diluted share) cumulative effect of accounting change resulting from the adoption of Statement of Financial Accounting Standards No. 143 “Accounting for Asset Retirement Obligations” on January 1, 2003. This compares to full year 2002 net income of $37.7 million, or $1.25 per diluted share, on revenues of $160.7 million. For 2003, cash flow from operations increased 35% to $123.8 million from $91.5 million for 2002. The increase in net income and cash flow from operations from 2002 was primarily a result of higher production and higher commodity prices throughout the year.

• We improved our financial flexibility and liquidity by negotiating an increased borrowing base under the existing credit facility from $220 million to $270 million. At December 31, 2003, we had $29 million outstanding on the borrowing base and $241 million available for funding of future capital requirements.

• We improved our ability to access capital markets with the filing of a $400 million universal shelf registration statement on Form S-3. We currently have $216 million availability remaining under the registration statement.

• We expanded the liquidity and public ownership of our common stock by facilitating the sale of common stock by J.P. Morgan and Warburg Pincus. On November 13, 2003, we priced a public offering of 8.0 million shares of our common stock at a price to the public of $20.25 per share. The underwriters also exercised their over-allotment option for an additional 1.06 million shares of common stock, at a price of $20.25 per share, on December 2, 2003, for a total of 9.06 million shares. We used all of the net proceeds to repurchase 6,866,643 shares of our common stock from J.P. Morgan and 2,193,357 shares from Warburg Pincus at a price of $19.3775 per share. The 9.06 million shares we purchased were retired upon repurchase. Our total shares outstanding did not change as a result of this offering. Net proceeds from the original offering and the over-allotment option totaled approximately $175.6 million, after deducting underwriting discounts and commissions and the estimated expenses of the offering. After giving effect to the repurchase, J.P. Morgan

no longer beneficially owns any of our common stock and Warburg Pincus beneficially owns 24.5% of our common stock.

• High-pressure air injection was implemented in a second area on the CCA properties in the Little Beaver area. We were able to negotiate the purchase of high-pressure air compression services from an offset operator. This allowed us to implement a project in Little Beaver unit, on the south end of the Cedar Creek Anticline, in less than one year. First injection began in Little Beaver phase one during December 2003 and phase one and phase two should be completed during 2004. Our independent reserve engineers, Miller and Lents, Ltd., booked 12.2 million barrels of oil reserves associated with high pressure air at year end 2003 at Little Beaver. High pressure air injection contributed to our FD&A cost during 2003.

Results of Operations

Comparison of 2003 to 2002

Set forth below is our comparison of operations during the year ended December 31, 2003 with the year ended December 31, 2002.

Revenues and Production. For the year ended December 31, 2003, revenues increased $59.4 million. The following table illustrates the primary components of oil and natural gas revenue for the years ended December 31, 2003 and 2002, as well as each year’s respective oil and natural gas volumes (dollars in thousands except per unit amounts):



		Year Ended December 31,


		2003						2002						*Difference*

		Revenue			$/Unit			Revenue			$/Unit			*Revenue*			*$/Unit*

Revenues:
Oil wellhead		$	190,203		$	28.82		$	141,119		$	23.38		$	49,084		$	5.44
Oil hedges			(13,852	)		(2.10	)		(6,265	)		(1.04	)		(7,587	)		(1.06	)

	Total Oil Revenues	$	176,351		$	26.72		$	134,854		$	22.34		$	41,497		$	4.38

Natural gas wellhead		$	45,218		$	5.00		$	24,803		$	3.03		$	20,415		$	1.97
Natural gas hedges			(1,473	)		(0.17	)		1,035			0.13			(2,508	)		(0.30	)

	Total Natural Gas Revenues	$	43,745		$	4.83		$	25,838		$	3.16		$	17,907		$	1.67

Combined wellhead		$	235,421		$	29.03		$	165,922		$	22.42		$	69,499		$	6.61
Combined hedges			(15,325	)		(1.89	)		(5,230	)		(0.70	)		(10,095	)		(1.19	)

	Total Combined Revenues	$	220,096		$	27.14		$	160,692		$	21.72		$	59,404		$	5.42

Average

Average

NYMEX

NYMEX

Production

$/Unit

Production

$/Unit

Production

$/Unit

Other data:

Oil (MBbls)

6,601

31.04

6,037

26.08

564

4.96

Natural Gas (MMcf)

9,051

5.50

8,175

3.36

876

2.14

Combined (MBOE)

8,110

7,399

711

Oil revenues increased $41.5 million in 2003 over 2002 as production increased 564 MBbls and our average realized price increased $4.38 per Bbl. The increase in production resulted from our successful development drilling program and uplift from the HPAI program. Oil revenues were reduced by $13.9 million in 2003 due to our hedging program. The hedging per Bbl reduction to our wellhead oil price of $2.10 represented a $1.06 per Bbl greater reduction than in 2002. This compares favorably with the

$4.96 increase in the average NYMEX price from 2002 to 2003 as we were able to realize additional upside due to a higher average ceiling on our 2003 hedges compared to NYMEX than in 2002. In addition, our oil wellhead revenue was reduced by $5.6 million and $2.0 million in 2003 and 2002, respectively, for the net profits interests payments made to others related to our CCA properties.

Natural gas revenues increased in 2003 by $17.9 million due to a 65% increase in the net wellhead price received along with increased production of 876 MMcf. The increase in net wellhead price received of $1.97 per Mcf resulted as the average NYMEX price increased $2.14 per Mcf over the same period. The natural gas production increase resulted from the Elm Grove acquisition during 2003. Averaging 7,984 Mcfe per day since its acquisition on July 31, 2003, the Elm Grove properties added 3,345 Mcfe per day to our average daily production for the full year.

For 2004, we anticipate increased production related to our budgeted $93 million capital drilling program and $34 million in HPAI projects. We also have an additional $13 million budgeted for leasehold and other general capital expenditures. The total capital budget for 2004 is $140 million.

Prices received for oil and natural gas production are largely based on current market prices, which are beyond our control. We have based our 2004 forecasts on the assumptions of $23.50 per Bbl and $3.75 per Mcf NYMEX prices. For comparability and accountability, we take a constant approach to budgeting commodity prices. We presently analyze our inventory of capital projects on $23.50 per Bbl and $3.75 per Mcf NYMEX prices to ensure a good rate of return to our shareholders without the benefit of escalating future commodity prices. If NYMEX prices trend downward below our base deck, we may reevaluate our capital projects. At these assumed prices, we have forecasted net hedge contract payments of approximately $0.9 million for oil and net receipts of $4.5 million for natural gas. However, these amounts will change directly with any change in the market price of oil and natural gas and with any change in our outstanding hedge positions. Additionally, we have anticipated net profits interests payments of $1.7 million for oil and $0.03 million for natural gas. These payments are highly dependent on the level of drilling in the CCA and commodity prices, and thus, any change in the level of drilling or market fluctuation in commodity prices will have a direct impact on the amount of payments we are required to make. If commodity prices are significantly lower than our forecasted prices of $23.50 for oil and $3.75 for natural gas, we will not have sufficient internally generated cash flow to fund the budgeted $93 million drilling program, $34 million in HPAI projects, and $13 million leasehold and other capital for 2004. In this case, we would have to borrow money under our existing revolving credit facility, seek capital markets, or curtail the capital program. If drilling is curtailed or ended, future cash flows could be materially negatively impacted.

Lease Operations Expense. Lease operations expense for the year ended December 31, 2003 increased by $7.2 million as compared to 2002. The increase in total lease operations expense resulted from the increase in volumes as a result of our 2003 drilling program, the Elm Grove acquisition and HPAI program. See “— Revenues and Production” above. On a per BOE basis, lease operations expense increased $0.52 primarily due to (1) full year results of our Paradox Basin properties, which had higher average per BOE lease operations expense of $9.04 for 2003 compared to our average of $4.67 per BOE, (2) the HPAI project on the CCA properties, and (3) lower production volumes from our Lodgepole properties, which have low operating costs.

For 2004, we anticipate an increase in total lease operations expense, as well as on a per BOE basis. We anticipate this increase due to a full year of production at our North Louisiana properties, as well as further implementation of the high-pressure air injection program. Also, the continued production decline of our Lodgepole properties, which have low per BOE operating costs, will continue to raise our lease operations expense on a per BOE basis. We have projected total lease operations expenses of approximately $46.5 million, or $5.56 per BOE, for 2004.

Production, Ad Valorem, and Severance Taxes. Production, ad valorem, and severance taxes for the year ended December 31, 2003 increased as compared to 2002 by approximately $6.4 million. The increase is a direct result of the increase in wellhead revenue. See “— Revenues and Production” above. As a

percentage of oil and natural gas revenues (excluding the effects of net profits and hedges), production, ad valorem, and severance taxes increased slightly from 9.3% to 9.4% from 2002 to 2003.

For 2004, total production, ad valorem, and severance taxes will depend in a large part on prevailing oil and natural gas prices. However, the production, ad valorem, and severance tax rate should remain relatively constant at an estimated 9.1% of wellhead revenues. However, if NYMEX prices continue to stay above $30 per barrel, we will temporarily lose production and severance tax incentives in Montana and North Dakota, which would cause our tax rates to increase in 2004.

Depletion, Depreciation, and Amortization (“DD&A”) Expense. Despite an increase in production, DD&A expense decreased by approximately $1.0 million in 2003. This decrease was due to the adoption of SFAS 143 on January 1, 2003, which resulted in a lower per BOE rate. As a result of the adoption of SFAS 143, we can no longer assume proceeds received for the salvage value of our equipment will offset plugging and abandonment costs, and thus are now required to deduct salvage value from the book value of equipment in calculating our depreciable base. This was the primary driver of the decrease in the average DD&A rate from $4.67 per BOE of production during 2002 to $4.13 per BOE in 2003.

We anticipate the total DD&A expense in 2004 will increase due to increased production resulting from the Elm Grove acquisition and our planned 2004 capital expenditures of $140 million. Assuming capital expenditures do not differ significantly from our budgeted amount, we expect our DD&A rate for 2004 to be approximately $4.60 per BOE. This per BOE increase from 2003 is primarily attributable to higher than historical FD&A costs for 2003. This rate could vary significantly based on actual capital expenditures, production rates, net profits interests, and any acquisition that closes in 2004. Additionally, changes in the market price for oil and natural gas could affect the level of our reserves. As the level of reserves change, the DD&A rate is inversely affected.

General and Administrative (“G&A”) Expense. G&A expense increased $2.5 million ($0.24 per BOE) to $8.7 million in 2003 (excluding non-cash stock based compensation of $0.6 million in 2003). The increase in G&A expense was a result of increased staffing levels used to manage our growing asset base and outside consulting services used in the evaluation of potential acquisitions.

We have forecast approximately $9.8 million for general and administrative expenses in 2004. This represents an increase of approximately $1.1 million from 2003. The increase is expected to result from the continued implementation of the HPAI projects, increased staffing, additional expenses related to compliance with the Sarbanes-Oxley Act of 2002 and the changes in listing requirements of The New York Stock Exchange.

Non-Cash Stock Based Compensation Expense. Non-cash stock based compensation expense increased from zero in 2002 to $0.6 million in 2003. This expense represents the amortization of deferred compensation, recorded in equity related to restricted stock granted under the 2000 Incentive Stock Plan. This amount is being amortized to expense over the vesting period of the restricted stock.

During 2002 and 2003, we issued 129,328 and 45,461 shares, respectively, of restricted stock to employees. Of these, 77,901 shares issued in 2002 and 45,461 shares issued in 2003 vest in equal installments on the third, fourth, and fifth anniversary of the date of the grant and depend only on continued employment for future issuance. These represent a fixed award per APB 25 and compensation expense will be recorded over the related service period. Of the remaining 51,427 shares issued in 2002, 34,464 remain outstanding at December 31, 2003. These were issued to two members of senior management and also vest in equal installments on the third, fourth, and fifth anniversary of the date of the grant. However, these shares not only depend on the passage of time and continued employment, but on certain performance measures for their future issuance. These represent a variable award under APB 25 and, thus, the full amount of compensation expense to be recorded for these shares will not be known until their eventual issuance.

Other Operating Expense. Other operating expense for the year ended December 31, 2003 increased as compared to 2002 by approximately $1.4 million. This amount primarily consists of 2003 severance payment obligations to former employees. The remaining amount relates to the inclusion of accretion

expense on our SFAS 143 future abandonment liability; and the abandonment in undeveloped leasehold costs.

For 2004, we anticipate other operating expense to be approximately $2.9 million.

Interest Expense. Interest expense for the year ended December 31, 2003 increased $3.8 million over 2002 due primarily to an increase in our weighted average interest rate from period to period, as well as an increase in debt outstanding related to our credit facility. We incurred additional debt in 2003 to fund the North Louisiana acquisition. The weighted average interest rate, net of hedges, for 2003 was 9.6% compared to 8.2% for 2002. This higher weighted average interest rate is the result of the issuance of $150 million aggregate principal amount of 8 3/8% senior subordinated notes in June 2002, which was the primary component of our total indebtedness during 2003, while the revolving credit facility with a lower floating rate was the primary component during the first half of 2002. In conjunction with the issuance of 8 3/8% notes in June 2002, we entered into an interest rate swap, which swaps fixed rates to floating, with the intent of lowering our effective interest payments. As this transaction does not qualify for hedge accounting, changes in its fair market value, as well as settlements, are not recorded in interest expense, but in ‘Derivative fair value (gain) loss’ on the Consolidated Statements of Operations. During 2003, a gain of $1.5 million related to this interest rate swap was recorded in ‘Derivative fair value (gain) loss’. See Note 11 to the accompanying consolidated financial statements.

The following table illustrates the components of interest expense for 2003 and 2002 (in thousands):


		2003		2002		Difference

8 3/8% senior subordinated notes		$	12,563	$	6,488	$	6,075
Revolving credit facility			453		2,260		(1,807	)
Hedge settlements			—		1,249		(1,249	)
Hedge loss amortization			1,910		1,619		291
Debt issuance cost amortization			714		314		400
Fees and other			511		376		135

	Total	$	16,151	$	12,306	$	3,845

Derivative Fair Value Gain/Loss. The derivative fair value gain of $0.9 million in 2003 represents the ineffective portion of the mark-to-market loss on our derivative hedging instruments, settlements received on our fixed to floating interest rate swap, any commodity derivatives not designated as hedges, and changes in the mark-to-market value of our fixed to floating interest rate swap.

Currently, this line item on the Statement of Operations is primarily dependent on the futures price of oil, natural gas and LIBOR interest rates. This is due to the fact that the main components are the mark-to-market movement of and any settlements on our commodity derivative contracts not designated as hedges and our fixed to floating interest rate swap.

Income Tax Expense. Income tax expense for 2003 increased $13.5 million over 2002. This increase is due primarily to the $38.6 million increase in Income before Income Taxes from 2002 to 2003. Our effective income tax rate, prior to adjusting for Section 43 credits, remained at a constant 38% for both 2002 and 2003. However, during 2003, we generated $2.1 million in Section 43 credits, as compared to $1.1 million of Section 43 credits generated in 2002. This increase resulted in an effective income tax rate of 36.5% in 2003, a decrease of 1% from our 2002 effective rate of 37.5%.

Comparison of 2002 to 2001

Set forth below is our comparison of operations during the year ended December 31, 2002 with the year ended December 31, 2001.

Revenues and Production. For the year ended December 31, 2002, revenues increased $24.8 million. The following table illustrates the primary components of oil and natural gas revenue for the years ended December 31, 2002 and 2001, as well as each year’s respective oil and natural gas volumes (dollars in thousands except per unit amounts):



		Year Ended December 31,


		2002						2001						*Difference*

		Revenue			$/Unit			Revenue			$/Unit			*Revenue*			*$/Unit*

Revenues:
Oil wellhead		$	141,119		$	23.38		$	114,723		$	23.25		$	26,396		$	0.13
Oil hedges			(6,265	)		(1.04	)		(8,955	)		(1.82	)		2,690			0.78

	Total Oil Revenues	$	134,854		$	22.34		$	105,768		$	21.43		$	29,086		$	0.91

Natural gas wellhead		$	24,803		$	3.03		$	34,014		$	4.21		$	(9,211	)	$	(1.18	)
Natural gas hedges			1,035			0.13			(3,865	)		(0.48	)		4,900			0.61

	Total Natural Gas Revenues	$	25,838		$	3.16		$	30,149		$	3.73		$	(4,311	)	$	(0.57	)


			Average				Average				*Average*
			NYMEX				NYMEX				*NYMEX*
	Production		$/Unit		Production		$/Unit		*Production*		*$/Unit*

Other data:
Oil (MBbls)		6,037	$	26.08		4,935	$	25.92		1,102	$	0.16
Gas (MMcf)		8,175		3.36		8,078		4.06		97		(0.70	)
Combined (MBOE)		7,399				6,281				1,118

Oil revenues increased $29.1 million in 2002 over 2001 primarily due to an increase in oil volumes, while the net wellhead price received remained relatively flat. Oil volumes increased 1,102 MBbls from 2001 to 2002 due to the Central Permian and Paradox Basin acquisitions, as well as increased production from our successful development drilling program. Wellhead oil revenues were reduced by $2.0 million and $2.7 million in 2002 and 2001, respectively, for the net profits interests payments held by others in the CCA. Total oil revenues were further increased by a decrease in hedge payments, which were $2.7 million lower.

Natural gas revenues decreased in 2002 by $4.3 million due to a 28% decrease in the net wellhead price received, from $4.21 in 2001 to $3.03 in 2002, with essentially flat production. This price decline is consistent with the NYMEX decline from $4.06 to $3.36 over the same period. We recovered a portion of the natural gas price decline through our hedges, which generated net receipts of $1.0 million in 2002 versus net payments of $3.9 million in 2001. These hedging receipts are a direct result of the decrease in the average NYMEX price for natural gas.

Lease Operations Expense. Lease operations expense for the year ended December 31, 2002 increased as compared to 2001 by $5.5 million. The increase in lease operations expenses resulted from the increase in volumes as a result of our 2002 Central Permian and Paradox Basin acquisitions and our successful drilling program. See “— Revenues and Production” above. On a per BOE basis, lease operations expenses increased from $4.00 in 2001 to $4.15 in 2002 primarily due to higher per BOE lifting costs for our 2002 acquisitions.

Production, Ad Valorem, and Severance Taxes. Production, ad valorem, and severance taxes for the year ended December 31, 2002 increased as compared to 2001 by approximately $1.8 million. The increase is a direct result of the increase in wellhead revenue. See “— Revenues and Production” above. As a

percentage of oil and natural gas revenues (excluding the effects of net profits and hedges), production, ad valorem, and severance taxes increased slightly from 9.1% to 9.3% from 2001 to 2002.

Depletion, Depreciation, and Amortization (“DD&A”) Expense. DD&A expense increased by approximately $2.8 million in 2002. This increase was due to a 1.1 MMBOE increase in production volumes, partially offset by a decrease in the DD&A rate per BOE. See “— Revenues and Production” above. The average DD&A rate decreased from $5.05 per BOE of production during 2001 to $4.67 per BOE in 2002. The increase in volumes caused a $5.6 million increase in related DD&A expense, while the decrease in the DD&A rate caused a $2.8 million decrease. The decrease is attributable to upward reserve revisions due to higher prices.

General and Administrative (“G&A”) Expense. G&A expense increased $1.1 million in 2002 (excluding non-cash stock based compensation of $9.6 million in 2001). The increase in G&A resulted from the additional staff necessary after the Permian and Paradox Basin acquisitions to manage, expand, and exploit our growing asset base. On a per BOE basis, G&A expense remained relatively flat at $0.83 during 2002 as compared to $0.80 during 2001.

Other Operating Expense. Other operating expense for the year ended December 31, 2002 increased as compared to 2001 by approximately $1.1 million. This amount primarily consists of 2001 severance payment obligations to former employees, as well as transportation costs, namely pipeline fees paid to third parties, geological and geophysical expenses, and delay rentals. The increase is due to higher transportation costs and geological and geophysical expenses in 2002, which more than offset the lack of severance payments in 2002.

Interest Expense. Interest expense for the year ended December 31, 2002 increased $6.3 million over 2001. The increase in interest expense is primarily due to increased levels of debt, amortization of hedge loss (see below), and a higher weighted average interest rate in 2002 as compared to 2001. On June 25, 2002, we issued $150.0 million in 8 3/8% senior subordinated notes, and used most of the proceeds to repay all amounts outstanding under the previous credit facility and entered into a new revolving credit facility. See “— Capital Commitments, Capital Resources and Liquidity” on page 31. For 2002, the weighted average debt balance was $149.7 million, compared with $89.3 million for 2001. Additionally, the weighted average interest rate, including hedges, in 2002 was 8.2%, while it was 6.8% in 2001. The higher weighted average interest rate is due to a higher fixed rate on the 8 3/8% notes as compared to the floating rate debt outstanding previously.

At the time the previous credit facility was terminated, we had three interest rate swaps outstanding, with a notional amount of $30.0 million each, which swapped LIBOR-based floating rates for fixed rates. According to the provisions of SFAS 133, these no longer qualified for hedge accounting. The unrealized loss of $3.8 million at June 25, 2002, which was recognized in accumulated other comprehensive income, is being amortized to interest expense over the original life of the swaps. We amortized $1.6 million of this loss to interest expense during 2002.

The following table illustrates the components of interest expense for 2002 and 2001 (in thousands):


		2002		2001		*Difference*

8 3/8% senior subordinated notes		$	6,488	$	—	$	6,488
Revolving credit facility			2,260		4,596		(2,336	)
Burlington note			—		389		(389	)
Hedge settlements			1,249		717		532
Hedge loss amortization			1,619		—		1,619
Debt issuance cost			314		120		194
Fees and other			376		219		157

	Total	$	12,306	$	6,041	$	6,265

Non-Cash Stock Based Compensation Expense. Non-cash stock based compensation expense decreased from $9.6 million for 2001 to zero in 2002. This non-cash stock based compensation expense is associated with the purchase by our management stockholders of Class A common stock under our management stock plan adopted in August 1998 and was recorded as compensation in accordance with variable plan accounting under Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees (“APB 25”). The $9.6 million of non-cash compensation expense recorded in the first quarter of 2001 represents the final amount of expense to be recorded related to the Class A common stock.

Derivative Fair Value Gain/Loss. The derivative fair value gain of $0.9 million in 2002 represents the ineffective portion of the mark-to-market loss on our derivative hedging instruments, as well as the mark-to-market loss on our two short puts outstanding at December 31, 2002 and our interest rate swap settlements subsequent to the issuance of the senior subordinated notes on June 25, 2002.

Bad Debt Expense. On December 2, 2001, Enron Corp. and certain subsidiaries, including Enron North America Corp. (“Enron”), each filed voluntary petitions for relief under Chapter 11 of Title 11 of the United States Bankruptcy Code. Prior to this date, we had entered into oil and natural gas hedging contracts with Enron, many of which were set to expire at December 31, 2001; however, others related to 2002 and 2003. As a result of the Chapter 11 bankruptcy declaration and pursuant to the terms of our contract with Enron, we terminated all outstanding oil and natural gas derivative contracts with Enron as of December 12, 2001. According to the terms of the contract, Enron is liable to us for the mark-to-market value of all contracts outstanding on that date, which totaled $6.6 million. Additionally, Enron failed to make timely payment of $0.4 million in 2001 hedge settlements. Both of these amounts remained outstanding as of December 31, 2001. Due to the uncertainty of future collection of any or all of the amounts owed to us by Enron, for the year ended December 31, 2001, we have recorded a charge to bad debt expense for the full amount of the receivable, $7.0 million, and recorded a related allowance on the receivable of $7.0 million.

At the time of termination, the market price of our commodity contracts with Enron exceeded their amortized cost on our balance sheet, giving rise to a gain. In accordance with the provisions of SFAS 133, this gain was recorded in other comprehensive income until such time as the original hedged production affected income. As a result, at December 31, 2001, we had $4.8 million in gross unrecognized gains in other comprehensive income that were reversed into earnings during 2002 and 2003. The following table illustrates the amortization of this amount to revenue (in thousands):


Period	Oil		Gas		Total

2002	$	2,822	$	1,594	$	4,416
2003		401		18		419

Total	$	3,223	$	1,612	$	4,835

Impairment of Oil and Natural Gas Properties. Throughout 2001, futures prices for oil and natural gas continued to decline from their December 31, 2000 levels. The SEC price case used for our 2000 reserve estimate was $26.80 per Bbl and $9.77 per Mcf dropping to $19.84 per Bbl and $2.57 per Mcf for the 2001 estimate. Although the SEC price case does not necessarily coincide with management’s estimates of future prices, this indicated the need to assess our oil and natural gas properties for any possible impairment. Thus, we compared the undiscounted future cash flows for each of our oil and natural gas properties to their net book value, which indicated the need for an impairment charge on certain properties. We then compared the net book value of the impaired assets to their estimated fair value, which resulted in a write-down of the value of proved oil and natural gas properties of $2.6 million. Fair value was determined using estimates of future production volumes and estimates of future prices we might receive for these volumes discounted back to a present value using a rate commensurate with the risks inherent in the industry.

We performed a similar review at December 31, 2002 and determined no impairment charge was necessary.

Description of Critical Accounting Estimates


	*Oil and Natural Gas Properties*

Successful Efforts Method. We utilize the successful efforts method of accounting for our oil and natural gas properties as opposed to the full cost method. In general, we believe that the successful efforts method of accounting for oil and natural gas would not result in materially different operating results as we do not currently maintain an active exploratory drilling program. Under the successful efforts method, all development and acquisition costs of proved properties are capitalized and amortized on a unit-of-production basis over the remaining life of proved developed reserves or proved reserves, as applicable. Exploration expenses, including geological and geophysical expenses and delay rentals, are charged to expense as incurred. Costs of drilling exploratory wells are initially capitalized, but charged to expense if and when the well is determined to be unsuccessful. To date, our exploration efforts have been minimal. Expenditures for repairs and maintenance to sustain or increase production from the existing producing reservoir are charged to expense as incurred. Expenditures to recomplete a current well in a different or additional proven or unproven reservoir are capitalized pending determination that economic reserves have been added. If the recompletion is not successful, the expenditures are charged to expense. Expenditures for redrilling or directional drilling in a previously abandoned well are classified as drilling costs to a proven or unproven reservoir for determination of capital or expense. Significant tangible equipment added or replaced is capitalized. Expenditures to construct facilities or increase the productive capacity from existing reserves are capitalized. Internal costs directly associated with the development and exploitation of properties are capitalized as a cost of the property and are classified accordingly in our consolidated financial statements.

Oil and Natural Gas Reserves. Assumptions used by the independent reserve engineers in calculating reserves or regarding the future cash flows or fair value of our properties are subject to change in the future. Future prices received for production and future production costs may vary, perhaps significantly, from the prices and costs assumed for purposes of calculating reserve estimates. We may not be able to develop proved reserves within the periods estimated. Furthermore, prices and costs will not remain constant. Actual production may not equal the estimated amounts used in the preparation of reserve projections. As these estimates change, the amount of calculated reserves change. Any change in reserves directly impacts our estimate of future cash flows from the property, as well as the property’s fair value.

Impairment. Impairments of proved oil and natural gas properties are directly affected by our reserve estimates. We are required to assess the need for an impairment of capitalized costs of oil and natural gas properties and other long-lived assets whenever events or circumstances indicate that the carrying value of those assets may not be recoverable. If impairment is indicated based on a comparison of the asset’s carrying value to its undiscounted expected future net cash flows, then it is recognized to the extent that the carrying value exceeds fair value. Each part of this calculation is subject to a large degree of management judgment, including the determination of property’s reserves, amount and timing of future cash flows, and fair value.

Depletion, Depreciation, and Amortization (“DD&A”). DD&A expense is directly affected by our reserve estimates. Any change in reserves directly impacts the amount of DD&A expense that we recognize in a given period. Assuming no other changes, such as an increase in depreciable base, as our reserves increase, the amount of DD&A expense in a given period decreases and vice versa. Changes in future commodity prices would likely result in increases or decreases in estimated recoverable reserves. Additionally, the Miller & Lents, Ltd., our independent reserve engineers estimate our reserves once a year at December 31.


	*Net Profits Interests*

A major portion of our acreage position in the Cedar Creek Anticline is subject to net profits interests (“NPI”) ranging from 1% to 50%. The holders of these net profits interests are entitled to receive a fixed percentage of the cash flow remaining after specified costs have been deducted from net revenues. The net profits calculations are contractually defined, but in general, net profits are determined after considering operating expense, overhead expense, interest expense, and drilling costs. The amounts of reserves and production calculated to be attributable to these net profits interests are deducted from our reserves and production data, and our revenues are reported net of NPI payments. The reserves and production that are attributed to the NPIs are calculated by dividing estimated future NPI payments (in the case of reserves) or prior period actual NPI payments (in the case of production) by the commodity prices current at the determination date. Fluctuations in commodity prices and the levels of development activities in the CCA from period to period will impact the reserves and production attributed to the NPIs and will have an inverse effect on our reported reserves and production. Based largely on higher commodity prices, we expect the net profit interest to be higher in the year 2004 and possibly beyond, which directly impacts our revenues, production, reserves, and earnings.


	*Revenue Recognition*

Revenues are recognized for our share of jointly owned properties as oil and natural gas is produced and sold, net of royalties and net profits interest payments. Natural gas revenues are also reduced by any processing and other fees paid except for transportation costs paid to third parties which are recorded as expense. Revenues are recorded using the sales method of accounting whereby revenue is recognized as natural gas is sold by us rather than as our working interest share of production. Royalties, net profits interests, and severance taxes are paid based upon the actual price received from the sales. To the extent actual quantities and values of oil and natural gas are unavailable for a given reporting period because of timing or information not received from third parties, we estimate and record the expected sales volumes and values for those properties. We also do not recognize revenue for the production in tanks or pipelines that has not been delivered to the purchaser yet. Our net oil inventories in pipelines were 46,622 Bbls and 104,954 Bbls at December 31, 2003 and 2002, respectively. Natural gas imbalances under-delivered to us at December 31, 2003 and December 31, 2002, were 446,000 MMBTU and 510,000 MMBTU, respectively.


	*Income Taxes*

Section 43 Credits. Section 43 of the Internal Revenue Code (“Code”) allows a 15 percent tax credit for certain enhanced oil recovery project costs incurred in the United States. We believe project costs incurred related to our HPAI tertiary recovery project on the CCA qualify under the provisions of the Code and, therefore, we have reduced income tax expense by 15 percent of project costs incurred to date. The tax basis for the properties (and related intangible drilling cost deductions and future depreciation deductions) is reduced by the amount of the enhanced oil recovery tax credit. In order to qualify for the credits a project must meet all of the following requirements:

      1. The project involves the application of one or more qualified tertiary recovery methods that is reasonably expected to result in more than an insignificant increase in the amount of crude oil that ultimately will be recovered;

      2. The project is located within the United States;

      3. The first injection of liquids, gases, or other matter for the project occurs after December 31, 1990; and

      4. The project is certified by a petroleum engineer.

According to the Code, the costs that will qualify for the credit when paid or incurred in connection with a qualifying enhanced oil recovery project include:

      1. Tangible Property. Any amount paid for tangible property that is an integral part of a qualified enhanced oil recovery project, and with respect to which depreciation is allowable.

      2. Intangible Drilling and Development Costs. Intangible drilling cost with respect to which the taxpayer may make an intangible drilling costs deduction election under Code Sec. 263(c).

      3. Qualified Tertiary Injectant Expenses. Any qualified tertiary injectant expenses for which a deduction is allowable under any Code section.

If our federal income tax returns are reviewed by the Internal Revenue Service (the “IRS”), the IRS could disagree with our decision and disallow a portion of the credit. While we believe our HPAI project qualifies for the tax credit and that our accounting and tracking of the costs related to project are accurate, should the IRS disagree with our position, we would be required to record additional income tax expense to the extent tax credits have been previously recognized.


	*Stock-based Compensation*

Employee stock options and restricted stock awards are accounted for under the provisions of Accounting Principles Board Opinion No. 25 (“APB 25”), “Accounting for Stock Issued to Employees.” Accordingly, no compensation is recorded for stock options that are granted to employees or non-employee directors with an exercise price equal to or above the common stock price on the grant date. If compensation expense for the stock based awards had been determined using the provisions of SFAS 123, our net income and net income per share would have been adjusted to the pro forma amounts indicated below (in thousands, except per share amounts):



		Year Ended December 31,


		2003		2002		2001

As Reported:
	Net income	$	63,641	$	37,685	$	16,179
	Non-cash stock based compensation (net of taxes)		381		—		9,587
	Diluted net income per share		2.10		1.25		0.56
Pro Forma:
	Net income	$	62,093	$	36,408	$	15,475
	Non-cash stock based compensation (net of taxes)		1,929		1,277		10,291
	Diluted net income per share		2.05		1.21		0.54


	*Hedging and Related Activities*

We use various financial instruments for non-trading purposes to manage and reduce price volatility and other market risks associated with our crude oil and natural gas production. These arrangements are structured to reduce our exposure to commodity price decreases, but they can also limit the benefit we might otherwise receive from commodity price increases. Our risk management activity is generally accomplished through over-the-counter forward derivative contracts executed with large financial institutions. We also use derivative instruments in the form of interest rate swaps, which hedge our risk related to interest rate fluctuation.

Effective January 1, 2001, we adopted Statement of Financial Accounting Standards No. 133 (“SFAS 133”), “Accounting for Derivative Instruments and Hedging Activities.” This standard requires us to recognize all of our derivative and hedging instruments in our statements of financial position as either assets or liabilities and measure them at fair value. If a derivative does not qualify for hedge accounting, it must be adjusted to fair value through earnings. However, if a derivative does qualify for hedge accounting, depending on the nature of the hedge, changes in fair value can be offset against the

change in fair value of the hedged item through earnings or recognized in other comprehensive income until such time as the hedged item is recognized in earnings.

To qualify for cash flow hedge accounting, the cash flows from the hedging instrument must be highly effective in offsetting changes in cash flows due to changes in the underlying items being hedged. In addition, all hedging relationships must be designated, documented, and reassessed periodically. Most of our derivative financial instruments qualify for hedge accounting. In accordance with the provisions of SFAS 133, cash flow hedges are marked-to-market through comprehensive income each quarter.

Currently, all of our derivative financial instruments that are designated as hedges are designated as cash flow hedges. These instruments hedge the exposure of variability in expected future cash flows that is attributable to a particular risk. The effective portion of the gain or loss on these derivative instruments is recorded in ‘Other Comprehensive Income’ in Stockholders’ Equity and reclassified into earnings in the same period in which the hedged transaction affects earnings. Any ineffective portion of the gain or loss is recognized as ‘Derivative fair value (gain) loss’ in the Consolidated Statements of Operations immediately. While management does not anticipate changing the designation of any of our current derivative contracts as hedges, factors beyond our control can preclude the use of hedge accounting. One example would be variability in the NYMEX price for oil or natural gas, upon which many of our commodity derivative contracts are based, that does not coincide with changes in the spot price for oil and natural gas that we are paid. Another example would be if the counterparty to a derivative contract was deemed no longer creditworthy and non-performance under the terms of the contract was likely. To the extent our derivative contracts are not designated as hedges, high earnings volatility can result, as any future changes in the market value of the contract would then be marked-to-market through earnings.

Capital Commitments, Capital Resources and Liquidity

Capital Commitments. Our primary needs for cash are as follows:

• Development and exploitation of our existing oil and natural gas properties

• High-pressure air injection programs on our CCA properties

• Acquisitions of oil and natural gas properties

• Leasehold and acreage costs

• Other general property and equipment

• Funding of necessary working capital

• Payment of contractual obligations

Development and Exploitation. Our capital expenditures for conventional development and exploitation during the years ended December 31, 2003 and 2002 totaled $86.1 million and $73.7 million, respectively.

For 2004, we expect to invest $93 million in development and exploitation. We have based our 2004 forecasts on the assumptions of $23.50 per Bbl and $3.75 per Mcf NYMEX prices. For comparability and accountability, we take a constant approach to budgeting commodity prices. We analyze our inventory of capital projects based on $23.50 per Bbl and $3.75 per Mcf NYMEX prices to ensure a rate of return to our shareholders without the benefit of escalating future commodity prices. If NYMEX prices trend downward below our base deck, we may reevaluate capital projects and may adjust the capital budgeted for development and exploitation investments accordingly.

High-Pressure Air Injection. Our capital expenditures for high-pressure air injection during the years ended December 31, 2003 and 2002 totaled $12.9 million and $6.6 million, respectively. In 2003, we began implementing our second HPAI program in the Little Beaver unit of the CCA and began injecting air in the reservoir in December 2003. We expect to have the Little Beaver unit fully implemented by the first quarter of 2004. The Little Beaver unit project was taken from concept to implementation in less than

9 months. We successfully negotiated a contract from a third party to supply the air compression services to Little Beaver, which reduced the up front capital requirements for the Little Beaver unit project. In 2002, we began a pilot program to begin injecting air into the Red River U4 reservoir in a portion of the Pennel Unit of the CCA. Because of positive results, we are planning to expand the project in the Pennel unit of the CCA with a $25.2 million expansion of the project which we expect to complete by early 2005. We believe that the HPAI program will generate a higher rate of return than other tertiary processes and can be applied throughout the CCA. The zone of our initial focus, the Red River U4 zone, is the same zone where HPAI has been successfully implemented by other operators in adjacent areas and on the Pennel unit of the CCA. Response from HPAI investments is not expected until ten to eighteen months from the time of first injection.

For 2004, we expect to invest $34 million in high-pressure air injection. We have based our 2004 forecasts on the assumptions of $23.50 per Bbl and $3.75 per Mcf NYMEX prices. See “— Development and Exploitation” above regarding our approach to budgeting commodity prices.

Acquisitions. Our capital expenditures for oil and natural gas acquisitions during the years ended December 31, 2003 and 2002 totaled $54.6 million and $78.5 million, respectively. In 2003, we completed an acquisition of interests in natural gas properties in North Louisiana. The properties are located in the Elm Grove Field in Bossier Parish, Louisiana and are non-operated working interests ranging from 2% to 38% across 1,800 net acres in 15 sections. The production and reserves of the properties are substantially all natural gas. On January 1, 2002, we completed the Central Permian acquisition from Conoco for approximately $50.1 million. During the second quarter of 2002, we closed a second, follow-on acquisition of additional working interest for $8.3 million. The Central Permian properties increased our operational presence in West Texas. On August 29, 2002 we acquired an interest in oil and natural gas properties in southeast Utah’s Paradox Basin.

We will continue to pursue acquisitions of properties with similar upside potential to our current producing properties portfolio. For the year ended 2003, we evaluated over $1 billion of potential acquisitions. We do not budget for acquisitions but we will continue to evaluate acquisition opportunities as they arise in 2004 with the same disciplined commitment to acquire assets that fit our portfolio and continue to create value.

Our current $140 million capital budget for 2004 does not include any funds for the development and exploitation of oil and natural gas properties that we may acquire during 2004. Our practice is to review our capital budget following a significant acquisition. We are currently undertaking such a review in connection with the Cortez transaction.

Leasehold and Acreage Costs. Our capital expenditures for leasehold and acreage costs during the years ended December 31, 2003 and 2002 totaled $0.1 million and $0.4 million, respectively.

For 2004, we expect to invest $12 million for leasehold and acreage costs. Compared to historical expenditures for leasehold and acreage, 2004 will be a significant increase in capital expenditures. We plan to actively pursue leases and acreage in our core areas that we are currently operating oil and natural gas properties. These investments are not expected to result in oil and natural gas production in 2004.

Other General Property and Equipment. Our capital expenditures for other general property and equipment during the years ended December 31, 2003 and 2002 totaled $1.5 million and $0.7 million, respectively. Capital expenditures for other general property and equipment include corporate leasehold improvements, computers, software, telecommunications equipment, field trucks, and field rental equipment.

For 2004, we expect to invest $0.8 million in other general property and equipment.

Working Capital. At December 31, 2003, our working capital was $(0.1) million while at December 31, 2002 working capital was $12.5 million, a decrease of $12.6 million. The decrease is primarily attributable to cash and cash equivalents. Excluding the decrease in cash of $12.6 million, working capital was essentially flat from 2002 to 2003. In order to minimize our interest expense, we use

excess cash reserves to pay down any amounts outstanding under our revolving credit facility. However, at the end of 2002, due to the margin maintenance requirements with our commodity derivative counterparties and the high commodity price environment, we maintained cash reserves on hand to satisfy any margin calls as they arose. Thus, we held a much higher cash and cash equivalents balance at December 31, 2002 than would otherwise be held. This resulted in the decrease in working capital from December 31, 2002 to December 31, 2003. Currently, as of March 3, 2004, we have $4.5 million posted related to our derivatives margin account.

For 2004, we expect working capital to remain relatively flat to 2003. We anticipate cash reserves to be close to zero as we use any excess cash to fund capital obligations and any additional excess cash would be used to pay down our existing credit facility. We do not plan to pay cash dividends in the foreseeable future. The overall 2004 commodity prices for oil and natural gas will be the largest variable driving the different components of working capital. Our operating cash flow is determined in a large part by commodity prices. Assuming moderate to high commodity prices, our operating cash flow should remain positive for the foreseeable future. We have budgeted capital expenditures of approximately $140.0 million for 2004. The level of these and other future expenditures is largely discretionary, and the amount of funds devoted to any particular activity may increase or decrease significantly, depending on available opportunities and market conditions. We plan to finance our ongoing expenditures using internally generated cash flow, available cash, and our existing credit agreement.

Contractual Obligations. The following table illustrates our contractual obligations and commercial commitments outstanding at December 31, 2003 (in thousands):



	Payments Due by Period
Contractual Obligations and
Commercial Commitments	Total		2004		2005-2006		2007-2008		Thereafter

8 3/8% Notes(1)	$	256,782	$	12,563	$	25,125	$	25,125	$	193,969
Revolving Credit Facility(2)		28,593		637		27,956		—		—
Derivative Obligations(3)		8,204		4,903		2,272		1,029		—
Development Commitments(4)		50,793		48,923		1,270		600		—
Operating Leases(5)		2,843		951		1,507		342		43

Totals	$	347,215	$	67,977	$	58,130	$	27,096	$	194,012

(1) Amounts included in the table above include both principal and projected interest payments. See information presented in “Note 6. Indebtedness” to the accompanying consolidated financial statements for additional information regarding our long-term debt.

(2) Amounts included in the table above include both principal and projected interest payments. See “Note 6. Indebtedness” to the accompanying consolidated financial statements for additional information regarding our long-term debt. Giving effect to the Cortez acquisition, the pro-forma amount outstanding under our revolving credit facility as of December 31, 2003 would be approximately $152.0 million.

(3) Derivative obligations represent liabilities for derivatives that were valued as of December 31, 2003. The ultimate settlement amounts of the remaining portions of our derivative obligations are unknown because they are subject to continuing market risk. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” and “Note 11. Financial Investments” to the accompanying consolidated financial statements for additional information regarding our derivative obligations.

(4) Development commitments represent authorized purchases not placed to vendors, thus not accrued at year-end. These purchases are authorized and expected to be made during 2004 unless circumstances change. Above amounts also include minimum transmission payments for electricity.

(5) Operating leases represent office space and equipment obligations that have remaining non-cancelable lease terms in excess of one year. See “Note 4. Commitments and Contingencies” to the accompanying consolidated financial statements for additional information regarding our operating leases.

Investing Activities. Cash used by investing activities decreased by $5.6 million from 2002 to 2003. This was due to offsetting changes in its two primary components: acquisition of oil and natural gas properties, which decreased by $23.9 million; and development of oil and natural gas properties, which increased $18.7 million. Cash used for the acquisition of oil and natural gas properties varies year to year based on our success in acquiring oil and natural gas properties. Our bid price is a price we feel provides a certain level of return based on our expectation of future oil and natural gas prices, while providing potential for some upside realization. Success in the acquisition market is largely driven by competition in the marketplace and in the availability of properties for sale. During 2002, we were successful in completing two major property acquisitions, one comprised of properties in the Paradox Basin of Utah and one comprised of properties in the Permian Basin of West Texas at a combined cost of $78.6 million, while in 2003 we were successful in completing one major property acquisition of properties in the North Louisiana Salt Basin of Louisiana at a cost of $54.6 million. The increase in cash used in the development of oil and natural gas properties of $18.7 was the result of drilling 29 more gross wells (8.3 net) and the expansion of the HPAI project into the Little Beaver area of the CCA.

Capital Resources. Our primary capital resources are net cash provided by operating activities, and proceeds from financing activities which are used to fund our capital commitments. Our primary needs for cash include our high-pressure air injection program in the CCA, acquisitions of oil and natural gas properties, development and exploitation of our existing oil and natural gas properties, leasehold and acreage cost, funding of necessary working capital, and payment of contractual obligations.

Operating Activities. For 2003, cash provided by operating activities increased by $32.3 million. This increase resulted from the $26.0 increase in net income coupled with an increase in deferred taxes of $11.8 million, offset by decrease in changes in operating assets and liabilities from 2002 to 2003 of $6.4 million. The increase in net income was primarily due to increased production volumes and higher commodity prices compared to 2002.

Financing Activities. During 2003 proceeds from financing activities was $17.3 million, while it was $80.7 million in 2002. In 2003, we were able to close the initial Elm Grove acquisition and subsequent interests for $54.6 million and fund our $99.0 million capital drilling program with only a modest $13.0 million increase in our revolving credit facility. During 2002, however, we increased our debt by $88.0 million to fund two property acquisitions, Central Permian and Paradox Basin, and fund $80.3 million in development expenditures.

Additionally during 2003, on November 13, 2003, we priced a public offering of 8.0 million shares of our common stock at a price to the public of $20.25 per share. The underwriters also exercised their over-allotment option for an additional 1.06 million shares of common stock, at a price of $20.25 per share, on December 2, 2003, for a total of 9.06 million shares. We used all of the net proceeds to repurchase 6,866,643 shares of our common stock from J.P. Morgan and 2,193,357 shares from Warburg Pincus at a price of $19.3775 per share. The 9.06 million shares we purchased were retired upon repurchase. Our total shares outstanding did not change as a result of this offering. Net proceeds from the original offering and the over-allotment option totaled approximately $175.6 million, after deducting underwriting discounts and commissions and the estimated expenses of the offering. After giving effect to the repurchase, J.P. Morgan no longer beneficially owns any of our common stock and Warburg Pincus beneficially owns 24.5% of our common stock.

This compares to 2002 when on June 25, 2002, we sold $150 million of 8 3/8% Senior Subordinated Notes maturing on June 15, 2012 in a private placement pursuant to Rule 144A. We received net proceeds of $145.6 million from the sale of the 8 3/8% notes, after deducting debt issuance costs. The proceeds were used to repay and retire our prior credit facility ($143.0 million), to pay the fees and expenses related to the new revolving credit facility ($1.5 million), and to hold in reserve for the Paradox Basin acquisition ($1.1 million).

Liquidity. Our principal source of short-term liquidity is our revolving credit facility. We entered into the current revolving credit facility on June 25, 2002. Borrowings under the facility are secured by a first priority lien on our proved oil and natural gas reserves. Availability under the facility is determined

through semi-annual borrowing base determinations and may be increased or decreased. The amount available under our credit facility increased in 2003 by $50.0 million to $270.0 million, with $29.0 million outstanding as of December 31, 2003. We expect the pending acquisition of Cortez will reduce the availability by $123.0 million. The maturity date of the new facility is June 25, 2006.

Amounts outstanding under the facility are subject to varying rates of interest based on the amount outstanding and our borrowing base. Based on our current $270.0 million borrowing base, our applicable interest rates are calculated as follows:


Amount Outstanding	Rate

$0 to $55,000,000		LIBOR + 1.000%
$55,000,001 to $110,000,000		LIBOR + 1.125%
$110,000,001 to $165,000,000		LIBOR + 1.250%
$165,000,001 to $198,000,000		LIBOR + 1.500%
$198,000,001 to $270,000,000		LIBOR + 1.750%

Our revolving credit facility and the indenture related to the 8 3/8% notes contain financial and other restrictive covenants that limit our ability to engage in activities that may be in our long-term best interests. The covenants under our revolving credit facility are similar but generally more restrictive than the covenants under the indenture. Our ability to borrow under our revolving credit facility is subject to financial covenants, including leverage, interest and fixed charge coverage ratios. Our revolving credit facility limits our ability to effect mergers, asset sales, and change of control events. These covenants also contain restrictions regarding our ability to incur additional indebtedness in the future. In some cases, our subsidiaries are subject to similar restrictions that may restrict their ability to make distributions to us. The indenture related to our 8 3/8% notes also contains limitations on our ability to effect mergers and change of control events, incur additional indebtedness, sell assets, declare and pay dividends or make other restricted payments, enter into transactions with affiliates and subject our assets to liens.

Based on current commodity conditions, we believe that our capital resources are adequate to meet the requirements of our business through 2005 and the foreseeable future. Based on our anticipated capital programs, we expect to invest our internally generated cash flow to replace production and enhance our development programs. During 2004, we have planned total capital expenditures of approximately $140 million, although we may need additional capital to pursue acquisitions or other capital projects. Our current capital budget does not include any funds for development and exploitation of oil and natural gas properties that we may acquire during 2004. Our practice is to review our capital budget following a significant transaction. We are currently undertaking such review in connection with the Cortez transaction.

Substantially all of our capital expenditures are discretionary and will be undertaken only if funds are available and the projected rates of return are satisfactory. Future cash flows are subject to a number of variables including the level of oil and natural gas production and prices. Operations and other capital resources may not provide cash in sufficient amounts to maintain planned levels of capital expenditures. Additionally, we are required to maintain margin amounts and/or letters of credits with the counterparties to our outstanding hedges if the mark-to-market value of our hedges reach a certain negative value. Although we did not have any margin deposits with our counterparties as of December 31, 2003, if commodity prices were to rise substantially, we would be required to post margin with one or more counterparties for expected future hedging settlements. Currently, as of March 3, 2004, we have $4.5 million posted related to our derivatives margin account.

Book Capitalization. At December 31, 2003, we had total assets of $672.1 million. Total capitalization was $538.0 million, of which 66.7% was represented by stockholders’ equity and 33.3% by senior debt.

Inflation and Changes in Prices

While the general level of inflation affects certain of our costs, factors unique to the petroleum industry result in independent price fluctuations. Historically, significant fluctuations have occurred in oil and natural gas prices. In addition, changing prices often cause costs of equipment and supplies to vary as industry activity levels increase and decrease to reflect perceptions of future price levels. Although it is difficult to estimate future prices of oil and natural gas, price fluctuations have had, and will continue to have, a material effect on us.

The following table indicates the average oil and natural gas prices received for the years ended December 31, 2003, 2002, and 2001. Average equivalent prices for 2003, 2002, and 2001 were decreased by $1.89, $0.70, and $2.04 per BOE, respectively, as a result of our hedging activities. Average prices per equivalent barrel indicate the composite impact of changes in oil and natural gas prices. Natural gas production is converted to oil equivalents at the conversion rate of six Mcf per Bbl.


	Oil		Natural Gas		Combined
	($/Bbl)		($/Mcf)		($/BOE)

Net Price Realization with Hedges
Year ended December 31, 2003	$	26.72	$	4.83	$	27.14
Year ended December 31, 2002		22.34		3.16		21.72
Year ended December 31, 2001		21.43		3.73		21.64
Average Wellhead Price
Year ended December 31, 2003	$	28.82	$	5.00	$	29.03
Year ended December 31, 2002		23.38		3.03		22.42
Year ended December 31, 2001		23.25		4.21		23.68

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

Our disclosure and analysis in this Report contains some forward-looking statements. Forward-looking statements give our current expectations or forecasts of future events. You can identify these statements by the fact that they do not relate strictly to historical or current facts. These statements may include words such as “anticipate”, “estimate”, “expect”, “project”, “intend”, “plan”, “believe”, “should”, and other words and terms of similar meaning in connection with any discussion of future operating or financial performance. In particular, these include, among other things, statements relating to:

• expected capital expenditures and the focus of our capital program;

• areas of future growth;

• our drilling program;

• future horizontal development, secondary development and tertiary recovery potential;

• the implementation of our High-Pressure Air Program, the ability to expand the program to other parts of the CCA and the effects thereof;

• the completion of current HPAI projects and the effects thereof;

• anticipated prices for oil and natural gas;

• projected revenues; FD&A costs; lifting costs; lease operations expenses; production, ad valorem and severance taxes; general and administrative expenses; taxes; and DD&A;

• timing and amount of future production of oil and natural gas;

• expected hedging positions and payments related to hedging contracts;

• expectations regarding working capital, cash flow and anticipated liquidity;

• the closing of the Cortez transaction and the benefits to be derived therefrom;

• projected borrowings under our credit facility; and

• marketing of oil and natural gas.

Our actual results may differ significantly from the results discussed in the forward-looking statements. Such statements involve risks and uncertainties, including, but not limited to, the matters discussed in the subsection entitled “Factors That May Affect Future Results and Financial Condition” below and elsewhere in this Report and our other filings with the Securities and Exchange Commission. If one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual outcomes may vary materially from those indicated. We undertake no responsibility to update for changes related to these or any other factors that may occur subsequent to this filing for any reason.

FACTORS THAT MAY AFFECT FUTURE RESULTS AND FINANCIAL CONDITION

You should read carefully the following factors and all other information contained in this Report. If any of the risks and uncertainties described below or elsewhere in this Report actually occur, our business, financial condition or results of operations could be materially adversely affected. In that case, the trading price of our common stock could decline, and an investor may lose all or part of his investment.

Risks Related to Our Business


	*Oil and natural gas prices are volatile and sustained periods of low prices could materially and adversely affect our financial condition and results of operations.*

Historically, the markets for oil and natural gas have been volatile, and these markets are likely to continue to be volatile in the future. Our revenues, profitability and future growth depend substantially on prevailing oil and natural gas prices. Lower oil and natural gas prices may reduce the amount of oil and natural gas that we can economically produce. Prevailing oil and natural gas prices also affect the amount of internally generated cash flow available for repayment of indebtedness and capital expenditures. In addition, the amount we can borrow under our revolving credit facility is subject to periodic redetermination based in part on changing expectations of future oil and natural gas prices.

The factors that can cause oil and natural gas price volatility include:

• the supply of domestic and foreign oil and natural gas;

• the ability of members of the Organization of Petroleum Exporting Countries to agree upon and maintain oil prices and production levels;

• political instability or armed conflict in oil or natural gas producing regions;

• the level of consumer demand;

• weather conditions;

• the price and availability of alternative fuels;

• domestic and foreign governmental regulations and taxes;

• domestic political developments; and

• worldwide economic conditions.

The volatile nature of markets for oil and natural gas makes it difficult to reliably estimate future prices. Any decline in oil and natural gas prices adversely affects our financial condition. If oil or natural gas prices decline significantly for a sustained period of time, we may, among other things, be unable to meet our financial obligations, make planned expenditures or raise additional capital.


	Reserve estimates depend on many assumptions that may prove to be inaccurate. Any material inaccuracies in our reserve estimates or underlying assumptions could cause the quantities and net present value of our reserves to be overstated.

Estimating quantities of proved oil and natural gas reserves is a complex process that requires interpretations of available technical data and numerous assumptions, including certain economic assumptions. Any significant inaccuracies in these interpretations or assumptions or changes in conditions could cause the quantities and net present value of our reserves to be overstated.

To prepare estimates of economically recoverable oil and natural gas reserves and future net cash flows, we must analyze many variable factors, such as historical production from the area compared with production rates from other producing areas. We must also analyze available geological, geophysical, production and engineering data, and the extent, quality and reliability of this data can vary. The process also involves economic assumptions relating to commodity prices, production costs, severance and excise taxes, capital expenditures and workover and remedial costs. Actual results most likely will vary from our estimates. Any significant variance could reduce the estimated quantities and present value of our reserves.

You should not assume that the present value of future net cash flows from our proved reserves referred to in this Report is the current market value of our estimated oil and natural gas reserves. In accordance with SEC requirements, we base the estimated discounted future net cash flows from our proved reserves on prices and costs in effect on the date of the estimate, holding the prices and costs constant throughout the life of the properties. Actual future prices and costs may differ materially from those used in the net present value estimate, and future net present value estimates using then current prices and costs may be significantly less than the current estimate.


	*The results of high pressure air injection techniques are uncertain.*

We utilize high pressure air injection, or HPAI, techniques on some of our properties and plan to use the techniques in the future on a substantial portion of our properties, including our CCA properties. The additional production and reserves attributable to our use of the techniques, if any, are inherently difficult to predict. If our HPAI programs do not allow for the extraction of residual hydrocarbons in the manner or to the extent that we anticipate, our future results of operations and financial condition could be materially adversely affected.


	*If oil and natural gas prices decrease, we may be required to take write downs.*

We may be required to write down the carrying value of our oil and natural gas properties when future estimated oil and gas prices are low or if we have substantial downward adjustments to our estimated proved reserves or increases in our estimates of operating expenses or development costs. We capitalize the costs to acquire, find and develop our oil and natural gas properties under the successful efforts accounting method. The net capitalized costs of our oil and natural gas properties may not exceed their estimated fair value. If net capitalized costs of our oil and natural gas properties exceed their fair value, we must charge the amount of the excess to earnings. We review the carrying value of our properties quarterly, based on changes in expectations of future oil and natural gas prices, expenses and tax rates. Once incurred, a write down of oil and natural gas properties is not reversible at a later date even if oil or gas prices increase.


	*Our acquisition strategy subjects us to numerous risks that could adversely affect our results of operations.*

Acquisitions are an essential part of our growth strategy, and our ability to acquire additional properties on favorable terms is important to our long-term growth. Depending on conditions in the acquisition market, it may be difficult or impossible for us to identify properties for acquisition or we may not be able to make acquisitions on terms that we consider economically acceptable. Even if we are able to identify suitable acquisition opportunities, our acquisition strategy depends upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals.

The successful acquisition of producing properties requires an assessment of several factors, including:

• recoverable reserves;

• future oil and natural gas prices;

• operating costs; and

• potential environmental and other liabilities.

The accuracy of these assessments is inherently uncertain. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. Inspections may not always be performed on every well, and structural and environmental problems are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. We are often not entitled to contractual indemnification for environmental liabilities and acquire properties on an “as is” basis.

Possible future acquisitions could result in our incurring additional debt, contingent liabilities and expenses, all of which could have a material adverse effect on our financial condition and operating results. Furthermore, our financial position and results of operations may fluctuate significantly from period to period based on whether significant acquisitions are completed in particular periods. Competition for acquisitions is intense and may increase the cost of, or cause us to refrain from, completing acquisitions.


	*The failure to properly manage growth through acquisitions could adversely affect our results of operations.*

Growing through acquisitions and managing that growth will require us to continue to invest in operational, financial and management information systems and to attract, retain, motivate and effectively manage our employees. Pursuing and integrating acquisitions involves a number of risks, including:

• diversion of management attention from existing operations;

• unexpected losses of key employees, customers and suppliers of the acquired business;

• conforming the financial, technological and management standards, processes, procedures and controls of the acquired business with those of our existing operations; and

• increasing the scope, geographic diversity and complexity of our operations.

The process of integrating acquired operations into our existing operations may result in unforeseen operating difficulties and may require significant management attention and financial resources that would otherwise be available for the ongoing development or expansion of existing operations.


	*A substantial portion of our producing properties is located in one geographic area.*

We have extensive operations in the Williston Basin of Montana and North Dakota. As of December 31, 2003, our CCA properties in the Williston Basin represented approximately 73% of our proved reserves and 61% of our 2003 production. Any circumstance or event that negatively impacts production or marketing of oil and natural gas in the Williston Basin could materially reduce our earnings and cash flow.


	*Derivative instruments expose us to risks of financial loss in a variety of circumstances.*

We use derivative instruments in an effort to reduce our exposure to fluctuations in the prices of oil and natural gas and to reduce our cash outflows related to interest. Our derivative instruments expose us to risks of financial loss in a variety of circumstances, including when:

• a counterparty to our derivative instruments is unable to satisfy its obligations;

• production is less than expected; or

• there is an adverse change in the expected differential between the underlying price in the derivative instrument and actual prices received for our production.

Derivative instruments may limit our ability to realize increased revenue from increases in the prices for oil and natural gas.

We adopted Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS 133”), on January 1, 2001. SFAS 133 generally requires us to record each hedging transaction as an asset or liability measured at its fair value. Each quarter we must record changes in the fair value of our hedges, which could result in significant fluctuations in net income and stockholders’ equity from period to period.


	*Drilling oil and natural gas wells is a high-risk activity.*

Drilling oil and natural gas wells, including development wells, involves numerous risks, including the risk that no commercially productive oil or natural gas reservoirs will be discovered. We often are uncertain as to the future cost or timing of drilling, completing and producing wells. We may not recover all or any portion of our investment in drilling oil and natural gas wells.

Our drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including unexpected drilling conditions or miscalculations, title problems, pressure or irregularities in formations, equipment failures or accidents, adverse weather conditions, compliance with environmental and other governmental requirements and cost of, or shortages or delays in the availability of, drilling rigs and equipment.


	*The failure to replace our reserves could adversely affect our financial condition.*

Our future success depends upon our ability to find, develop or acquire additional oil and natural gas reserves that are economically recoverable. Our proved reserves generally decline when reserves are produced, unless we conduct successful exploitation or development activities or acquire properties containing proved reserves, or both. We may not be able to find, develop or acquire additional reserves on an economic basis.

Substantial capital is required to replace and grow reserves. If lower oil and natural gas prices or operating difficulties result in our cash flow from operations being less than expected or limit on our ability to borrow under our revolving credit facility, we may be unable to expend the capital necessary to find, develop or acquire new oil and natural gas reserves.


	*We have limited control over the activities on properties we do not operate.*

Other companies operate some of the properties in which we have an interest. We have limited ability to influence or control the operation or future development of these non-operated properties or the amount of capital expenditures that we are required to fund with respect to them. Our dependence on the operator and other working interest owners for these projects and our limited ability to influence or control the operation and future development of these properties could materially adversely affect the realization of our targeted returns on capital in drilling or acquisition activities and lead to unexpected future costs.


	*Our business involves many operating risks that can cause substantial losses; insurance may be unavailable or inadequate to protect us against these risks.*

Our operations are subject to hazards and risks inherent in drilling for, producing and transporting oil and natural gas, such as fires; natural disasters; explosions; formations with abnormal pressures; blowouts; collapses of wellbore, casing or other tubulars; failure of oilfield drilling and service tools; uncontrollable flows of oil, natural gas, formation water or drilling fluids; pressure forcing oil or natural gas out of the wellbore at a dangerous velocity coupled with the potential for fire or explosion; changes in below-ground pressure in a formation that cause surface collapse or cratering; pipeline ruptures or cement failures; environmental hazards, such as oil spills, natural gas leaks and discharges of toxic gases; and weather. If any of these events occur, we could incur substantial losses as a result of injury or loss of life; damage to and destruction of property, natural resources and equipment; pollution and other environmental damage; regulatory investigations and penalties; suspension of our operations; and repair and remediation costs.

We do not maintain insurance against the loss of oil or natural gas reserves as a result of operating hazards, nor do we maintain business interruption insurance. In addition, pollution and environmental risks generally are not fully insurable. We may experience losses for uninsurable or uninsured risks or losses in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could harm our financial condition and results of operations.


	*Terrorist activities and the potential for military and other actions could adversely affect our business.*

The threat of terrorism and the impact of military and other action have caused instability in world financial markets and could lead to increased volatility in prices for oil and natural gas, all of which could adversely affect the markets for our operations. Future acts of terrorism could be directed against companies operating in the United States. The U.S. government has issued public warnings that indicate that energy assets might be specific targets of terrorist organizations. These developments have subjected our operations to increased risk and, depending on their ultimate magnitude, could have a material adverse effect on our business.


	*Our development and exploitation operations require substantial capital, and we may be unable to obtain needed financing on satisfactory terms.*

We make and will continue to make substantial capital expenditures in development and exploitation projects. We intend to finance these capital expenditures through a combination of cash flow from operations and external financing arrangements. Additional financing sources may be required in the future to fund our capital expenditures. Financing may not continue to be available under existing or new financing arrangements, or on acceptable terms, if at all. If additional capital resources are not available, we may be forced to curtail our drilling and other activities or be forced to sell some of our assets on an untimely or unfavorable basis.


	*The loss of key personnel could adversely affect our business.*

We depend to a large extent on the efforts and continued employment of I. Jon Brumley, our Chairman of the Board and Chief Executive Officer, Jon S. Brumley, our President, and other key personnel. The loss of the services of Mr. I. Jon Brumley or Mr. Jon S. Brumley or other key personnel could adversely affect our business, and we do not have employment agreements with, and do not maintain key man insurance on the lives of, any of these persons. Our drilling success and the success of other activities integral to our operations will depend, in part, on our ability to attract and retain experienced geologists, engineers and other professionals. Competition for experienced geologists, engineers and some other professionals is extremely intense. If we cannot retain our technical personnel or attract additional experienced technical personnel, our ability to compete could be harmed.


	*The marketability of our oil and natural gas production is dependent upon transportation facilities over which we have no control.*

The marketability of our oil and natural gas production depends in part upon the availability, proximity and capacity of pipelines, oil and natural gas gathering systems and processing facilities. Any significant change in market factors affecting these infrastructure facilities could harm our business. We deliver oil and natural gas through gathering systems and pipelines that we do not own. These facilities may not be available to us in the future.


	*Competition in the oil and natural gas industry is intense, and many of our competitors have greater financial, technological and other resources than we do.*

We operate in the highly competitive areas of oil and natural gas acquisition, development, exploitation and production. The oil and natural gas industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. We face intense competition from independent, technology-driven companies as well as from both major and other independent oil and natural gas companies in each of the following areas:

• acquiring desirable producing properties or new leases for future exploration;

• marketing our oil and natural gas production;

• integrating new technologies; and

• acquiring the equipment and expertise necessary to develop and operate our properties.

Many of our competitors have financial, technological and other resources substantially greater than ours, which may adversely affect our ability to compete with these companies. These companies may be able to pay more for development prospects and productive oil and natural gas properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. Further, these companies may enjoy technological advantages and may be able to implement new technologies more rapidly than we can. Our ability to develop and exploit our oil and natural gas properties and to acquire additional properties in the future will depend upon our ability to successfully conduct operations, implement advanced technologies, evaluate and select suitable properties and consummate transactions in this highly competitive environment.


	*We are subject to complex federal, state and local laws and regulations that could adversely affect our business.*

Exploration, development, production and sale of oil and natural gas in North America are subject to extensive federal, state, provincial and local laws and regulations, including complex tax and environmental laws and regulations. We may be required to make large expenditures to comply with applicable laws and regulations, which could adversely affect our results of operations and financial condition. Matters subject to regulation include discharge permits for drilling operations, drilling bonds, spacing of wells, unitization and pooling of properties, environmental protection, reports concerning operations and taxation. Under these laws and regulations, we could be liable for personal injuries, property damage, oil spills, discharge of hazardous materials, reclamation costs, remediation and clean-up costs and other environmental damages.

We do not believe that full insurance coverage for all potential environmental damages is available at a reasonable cost, and we may need to expend significant financial and managerial resources to comply with environmental regulations and permitting requirements. We could incur substantial additional costs and liabilities in our oil and natural gas operations as a result of stricter environmental laws, regulations and enforcement policies.

Failure to comply with these laws and regulations also may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties. Further, these laws and regulations could change in ways that substantially increase our costs. Any of these liabilities, penalties,

suspensions, terminations or regulatory changes could make it more expensive for us to conduct our business or cause us to limit or curtail some of our operations.


Item 7A.	*Quantitative and Qualitative Disclosures About Market Risk*

Hedging Policy. We have adopted a formal hedging policy. The purpose of our hedging program is to mitigate the negative effects of declining commodity prices on our business. The hedging policy is set by the President with input from the Chief Executive Officer and the Chief Financial Officer. We plan to continue in the normal course of business to hedge our exposure to fluctuating commodity prices. The volumes we have capped or swapped will not exceed 75% of our anticipated production from proved producing reserves. Under our hedging policy, we do not enter into derivatives for speculative purposes. However, not all of our derivatives qualify for hedge accounting and in some instances management has determined it is more cost effective not to designate certain derivatives as hedges.

Counterparties. Our counterparties to hedging contracts include: BNP Paribas; Deutsche Bank; Koch; Morgan Stanley; Mitsui & Co; Shell Trading; Credit Lyonnais; J. Aron & Company, a wholly-owned subsidiary of Goldman, Sachs & Co. At December 31, 2003 approximately 35%, 23%, 20%, and 16% of estimated oil production hedged is committed to Morgan Stanley, J. Aron & Company, Deutsche Bank, and Credit Lyonnais, respectively. Approximately 42%, 33%, and 25% of our hedged gas production is contracted with BNP Paribas, J. Aron & Company, and Morgan Stanley, respectively. Performance on all of J. Aron & Company’s contracts with us is guaranteed by their parent, Goldman, Sachs & Co. We feel the credit-worthiness of our current counterparties is sound and we do not anticipate any non-performance of contractual obligations. As long as each counterparty maintains an investment grade credit rating, pursuant to our hedging contracts, no collateral is required.

In order to mitigate the credit risk of financial instruments, we enter into master netting agreements with significant counterparties. The master netting agreement is a standardized, bilateral contract between a given counterparty and us. Instead of treating separately each financial transaction between our counterparty and us, the master netting agreement enables our counterparty and us to aggregate all financial trades and treat them as a single agreement. This arrangement benefits us in three ways. First, the netting of the value of all trades reduces the requirements of daily collateral posting by us. Second, default by counterparty under one financial trade can trigger rights for us to terminate all financial trades with such counterparty. Third, netting of settlement amounts reduces our credit exposure to a given counterparty in the event of close-out.

Commodity Price Sensitivity. The tables in this section provide information about derivative financial instruments to which we were a party as of December 31, 2003 that are sensitive to changes in oil and natural gas commodity prices.

We hedge commodity price risk with swap contracts, put contracts, and collar contracts. Swap contracts provide a fixed price for a notional amount of sales volumes. Put contracts provide a fixed floor price on a notional amount of sales volumes while allowing full price participation if the relevant index price closes above the floor price. Collar contracts provide a floor price on a notional amount of sales volumes while allowing some additional price participation if the relevant index price closes above the floor price. Additionally, we occasionally we sell short put contracts with a strike price well below the floor price of the collar. These short put contracts do not qualify for hedge accounting under SFAS 133, and accordingly, the mark-to-market change in the value of these contracts is recorded as fair value gain/loss in the statements of operations. Thus, not all of our derivatives qualify for hedge accounting and in some instances management has determined it is more cost effective not to designate certain derivatives as hedges. The unrealized mark-to-market loss on our outstanding commodity derivatives at December 31, 2003 was approximately $(16.0) million. The fair market value of our oil derivative contracts was $(7.1) million and the fair market value of our natural gas derivative contracts was $(0.6) million.


	*Oil Derivative Contracts at December 31, 2003*


	Daily		Floor		Daily		Cap		Daily		Swap
	Floor Volume		Price		Cap Volume		Price		Swap Volume		Price
Period	(Bbls)		(per Bbl)		(Bbls)		(per Bbl)		(Bbls)		(per Bbl)

Jan. - June 2004		17,000	$	23.16		7,000	$	29.06		500	$	26.48
July - Dec. 2004		17,000		23.91		5,000		28.33		500		26.48
Jan. - June 2005		2,500		23.00		2,000		30.41		1,000		25.12
July - Dec. 2005		1,500		23.00		1,500		30.18		1,000		25.12
Jan. - Dec. 2006		—		—		—		—		2,000		25.03
Jan. - Dec. 2007		—		—		—		—		2,000		25.11


	*Natural Gas Derivative Contracts at December 31, 2003*


	Daily		Floor		Daily		Cap		Daily		Swap
	Floor Volume		Price		Cap Volume		Price		Swap Volume		Price
Period	(Mcf)		(per Mcf)		(Mcf)		(per Mcf)		(Mcf)		(per Mcf)

Jan. - Dec. 2004		20,000	$	4.07		7,500	$	6.02		5,000	$	5.01
Jan. - Dec. 2004		—		—		—		—		5,000		4.63

Subsequent to December 31, 2003, we entered into several additional oil and natural gas derivative contracts. The tables below summarize the terms of the contracts entered into from January 1, 2004 through March 4, 2004:


	*Additional Oil Derivative Contracts at March 4, 2004*


	Daily		Floor		Daily		Cap		Daily		Swap
	Floor Volume		Price		Cap Volume		Price		Swap Volume		Price
Period	(Bbls)		(per Bbl)		(Bbls)		(per Bbl)		(Bbls)		(per Bbl)

July - Dec. 2004		1,000	$	31.50		1,000	$	34.56		—		—
Jan. - Dec 2005		1,000		28.50		1,000		32.40		—		—
Jan. - Dec 2006		1,000		27.50		1,000		29.88		—		—


	*Additional Natural Gas Derivative Contracts at March 4, 2004*


									Daily
	Daily		Floor		Daily		Cap		Swap		Swap
	Floor Volume		Price		Cap Volume		Price		Volume		Price
Period	(Mcf)		(per Mcf)		(Mcf)		(per Mcf)		(Mcf)		(per Mcf)

July - Dec. 2004		—		—		—		—		5,000	$	5.65
Jan. - Dec 2005		5,000	$	5.05		5,000	$	5.97		—		—
Jan. - Dec. 2006		5,000		4.85		5,000		5.68		—		—

Interest Rate Sensitivity. At December 31, 2003, we had total long-term debt of $179.0 million. Of this amount, $150.0 million bears interest at a fixed rate of 8 3/8%. The remaining outstanding long-term debt balance of $29.0 million is under our credit agreement and is subject to floating market rates of interest. Borrowings under the credit agreement bear interest at a fluctuating rate that is linked to LIBOR. As of December 31, 2003, we had one outstanding interest rate swap. This swap does not qualify for hedge accounting as it swaps fixed interest rate for a floating interest rate tied to LIBOR. The following table summarizes the terms of this swap:


	*Interest Rate Derivative Contract at December 31, 2003*

Fair Market Value

Encore

at December 31,

Notional Swap Amount

Start Date

End Date

Encore Pays

Receives

2003

(In thousands)

$80,000

June 25, 2002

June 15, 2005

LIBOR + 3.89%

8.375%

2,420

GLOSSARY OF OIL AND NATURAL GAS TERMS

The following are abbreviations and definitions of certain terms commonly used in the oil and natural gas industry and this Report:

Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbons.

Bcf. One billion cubic feet of natural gas at standard atmospheric conditions.

Bbl/ D. One stock tank barrel of oil or other liquid hydrocarbons per day.

BOE. One barrel of oil equivalent, calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf to one Bbl of oil.

BOE/ D. One barrel of oil equivalent per day, calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf to one Bbl of oil.

Completion. The installation of permanent equipment for the production of oil or natural gas.

Delay Rentals. Fees paid to the lessor of the oil and natural gas lease during the primary term of the lease prior to the commencement of production from a well.

Developed Acreage. The number of acres which are allocated or assignable to producing wells or wells capable of production.

Development Well. A well drilled within or in close proximity to an area of known production targeting existing reservoirs.

Exploratory Well. A well drilled to find and produce oil or natural gas in an unproved area or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir.

Finding, Development, and Acquisition (“FD&A”) Costs. Capital costs incurred in the finding, development, acquisition, exploitation, improved recovery, and revisions of proved oil and natural gas reserves, excluding non-cash asset retirement obligations.

Gross Acres or Gross Wells. The total acres or wells, as the case may be, in which we have a working interest.

High-Pressure Air Injection (“HPAI”). High-pressure air injection involves utilizing compressors to inject air into previously produced oil and natural gas formations in order to displace remaining resident hydrocarbons and force them under pressure to a common lifting point for production.

Horizontal Drilling. A drilling operation in which a portion of the well is drilled horizontally within a productive or potentially productive formation. This operation usually yields a well which has the ability to produce higher volumes than a vertical well drilled in the same formation.

Lease Operations Expense. All direct and indirect costs of producing oil and natural gas after completion of drilling and before removal of production from the property. Such costs include labor, superintendence, supplies, repairs, maintenance, and direct overhead charges.

MBbl. One thousand barrels of oil or other liquid hydrocarbons.

MBOE. One thousand barrels of oil equivalent, calculated by converting gas to oil equivalent barrels at a ratio of six Mcf to one Bbl of oil.

Mcf. One thousand cubic feet of natural gas.

Mcf/ D. One thousand cubic feet of natural gas per day.

Mcfe. One thousand cubic feet of natural gas equivalent, calculated by converting oil to natural gas equivalent at a ratio of one Bbl of oil to six Mcf.

MMBOE. One million barrels of oil equivalent, calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf to one Bbl of oil.

MMBtu. One million British thermal units. One British thermal unit is the amount of heat required to raise the temperature of one pound of water one degree Fahrenheit.

MMcf. One million cubic feet of natural gas.

Net Acres or Net Wells. Gross acres or wells multiplied, as the case may be, by the percentage working interest owned by us.

Net Production. Production that is owned by us less royalties and production due others.

NYMEX. New York Mercantile Exchange.

Oil. Crude oil or condensate.

Operating Income. Gross oil and natural gas revenue less applicable production taxes and lease operating expense.

Operator. The individual or company responsible for the exploration, exploitation, and production of an oil or natural gas well or lease.

Present Value of Future Net Revenues or Present Value or PV-10. The pretax present value of estimated future revenues to be generated from the production of proved reserves, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation, without giving effect to hedging activities, non-property related expenses such as general and administrative expenses, debt service and depletion, depreciation, and amortization, and discounted using an annual discount rate of 10%.

Proved Developed Reserves. Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

Proved Reserves. The estimated quantities of oil, natural gas, and natural gas liquids that geological and engineering data demonstrate with reasonable certainty are recoverable in future years from known reservoirs under existing economic and operating conditions.

Proved Undeveloped Reserves. Proved undeveloped reserves are proved reserves that are expected to be recovered from new wells drilled to known reservoirs on acreage yet to be drilled for which the existence and recoverability of such reserves can be estimated with reasonable certainty, or from existing wells where a relatively major expenditure is required to establish production. Proved undeveloped reserves include unrealized production response from fluid injection and other improved recovery techniques where such techniques have been proved effective by actual tests in the area and in the same reservoir.

Reserve-To-Production Index or R/ P Index. An estimate expressed in years, of the total estimated proved reserves attributable to a producing property divided by production from the property for the 12 months preceding the date as of which the proved reserves were estimated.

Royalty. An interest in an oil and natural gas lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage (or of the proceeds of the sale thereof), but does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.

Standardized Measure. Future cash inflows from proved oil and natural gas reserves, less future development and production costs and future income tax expenses, discounted at 10% per annum to reflect the timing of future cash flows. Standardized measure differs from PV-10 because standardized measure includes the effect of future income taxes.

Tertiary Recovery. An enhanced recovery operation that normally occurs after waterflooding in which chemicals or natural gasses are used as the injectant. HPAI is a form of tertiary recovery.

Unit. A specifically defined area within which acreage is treated as a single consolidated lease for operations and for allocations of costs and benefits without regard to ownership of the acreage. Units are established for the purpose of recovering oil and natural gas from specified zones or formations.

Waterflood. A secondary recovery operation in which water is injected into the producing formation in order to maintain reservoir pressure and force oil toward and into the producing wells.

Working Interest. An interest in an oil and natural gas lease that gives the owner of the interest the right to drill for and produce oil and natural gas on the leased acreage and requires the owner to pay a share of the costs of drilling and production operations.


Item 8.	*Financial Statements and Supplementary Data*


Independent Auditor’s Report			49
Consolidated Balance Sheets as of December 31, 2003 and 2002			51
Consolidated Statements of Operations for the Years Ended December 31, 2003, 2002, and 2001			52
Consolidated Statement of Stockholders’ Equity for the Years Ended December 31, 2003, 2002, and 2001			53
Consolidated Statements of Cash Flows for the Years Ended December 31, 2003, 2002, and 2001			54
Notes to Consolidated Financial Statements			55
Supplemental Information			74

REPORT OF INDEPENDENT AUDITORS

To the Board of Directors and Shareholders of Encore Acquisition Company:

We have audited the accompanying consolidated balance sheets of Encore Acquisition Company and subsidiaries (“the Company”) as of December 31, 2003 and 2002, and the related consolidated statements of operations, stockholders’ equity, and cash flows for years then ended. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. The financial statements of Encore Acquisition Company as of December 31, 2001, and for the year then ended were audited by other auditors who have ceased operations. Those auditors expressed an unqualified opinion on those financial statements in their report dated March 1, 2002.

We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Encore Acquisition Company and subsidiaries at December 31, 2003 and 2002, and the consolidated results of their operations and their cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States.

As explained in Note 2 to the consolidated financial statements, effective January 1, 2003, the Company adopted Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations.”

/s/ ERNST & YOUNG LLP

Fort Worth, Texas

February 6, 2004

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

To the Shareholders of Encore Acquisition Company:

We have audited the accompanying consolidated balance sheets of Encore Acquisition Company (a Delaware corporation) and subsidiaries as of December 31, 2001 and 2000, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2001. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Encore Acquisition Company and subsidiaries as of December 31, 2001 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2001, in conformity with accounting principles generally accepted in the United States.

As explained in Note 2 to the financial statements, effective January 1, 2001, the Company changed its method of accounting for derivatives.

ARTHUR ANDERSEN LLP

Dallas, Texas

March 1, 2002

Subsequent to the completion of the audit of the Company’s 2001 financial statements, Arthur Andersen LLP was convicted of obstruction of justice charges relating to a federal investigation of Enron Corporation and ceased operations as a public accounting firm. Accordingly, the report of independent public accountants included above is a copy of a report previously issued by Arthur Andersen. Arthur Andersen has not reissued its report for inclusion in this document.

ENCORE ACQUISITION COMPANY

CONSOLIDATED BALANCE SHEETS



			December 31,

			2003			2002


			(In thousands
			except share data)
ASSETS
Current assets:
	Cash and cash equivalents		$	431		$	13,057
	Accounts receivable (net of allowance of $0 and $7.0 million, respectively)			27,640			21,981
	Inventory			6,019			5,032
	Derivative assets			5,588			3,245
	Deferred tax asset			3,592			4,833
	Other current assets			1,673			1,317

		Total current assets		44,943			49,465

Properties and equipment, at cost — successful efforts method:
	Producing properties			739,288			581,012
	Undeveloped properties			921			1,168
	Accumulated depletion, depreciation, and amortization			(124,646	)		(94,356	)

				615,563			487,824

	Other property and equipment			3,831			3,680
	Accumulated depreciation			(2,586	)		(1,917	)

				1,245			1,763

Other assets				10,387			10,844

		Total assets	$	672,138		$	549,896


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
	Accounts payable		$	10,668		$	9,650
	Accrued lease operations expense			2,507			2,373
	Accrued development capital			9,302			4,500
	Derivative liabilities			8,026			8,558
	Production and severance taxes payable			5,365			4,822
	Other current liabilities			9,127			7,073

		Total current liabilities		44,995			36,976

Derivative liabilities				3,514			2,998
Future abandonment cost				5,341			—
Deferred tax liability				80,313			47,656
Long-term debt				179,000			166,000

		Total liabilities		313,163			253,630

Commitments and contingencies				—			—
Stockholders’ equity:
	Preferred stock, $.01 par value, 5,000,000 shares authorized, none issued and outstanding			—			—
	Common stock, $.01 par value, 60,000,000 shares authorized, 30,335,693 and 30,162,955 issued and outstanding			303			302
	Additional paid-in capital			253,865			251,231
	Deferred compensation			(2,528	)		(2,396	)
	Retained earnings			117,365			53,724
	Accumulated other comprehensive income			(10,030	)		(6,595	)

		Total stockholders’ equity		358,975			296,266

		Total liabilities and stockholders’ equity	$	672,138		$	549,896

The accompanying notes are an integral part of these consolidated financial statements.

ENCORE ACQUISITION COMPANY

CONSOLIDATED STATEMENTS OF OPERATIONS



			Year Ended December 31,

			2003			2002			2001


			(In thousands except per share data)
Revenues:
	Oil		$	176,351		$	134,854		$	105,768
	Natural gas			43,745			25,838			30,149

Total revenues				220,096			160,692			135,917

Expenses:
	Production —
		Lease operations		37,846			30,678			25,139
		Production, ad valorem, and severance taxes		22,013			15,653			13,809
	Depletion, depreciation, and amortization			33,530			34,550			31,721
	General and administrative (excluding non-cash stock based compensation)			8,680			6,150			5,053
	Non-cash stock based compensation			614			—			9,587
	Derivative fair value (gain) loss			(885	)		(900	)		680
	Bad debt expense			—			—			7,005
	Impairment of oil and natural gas properties			—			—			2,598
	Other operating expense			3,481			2,045			934

Total expenses				105,279			88,176			96,526

Operating income				114,817			72,516			39,391

Other income (expenses):
	Interest			(16,151	)		(12,306	)		(6,041	)
	Other			214			91			46

Total other income (expenses)				(15,937	)		(12,215	)		(5,995	)

Income before income taxes and cumulative effect of accounting change				98,880			60,301			33,396
Current income tax benefit (provision)				(991	)		745			(1,919	)
Deferred income tax provision				(35,111	)		(23,361	)		(14,414	)

Income before cumulative effect of accounting change				62,778			37,685			17,063
Cumulative effect of accounting change, net of income taxes				863			—			(884	)

Net income			$	63,641		$	37,685		$	16,179

Income before cumulative effect of accounting change per common share:
	Basic		$	2.09		$	1.25		$	0.59
	Diluted			2.07			1.25			0.59
Net income per common share:
	Basic		$	2.11		$	1.25		$	0.56
	Diluted			2.10			1.25			0.56
Weighted average common shares outstanding:
	Basic			30,102			30,031			28,718
	Diluted			30,333			30,161			28,723

The accompanying notes are an integral part of these consolidated financial statements.

ENCORE ACQUISITION COMPANY

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY


														Notes												Accumulated
		Class A			Class B						Additional			Receivable									Retained			Other			Total
		Common			Common			Common			Paid-In			Officers/			Treasury			Deferred			Earnings			Comprehensive			Stockholders’
		Stock			Stock			Stock			Capital			Employees			Stock			Compensation			(Deficit)			Income			Equity


		(In thousands except share data)
Balance at December 31, 2000		$	1		$	3		$	—		$	147,968		$	(21	)	$	—		$	—		$	(140	)	$	—		$	147,811
Proceeds from initial public offering (net of offering costs of $1,568)			—			—			71			91,456			—			—			—			—			—			91,527
Non-cash stock based compensation			—			—			—			9,587			—			—			—			—			—			9,587
Recapitalization			(1	)		(3	)		229			(225	)		—			—			—			—			—			—
Repayment of notes receivable — officers and employees			—			—			—			—			21			—			—			—			—			21
Components of comprehensive income:
	Net income		—			—			—			—			—			—			—			16,179			—			16,179
	Change in deferred hedge gain/loss (net of income taxes of $12,226)		—			—			—			—			—			—			—			—			19,058			19,058
	Cumulative effect of accounting change (net of income taxes of $9,121)		—			—			—			—			—			—			—			—			(14,881	)		(14,881	)

Total comprehensive income																														20,356

Balance at December 31, 2001			—			—			300			248,786			—			—			—			16,039			4,177			269,302
Exercise of stock options			—			—			—			51			—			—			—			—			—			51
Issuance of restricted stock			—			—			2			2,394			—			—			(2,396	)		—			—			—
Components of comprehensive income:
	Net income		—			—			—			—			—			—			—			37,685			—			37,685
	Change in deferred hedge gain/loss (Net of income taxes of $6,602)		—			—			—			—			—			—			—			—			(10,772	)		(10,772	)

Total comprehensive income																														26,913

Balance at December 31, 2002			—			—			302			251,231			—			—			(2,396	)		53,724			(6,595	)		296,266
Exercise of stock options			—			—			1			1,974			—			—			—			—			—			1,975
Issuance of Common Stock			—			—			91			175,383			—			—			—			—			—			175,474
Purchase of Treasury Stock			—			—			—			—			—			(175,560	)		—			—			—			(175,560	)
Cancellation of Treasury Stock			—			—			(91	)		(175,469	)		—			175,560			—			—			—			—
Deferred compensation:
	Issuance of restricted Common Stock		—			—			—			927			—			—			(927	)		—			—			—
	Amortization of expense		—			—			—			—			—			—			614			—			—			614
	Other changes		—			—			—			(181	)		—			—			181			—			—			—
Components of comprehensive income:
	Net income		—			—			—			—			—			—			—			63,641			—			63,641
	Change in deferred hedge gain/loss (Net of income taxes of $2,105)		—			—			—			—			—			—			—			—			(3,435	)		(3,435	)

Total comprehensive income																														60,206

Balance at December 31, 2003		$	—		$	—		$	303		$	253,865		$	—		$	—		$	(2,528	)	$	117,365		$	(10,030	)	$	358,975

The accompanying notes are an integral part of these consolidated financial statements.

ENCORE ACQUISITION COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS



			Year Ended December 31,

			2003			2002			2001


			(In thousands)
Operating activities
Net income			$	63,641		$	37,685		$	16,179
Adjustments to reconcile net income to net cash provided by operating activities:
	Depletion, depreciation, and amortization			33,530			34,550			31,721
	Deferred taxes			35,111			23,361			13,718
	Non-cash stock based compensation			614			—			9,587
	Cumulative effect of accounting change			(863	)		—			884
	Non-cash derivative fair value (gain) loss			(165	)		(1,239	)		680
	Other non-cash			1,293			177			1,718
	Loss on disposition of assets			322			254			165
	Bad debt expense			—			—			7,005
	Impairment of oil and natural gas properties			—			—			2,598
	Changes in operating assets and liabilities:
		Accounts receivable		(5,602	)		(5,695	)		4,564
		Other current assets		(8,592	)		(3,161	)		(2,258	)
		Other assets		(2,024	)		2,177			(4,605	)
		Accounts payable and other current liabilities		6,553			3,400			(1,744	)

Cash provided by operating activities				123,818			91,509			80,212
Investing activities
	Proceeds from disposition of assets			1,295			226			310
	Purchases of other property and equipment			(1,464	)		(680	)		(1,091	)
	Acquisition of oil and natural gas properties			(54,601	)		(78,549	)		(1,622	)
	Development of oil and natural gas properties			(98,977	)		(80,313	)		(87,180	)

Cash used by investing activities				(153,747	)		(159,316	)		(89,583	)
Financing activities
	Proceeds from issuance of common stock			176,127			—			93,095
	Purchase of treasury stock			(175,560	)		—			—
	Offering costs paid			(653	)		—			(1,568	)
	Proceeds from issuance of 8 3/8% note			—			150,000			—
	Payments for debt issuance costs			(125	)		(6,195	)		—
	Exercise of stock options			1,975			51			—
	Proceeds from notes receivable — officers and employees			—			—			21
	Proceeds from long-term debt			112,500			144,000			161,000
	Payments on long-term debt			(99,500	)		(206,000	)		(227,500	)
	Cash overdrafts			2,539			—			—
	Payments on note payable			—			(1,107	)		(16,438	)

Cash provided by financing activities				17,303			80,749			8,610
Increase (decrease) in cash and cash equivalents				(12,626	)		12,942			(761	)
Cash and cash equivalents, beginning of period				13,057			115			876

Cash and cash equivalents, end of period			$	431		$	13,057		$	115

The accompanying notes are an integral part of these consolidated financial statements.

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


1.	Formation of the Company and Basis of Presentation

Encore Acquisition Company (the “Company”), a Delaware Corporation, is an independent (non-integrated) oil and natural gas company in the United States. We were organized in April 1998 and are engaged in the acquisition, development, exploitation, and production of North American oil and natural gas reserves. Our oil and natural gas reserves are concentrated in fields located in the Williston Basin of Montana and North Dakota, the Permian Basin of Texas and New Mexico, the Anadarko Basin of Oklahoma, the Powder River Basin of Montana, the Paradox Basin of Utah, and the North Louisiana Salt Basin.


2.	Summary of Significant Accounting Policies


	*Principles of Consolidation*

Our consolidated financial statements include the accounts of all subsidiaries in which we hold a controlling interest. All material intercompany balances and transactions are eliminated.


	*Cash and Cash Equivalents*

Cash and cash equivalents include cash in banks, money market accounts, and all highly liquid investments with an original maturity of three months or less. On a bank-by-bank basis, cash accounts that are overdrawn are reclassified to current liabilities and any change in cash overdrafts is shown as a financing activity in the consolidated statements of cash flows.


	*Inventories*

Inventories are comprised principally of materials and supplies, which are stated at the lower of cost (determined on an average basis) or market, and oil in pipelines. Oil produced at the lease which resides unsold in pipelines is carried at an amount equal to its operating costs to produce.


	*Oil and Natural Gas Properties*

We utilize the successful efforts method of accounting for our oil and natural gas properties. Under this method, all development and acquisition costs of proved properties are capitalized and amortized on a unit-of-production basis over the remaining life of proved developed reserves or proved reserves, as applicable. Exploration expenses, including geological and geophysical expenses and delay rentals, are charged to expense as incurred. Costs of drilling exploratory wells are initially capitalized, but charged to expense if and when the well is determined to be unsuccessful. Expenditures for repairs and maintenance to sustain or increase production from the existing producing reservoir are charged to expense as incurred. Expenditures to recomplete a current well in a different or additional proven or unproven reservoir are capitalized pending determination that economic reserves have been added. If the recompletion is not successful, the expenditures are charged to expense. Expenditures for redrilling or directional drilling in a previously abandoned well are classified as drilling costs to a proven or unproven reservoir for determination of capital or expense. Significant tangible equipment added or replaced is capitalized. Expenditures to construct facilities or increase the productive capacity from existing reserves are capitalized. Internal costs directly associated with the development and exploitation of properties are capitalized as a cost of the property and are classified accordingly in the Company’s consolidated financial statements. Natural gas volumes are converted to equivalent barrels at the rate of six Mcf to one barrel. See Note 2, “New Accounting Standards,” on page 58 for a discussion of Statement of Financial Accounting Standard No. 143, “Accounting for Asset Retirement Obligations” (“SFAS 143”), which the Company adopted as of January 1, 2003.

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The Company is required to assess the need for an impairment of capitalized costs of oil and natural gas properties and other long-lived assets whenever events or circumstances indicate that the carrying value of those assets may not be recoverable. If impairment is indicated based on a comparison of the asset’s carrying value to its undiscounted expected future net cash flows, then it is recognized to the extent that the carrying value exceeds fair value. Any impairment charge incurred is expensed reduces our recorded basis in the asset.

The costs of retired, sold, or abandoned properties that constitute part of an amortization base are charged or credited, net of proceeds received, to the accumulated depletion, depreciation, and amortization reserve. Gains or losses from the disposal of other properties are recognized in the current period.

Additionally, the Company’s independent reserve engineers estimate our reserves once a year at December 31. This results in a new DD&A rate which the Company uses for the preceding fourth quarter and, to the extent no other reserve estimates change materially, the subsequent three quarters of the following year.


	*Stock-based Compensation*

Employee stock options and restricted stock awards are accounted for under the provisions of Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees” (“APB 25”). Accordingly, no compensation is recorded for stock options that are granted to employees or non-employee directors with an exercise price equal to or above the common stock price on the grant date. However, expense is recorded related to restricted stock granted to employees. If compensation expense for the stock based awards had been determined using the provisions of Statement of Financial Accounting Standard No. 123, “Accounting for Stock-Based Compensation” (“SFAS 123”), the Company’s net income and net income per share would have been adjusted to the pro forma amounts indicated below (in thousands, except per share amounts):



		Year Ended December 31,

		2003		2002		2001

As Reported:
	Net income	$	63,641	$	37,685	$	16,179
	Non-cash stock based compensation (net of taxes)		381		—		9,587
	Diluted net income per share		2.10		1.25		0.56
Pro Forma:
	Net income	$	62,093	$	36,408	$	15,475
	Non-cash stock based compensation (net of taxes)		1,929		1,277		10,291
	Diluted net income per share		2.05		1.21		0.54


	*Segment Reporting*

The Company has only one operating segment, the development and exploitation of oil and natural gas reserves. Additionally, all of our assets are located in the United States and all of our oil and natural gas revenues are derived from customers located in the United States.

For 2003, 28%, 26%, and 11% of total oil and natural gas production was sold to ConocoPhillips, Shell, and Eighty-Eight Oil, respectively. In 2002, ConAgra and Equiva Trading Company (a joint venture between Shell and Texaco) accounted for 16% and 10% of total oil and natural gas sales, respectively. For 2001, 25%, 17%, and 11% of total oil and natural gas production was sold to ConAgra, Equiva Trading Company and EOTT Energy Co., respectively.

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	*Income Taxes*

Deferred tax assets and liabilities are recognized for future tax consequences attributable to differences between financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Valuation allowances are established when necessary to reduce deferred tax assets to amounts expected to be realized. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled.


	*Revenue Recognition*

Revenues are recognized for Encore’s share of jointly owned properties as oil and natural gas is produced and sold, net of royalties and net profits interest payments. Revenues are also reduced by any processing and other fees paid except for transportation costs paid to third parties which are recorded as expense. Natural gas revenues are recorded using the sales method of accounting whereby revenue is recognized as natural gas is sold by the Company rather than as the Company’s working interest share of production. Royalties, net profits interests, and severance taxes are paid based upon the actual price received from the sales. To the extent actual quantities and values of oil and natural gas are unavailable for a given reporting period because of timing or information not received from third parties, we estimate and record the expected sales volumes and values for those properties. The Company also does not recognize revenue for the production in tanks or pipelines that has not been delivered to the purchaser yet. Encore’s net oil inventories in pipelines were 46,622 Bbls and 104,954 Bbls at December 31, 2003 and 2002, respectively. Natural gas imbalances under-delivered to Encore at December 31, 2003 and December 31, 2002, were 446,000 MMBTU and 510,000 MMBTU, respectively.


	*Shipping Costs*

Shipping costs in the form of pipeline fees paid to third parties are incurred to move oil and natural gas production from certain properties to a different market location for ultimate sale. These costs are included in other operating expense in our statements of operations.


	*Hedging and Related Activities*

We use various financial instruments for non-trading purposes to manage and reduce price volatility and other market risks associated with our oil and natural gas production. These arrangements are structured to reduce our exposure to commodity price decreases, but they can also limit the benefit we might otherwise receive from commodity price increases. Our risk management activity is generally accomplished through over-the-counter forward derivative contracts with large financial institutions.

Effective January 1, 2001, the Company adopted Statement of Financial Accounting Standards No. 133 (“SFAS 133”), “Accounting for Derivative Instruments and Hedging Activities”. This standard requires us to recognize all of our derivative financial instruments in our consolidated balance sheets as either assets or liabilities and measure them at fair value. If a derivative does not qualify for hedge accounting, it must be adjusted to fair value through earnings. However, if a derivative does qualify for hedge accounting, depending on the nature of the hedge, changes in fair value can be offset against the change in fair value of the hedged item through earnings or recognized in other comprehensive income until such time as the hedged item is recognized in earnings.

To qualify for cash flow hedge accounting, the cash flows from the hedging instrument must be highly effective in offsetting changes in cash flows of the hedged item. In addition, all hedging relationships must be designated, documented, and reassessed periodically. The impact of adopting SFAS 133 on January 1, 2001 was to record the fair value of our derivatives as a reduction in assets of $1.1 million and as a

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

liability in the amount of $24.4 million. Additionally, we recorded a reduction in earnings as the cumulative effect of an accounting change of $0.9 million (net of taxes of $0.5 million) and a decrease to stockholders’ equity for other comprehensive income in the amount of $14.9 million (net of deferred taxes of $9.1 million).


	*Comprehensive Income*

Comprehensive income includes net income and other comprehensive income, which includes, effective January 1, 2001, unrealized gains and losses on derivative financial instruments. Encore chooses to show yearly comprehensive income as part of its consolidated statement of stockholders’ equity.


	*Use of Estimates*

Preparing financial statements in conformity with accounting principles generally accepted in the United States requires management to make certain estimations and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities in the consolidated financial statements and the reported amounts of revenues and expenses reported. Actual results could differ materially from those estimates.

Estimates made in preparing these consolidated financial statements include the Company’s estimated proved oil and natural gas reserve volumes used in calculating depletion, depreciation, and amortization expense; the estimated future cash flows and fair value of our properties used in determining the need for any impairment write-down; and the timing and amount of future abandonment costs used in calculating the Company’s asset retirement obligations. See “Note 4. Commitments and Contingencies — Asset Retirement Obligations.” Future changes in the assumptions used could have a significant impact on reported results in future periods.

New Accounting Standards

Statements of Financial Accounting Standards No. 141, “Business Combinations” (“SFAS 141”) and No. 142, “Goodwill and Other Intangible Assets” (“SFAS 142”) were issued in July 2001. SFAS 141 requires that all business combinations entered into subsequent to June 30, 2001 be accounted for under the purchase method of accounting and that certain acquired intangible assets in a business combination be recognized and reported as assets apart from goodwill. SFAS 142 requires that amortization of goodwill be replaced with periodic tests of the goodwill’s impairment at least annually in accordance with the provisions of SFAS 142 and that intangible assets other than goodwill be amortized over their useful lives.

Currently, the Emerging Issues Task Force staff are engaged in discussions on the issue of whether SFAS 141 and SFAS 142 which were effective June 30, 2001, called for mineral rights held under a lease or other contractual arrangement to be classified on the balance sheet as intangible assets and accompanied by specific footnote disclosures. Historically, oil and gas companies, including Encore, have included these costs with all other oil and natural gas property costs in Property, Plant, and Equipment on the consolidated balance sheet.

In the event this interpretation is adopted, a substantial portion of the acquisition costs of oil and natural gas properties would be required to be classified on the balance sheet as an intangible asset. The

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Company believes this interpretation would not have a material effect on our results of operations for the periods presented or in the future as these intangible assets would be depleted using the units of production method in a manner consistent with the method currently used to calculate depletion, depreciation, and amortization expense on these assets.

At December 31, 2003, the Company had $0.9 million of undeveloped leasehold costs and $291.5 million of developed leasehold costs (net of accumulated depletion) that would be reclassified as “Intangible developed and undeveloped leasehold costs” if the Company were to apply the interpretation as currently discussed.

In August 2001, the FASB issued SFAS 143, which the Company adopted as of January 1, 2003. This statement requires us to record a liability in the period in which an asset retirement obligation (“ARO”) is incurred. Also, upon initial recognition of the liability, we must capitalize additional asset cost equal to the amount of the liability. In addition to any obligations that arise after the effective date of SFAS 143, upon initial adoption we must recognize (1) a liability for any existing AROs, (2) capitalized cost related to the liability, and (3) accumulated depletion, depreciation, and amortization on that capitalized cost.

The adoption of SFAS 143 resulted in a January 1, 2003 cumulative effect adjustment to record (i) a $4.0 million increase in the carrying values of proved properties, (ii) a $2.1 million decrease in accumulated depletion, depreciation, and amortization, and (iii) a $5.2 million increase in other non-current liabilities, and (iv) a gain of $0.9 million, net of tax, as a cumulative effect of accounting change on January 1, 2003. The Company does not include a market risk premium in its risk estimates as the effect would not be material.

The following table shows net income and basic and diluted net income per common share as reported, as well as pro forma amounts as if the Company had adopted SFAS 143 prior to January 1, 2001 (in thousands, except per common share amounts):



		Year Ended December 31,

		2003		2002		2001

As Reported:
	Net income	$	63,641	$	37,685	$	16,179
	Basic net income per common share		2.11		1.25		0.56
	Diluted net income per common share		2.10		1.25		0.56
Pro Forma:
	Net income	$	62,778	$	38,035	$	16,549
	Basic net income per common share		2.09		1.27		0.58
	Diluted net income per common share		2.07		1.26		0.58

In August 2001, the FASB issued Statement of Financial Accounting Standards No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” (“SFAS 144”), which is effective for financial statements issued for fiscal years beginning after December 15, 2001 and interim periods within those fiscal years. SFAS 144 requires that long-lived assets to be disposed of by sale be measured at the lower of the carrying amount or fair value less cost to sell, whether reported in continuing operations or in discontinued operations. SFAS 144 broadens the reporting of discontinued operations to include all components of an entity with operations that can be distinguished from the rest of the entity and that will be eliminated from the ongoing operations of the entity in a disposal transaction. The Company adopted SFAS No. 144 effective January 1, 2002. The Company’s adoption of this statement has not had a material effect on its financial position or results of operations.

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

In April 2002, the FASB issued SFAS 145, “Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections.” Under Statement 4, all gains and losses from extinguishment of debt were required to be aggregated and, if material, classified as an extraordinary item, net of related income tax effect. This Statement eliminates Statement 4 and, thus, the exception to applying Opinion 30 to all gains and losses related to extinguishments of debt. As a result, gains and losses from extinguishment of debt should be classified as extraordinary items only if they meet the criteria in Opinion 30. Applying the provisions of Opinion 30 will distinguish transactions that are part of an entity’s recurring operations from those that are unusual or infrequent or that meet the criteria for classification as an extraordinary item. This statement is effective for Encore beginning January 1, 2003, at which time the extraordinary loss on extinguishment of debt of $0.9 million recorded in the second quarter of 2002 was reclassified to operating income.

In December 2002, the FASB issued SFAS No. 148, “Accounting for Stock-Based Compensation — Transition and Disclosure, an Amendment of FASB Statement No. 123” (“SFAS 148”). This Statement amends SFAS 123, to provide alternative methods of transition for a voluntary change to the fair value method of accounting for stock-based employee compensation. In addition, this Statement amends the disclosure requirements of SFAS 123 to require prominent disclosures in both annual and interim financial statements. Certain of the disclosure modifications are required for fiscal years ending after December 15, 2002. SFAS 148 has not had any effect on the Company’s financial position or results of operations. See additional required disclosures at “Note 10. Employee Benefit Plans.”


3.	Acquisitions


	*2001 Acquisitions*

During 2001, we made small miscellaneous acquisitions of undeveloped acreage. No material proved property acquisitions were made.


	*2002 Acquisitions*

On January 4, 2002 we closed the purchase of our Central Permian properties. These properties were purchased from Conoco for approximately $50.1 million. The properties include two major operated fields: East Cowden Grayburg and Fuhrman-Nix; and two non-operated fields: North Cowden and Yates. During the second quarter of 2002, we closed a second follow-on acquisition of additional working interests in the East Cowden Field for $8.3 million.

On August 29, 2002, we completed an acquisition of interests in oil and natural gas properties in southeast Utah’s Paradox Basin. The final purchase price after the exercise of preferential rights was $17.9 million ($16.7 million after closing adjustments). The properties are divided between two oil producing units: the Ratherford Unit operated by ExxonMobil and the Aneth Unit operated by Chevron Texaco.


	*2003 Acquisitions*

On July 31, 2003, we closed the initial acquisition of the North Louisiana properties. Subsequently, we have purchased several smaller interests in these properties. The original purchase was effective June 1, 2003. The Company purchased interests in natural gas properties in North Louisiana (the “Elm Grove” acquisition) from a group of private sellers at a cost of $54.6 million. Beginning August 1, 2003, revenues and expenses from these properties have been included in the Company’s Consolidated Statements of Operations and drilling costs have been included in “Development of oil and natural gas properties’ in the Consolidated Statements of Cash Flows. From June 1, 2003 to July 31, 2003, revenues, expenses, and development capital of the properties were treated as adjustments to the purchase price. The properties are

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

located in the Elm Grove Field in Bossier Parish, Louisiana and are non-operated working interests ranging from 2% to 38% across 1,800 net acres in 15 sections.

These acquisitions have been accounted for as purchases. The operating results of the acquired properties have been included in our consolidated financial statements since the date of acquisition.


4.	Commitments and Contingencies


	*Leases*

We lease office space and equipment that have remaining non-cancelable lease terms in excess of one year. The following table summarizes by year our remaining non-cancelable future payments under operating leases as of December 31, 2003 (in thousands):


2004	$	951
2005		987
2006		520
2007		171
2008		171
Thereafter		43

Our operating lease rental expense was approximately $1.5 million, $0.9 million, and $0.7 million in 2003, 2002, and 2001, respectively.


	*Asset Retirement Obligations*

The Company’s primary asset retirement obligations relate to future plugging and abandonment expenses on our oil and natural gas properties and related facilities disposal. As of December 31, 2003, the Company had $2.7 million held in an escrow account from which funds are released only for reimbursement of plugging and abandonment expenses on our Bell Creek property. This amount is included in ‘Other assets’ in the accompanying Consolidated Balance Sheet. The following table summarizes the changes in the Company’s future abandonment liability recorded in ‘Future abandonment cost’ on the Company’s Consolidated Balance Sheet from the liability initially recorded upon adoption of SFAS 143 on January 1, 2003 through December 31, 2003 (in thousands):


		Year Ended
		December 31,
		2003

Future abandonment liability at January 1, 2003		$	4,791
	Acquisition of Elm Grove properties		337
	Wells Drilled		83
	Accretion expense		272
	Plugging and abandonment costs incurred		(100	)
	Revision of estimates		(42	)

Future abandonment liability at December 31, 2003		$	5,341

The pro-forma asset retirement obligation as of December 31, 2001 and 2000 would have been $4.1 million and $4.2 million, respectively, had the Company adopted SFAS 143 prior to January 1, 2001.

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


5.	Accounts Payable and Accrued Liabilities

Other current liabilities were as follows at December 31 (in thousands):


		2003		2002

Cash overdrafts		$	2,681	$	—
Oil and natural gas revenue payable			1,176		4,108
Net profits payable			589		237
Interest			563		595
Other			4,118		2,133

	Total	$	9,127	$	7,073


6.	Indebtedness

The following table details the Company’s indebtedness at December 31 (in thousands):


		2003		2002

Revolving Credit Facility		$	29,000	$	16,000
8 3/8% Notes			150,000		150,000

	Total	$	179,000	$	166,000

Prior to restructuring our debt on June 25, 2002 (see below), the Company’s operating subsidiary maintained a credit agreement with a group of banks that matured in May 2004. The Company guaranteed the subsidiary’s obligations under the credit agreement and pledged the stock and other equity interests of its subsidiaries to secure the guaranty.

On June 25, 2002, the Company sold $150 million of 8 3/8% Senior Subordinated Notes maturing on June 15, 2012 (the “Notes”). The offering was made through a private placement pursuant to Rule 144A. Subsequently, the Company filed a registration statement on Form S-4/ A, which was declared effective on December 6, 2002. The Company received net proceeds of $145.6 million from the sale of the Notes, after deducting debt issuance costs. The proceeds were used to repay and retire the Company’s prior credit facility ($143.0 million), to pay the fees and expenses related to a new revolving credit facility ($1.5 million), and to hold in reserve for the Paradox Basin acquisition ($1.1 million).

All of the Company’s subsidiaries are currently subsidiary guarantors of the Notes. Since (i) each subsidiary guarantor is 100% owned by the Company, (ii) the Company has no assets or operations that are independent of its subsidiaries, (iii) the subsidiary guarantees are full and unconditional and joint and several and (iv) all of the Company’s subsidiaries are subsidiary guarantors, the Company has not included the financial statements of each subsidiary in this report. The subsidiary guarantors may without restriction transfer funds to the Company in the form of cash dividends, loans and advances.

Concurrently with the issuance of the Notes, the Company also entered into a new revolving credit facility (the “Facility”) on June 25, 2002. Borrowings under the Facility are secured by a first priority lien on the Company’s proved oil and natural gas reserves. Availability under the Facility is determined through semi-annual borrowing base determinations and may be increased or decreased. The amount available under the Facility at December 31, 2003 was $270.0 million, with $29.0 million outstanding as of December 31, 2003. The maturity date of the Facility is June 25, 2006.

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Amounts outstanding under the Facility are subject to varying rates of interest based on the amount outstanding and the Company’s borrowing base. Based on our current $270.0 million borrowing base, our applicable interest rates are calculated as follows:


Amount Outstanding	Rate

$0 to $55,000,000		LIBOR + 1.000%
$55,000,001 to $110,000,000		LIBOR + 1.125%
$110,000,001 to $165,000,000		LIBOR + 1.250%
$165,000,001 to $198,000,000		LIBOR + 1.500%
$198,000,001 to $270,000,000		LIBOR + 1.750%

During 2003 and 2002, the weighted average interest rate under the Facility was 9.6% and 8.2%, respectively.

Additionally, under the Facility, the Company is subject to certain affirmative, negative, and financial covenants. These include limitations on incurrence of additional debt, restrictions on asset dispositions and restricted payments, maintenance of a 1.0 to 1.0 current ratio, and maintenance of an EBITDA, as defined, to interest expense ratio of at least 2.5 to 1.0. As of December 31, 2003, the Company was in compliance with all covenants.

The following table illustrates the Company’s long-term debt maturities at December 31, 2003 (in thousands):



		Payments Due by Period

		Total		2004		2005 - 2006		2007 - 2008		Thereafter

8 3/8% Notes		$	150,000	$	—	$	—	$	—	$	150,000
Revolving credit facility			29,000		—		29,000		—		—

	Totals	$	179,000	$	—	$	29,000	$	—	$	150,000

Consolidated cash payments for interest were $16.2 million, $13.2 million, and $6.4 million, respectively, for 2003, 2002, and 2001.


7.	Taxes


	*Income Taxes*

The components of the Company’s total income tax expense including amounts related to items shown net of income taxes on the statements of operations were attributed to the following items (in thousands):



		Year Ended December 31,

		2003		2002		2001

Taxes related to:
	Income before cumulative effect of accounting change	$	36,102	$	22,616	$	16,333
	Cumulative effect of accounting change		529		—		541

Total tax expense		$	36,631	$	22,616	$	16,874

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The components of the income tax provision related to income/ loss before cumulative effect of accounting change and extraordinary loss are as follows (in thousands):



			Year Ended December 31,

			2003		2002			2001

Federal:
	Current		$	991	$	(745	)	$	1,919
	Deferred			32,145		21,552			13,125

		Total federal		33,136		20,807			15,044

State:
	Current			—		—			—
	Deferred			2,966		1,809			1,289

		Total state		2,966		1,809			1,289

Income tax provision			$	36,102	$	22,616		$	16,333

Reconciliation of income tax expense with tax at the Federal statutory rate is as follows (in thousands):



		Year Ended December 31,

		2003			2002			2001

Income before income taxes		$	98,880		$	60,301		$	33,396

Tax at statutory rate		$	34,608		$	21,105		$	11,689
State income taxes, net of federal benefit			2,966			1,809			1,289
Non-cash stock based compensation			—			—			3,355
Section 29 & 43 credits			(1,322	)		(632	)		—
Other			(150	)		334			—

	Income tax provision	$	36,102		$	22,616		$	16,333

The major components of the net current deferred tax asset and net long-term deferred tax liability are as follows at December 31 (in thousands):



			December 31,

			2003			2002

Current:
Assets:
	Allowance for bad debt		$	—		$	984
	Unrealized hedge loss in other comprehensive income			4,626			3,883
	Other			—			65

		Total current deferred tax assets		4,626			4,932

Liabilities:
	Derivative fair value loss			(881	)		(99	)
	Other			(153	)		—

		Total current deferred tax liabilities		(1,034	)		(99	)

Net current deferred tax asset			$	3,592		$	4,833

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)



			December 31,

			2003			2002

Long-term:
Assets:
	Alternative minimum tax		$	1,972		$	1,312
	Unrealized hedge loss in other comprehensive income			1,453			159
Section 43 credits				1,062			1,019
	Other			251			14

		Total long-term deferred tax assets		4,738			2,504

Liabilities:
	Book basis of oil and natural gas properties in excess of tax basis			(85,051	)		(50,160	)

Net long-term deferred tax liability			$	(80,313	)	$	(47,656	)

Cash income tax payments in the amount of $1.5 million were made in 2003 and in 2001. No cash income tax payments were made in 2002.


	*Taxes Other than Income Taxes*

Taxes other than income taxes were comprised of the following (in thousands):



		Year Ended December 31,

		2003		2002		2001

Production and severance		$	19,999	$	14,397	$	13,303
Property and ad valorem			2,014		1,256		506
Franchise, payroll and other taxes			677		383		316

	Total	$	22,690	$	16,036	$	14,125


8.	Stockholders’ Equity


	*Public Offerings of Common Stock*

On March 8, 2001, the Company priced its shares to be issued in its initial public offering (“IPO”) and began trading on the New York Stock Exchange the following day under the ticker symbol “EAC”. Immediately prior to Encore’s IPO, all of the outstanding shares of Class A and Class B stock held by management and institutional investors were converted into 2,630,203 and 20,249,758 shares, respectively, of a single class of common stock. Through the IPO, the Company sold an additional 7,150,000 shares of common stock to the public at the offering price of $14.00 per share, resulting in total outstanding shares of 30,029,961. The Company received $91.5 million in net proceeds after deducting the underwriter’s discounts and commissions and related offering expenses. The proceeds received from the IPO were used to pay down debt outstanding under our credit facility.

On November 13, 2003, the Company priced a public offering of 8.0 million shares of Encore’s common stock at a price to the public of $20.25 per share. The underwriters also exercised their over-allotment option for an additional 1.06 million shares of common stock, at a price of $20.25 per share, on December 2, 2003, for a total of 9.06 million shares. The Company used all of the net proceeds to repurchase 6,866,643 shares of Encore’s common stock from J.P. Morgan Partners (SBIC), LLC (“J.P. Morgan”) and 2,193,357 shares from Warburg Pincus Equity Partners L.P. (“Warburg Pincus”) at a price of $19.3775 per share. The 9.06 million shares the Company purchased were retired upon

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

repurchase. Encore’s total shares outstanding did not change as a result of this offering. Net proceeds from the original offering and the over-allotment option totaled approximately $175.6 million, after deducting underwriting discounts and commissions and the estimated expenses of the offering. After giving effect to the repurchase, J.P. Morgan no longer beneficially owns any of Encore’s common stock and Warburg Pincus beneficially owns 24.5% of Encore’s common stock.


	*Common Stock Option Exercises*

During the years ended December 31, 2003 and 2002, employees of the Company exercised 145,727 and 3,666 options, respectively. The Company received proceeds from the option exercises of $2.0 million and $0.1 million in the years ended December 31, 2003 and 2002, respectively, related to these option exercises.


	*Preferred Stock*

The Company has authorized a class of undesignated preferred stock consisting of 5,000,000 shares, none of which are issued and outstanding. The Board of Directors has not determined the rights and privileges of holders of such preferred stock and we have no current plans to issue any shares of preferred stock.


	*Non-Cash Stock Based Compensation Expense on Class A Stock*

The Company followed variable plan accounting for the Class A stock sold to management. Accordingly, compensation expense was based on the excess of the estimated fair value of the Class A stock over the amount paid by the shareholders. Compensation expense was adjusted in each reporting period based on the most recent fair value estimates until the measurement date occurred. Compensation expense was recorded over the expected service period of the Class A stock, which was based on a vesting schedule. The Class A stock vested 25% upon issuance and an additional 15% per year for the following five years. Prior to September 1, 2000, the Company estimated the fair value of our Class A common stock based on discounted cash flow estimates of our oil and natural gas properties. Beginning on September 1, 2000, we estimated the fair value of the Class A stock based on 90% of the estimated offering price in the Company’s IPO. The measurement date occurred on March 8, 2001, the date of the IPO, as after this date the Class A shareholders were no longer required to make future capital contributions. Total compensation expense on the Class A shares using the IPO price of $14.00 per share was $35.6 million. Based on the estimated fair values and vesting at the end of each period, the Company recorded $9.6 million of compensation expense for 2001 and $26.0 million in 2000. The $9.6 million recorded in 2001 represented the final compensation expense to be recorded related to the Class A shares.


9.	Earnings Per Share (“EPS”)

Under Statement of Financial Accounting Standards No. 128, the Company must report basic EPS, which excludes the effect of potentially dilutive securities, and diluted EPS, which includes the effect of all potentially dilutive securities. EPS for the periods presented is based on weighted average common shares outstanding for the period.

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following table reflects EPS data for the years ended December 31 (in thousands, except per share data):



		Year Ended December 31,

		2003		2002		2001

Numerator:
Income before cumulative effect of accounting change		$	62,778	$	37,685	$	17,063
Cumulative effect of accounting change			863		—		(884	)

	Net income	$	63,641	$	37,685	$	16,179

Denominator:
Denominator for basic earnings per share — weighted average shares outstanding			30,102		30,031		28,718
Effect of dilutive options and dilutive restricted stock(a)			231		130		5

Denominator for diluted earnings per share			30,333		30,161		28,723

Basic income per common share before accounting change		$	2.09	$	1.25	$	0.59
Cumulative effect of accounting change, net of tax			0.02		—		(0.03	)

Basic income per common share after accounting change		$	2.11	$	1.25	$	0.56
Diluted income per common share before accounting change		$	2.07	$	1.25	$	0.59
Cumulative effect of accounting change, net of tax			0.03		—		(0.03	)

Diluted income per common share after accounting change		$	2.10	$	1.25	$	0.56


(a)		There were no antidilutive options or antidilutive restricted stock outstanding for the year ended December 31, 2003 and December 31, 2001. Options to purchase 272,177 shares of common stock were outstanding but not included in the above calculation of 2002 diluted earnings per share because their effect would be antidilutive. Additionally, the Company issued 129,328 shares of restricted stock at the end of 2002 which are not included in the calculation of 2002 diluted earnings per share because their effect on the shares outstanding would be nominal.


10.	Employee Benefit Plans


	*401(k) plan*

We make contributions to the Encore Acquisition Company 401(k) Plan, which is a voluntary and contributory plan for eligible employees. Our contributions, which are based on a percentage of matching employee contributions, totaled $0.5 million in 2003, $0.5 million in 2002, and $0.4 million in 2001. The Company’s 401(k) plan does not currently allow employees to invest in securities of the Company.


	*Incentive Stock Plans*

During 2000, the Company’s Board of Directors approved the 2000 Incentive Stock Plan (the “Plan”). The purpose of the Plan is to attract, motivate, and retain selected employees of the Company and to provide the Company with the ability to provide incentives more directly linked to the profitability of the business and increases in shareholder value. All directors and full-time regular employees of the Company and its subsidiaries and affiliates are eligible to be granted awards under the Plan. The total number of shares of common stock reserved and available for distribution pursuant to the Plan is 1.8 million. The Plan provides for the granting of incentive stock options, non-qualified stock options, and restricted stock at the discretion of the Company’s Board of Directors.

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

All options granted under the Plan have a strike price equal to the market price on the date of grant. Additionally, all have a ten-year life and vest equally over a two or three-year period. The following table summarizes the changes in the number of outstanding options and their related weighted average strike prices during 2003, 2002, and 2001:



		Year Ended December 31,					Year Ended December 31,					Year Ended December 31,
		2003					2002					2001

					Weighted					Weighted					Weighted
		Number of			Average		Number of			Average		Number of			Average
		Options			Strike Price		Options			Strike Price		Options			Strike Price

Outstanding at beginning of year			1,178,511		$	14.62		847,500		$	13.44		—		$	—
	Granted(a)		49,792			19.45		378,177			17.21		940,000			13.49
	Forfeited		(119,622	)		16.11		(43,500	)		14.24		(92,500	)		14.00
	Exercised		(145,727	)		13.43		(3,666	)		14.00		—			—

Outstanding at end of year			962,954			14.86		1,178,511			14.62		847,500			13.44

Exercisable at end of year			581,610			13.95		324,278			13.31		—			—


(a)		During 2003 and 2002, 15,000 and none of the options granted, respectively, were granted to non-employee directors. The weighted average fair value of individual options granted in 2003 and 2002 was $6.38 and $6.91, respectively.

Additional information about common stock options outstanding and exercisable at December 31, 2003 is as follows:

Options Outstanding

Weighted

Number of

Average Life

Average

Range of Strike Prices per Share

Options

(Years)

Strike Price

$12.49 to $14.00

682,667

7.5

13.37

$14.01 to $20.41

280,287

9.0

18.50

Under the Plan during 2003 and 2002, the Company issued 45,461 and 129,328 shares, respectively, of restricted common stock to employees. Of these, 45,461 shares issued in 2003 and 77,901 shares issued in 2002 vest in equal installments over a five year period evenly in years three, four, and five and depend only on continued employment for future issuance. These represent a fixed award per APB 25 and compensation expense is being recorded over the related five-year service period. Of the remaining 51,427 shares issued in 2002, only 34,464 remain outstanding at December 31, 2003. These were issued to two members of senior management and also vest in equal installments over a five year period evenly in years three, four, and five. However, these shares not only depend on the passage of time and continued employment, but on certain performance measures for their future issuance. These represent a variable award under APB 25, and thus, the full amount of compensation expense to be recorded for these shares will not be known until their eventual issuance as it is dependent on the price of the Company’s common stock on that date. The closing stock price on the date of grant in 2002 was $18.60 and was $24.65 on December 31, 2003.

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	*SFAS 123 disclosures*

Under SFAS 123, the fair value of each stock option grant is estimated on the date of grant using the Black-Scholes option-pricing model. See “Stock-based Compensation” in Note 2. The following amounts represent weighted average values used in the model to calculate the fair value of the options granted during 2003, 2002, and 2001:

Year Ended

December 31,

2003

2002

2001

Risk free interest rate

3.0%

3.4%

4.4%

Expected life

4 years

Expected volatility

36.5%

46.7%

28.9%

Expected dividend yield

0.0%


11.	Financial Instruments

The following table sets forth the book value and estimated fair value of the Company’s financial instruments (in thousands):



	December 31, 2003						December 31, 2002

	Book Value			Fair Value			Book Value			Fair Value

Cash and cash equivalents	$	431		$	431		$	13,057		$	13,057
Accounts receivable, net		27,640			27,640			21,981			21,981
Accounts payable		(10,668	)		(10,668	)		(9,650	)		(9,650	)
8 3/8% Notes		(150,000	)		(162,750	)		(150,000	)		(161,000	)
Revolving credit facility		(29,000	)		(29,000	)		(16,000	)		(16,000	)
Commodity derivative contracts		(7,768	)		(7,768	)		(5,047	)		(5,047	)
Interest rate swaps		2,420			2,420			(1,325	)		(1,325	)
Plugging bond		589			643			554			633

The book value of cash and cash equivalents approximates fair value because of the short maturity of these instruments. The fair value of our 8 3/8% bonds was determined using their open market quote as of December 31, 2003. The difference between book value and fair value represents the premium on that date. The book value of the Facility approximates the fair value as the interest rate is variable. The plugging bond is classified as held to maturity and therefore is recorded at amortized cost, which at December 31, 2003 is less than fair value. Commodity contracts and interest rate swaps are marked to market each quarter in accordance with the provisions of SFAS 133.


	*Commodity Derivatives*

The Company hedges commodity price risk with swap contracts, put contracts, and collar contracts and hedges interest rate risk with swap contracts. Swap contracts provide a fixed price for a notional amount of volume. Put contracts provide a fixed floor price on a notional amount of volume while allowing full price participation if the relevant index price closes above the floor price. Collar contracts provide floor price for a notional amount of volume while allowing some additional price participation if the relevant index price closes above the floor price. Additionally, we occasionally sell put contracts with a strike price well below the floor price of the collar. These short put contracts do not qualify for hedge accounting under SFAS 133, and accordingly, the mark-to-market change in the value of these contracts is recorded as fair value gain/loss in the statement of operations.

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The Company has several oil and natural gas put contracts in place at December 31, 2003 which the Company did not designate as cash flow hedges, and thus they are also marked to market through earnings each quarter. Some instances management has determined it is more cost effective to not designate certain derivatives as hedges. At December 31, 2003, we had oil put contracts of 1,500 Bbls per day in the first half of 2004, 2,500 Bbls of oil put contracts in the second half of 2004, and natural gas put contracts of 5,000 Mcf per day for 2004 that were not designated as cash flow hedges. The fair value of these contracts at December 31, 2003 was $0.9 million.

In order to more effectively hedge the cash flows received on our oil and natural gas production, the Company enters into financial instruments whereby we swap certain per Bbl or per Mcf floating market indices for a fixed amount. These market indices are a component of the price the Company is paid on its actual production and by fixing this component of our marketing price, we are able to realize a net price with a more consistent differential to NYMEX. Since NYMEX is the basis of all our derivative oil hedging contracts and some of our natural gas contracts, a more consistent differential results in more effective hedges. However, management has elected not to use hedge accounting for certain of these contracts. Instead, we mark these contracts to market each quarter through “Derivative fair value (gain) loss’ in the Consolidated Statements of Operations. Thus, as these contracts do not change the Company’s overall hedged volumes, average prices presented in the table below are exclusive of any effect of these non-hedge instruments. As of December 31, 2003, the mark-to-market value of these contracts is $0.1 million.

The following tables summarize our open commodity derivative positions designated as cash flow hedges as of December 31, 2003:


	*Oil Hedges at December 31, 2003*


	Daily Floor		Floor		Daily Cap		Cap		Daily Swap		Swap		Fair Market
	Volume		Price		Volume		Price		Volume		Price		Value
Period	(Bbls)		(per Bbl)		(Bbls)		(per Bbl)		(Bbls)		(per Bbl)		(In thousands)

Jan. – June 2004		15,500	$	22.98		7,000	$	29.06		500	$	26.48	$	(3,679	)
July – Dec. 2004		14,500		23.72		5,000		28.33		500		26.48		(1,203	)
Jan. – June 2005		2,500		23.00		2,000		30.41		1,000		25.12		(421	)
July – Dec. 2005		1,500		23.00		1,500		30.18		1,000		25.12		(509	)
Jan. – Dec. 2006		—		—		—		—		2,000		25.03		(1,139	)
Jan. – Dec. 2007		—		—		—		—		2,000		25.11		(1,029	)


	*Natural Gas Hedges at December 31, 2003*


	Daily Floor		Floor		Daily Cap		Cap		Daily Swap		Swap		Fair Market
	Volume		Price		Volume		Price		Volume		Price		Value
Period	(Mcf)		(per cf)		(Mcf)		(per Mcf)		(Mcf)		(per Mcf)		(In thousands)

Jan. – Dec. 2004		15,000	$	4.02		7,500	$	6.03		5,000	$	5.01	$	(477	)
Jan. – Dec. 2005		—		—		—		—		5,000		4.63		(311	)

As a result of all of our hedging transactions for oil and natural gas we recognized a pre-tax reduction in revenues of approximately $15.3 million, $5.2 million, and $12.8 million in 2003, 2002, and 2001, respectively. Based on the fair value of our hedges at December 31, 2003, our unrealized pre-tax loss recorded in other comprehensive income related to outstanding hedges is $13.9 million for oil and $2.1 million for natural gas. Of the total deferred hedge loss at December 31, 2003 related to commodity contracts, $12.1 million relates to 2004 contracts, and $1.7 million, $1.2 million, $1.0 million relate to 2005, 2006, and 2007 contracts, respectively.

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	*Interest Rate Derivatives*

As discussed in “Note 6. Indebtedness,” in conjunction with the sale of the Notes, the Company repaid all amounts outstanding under its previous credit facility on June 25, 2002, and terminated the prior revolving credit facility on that date. At the time, the Company had three interest rate swaps outstanding, with a notional amount of $30 million each, which swapped LIBOR based floating rates for fixed rates. According to the provisions of SFAS 133, these no longer qualified for hedge accounting. Their unrealized loss of $3.8 million through June 25, 2002 was recognized in accumulated other comprehensive income, and is being amortized to interest expense over the original life of the swaps as follows (in thousands):


Year		1st Quarter			2nd Quarter			3rd Quarter			4th Quarter			Total

2002		$	—		$	(59	)	$	(806	)	$	(754	)	$	(1,619	)
2003			(654	)		(544	)		(414	)		(297	)		(1,909	)
2004			(212	)		(153	)		(109	)		(72	)		(546	)
2005			(40	)		72			85			60			177
2006			22			24			29			33			108
2007			38			1			—			—			39

	Total													$	(3,750	)

During the third quarter of 2002, the Company cash settled one of three interest rate swaps discussed above and during the first quarter of 2003, the Company cash settled the remaining two. This resulted in a gain of $0.6 million in 2003 and a loss of $0.4 million in 2002, which was included in “Derivative fair value (gain) loss’ in the Statements of Operations.

The following table summarizes the Company’s only remaining interest rate swap contract at December 31, 2003:

Fair Market

Encore

Value

Contract Expiration

Notional Amount

Encore Pays

Receives

(In thousands)

June 2005

80,000,000

LIBOR + 3.89%

8.375%

2,420

As a result of our hedging transactions for interest, we recognized in interest expense a pre-tax loss of approximately $1.9 million, $1.6 million, and $0.7 million in 2003, 2002, and 2001, respectively. Additionally, $1.5 million gain was recognized in “Derivative fair value (gain) loss’ in 2003 for settlements and changes in fair value of our current interest rate swap, which does not qualify for hedge accounting.

The actual gains or losses we realize from our derivative transactions may vary significantly from the deferred loss amount recorded in equity at December 31, 2003 due to fluctuation of prices in the commodities markets and/or fluctuations in the floating LIBOR interest rate.


	*Counterparty Risk*

The Company’s counterparties to hedging contracts include: Paribas BNP; Deutsche Bank; Koch; Morgan Stanley; Mitsui & Co; Shell Trading; Credit Lyonnais; J. Aron & Company, a wholly-owned subsidiary of Goldman, Sachs & Co. Approximately 35%, 23%, 20%, and 16% of estimated oil production hedged is committed to Morgan Stanley, J. Aron & Company, Deutsche Bank, and Credit Lyonnais, respectively. Approximately 42%, 33%, and 25% of our hedged gas production is contracted with BNP Paribas, J. Aron & Company, and Morgan Stanley, respectively. Performance on all of J. Aron & Company’s contracts with the Company is guaranteed by their parent Goldman, Sachs & Co. We feel the credit-worthiness of our current counterparties is sound and we do not anticipate any non-performance of

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

contractual obligations. However, as long as each counterparty maintains an investment grade credit rating, pursuant to our hedging contracts, no collateral is required.

In order to mitigate the credit risk of financial instruments, the Company enters into master netting agreements with significant counterparties. The master netting agreement is a standardized, bilateral contract between the Company and a given counterparty. Instead of treating each financial transaction between the Company and its counterparty separately, the master netting agreement enables the Company and its counterparty to aggregate all financial trades and treat them as a single agreement. This arrangement benefits the Company in three ways. First, the netting of the value of all trades reduces the requirements of daily collateral posting by the Company. Second, default by a counterparty under one financial trade can trigger rights for the Company to terminate all financial trades with such counterparty. Third, netting of settlement amounts reduces the Company’s credit exposure to a given counterparty in the event of close-out.


12.	Termination of Enron Hedges

On December 2, 2001, Enron Corp. and certain subsidiaries, including Enron North America Corp. (“Enron”), each filed voluntary petitions for relief under Chapter 11 of Title 11 of the United States Bankruptcy Code. Prior to this date, the Company had entered into oil and natural gas hedging contracts with Enron, many of which were set to expire at December 31, 2001; however, others related to 2002 and 2003. As a result of the Chapter 11 bankruptcy declaration and pursuant to the terms of the Company’s contract with Enron, we terminated all outstanding oil and natural gas derivative contracts with Enron as of December 12, 2001. According to the terms of the contract, Enron is liable to the Company for the mark-to-market value of all contracts outstanding on that date, which totaled $6.6 million. Additionally, Enron failed to make timely payment of $0.4 million in 2001 hedge settlements. Both of these amounts remained outstanding as of December 31, 2001. Due to the uncertainty of future collection of any or all of the amounts owed to the Company by Enron, the Company recorded an allowance for the full amount of the receivable of $7.0 million.

At the time of termination, the market price of our commodity contracts with Enron exceeded their amortized cost on our balance sheet, giving rise to a gain. In accordance with the provisions of SFAS 133, this gain was recorded in other comprehensive income and was reversed into earnings during 2003 and 2002. The following table illustrates the amortization of this amount to revenue by year (in thousands):


		Oil		Natural Gas
Period		Revenue		Revenue		Total

2002		$	2,822	$	1,594	$	4,416
2003			401		18		419

	Total	$	3,223	$	1,612	$	4,835

During the first quarter of 2003, due to continued uncertainty of any ultimate collection and continuing legal fees, the Company sold its entire Enron receivable to a third party for $0.5 million. As the receivable was fully reserved, this amount was recorded as a gain in 2003 and included in ‘Other operating expense’ in the Consolidated Statements of Operations. The Company no longer has any claims outstanding against Enron and accordingly has eliminated the previously recorded $7.0 million receivable and related allowance from the accompanying consolidated balance sheet as of December 31, 2003.

The Company actively evaluates the credit exposure related to its derivatives and receivables, and considers its history with the debtor, how long the amount has been outstanding, potential offsets to the amount owed, and general economic conditions. Other than the Enron loss, the Company has not become aware of any conditions which warrant an allowance or write-off of a receivable or derivative position.

ENCORE ACQUISITION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


13.	Impairment of Long-Lived Assets

Throughout 2001, futures prices for oil and natural gas continued to decline from their December 31, 2000 levels. The SEC price case used for our 2000 reserve estimate was $26.80 per Bbl and $9.77 per Mcf dropping to $19.84 per Bbl and $2.57 per Mcf for the 2001 estimate. Although the SEC price case does not necessarily coincide with management’s estimates of future prices, this indicated the need to assess our oil and natural gas properties for any possible impairment. Thus, we compared the undiscounted future cash flows for each of our oil and natural gas properties to their net book value, which indicated the need for an impairment charge on certain properties. We then compared the net book value of the impaired assets to their estimated fair value, which resulted in a write-down of the value of proved oil and natural gas properties of $2.6 million. Fair value was determined using estimates of future production volumes and estimates of future prices we might receive for these volumes discounted back to a present value using a rate commensurate with the risks inherent in the industry. We performed a similar review at December 31, 2003 and 2002, and determined no impairment charge was necessary.


14.	Subsequent Events (unaudited)

On March 2, 2004, the Company entered into a stock purchase agreement to acquire all of the outstanding common stock of Cortez Oil & Gas, Inc., a privately held, independent oil and gas company (“Cortez”), for total consideration of approximately $123.0 million. The Company intends to fund the acquisition initially with bank debt under the Company’s existing credit facility. The acquired oil and natural gas assets from Cortez are in the same areas as our producing properties located in the CCA of Montana, the Permian Basin of West Texas and Southeastern New Mexico, and in our Mid Continent area, including the Anadarko and Arkoma Basins of Oklahoma, and the Barnett Shale north of Fort Worth, Texas. We expect to close the transaction in the second quarter of 2004, however, the closing is subject in some respects to the Company’s due diligence review and other closing conditions, and there can be no assurance that the closing will occur as expected.

In connection with the Cortez acquisition, we entered into several oil and natural gas hedges subsequent to December 31, 2003. The table below shows the terms of these contracts as of March 4, 2004:


	*Additional Oil Derivative Contracts at March 4, 2004*


	Daily Floor		Floor		Daily Cap		Cap		Daily Swap		Swap
	Volume		Price		Volume		Price		Volume		Price
Period	(Bbls)		(per Bbl)		(Bbls)		(per Bbl)		(Bbls)		(per Bbl)

July – Dec. 2004		1,000	$	31.50		1,000	$	34.56		—		—
Jan. – Dec 2005		1,000		28.50		1,000		32.40		—		—
Jan. – Dec 2006		1,000		27.50		1,000		29.88		—		—


	*Additional Natural Gas Derivative Contracts at March 4, 2004*


	Daily Floor		Floor		Daily Cap				Daily Swap		Swap
	Volume		Price		Volume		Cap Price		Volume		Price
Period	(Mcf)		(per Mcf)		(Mcf)		(per Mcf)		(Mcf)		(per Mcf)

July – Dec. 2004		—		—		—		—		5,000	$	5.65
Jan. – Dec. 2005		5,000	$	5.05		5,000	$	5.97		—		—
Jan. – Dec. 2006		5,000		4.85		5,000		5.68		—		—

SUPPLEMENTAL INFORMATION

Capitalized Costs Relating to Oil and Gas Producing Activities

The capitalized cost of oil and natural gas properties at December 31, 2003 and 2002 are as follows (in thousands):



Properties and equipment, at cost — successful efforts method:
	Producing properties	$	739,288		$	581,012
	Undeveloped properties		921			1,168
	Accumulated depletion, depreciation, and amortization		(124,646	)		(94,356	)

		$	615,563		$	487,824

Costs Incurred Relating to Oil and Gas Producing Activities

The following table summarizes costs incurred related to oil and natural gas properties:



			Year Ended December 31,

			2003		2002		2001


			(In thousands)
Acquisitions
	Producing properties		$	54,484	$	78,158	$	1,471
	Undeveloped properties			117		391		151
	Asset retirement obligations(1)			337		—		—
Development
	Drilling and exploitation			98,977		80,313		87,180
	Asset retirement obligations(1)			83		—		—

		Total	$	153,998	$	158,862	$	88,802

(1) The Company adopted SFAS 143 on January 1, 2003 which requires us to capitalize additional asset cost equal to the amount of our discounted asset retirement obligation assumed in a property purchase or incurred in the drilling of new wells. Had the Company adopted SFAS 143 prior to January 1, 2001, the Company’s acquisition cost incurred on a pro-forma basis would have been increased by $0.7 million and zero for the years ended December 31, 2002 and 2001, respectively. The effect on the Company’s development cost incurred on a pro-forma basis would have been insignificant.

Oil & Natural Gas Producing Activities (unaudited)

The estimates of the Company’s proved oil and natural gas reserves, which are located entirely within the United States, were prepared in accordance with guidelines established by the Securities and Exchange Commission and the Financial Accounting Standards Board. Proved oil and natural gas reserve quantities are based on estimates prepared by Miller and Lents, Ltd., who are independent petroleum engineers.

Future prices received for production and future production costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. There can be no assurance that the proved reserves will be developed within the periods assumed or that prices and costs will remain constant. Actual production may not equal the estimated amounts used in the preparation of reserve projections. In accordance with the Securities and Exchange Commission’s guidelines, the Company’s estimates of future net cash flows from the properties and the representative value thereof are made using oil and natural gas prices in effect as of the dates of such estimates and are held constant throughout the life of the properties. Average prices used in estimating net cash flows at December 31, 2003, 2002, and 2001 were $32.55, $31.20, and $19.84 per barrel, respectively, for oil and $5.83, $4.79, and $2.57 per Mcf, respectively, for natural gas. The net profits interest on our Cedar Creek Anticline properties has been

deducted from future cash inflows in the calculation of Standardized Measure. The Company’s reserve and production quantities have been reduced by the amounts attributable to the net profits interest. In addition, net future cash inflows have not been adjusted for hedge positions outstanding at the end of the year. The future cash flows are reduced by estimated production costs and development costs, which are based on year-end economic conditions and held constant throughout the life of the properties, and by the estimated effect of future income taxes. Future income taxes are based on statutory income tax rates in effect at year end, the Company’s tax basis in its proved oil and natural gas properties, and the effect of net operating loss, alternative minimum tax and Section 43 credits, and other carry forwards.

There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures. Oil and natural gas reserve engineering is and must be recognized as a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in any exact way, and estimates of other engineers might differ materially from those included in this Annual Report on Form 10-K. The accuracy of any reserve estimate is a function of the quality of available data and engineering, and estimates may justify revisions. Accordingly, reserve estimates are often materially different from the quantities of oil and natural gas that are ultimately recovered. Reserve estimates are integral to management’s analysis of impairments of oil and natural gas properties and the calculation of depletion, depreciation, and amortization on these properties.

Estimated net quantities of proved oil and natural gas reserves of the Company were as follows:


		Oil		Natural Gas		Oil Equivalent
		(MBbl)		(MMcf)		(MBOE)

December 31, 2003
	Proved reserves		117,732		138,950		140,890
	Proved developed reserves		92,377		104,767		109,838
December 31, 2002
	Proved reserves		111,674		99,818		128,310
	Proved developed reserves		93,945		82,217		107,648
December 31, 2001
	Proved reserves		91,369		75,687		103,983
	Proved developed reserves		71,639		69,941		83,296

The change in proved reserves were as follows for the years ended:


	Oil			Natural Gas			Oil Equivalent
	(MBbl)			(MMcf)			(MBOE)

Balance, December 31, 2000		78,910			72,970			91,072

Acquisitions of minerals-in-place		—			—			—
Extensions and discoveries		19,266			14,063			21,610
Revisions of estimates		(1,872	)		(3,268	)		(2,418	)
Production		(4,935	)		(8,078	)		(6,281	)

Balance, December 31, 2001		91,369			75,687			103,983

Acquisitions of minerals-in-place		14,555			5,434			15,461
Extensions and discoveries		9,605			23,643			13,546
Revisions of estimates		2,182			3,229			2,719
Production		(6,037	)		(8,175	)		(7,399	)

Balance, December 31, 2002		111,674			99,818			128,310

Acquisitions of minerals-in-place		13			37,464			6,257
Extensions and discoveries		3,957			7,354			5,182
Improved recovery		12,773			(178	)		12,744
Revisions of estimates		(4,084	)		3,543			(3,493	)
Production		(6,601	)		(9,051	)		(8,110	)

Balance, December 31, 2003		117,732			138,950			140,890

The Standardized Measure of discounted estimated future net cash flows and changes therein related to proved oil and natural gas reserves (in thousands) is as follows at:



	December 31,

	2003			2002			2001

Net future cash inflows	$	4,245,574		$	3,648,515		$	1,770,384
Future production costs		(1,683,810	)		(1,448,110	)		(794,139	)
Future development costs		(81,076	)		(63,194	)		(67,652	)
Future income tax expense		(716,869	)		(623,987	)		(215,568	)

Future net cash flows		1,763,819			1,513,224			693,025
10% annual discount		(1,026,880	)		(888,506	)		(408,716	)

Standardized measure of discounted estimated future net cash flows	$	736,939		$	624,718		$	284,309

Primary changes in the Standardized Measure of discounted estimated future net cash flows (in thousands) are as follows for the year ended:



		Year Ended December 31,

		2003			2002			2001

Standardized measure, beginning of year		$	624,718		$	284,309		$	599,276
	Net change in sales prices and production costs		81,964			305,097			(334,809	)
	Acquisitions of minerals-in-place		91,654			131,370			—
	Extensions, discoveries, and improved recovery		103,780			135,897			71,090
	Revisions of quantity estimates		(25,650	)		18,216			(18,244	)
	Sales, net of production costs		(151,955	)		(114,361	)		(96,969	)
	Development costs incurred during the year		98,977			80,313			87,179
	Accretion of discount		86,511			36,036			70,636
	Change in estimated future development costs		(116,859	)		(44,285	)		(51,238	)
	Net change in income taxes		(52,992	)		(164,334	)		31,028
	Change in timing and other		(3,209	)		(43,540	)		(73,640	)

Standardized measure, end of year		$	736,939		$	624,718		$	284,309

Selected Quarterly Financial Data

The following table sets forth selected quarterly financial data for the years ended December 31, 2003 and 2002:



		Quarter

		First		Second		Third		Fourth


		(In thousands, except per share data)
2003
Revenues		$	55,787	$	51,243	$	55,724	$	57,342
Operating Income		$	31,377	$	26,679	$	28,789	$	27,972
Income before accounting change		$	17,115	$	14,233	$	15,768	$	15,662
Cumulative effect of accounting change, net of tax of $329			863		—		—		—

Net income		$	17,978	$	14,233	$	15,768	$	15,662

Basic income per common share:
	Before accounting change	$	0.57	$	0.47	$	0.52	$	0.51
	Accounting change, net of tax		0.03		—		—		—

	After accounting change	$	0.60	$	0.47	$	0.52	$	0.51

Diluted income per common share:
	Before accounting change	$	0.57	$	0.47	$	0.52	$	0.51
	Accounting change, net of tax		0.02		—		—		—

	After accounting change	$	0.59	$	0.47	$	0.52	$	0.51

2002
Revenues		$	32,297	$	37,807	$	43,502	$	47,086
Operating Income		$	12,929	$	16,951	$	19,789	$	22,846
Net income		$	7,110	$	9,126	$	10,113	$	11,336
Basic income per common share:		$	0.24	$	0.30	$	0.34	$	0.38

Diluted income per common share:		$	0.24	$	0.30	$	0.33	$	0.38


Item 9.	*Changes in and Disagreements with Accountants on Accounting and Financial Disclosure*

On April 1, 2002, we dismissed Arthur Andersen LLP as our independent accountants effective as of that date. The decision to dismiss Arthur Andersen LLP was recommended by the Audit Committee of the Board of Directors and was approved by the Board of Directors on April 1, 2002.

Arthur Andersen’s report on the Company’s consolidated financial statements for the fiscal year ended December 31, 2001 did not contain an adverse opinion or disclaimer of opinion and was not qualified or modified as to uncertainty or audit scope. Arthur Andersen LLP included in its opinion explanatory language related to the Company’s change in its method of accounting for derivatives as a result of the Company’s adoption of Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities.” During 2001 and the period from January 1, 2002 through the date of Arthur Andersen LLP’s termination, there were no disagreements between us and Arthur Andersen LLP on any matter of accounting principles or practices, financial statement disclosure, or auditing scope or procedure, that, if not resolved to the satisfaction of Arthur Andersen LLP, pursuant to Item 304(a)(1) of Regulation S-K, would have caused it to make reference to the subject matter of the disagreements in its report.

As required under the regulations of the SEC, we provided Arthur Andersen LLP with a copy of our disclosure in connection with this matter and requested Arthur Andersen LLP to furnish us with a letter addressed to the SEC stating whether it agreed with our statements and, if not, stating the respects in which it did not agree. Arthur Andersen LLP’s letter was filed as Exhibit 16.1 to our Current Report on Form 8-K filed with the SEC on April 5, 2002.

Effective April 11, 2002, we engaged Ernst & Young LLP, as our new independent accountants for the fiscal year ending December 31, 2002. The decision to appoint Ernst & Young LLP was recommended by the Audit Committee of the Board of Directors and was approved by the Board of Directors on April 1, 2002.

There have been no disagreements with our independent accountants on our accounting or financial reporting that would require our independent accountants to qualify or disclaim their report on our consolidated financial statements, or otherwise require disclosure in this Form 10-K.


Item 9A.	*Controls and Procedures*

Our Chief Executive Officer and our Chief Financial Officer (our principal executive officer and principal financial officer, respectively) have concluded, based on their evaluation as of the end of the period covered by this annual report on Form 10-K, that our disclosure controls and procedures are effective to ensure that information required to be disclosed by us in the reports filed or submitted by us under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and include controls and procedures designed to ensure that information required to be disclosed by us in such reports is accumulated and communicated to our management, including our Chief Executive Officer and our Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. There were no changes in our internal control over financial reporting that occurred during the most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART III


Item 10.	*Directors and Executive Officers of the Registrant*

The information required in response to this item is set forth in the Company’s definitive proxy statement for the annual meeting of stockholders to be held on April 29, 2004 and is incorporated herein by reference.

We have adopted a Code of Business Conduct and Ethics covering our directors, officers, and employees, which is available free of charge on our Internet website (www.encoreacq.com).


Item 11.	*Executive Compensation*


Item 12.	*Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters*


Item 13.	*Certain Relationships and Related Transactions*


Item 14.	*Principal Accountant Fees and Services*

PART IV


Item 15.	*Exhibits, Financial Statement Schedules, and Reports on Form 8-K*

(a) The following documents are filed as a part of this Report at page 48:

1. Financial Statements:


Report of Independent Public Accountant			49
Consolidated Balance Sheets as of December 31, 2003 and 2002			51
Consolidated Statements of Operations for the Years Ended December 31, 2003, 2002 and 2001			52
Consolidated Statement of Stockholders’ Equity for the Years Ended December 31, 2003, 2002, and 2001			53
Consolidated Statements of Cash Flows for the Years Ended December 31, 2003, 2002 and 2001			54
Notes to Consolidated Financial Statements			55

2. Financial Statement Schedules:

All financial statement schedules have been omitted because they are not applicable or the required information is presented in the financial statements or the notes to the consolidated financial statements.

(b) Reports on Form 8-K

We filed the following reports on Form 8-K during the quarter ended December 31, 2003:

1. On November 4, 2003, we filed a Form 8-K to furnish certain earnings-related information under Items 7 and 12.

2. On November 7, 2003, we filed a Form 8-K to furnish information under Items 7 and 9 regarding the appointment of Roy W. Jageman as our Chief Financial Officer.

3. On November 10, 2003, we filed a Form 8-K to furnish information under Items 7 and 9 regarding a public offering of up to 9.2 million shares of our common stock and the use of proceeds therefrom.

4. On November 14, 2003, we filed an Item 5 and Item 7 Form 8-K to disclose the execution of an underwriting agreement with respect to the public offering of up to 9.2 million shares of our common stock and the execution of a stock purchase agreement with respect to the repurchase of up to 9.2 million shares of our common stock from J.P. Morgan Partners (SBIC), LLC and Warburg, Pincus Equity Partners L.P.

5. On November 20, 2003, we filed a Form 8-K to furnish information under Items 7 and 9 regarding the closing of a public offering of 8.0 million shares of our common stock and the use of proceeds therefrom.

6. On December 3, 2003, we filed a Form 8-K to furnish information under Items 7 and 9 regarding the sale of 1,060,000 shares of our common stock pursuant the exercise of the underwriters’ over-allotment option and the use of proceeds therefrom.

See Exhibits to Index on the following page for a description of the exhibits filed as a part of this report.

INDEX TO EXHIBITS


Exhibit
No.			Description

	3	.1	Second Amended and Restated Certificate of Incorporation of the Company (incorporated by reference to the Company’s Quarterly Report on Form 10-Q for the fiscal quarter ended September 30, 2001, filed with the SEC on November 7, 2001).
	3	.2	Second Amended and Restated Bylaws of the Company (incorporated by reference to the Company’s Quarterly Report on Form 10-Q for the fiscal quarter ended September 30, 2001, filed with the SEC on November 7, 2001).
	4	.1	Specimen certificate of the Company (incorporated by referenced to Exhibit 4.1 to Registration Statement on Form S-1, Registration No. 333-47540, filed with the SEC on December 15, 2000).
	4	.2	Indenture, dated as of June 25, 2002, among the Company, subsidiary guarantors party thereto and Wells Fargo Bank, N.A. (incorporated by reference to Exhibit 4.1 to Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2002, filed with the SEC on August 9, 2002).
	4	.3	Form of 8 3/8% Senior Subordinated Note to Cede & Co. or its registered assigns, dated January 16, 2003.
	10	.1+	2000 Incentive Stock Plan (incorporated by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q for the fiscal quarter ended September 30, 2001, filed with the SEC on November 14, 2002).
	10	.2+	Employee Severance Protection Plan (incorporated by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2003, filed with the SEC on May 8, 2003).
	10	.3+	Form of Restricted Stock Award — Executive (incorporated by reference to Exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2003, filed with the SEC on May 8, 2003).
	10	.4	Credit Agreement, dated June 25, 2002 (the “Credit Agreement”), among the Company, Encore Operating, L.P., Fleet National Bank, a national banking association, as Administrative Agent, Wachovia Bank, N.A., as Syndication Agent, Fortis Capital Corp., as Documentary Agent and the financial institutions listed therein (incorporated by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2002, filed with the SEC on August 9, 2002).
	10	.5*	First Amendment to Credit Agreement dated October 31, 2002.
	10	.6*	Second Amendment to Credit Agreement dated October 21, 2003.
	10	.7	Registration Rights Agreement, dated August 18, 1998, by and among the Company and the other parties thereto (incorporated by reference to Exhibit 4.2 to the Company’s Registration Statement on Form S-1 (File No. 333-47540), filed with the SEC on October 6, 2000).
	10	.8*+	Severance Agreement, dated December 18, 2003, between the Company and Morris B. Smith.
	10	.9*	Stock Purchase Agreement dated March 2, 2004 by and among Cortez Oil & Gas, Inc., HRM Resources, Inc., the Security Holders of Cortez Oil & Gas, Inc., and Encore Acquisition Company.
	16	.1	Current Report on Form 8-K, filed with the SEC on April 5, 2002, regarding the dismissal of independent auditor.
	21	.1*	Subsidiaries of the Company.
	23	.1*	Consent of Ernst & Young LLP
	23	.2*	Consent of Miller and Lents, Ltd.
	24	.1*	Power of Attorney (included on the signature page of this report).
	31	.1*	Rule 13a-14(a)/15d-14(a) Certification (Principal Executive Officer)
	31	.2*	Rule 13a-14(a)/15d-14(a) Certification (Principal Executive Officer)


Exhibit
No.			Description

	32	.1*	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
	32	.2*	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

* Filed herewith

+ Management contract or compensatory plan, contract or arrangement.

Copies of the above exhibits not contained herein are available at the cost of reproduction to any security holder upon written request to the Assistant Treasurer, Encore Acquisition Company, 777 Main Street, Suite 1400, Fort Worth, Texas 76102.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on the 11th day of March, 2004.

ENCORE ACQUISITION COMPANY

By: /s/ I. JON BRUMLEY

I. Jon Brumley

Chief Executive Officer

KNOW ALL MEN BY THESE PRESENTS, that each individual whose signature appears below constitutes and appoints I. Jon Brumley and Roy W. Jageman, and each of them, his true and lawful attorneys-in-fact and agents with full power of substitution, for him and in his name, place and stead, in any and all capacities, to sign any and all amendments (including post-effective amendments) to this report, and to file the same, with all exhibits thereto, and all documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, full power and authority to do and perform each and every act and thing requisite and necessary to be done in and about the premises, as fully to all intents and purposes as he might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or his or their substitutes, may lawfully do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant in the capacities indicated on March 11, 2004.



Signature				Title or Capacity


/s/ I. JON BRUMLEY I. Jon Brumley				Chairman of the Board, Chief Executive Officer, and Director (Principal Executive Officer)

/s/ JON S. BRUMLEY Jon S. Brumley				President and Director

/s/ ROY W. JAGEMAN Roy W. Jageman				Chief Financial Officer, Treasurer, Executive Vice President and Corporate Secretary (Principal Financial Officer)

/s/ ROBERT C. REEVES Robert C. Reeves				Vice President, Controller and Assistant Corporate Secretary (Principal Accounting Officer)

/s/ ARNOLD L. CHAVKIN Arnold L. Chavkin				Director

/s/ HOWARD H. NEWMAN Howard H. Newman				Director



Signature				Title or Capacity


/s/ TED A. GARDNER Ted A. Gardner				Director

/s/ TED COLLINS, JR. Ted Collins, Jr.				Director

/s/ JAMES A. WINNE, III James A. Winne, III				Director

85 EX-10.5 3 d12839exv10w5.txt FIRST AMENDMENT TO CREDIT AGREEMENT EXHIBIT 10.5 FIRST AMENDMENT TO CREDIT AGREEMENT This First Amendment to Credit Agreement (this "FIRST AMENDMENT") is executed as of October 31, 2002 (the "EFFECTIVE DATE"), by and among Encore Acquisition Company, a Delaware corporation ("BORROWER"), Encore Operating, L.P., a Texas limited partnership ("OPERATING"), Fleet National Bank, a national banking association, as Administrative Agent ("ADMINISTRATIVE AGENT"), and the financial institutions a party hereto as Banks ("BANKS"). WITNESSETH: WHEREAS, Borrower, Operating, Administrative Agent, the other Agents a party thereto and Banks are parties to that certain Credit Agreement dated as of June 25, 2002 (the "CREDIT AGREEMENT") (unless otherwise defined herein, all terms used herein with their initial letter capitalized shall have the meaning given such terms in the Credit Agreement); and WHEREAS, pursuant to the Credit Agreement, Banks have made a revolving credit loan to Borrower; and WHEREAS, Borrower and Operating have requested that Banks (a) amend certain terms of the Credit Agreement in certain respects, and (b) reaffirm the Borrowing Base of $220,000,000 to be effective as of December 1, 2002 and continuing until the first Redetermination thereafter; and WHEREAS, subject to the terms and conditions set forth herein, Banks have agreed to Borrower's and Operating's requests. NOW THEREFORE, for and in consideration of the mutual covenants and agreements herein contained and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged and confessed, Borrower, Operating, Administrative Agent and each Bank hereby agree as follows: SECTION 1. AMENDMENTS. In reliance on the representations, warranties, covenants and agreements contained in this First Amendment, and subject to the satisfaction of the conditions precedent set forth in Section 3 hereof, the Credit Agreement is hereby amended effective as of the Effective Date in the manner provided in this Section 1. 1.1. AMENDMENT TO DEFINITIONS. The definitions of "LOAN PAPERS" and "PERMITTED ENCUMBRANCES" contained in Section 1.1 of the Credit Agreement shall be amended to read in full as follows: "LOAN PAPERS" means this Agreement, the First Amendment, the Notes, the Mortgages, each Borrower Pledge Agreement, each Subsidiary Pledge Agreement, each Facility Guaranty, and all other certificates, documents or instruments delivered in connection with this Agreement, as the foregoing may be amended from time to time. "PERMITTED ENCUMBRANCES" means with respect to any asset: 1 (a) Liens (if any) securing the Obligations (including, without limitation, indebtedness, liabilities and obligations pursuant to any Hedge Transaction entered into by a Credit Party with any Bank or any Affiliate of any Bank); (b) minor defects in title which do not secure the payment of money and otherwise have no material adverse effect on the value or the operation of the subject property, and for the purposes of this Agreement, a minor defect in title shall include, but not be limited to, easements, zoning restrictions, rights-of-way, servitudes, permits, surface leases and other similar rights in respect of surface operations, and easements for pipelines, streets, alleys, highways, telephone lines, power lines, railways and other easements and rights-of-way, on, over or in respect of any of the properties of any Credit Party that are customarily granted in the oil and gas industry; (c) contractual or statutory Liens securing obligations for labor, services, materials and supplies furnished to Mineral Interests and Liens arising under joint operating agreements entered into in the ordinary course of business, in each case securing obligations which are not delinquent (except to the extent permitted by Section 9.7); (d) contractual or statutory mechanic's, materialmen's, warehouseman's, journeyman's and carrier's Liens and other similar Liens arising in the ordinary course of business which are not delinquent (except to the extent permitted by Section 9.7); (e) Liens for Taxes or assessments not yet due or not yet delinquent, or, if delinquent, that are not required to be paid subject to satisfaction of the conditions set forth in Section 9.7; (f) lease burdens payable to third parties which are deducted in the calculation of discounted present value in the Reserve Report including, without limitation, any royalty, overriding royalty, net profits interest, production payment, carried interest or reversionary working interest; (g) Liens encumbering assets securing Debt incurred to finance the purchase of such assets, provided, that (i) the principal amount of the Debt secured by a purchased asset shall not exceed one hundred percent (100%) of the purchase price of such asset, (ii) such Liens shall not extend to or encumber any other asset of any Credit Party, (iii) such Liens shall attach to such purchased asset substantially simultaneously with the purchase of such asset, and (iv) the aggregate amount of all Debt secured by such Liens shall not exceed $15,000,000; (h) Liens securing Hedge Transactions, including, without limitation, pledges of cash or cash equivalents, provided, that, (i) such Hedge Transactions comply with Section 10.11 to the extent applicable, and (ii) the aggregate amount of cash or cash equivalents pledged (or the fair market value of other, non-cash collateral pledged) shall not exceed $10,000,000 at any time; and (i) to the extent not included in clauses (a) through (h) above, Permitted Encumbrances under and as defined in the Mortgages. 2 1.2. DEBT COVENANT. Section 10.1 of the Credit Agreement shall be amended to read in full as follows: "Section 10.1 INCURRENCE OF DEBT. Borrower and Operating will not, nor will Borrower and/or Operating permit any other Credit Party to, incur, become or remain liable for any Debt other than (a) the Obligations (including, without limitation, Debt pursuant to any Hedge Transaction entered into by a Credit Party with a Bank or any Affiliate of any Bank), (b) the Permitted Subordinate Debt, (c) other Debt under Hedge Transactions, provided, that such Hedge Transactions comply with the terms and provisions of this Agreement, including, without limitation, Section 10.11, and (d) other Debt in an aggregate amount outstanding at any time not to exceed $15,000,000." 1.3. USE OF PROCEEDS COVENANTS. Section 10.7 of the Credit Agreement shall be amended by deleting the last sentence thereof, and in lieu thereof, substituting the following sentence: "Without limiting the foregoing, no Letter of Credit will be issued hereunder for the purpose of providing credit enhancement with respect to any Debt or equity security of any Credit Party, or to secure any Credit Party's obligations with respect to Hedge Transactions other than (i) Hedge Transactions with a Bank or an Affiliate of such Bank, or (ii) Hedge Transactions with a counterparty other than a Bank or an Affiliate of a Bank provided that such Hedge Transactions otherwise comply with the terms and provisions of this Agreement, including, without limitation, Section 10.1 and Section 10.11. SECTION 2. BORROWING BASE. The Borrowing Base shall continue to be $220,000,000 from December 1, 2002 and continuing until the first Redetermination thereafter. Borrower, Operating and Banks agree that the Redetermination provided for in this Section 2 (a) shall be deemed to be the Scheduled Redetermination to occur on December 1, 2002 pursuant to Section 5.2 of the Credit Agreement, and (b) shall not be construed or deemed to be a Special Redetermination for purposes of Section 5.3 of the Credit Agreement. SECTION 3. CONDITIONS PRECEDENT. The effectiveness of the amendments to the Credit Agreement contained in Section 1 hereof is subject to the satisfaction of each of the following conditions precedent: 3.1. NO DEFAULT. No Default or Event of Default shall have occurred which is continuing. 3.2. FEES. Borrower shall have paid to Administrative Agent any fees payable to Administrative Agent or any Affiliate of Administrative Agent pursuant to this First Amendment and any separate agreement among Borrower, Operating, Administrative Agent or any Affiliate of Administrative Agent in consideration for providing services in connection with the credit facilities provided by the Credit Agreement. 3.3. OTHER DOCUMENTS. Administrative Agent shall have been provided with such other documents, instruments and agreements, and Borrower and Operating shall have taken such actions, as Administrative Agent may reasonably require in connection with this First Amendment and the transactions contemplated hereby. 3 SECTION 4. REPRESENTATIONS AND WARRANTIES OF BORROWER AND OPERATING. TO induce Banks and Administrative Agent to enter into this First Amendment, Borrower and Operating hereby jointly and severally represent and warrant to Banks and Administrative Agent as follows: 4.1. REAFFIRM EXISTING REPRESENTATIONS AND WARRANTIES. Each representation and warranty of each Credit Party contained in the Credit Agreement and the other Loan Papers is true and correct on the date hereof and will be true and correct after giving effect to the amendments set forth in Section 1 hereof. 4.2. DUE AUTHORIZATION; NO CONFLICT. The execution, delivery and performance by Borrower and Operating of this First Amendment are within Borrower's and Operating's corporate and partnership powers (as applicable), have been duly authorized by all necessary action, require no action by or in respect of, or filing with, any governmental body, agency or official and do not violate or constitute a default under any provision of applicable law or any Material Agreement binding upon Borrower, Operating or any other Credit Party or result in the creation or imposition of any Lien upon any of the assets of any Credit Party except Permitted Encumbrances. 4.3. VALIDITY AND ENFORCEABILITY; EXTENSION OF LIENS. This First Amendment constitutes the valid and binding obligation of Borrower and Operating enforceable in accordance with its terms, except as (i) the enforceability thereof may be limited by bankruptcy, insolvency or similar laws affecting creditor's rights generally, and (ii) the availability of equitable remedies may be limited by equitable principles of general application. 4.4. NO DEFAULT OR EVENT OF DEFAULT. No Default or Event of Default has occurred which is continuing. SECTION 5. MISCELLANEOUS. 5.1. REAFFIRMATION OF LOAN PAPERS. Any and all of the terms and provisions of the Credit Agreement and the Loan Papers shall, except as amended and modified hereby, remain in full force and effect. The amendments contemplated hereby shall not limit or impair any Liens securing the Obligations, each of which are hereby ratified, affirmed and extended to secure the Obligations as they may be modified pursuant hereto. 5.2. PARTIES IN INTEREST. All of the terms and provisions of this First Amendment shall bind and inure to the benefit of the parties hereto and their respective successors and assigns. 5.3. LEGAL EXPENSES. Borrower hereby agrees to pay on demand all reasonable fees and expenses of counsel to Administrative Agent incurred by Administrative Agent in connection with the preparation, negotiation and execution of this First Amendment and all related documents. 5.4. COUNTERPARTS. This First Amendment may be executed in counterparts, and all parties need not execute the same counterpart; however, no party shall be bound by this First Amendment until Borrower, Operating and Required Banks have executed a counterpart. Facsimiles shall be effective as originals. 4 5.5. COMPLETE AGREEMENT. THIS FIRST AMENDMENT, THE CREDIT AGREEMENT AND THE OTHER LOAN PAPERS REPRESENT THE FINAL AGREEMENT AMONG THE PARTIES AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS OR ORAL AGREEMENTS OF THE PARTIES. THERE ARE NO UNWRITTEN ORAL AGREEMENTS BETWEEN OR AMONG THE PARTIES. 5.6. HEADINGS. The headings, captions and arrangements used in this First Amendment are, unless specified otherwise, for convenience only and shall not be deemed to limit, amplify or modify the terms of this First Amendment, nor affect the meaning thereof. 5.7. EFFECTIVENESS. This First Amendment shall be effective automatically and without necessity of any further action by Borrower, Operating, Administrative Agent or Banks when counterparts hereof have been executed by Borrower, Operating and Required Banks, and all conditions to the effectiveness hereof set forth herein have been satisfied. IN WITNESS WHEREOF, the parties hereto have caused this First Amendment to be duly executed by their respective Authorized Officers on the date and year first above written. [Signature pages to follow] 5 SIGNATURE PAGE TO FIRST AMENDMENT TO CREDIT AGREEMENT BY AND AMONG ENCORE ACQUISITION COMPANY, ENCORE OPERATING, L.P., FLEET NATIONAL BANK, AS ADMINISTRATIVE AGENT, AND THE BANKS A PARTY THERETO BORROWER: ENCORE ACQUISITION COMPANY, a Delaware corporation By: /s/ MORRIS B SMITH -------------------------------- Name: MORRIS B SMITH Title: EJP - CFO OPERATING: ENCORE OPERATING, L.P., a Texas limited partnership By: EAP Operating, Inc., a Delaware corporation, its sole general partner By: /s/ MORRIS B SMITH ----------------------------------- Name: MORRIS B SMITH Title: EJP - CFO [Signature Page] SIGNATURE PAGE TO FIRST AMENDMENT TO AMENDED AND RESTATED CREDIT AGREEMENT BY AND AMONG HYPERION ENERGY, LP, FLEET NATIONAL BANK, AS ADMINISTRATIVE AGENT, AND THE BANKS A PARTY THERETO ADMINISTRATIVE AGENT: FLEET NATIONAL BANK, as Administrative Agent By: /s/ Jeffrey H. Rathkamp ------------------------------- Jeffrey H. Rathkamp, Vice President BANKS: FLEET NATIONAL BANK, as a Bank BY: /s/ Jeffrey H. Rathkamp ------------------------------------ Jeffrey H. Rathkamp, Vice President [Signature Page] SIGNATURE PAGE TO FIRST AMENDMENT TO CREDIT AGREEMENT BY AND AMONG ENCORE ACQUISITION COMPANY, ENCORE OPERATING, L.P., FLEET NATIONAL BANK, AS ADMINISTRATIVE AGENT, AND THE BANKS A PARTY THERETO BANK: WACHOVIA BANK, N.A. By: /s/ David E. Humphreys ------------------------------- Name: David E. Humphreys Title: Vice President [Signature Page] SIGNATURE PAGE TO FIRST AMENDMENT TO CREDIT AGREEMENT BY AND AMONG ENCORE ACQUISITION COMPANY, ENCORE OPERATING, L.P., FLEET NATIONAL BANK, AS ADMINISTRATIVE AGENT, AND THE BANKS A PARTY THERETO BANK: FORTIS CAPITAL CORP. BY: /s/ David Montgomery ----------------------------------- NAME: David Montgomery Title: Senior Vice President By /s/ Darrell W. Holley --------------------------------------- Name: Darrell W. Holley Title: Managing Director [Signature Page] SIGNATURE PAGE TO FIRST AMENDMENT TO CREDIT AGREEMENT BY AND AMONG ENCORE ACQUISITION COMPANY, ENCORE OPERATING, L.P., FLEET NATIONAL BANK, AS ADMINISTRATIVE AGENT, AND THE BANKS A PARTY THERETO BANK: BNP PARIBAS By: /s/ David Dodd ---------------------------- Name: David Dodd Title: Director By: /s/ Betsy Jocher ------------------------------- Name: Betsy Jocher TITLE: Vice President [Signature Page] SIGNATURE PAGE TO FIRST AMENDMENT TO CREDIT AGREEMENT BY AND AMONG ENCORE ACQUISITION COMPANY, ENCORE OPERATING, L.P., FLEET NATIONAL BANK, AS ADMINISTRATIVE AGENT, AND THE BANKS A PARTY THERETO BANK: CREDIT SUISSE FIRST BOSTON, CAYMAN ISLANDS BRANCH By: /s/ James P. Moran ----------------------------------- Name: JAMES P. MORAN Title: DIRECTOR By: /s/ Ian W. Nalitt ------------------------------------- Name: IAN W. NALITT Title: ASSOCIATE [Signature Page] SIGNATURE PAGE TO FIRST AMENDMENT TO CREDIT AGREEMENT BY AND AMONG ENCORE ACQUISITION COMPANY, ENCORE OPERATING, L.P., FLEET NATIONAL BANK, AS ADMINISTRATIVE AGENT, AND THE BANKS A PARTY THERETO BANK: THE FROST NATIONAL BANK By: /s/ John S. Warren ------------------------------------ Name: John S. Warren TITLE: Senior Vice President [Signature Page] SIGNATURE PAGE TO FIRST AMENDMENT TO CREDIT AGREEMENT BY AND AMONG ENCORE ACQUISITION COMPANY, ENCORE OPERATING, L.P., FLEET NATIONAL BANK, AS ADMINISTRATIVE AGENT, AND THE BANKS A PARTY THERETO BANK: UNION BANK OF CALIFORNIA, N.A. By: /s/ Gary Shekerjian ------------------------------ Name: Gary Shekerjian Title: Vice President [Signature Page] SIGNATURE PAGE TO FIRST AMENDMENT TO CREDIT AGREEMENT BY AND AMONG ENCORE ACQUISITION COMPANY, ENCORE OPERATING, L.P., FLEET NATIONAL BANK, AS ADMINISTRATIVE AGENT, AND THE BANKS A PARTY THERETO BANK: COMERICA BANK - TEXAS By: /s/ Michele Jones ---------------------------------- Name: Michele Jones Title: Vice President [Signature Page] SIGNATURE PAGE TO FIRST AMENDMENT TO CREDIT AGREEMENT BY AND AMONG ENCORE ACQUISITION COMPANY, ENCORE OPERATING, L.P., FLEET NATIONAL BANK, AS ADMINISTRATIVE AGENT, AND THE BANKS A PARTY THERETO BANK: COMPASS BANK By: /s/ Dorothy Marchand ------------------------------ Name: Dorothy Marchand Title: Senior Vice President [Signature Page] SIGNATURE PAGE TO FIRST AMENDMENT TO CREDIT AGREEMENT BY AND AMONG ENCORE ACQUISITION COMPANY, ENCORE OPERATING, L.P., FLEET NATIONAL BANK, AS ADMINISTRATIVE AGENT, AND THE BANKS A PARTY THERETO BANK: SUNTRUST BANK By: /s/ Ilene S. Fowler ---------------------------- Name: Ilene S. Fowler Title: Director [Signature Page] SIGNATURE PAGE TO FIRST AMENDMENT TO CREDIT AGREEMENT BY AND AMONG ENCORE ACQUISITION COMPANY, ENCORE OPERATING, L.P., FLEET NATIONAL BANK, AS ADMINISTRATIVE AGENT, AND THE BANKS A PARTY THERETO BANK: RZB FINANCE LLC By: /s/ Pearl Geffers --------------------------------- Name: PEARL GEFFERS Title: FIRST VICE PRESIDENT By: /s/ John A. Valiska ---------------------------------- Name: John A. Valiska Title: Group Vice President [Signature Page] SIGNATURE PAGE TO FIRST AMENDMENT TO CREDIT AGREEMENT BY AND AMONG ENCORE ACQUISITION COMPANY, ENCORE OPERATING, L.P., FLEET NATIONAL BANK, AS ADMINISTRATIVE AGENT, AND THE BANKS A PARTY THERETO BANK: BANK OF SCOTLAND By: /s/ Joseph Fratus ---------------------------------- Name: JOSEPH FRATUS TITLE: FIRST VICE PRESIDENT [Signature Page] EX-10.6 4 d12839exv10w6.txt SECOND AMENDMENT TO CREDIT AGREEMENT EXHIBIT 10.6 SECOND AMENDMENT TO CREDIT AGREEMENT This Second Amendment to Credit Agreement (this "SECOND AMENDMENT") is executed as of October 21, 2003 (the "EFFECTIVE DATE"), by and among Encore Acquisition Company, a Delaware corporation ("BORROWER"). Encore Operating, L.P., a Texas limited partnership ("OPERATING"). Fleet National Bank, a national banking association, as Administrative Agent ("ADMINISTRATIVE AGENT"), and the financial institutions a party hereto as Banks ("BANKS"). W I T N E S S E T H: WHEREAS, Borrower, Operating, Administrative Agent, the other Agents a party thereto and Banks are parties to that certain Credit Agreement dated as of June 25, 2002 (as amended, the "CREDIT AGREEMENT") (unless otherwise defined herein, all terms used herein with their initial letter capitalized shall have the meaning given such terms in the Credit Agreement); and WHEREAS, pursuant to the Credit Agreement, Banks have made a revolving credit loan to Borrower; and WHEREAS, Borrower and Operating have requested that Banks (a) amend certain terms of the Credit Agreement in certain respects, and (b) increase the Borrowing Base to $270,000,000 to be effective as of December 1, 2003 and continuing until the first Redetermination thereafter; and WHEREAS, subject to the terms and conditions set forth herein, Banks have agreed to Borrower's and Operating's requests. NOW THEREFORE, for and in consideration of the mutual covenants and agreements herein contained and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged and confessed, Borrower, Operating, Administrative Agent and each Bank hereby agree as follows: SECTION 1. AMENDMENTS. In reliance on the representations, warranties, covenants and agreements contained in this Second Amendment, and subject to the satisfaction of the conditions precedent set forth in Section 3 hereof, the Credit Agreement is hereby amended effective as of the Effective Date in the manner provided in this Section 1. 1.1. AMENDMENT TO DEFINITIONS. The definitions of "LOAN PAPERS" and "PERMITTED ENCUMBRANCES" contained in Section 1.1 of the Credit Agreement shall be amended to read in full as follows: "LOAN PAPERS" means this Agreement, the First Amendment, the Second Amendment, the Notes, the Mortgages, each Borrower Pledge Agreement, each Subsidiary Pledge Agreement, each Facility Guaranty, and all other certificates, documents or instruments delivered in connection with this Agreement, as the foregoing may be amended from time to time. 1 "PERMITTED ENCUMBRANCES" means with respect to any asset: (a) Liens (if any) securing the Obligations (including, without limitation, indebtedness, liabilities and obligations pursuant to any Hedge Transaction entered into by a Credit Party with any Bank or any Affiliate of any Bank); (b) minor defects in title which do not secure the payment of money and otherwise have no material adverse effect on the value or the operation of the subject property, and for the purposes of this Agreement, a minor defect in title shall include, but not be limited to, easements, zoning restrictions, rights-of-way, servitudes, permits, surface leases and other similar rights in respect of surface operations, and easements for pipelines, streets, alleys, highways, telephone lines, power lines, railways and other easements and rights-of-way, on, over or in respect of any of the properties of any Credit Party that are customarily granted in the oil and gas industry; (c) contractual or statutory Liens securing obligations for labor, services, materials and supplies furnished to Mineral Interests and Liens arising under joint operating agreements entered into in the ordinary course of business, in each case securing obligations which are not delinquent (except to the extent permitted by Section 9.7); (d) contractual or statutory mechanic's, materialmen's, warehouseman's, journeyman's and carrier's Liens and other similar Liens arising in the ordinary course of business which are not delinquent (except to the extent permitted by Section 9.7); (e) Liens for Taxes or assessments not yet due or not yet delinquent, or, if delinquent, that are not required to be paid subject to satisfaction of the conditions set forth in Section 9.7; (f) lease burdens payable to third parties which are deducted in the calculation of discounted present value in the Reserve Report including, without limitation, any royalty, overriding royalty, net profits interest, production payment, carried interest or reversionary working interest; (g) Liens encumbering assets securing Debt incurred to finance the purchase of such assets, provided, that (i) the principal amount of the Debt secured by a purchased asset shall not exceed one hundred percent (100%) of the purchase price of such asset, (ii) such Liens shall not extend to or encumber any other asset of any Credit Party, (iii) such Liens shall attach to such purchased asset substantially simultaneously with the purchase of such asset, and (iv) the aggregate amount of all Debt secured by such Liens shall not exceed $15,000,000; (h) Liens securing Hedge Transactions, including, without limitation, pledges of cash or cash equivalents, provided, that, (i) such Hedge Transactions comply with Section 10.11 to the extent applicable, and (ii) the aggregate amount of cash or cash equivalents pledged (or the fair market value of other, non-cash collateral pledged) shall not exceed $15,000,000 at any time; and 2 (i) to the extent not included in clauses (a) through (h) above, Permitted Encumbrances under and as defined in the Mortgages. SECTION 2. BORROWING BASE. The Borrowing Base shall be $270,000,000 effective December 1, 2003 and continuing until the first Redetermination thereafter. Borrower, Operating and Banks agree that the Redetermination provided for in this Section 2 (a) shall be deemed to be the Scheduled Redetermination to occur on December 1, 2003 pursuant to Section 5.2 of the Credit Agreement, and (b) shall not be construed or deemed to be a Special Redetermination for purposes of Section 5.3 of the Credit Agreement. SECTION 3. CONDITIONS PRECEDENT. The effectiveness of the amendments to the Credit Agreement contained in Section 1 hereof is subject to the satisfaction of each of the following conditions precedent: 3.1. NO DEFAULT. No Default or Event of Default shall have occurred which is continuing. 3.2. BORROWING BASE INCREASE FEE. Borrower shall have paid to Administrative Agent, for the ratable benefit of each Bank, a borrowing base increase fee in an amount equal to one-quarter of one percent (0.250%) of the amount of the increase in the Borrowing Base as reflected in Section 2 hereof. 3.3. OTHER FEES. Borrower shall have paid to Administrative Agent any fees payable to Administrative Agent or any Affiliate of Administrative Agent pursuant to this Second Amendment and any separate agreement among Borrower, Operating, Administrative Agent or any Affiliate of Administrative Agent in consideration for providing services in connection with the credit facilities provided by the Credit Agreement. 3.4. OTHER DOCUMENTS. Administrative Agent shall have been provided with such other documents, instruments and agreements, and Borrower and Operating shall have taken such actions, as Administrative Agent may reasonably require in connection with this Second Amendment and the transactions contemplated hereby. SECTION 4. REPRESENTATIONS AND WARRANTIES OF BORROWER AND OPERATING. To induce Banks and Administrative Agent to enter into this Second Amendment, Borrower and Operating hereby jointly and severally represent and warrant to Banks and Administrative Agent as follows: 4.1. REAFFIRM EXISTING REPRESENTATIONS AND WARRANTIES. Each representation and warranty of each Credit Party contained in the Credit Agreement and the other Loan Papers is true and correct on the date hereof and will be true and correct after giving effect to the amendments set forth in Section 1 hereof. 4.2. DUE AUTHORIZATION; NO CONFLICT. The execution, delivery and performance by Borrower and Operating of this Second Amendment are within Borrower's and Operating's corporate and partnership powers (as applicable), have been duly authorized by all necessary action, require no action by or in respect of, or filing with, any governmental body, agency or official and do not violate or constitute a default under any provision of applicable law or any Material Agreement binding upon Borrower, Operating or any other Credit Party or result in the 3 creation or imposition of any Lien upon any of the assets of any Credit Party except Permitted Encumbrances. 4.3. VALIDITY AND ENFORCEABILITY; EXTENSION OF LIENS. This Second Amendment constitutes the valid and binding obligation of Borrower and Operating enforceable in accordance with its terms, except as (i) the enforceability thereof may be limited by bankruptcy, insolvency or similar laws affecting creditor's rights generally, and (ii) the availability of equitable remedies may be limited by equitable principles of general application. 4.4. NO DEFAULT OR EVENT OF DEFAULT. No Default or Event of Default has occurred which is continuing. SECTION 5. MISCELLANEOUS. 5.1. REAFFIRMATION OF LOAN PAPERS. Any and all of the terms and provisions of the Credit Agreement and the Loan Papers shall, except as amended and modified hereby, remain in full force and effect. The amendments contemplated hereby shall not limit or impair any Liens securing the Obligations, each of which are hereby ratified, affirmed and extended to secure the Obligations as they may be modified pursuant hereto. 5.2. PARTIES IN INTEREST. All of the terms and provisions of this Second Amendment shall bind and inure to the benefit of the parties hereto and their respective successors and assigns. 5.3. LEGAL EXPENSES. Borrower hereby agrees to pay on demand all reasonable fees and expenses of counsel to Administrative Agent incurred by Administrative Agent in connection with the preparation, negotiation and execution of this Second Amendment and all related documents. 5.4. COUNTERPARTS. This Second Amendment may be executed in counterparts, and all parties need not execute the same counterpart; however, no party shall be bound by this Second Amendment until Borrower, Operating and Required Banks have executed a counterpart. Facsimiles shall be effective as originals. 5.5. COMPLETE AGREEMENT. THIS SECOND AMENDMENT, THE CREDIT AGREEMENT AND THE OTHER LOAN PAPERS REPRESENT THE FINAL AGREEMENT AMONG THE PARTIES AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS OR ORAL AGREEMENTS OF THE PARTIES. THERE ARE NO UNWRITTEN ORAL AGREEMENTS BETWEEN OR AMONG THE PARTIES. 5.6. HEADINGS. The headings, captions and arrangements used in this Second Amendment are, unless specified otherwise, for convenience only and shall not be deemed to limit, amplify or modify the terms of this Second Amendment, nor affect the meaning thereof. 5.7. EFFECTIVENESS. This Second Amendment shall be effective automatically and without necessity of any further action by Borrower, Operating, Administrative Agent or Banks when counterparts hereof have been executed by Borrower, Operating and Required Banks, and all conditions to the effectiveness hereof set forth herein have been satisfied. 4 IN WITNESS WHEREOF, the parties hereto have caused this Second Amendment to be duly executed by their respective Authorized Officers on the date and year first above written. [Signature pages to follow] 5 SIGNATURE PAGE TO SECOND AMENDMENT TO CREDIT AGREEMENT BY AND AMONG ENCORE ACQUISITION COMPANY, ENCORE OPERATING, L.P., FLEET NATIONAL BANK, AS ADMINISTRATIVE AGENT, AND THE BANKS A PARTY THERETO BORROWER: ENCORE ACQUISITION COMPANY, a Delaware corporation By: [ILLEGIBLE] Name: [ILLEGIBLE] Title: ASSISTANT TREASURER OPERATING: ENCORE OPERATING, L.P., a Texas limited partnership BY: EAP Operating, Inc., a Delaware corporation, its sole general partner By: [ILLEGIBLE] Name: [ILLEGIBLE] Title: ASSISTANT TREASURER [Signature Page] SIGNATURE PAGE TO SECOND AMENDMENT TO CREDIT AGREEMENT BY AND AMONG ENCORE ACQUISITION COMPANY, ENCORE OPERATING, L.P., FLEET NATIONAL BANK, AS ADMINISTRATIVE AGENT, AND THE BANKS A PARTY THERETO ADMINISTRATIVE AGENT: FLEET NATIONAL BANK, as Administrative Agent By: [ILLEGIBLE] [ILLEGIBLE] Director BANK: FLEET NATIONAL BANK, as a Bank By: [ILLEGIBLE] [ILLEGIBLE] Director [Signature Page] SIGNATURE PAGE TO SECOND AMENDMENT TO CREDIT AGREEMENT BY AND AMONG ENCORE ACQUISITION COMPANY, ENCORE OPERATING, L.P., FLEET NATIONAL BANK, AS ADMINISTRATIVE AGENT, AND THE BANKS A PARTY THERETO BANK: WACHOVIA BANK, N.A. By: /s/ David Humphreys --------------------------- Name: David Humphreys Title: Vice President [Signature Page] SIGNATURE PAGE TO SECOND AMENDMENT TO CREDIT AGREEMENT BY AND AMONG ENCORE ACQUISITION COMPANY, ENCORE OPERATING, L.P., FLEET NATIONAL BANK, AS ADMINISTRATIVE AGENT, AND THE BANKS A PARTY THERETO BANK: FORTIS CAPITAL CORP. By: /s/ David Montgomery -------------------- Name: DAVID MONTGOMERY Title: SENIOR VICE PRESIDENT By: /s/ Darrell W. Holley --------------------- Name: DARRELL W. HOLLEY Title: MANAGING DIRECTOR [Signature Page] SIGNATURE PAGE TO SECOND AMENDMENT TO CREDIT AGREEMENT BY AND AMONG ENCORE ACQUISITION COMPANY, ENCORE OPERATING, L.P., FLEET NATIONAL BANK, AS ADMINISTRATIVE AGENT, AND THE BANKS A PARTY THERETO BANK: BNP PARIBAS By: /s/ David Dodd --------------------- Name DAVID DODD Title: DIRECTOR By: /s/ Polly Schott -------------------- Name POLLY SCHOTT Title: VICE PRESIDENT [Signature Page] SIGNATURE PAGE TO SECOND AMENDMENT TO CREDIT AGREEMENT BY AND AMONG ENCORE ACQUISITION COMPANY, ENCORE OPERATING, L.P., FLEET NATIONAL BANK, AS ADMINISTRATIVE AGENT, AND THE BANKS A PARTY THERETO BANK: CREDIT SUISSE FIRST BOSTON, acting through its CAYMAN ISLANDS BRANCH By: /s/ James P. Moran ------------------ Name: JAMES P. MORAN Title: DIRECTOR By: /s/ David J. Dodd ------------------ Name: DAVID J. DODD Title: ASSOCIATE [Signature Page] SIGNATURE PAGE TO SECOND AMENDMENT TO CREDIT AGREEMENT BY AND AMONG ENCORE ACQUISITION COMPANY, ENCORE OPERATING, L.P., FLEET NATIONAL BANK, AS ADMINISTRATIVE AGENT, AND THE BANKS A PARTY THERETO BANK: THE FROST NATIONAL BANK By: /s/ John s. Warren ------------------- Name: JOHN S. WARREN Title: SENIOR VICE PRESIDENT [Signature Page] SIGNATURE PAGE TO SECOND AMENDMENT TO CREDIT AGREEMENT BY AND AMONG ENCORE ACQUISITION COMPANY, ENCORE OPERATING, L.P., FLEET NATIONAL BANK, AS ADMINISTRATIVE AGENT, AND THE BANKS A PARTY THERETO BANK: COMMERCIAL BANK By: [ILLEGIBLE] Name: [ILLEGIBLE] Title: VICE PRESIDENT [Signature Page] SIGNATURE PAGE TO SECOND AMENDMENT TO CREDIT AGREEMENT BY AND AMONG ENCORE ACQUISITION COMPANY, ENCORE OPERATING, L.P., FLEET NATIONAL BANK, AS ADMINISTRATIVE AGENT, AND THE BANKS A PARTY THERETO BANK: UNION BANK OF CALIFORNIA N.A. By: [ILLEGIBLE] Name: [ILLEGIBLE] Title: AVP [Signature Page] SIGNATURE PAGE TO SECOND AMENDMENT TO CREDIT AGREEMENT BY AND AMONG ENCORE ACQUISITION COMPANY, ENCORE OPERATING, L.P., FLEET NATIONAL BANK, AS ADMINISTRATIVE AGENT, AND THE BANKS A PARTY THERETO BANK: CREDIT LYONNAIS NEW YORK BRANCH By: [ILLEGIBLE] Name: [ILLEGIBLE] Title: SENIOR VICE PRESIDENT [Signature Page] SIGNATURE PAGE TO SECOND AMENDMENT TO CREDIT AGREEMENT BY AND AMONG ENCORE ACQUISITION COMPANY, ENCORE OPERATING, L.P., FLEET NATIONAL BANK, AS ADMINISTRATIVE AGENT, AND THE BANKS A PARTY THERETO BANK: COMPASS BANK By: [ILLEGIBLE] Name: [ILLEGIBLE] Title: SENIOR VICE PRESIDENT [Signature Page] SIGNATURE PAGE TO SECOND AMENDMENT TO CREDIT AGREEMENT BY AND AMONG ENCORE ACQUISITION COMPANY, ENCORE OPERATING, L.P., FLEET NATIONAL BANK, AS ADMINISTRATIVE AGENT, AND THE BANKS A PARTY THERETO BANK: SUNTRUST BANK By: /s/ JAMES M. WARREN ------------------- Name: JAMES M. WARREN Title: DIRECTOR [Signature Page] SIGNATURE PAGE TO SECOND AMENDMENT TO CREDIT AGREEMENT BY AND AMONG ENCORE ACQUISITION COMPANY, ENCORE OPERATING, L.P., FLEET NATIONAL BANK, AS ADMINISTRATIVE AGENT, AND THE BANKS A PARTY THERETO BANK: RZB FINANCE LLC By: [ILLEGIBLE] Name: [ILLEGIBLE] Title: VICE PRESIDENT By: [ILLEGIBLE] Name: [ILLEGIBLE] Title: ASSISTANT VICE PRESIDENT [Signature Page] SIGNATURE PAGE TO SECOND AMENDMENT TO CREDIT AGREEMENT BY AND AMONG ENCORE ACQUISITION COMPANY, ENCORE OPERATING, L.P., FLEET NATIONAL BANK, AS ADMINISTRATIVE AGENT, AND THE BANKS A PARTY THERETO BANK: BANK OF SCOTLAND By: [ILLEGIBLE] Name: [ILLEGIBLE] Title: FIRST VICE PRESIDENT [Signature Page] EX-10.8 5 d12839exv10w8.txt SEVERANCE AGREEMENT WITH MORRIS B. SMITH EXHIBIT 10.8 SEVERANCE AGREEMENT THIS SEVERANCE AGREEMENT ("Agreement") is made and effective as of the 18th day of December, 2003 (the "Effective Date"), by and between ENCORE ACQUISITION COMPANY, a Delaware corporation (the "Company"), and MORRIS B. SMITH ("Employee"). 1. Resignation of Employment: Effective as of December 31, 2003 (the "Severance Date"), the Employee resigns his position as an employee of the Company. 2. Severance Payments: In lieu of severance under any other plan or arrangement of the Company, the Company shall pay to Employee (or his estate as applicable) a lump sum severance amount in two equal installments (the "Severance Payments"), provided that the Waiver and Release has been executed as provided in Section 12 and not revoked for a period of 7 days and Employee is otherwise in compliance with this Agreement. Each Severance Payment shall be equal to one-half of the sum of: (1) $352,500; (2) an amount equal to the product of (i) the number of shares subject to Employee's unvested options to purchase the Company's common stock and (ii) the difference between (A) the closing sales price of a share of the Company's common stock, as reported on the New York Stock Exchange Composite Transactions on the Severance Date, and (B) the weighted average exercise price of such unvested options; and (3) an amount equal to the product of (i) one-third of the number of Employee's restricted shares of the Company's common stock held by Employee, rounded to the nearest share, and (ii) the closing sales price of a share of the Company's common stock, as reported on the New York Stock Exchange Composite Transactions on the Severance Date. The first Severance Payment will be paid within 30 days following the Severance Date, and the second Severance Payment will be payable within 30 days following June 30, 2004. The parties agree that the unvested options and restricted shares which are the subject of this obligation are listed on Exhibit A attached hereto, and that except for the payment obligations described above, such options and restricted shares shall be forfeited as of the Severance Date. 3. Confidentiality and Noncompetition: (a) The Company has, and until the Severance Date will, provide Employee with Confidential Information regarding the Company and the Company's business. In return for this and other consideration provided under this Agreement, Employee agrees he will not disclose or make available to any other person or entity, or use for his own personal gain, any Confidential Information, except for such disclosures as required in the performance of his duties hereunder or as required pursuant to any law or governmental regulation or ruling. For purposes of this Agreement, "Confidential Information" shall mean any and all information, data and knowledge that has been created, discovered, developed or otherwise become known to the Company or any of its affiliates or ventures or in which property rights have been assigned or otherwise conveyed to the Company or any of its affiliates or ventures, which information, data or knowledge has commercial value in the business in which the Company is engaged, except such information, data or knowledge as is or becomes known to the public without violation of the terms of this Agreement. By way of illustration, but not limitation, Confidential Information includes trade secrets, acquisition, exploration, development, exploitation and production prospects and strategies for oil and natural gas reserves, processes, formulas, know-how, improvements, discoveries, developments, designs, inventions, techniques, marketing plans, manuals, records of research, reports, memoranda, computer software, strategies, forecasts, new products, unpublished financial statements or parts thereof, budgets or other financial information, projections, licenses, prices, costs, and employee, customer and supplier lists or parts thereof (b) Employee recognizes that in each of the highly competitive businesses in which the Company is engaged, the Company's trade secrets and other Confidential Information, along with personal contacts, are of primary importance in (i) identifying, acquiring, exploring for, developing, exploiting and producing oil and natural gas reserves, and (ii) retaining the accounts and goodwill of present customers and protecting the business of the Company. The Employee, therefore, agrees that until the Severance Date and (A) for a period of six months thereafter, he will not (i) acquire, for his own account or the account of any business in which he owns more than 5% of the outstanding capital stock, any oil or natural gas property in Crockett County, Texas Andrews County, Texas, Ecotr County, Texas, Claiborne Parish, Louisiana, Webster Parish, Louisiana, Bossier Parish , Louisiana, Blaine County, Montana, Carter County, Montana, Dawson County, Montana, Fallon County , Montana, Hill County, Montana, Powder River County, Montana, Prairie County, Montana, Wibaux County, Montana, Bowman County North Dakota, Stark County, North Dakota, Ward County, North Dakota or San Juan County, Utah (the "Relevant Geographic Area"), (ii) accept employment, advise, assist or render service in any way to any person that competes directly with the Company in the acquisition, exploration, development, exploitation or production of oil and natural gas in the Relevant Geographic Area or (iii) enter into or take part in or lend his name, counsel or assistance to any business, either as proprietor, principal, investor, partner, director, officer, executive, consultant, advisor, agent, independent contractor, or in any other capacity whatsoever, for any purpose that would be directly competitive with the acquisition, exploration, development, exploitation or production activities of the Company or any of its affiliated companies in the Relevant Geographic Area and (B) for a period of six months after the Severance Date he will not, on his own behalf or on behalf of any person, firm or company, directly or indirectly, solicit or offer employment to any person who has been employed by the Company or any subsidiary thereof at any time during the one-year period immediately preceding such solicitation (all of the foregoing activities are collectively referred to as the "Prohibited Activity"). The Employee shall not, directly or indirectly, make or cause to be made and shall use his best efforts to cause the officers, directors, employee, agents and representatives of any -2- entity or person controlled by the Employee not to make or cause to be made, any disparaging, denigrating, derogatory or other negative, misleading or false statement orally or in writing to any person or entity, including members of the investment community, press, and customers, competitors and advisors to the Company, about the Company, its shareholders, subsidiaries or affiliates, their respective officers or members of their boards of directors, or the business strategy or plans, policies, practices or operations of the Company, its shareholders, subsidiaries or affiliates. (c) In addition to all other remedies at law or in equity which the Company may have for breach of a provision of this Section 3 by the Employee, it is agreed that in the event of any breach or attempted or threatened breach of any such provision, the Company shall be entitled to immediately cease any payment otherwise required under Section 2 and, upon application to any court of proper jurisdiction, to a temporary restraining order or preliminary injunction (without the necessity of (i) proving irreparable harm, (ii) establishing that monetary damages are inadequate or (iii) posting any bond with respect thereto) against the Employee prohibiting such breach or attempted or threatened breach by proving only the existence of such breach or attempted or threatened breach. If the provisions of this Section 3 should ever be deemed to exceed the time, geographic or occupational limitations permitted by the applicable law, the Employee and the Company agree that such provisions shall be and are hereby reformed to the maximum time, geographic or occupational limitations permitted by the applicable law. (d) The covenants of the Employee set forth in this Section 3 are independent of and severable from every other provision of this Agreement; and the breach of any other provision of this Agreement by the Company or the breach by the Company of any other agreement between the Company and the Employee shall not affect the validity of the provisions of this Section 3 or constitute a defense of the Employee in any suit or action brought by the Company to enforce any of the provisions of this Section 3 or seek any relief for the breach thereof by Employee. (e) The Employee acknowledges, agrees and stipulates that: (i) the terms and provisions of this Agreement are reasonable and constitute an otherwise enforceable agreement to which the terms and provisions of this Section 3 are ancillary or a part of; (ii) the consideration provided by the Company under this Agreement is not illusory; and (iii) the consideration given by the Company under this Agreement, including, without limitation, the provision by the Company of Confidential Information to the Employee as contemplated by this Section 3, gives rise to the Company's interest in restraining and prohibiting the Employee from engaging in the Prohibited Activity within the Relevant Geographic Area as provided under this Section 3, and the Employee's covenant not to engage in the Prohibited Activity within the Relevant Geographic Area pursuant to this Section 3 is designed to enforce the Employee's consideration (or return promises), including, without limitation, the Employee's promise to not disclose Confidential Information under this Agreement. 4. Expenses: The Company and Employee shall each be responsible for their own costs and expenses, including, without limitation, court costs and attorneys' fees, incurred as a -3- result of any claim, action or proceeding arising out of, or challenging the validity or enforceability of, this Agreement or any provisions hereof. 5. Notices: For purposes of this Agreement, notices and all other communications provided for herein shall be in writing and shall be deemed to have been duly given when personally delivered or when mailed by United States registered or certified mail, return receipt requested, postage prepaid, addressed as follows: If to the Company: Encore Acquisition Company 777 Main Street, Suite 1400 Fort Worth, TX 76102 Attention: President If to Employee: Morris B. Smith [Address] [Address] or to such other address as either party may furnish to the other in writing in accordance herewith, except that notices of changes of address shall be effective only upon receipt. 6. Applicable Law: The validity, interpretation, construction and performance of this Agreement will be governed by and construed in accordance with the substantive laws of the State of Texas, but without giving effect to the principles of conflict of laws of such State. 7. Severability: If a court of competent jurisdiction determines that any provision of this Agreement is invalid or unenforceable, then the invalidity or unenforceability of that provision shall not affect the validity or enforceability of any other provision of this Agreement and all other provisions shall remain in full force and effect. 8. Withholding of Taxes: The Company may withhold from any benefits payable under this Agreement all federal, state, city or other taxes as may be required pursuant to any law or governmental regulation or ruling. 9. No Assignment; Successors: Employee's right to receive payments or benefits hereunder shall not be assignable or transferable, whether by pledge, creation or a security interest or otherwise, whether voluntary, involuntary, by operation of law or otherwise, other than by will or by the laws of descent or distribution, and in the event of any attempted assignment or transfer contrary to this Section 9 the Company shall have no liability to pay any amount so attempted to be assigned or transferred. This Agreement shall inure to the benefit of and be enforceable by Employee's personal or legal representatives, executors, administrators, successors, heirs, distributees, devisees and legatees. This Agreement shall be binding upon and inure to the benefit of the Company, its successors and assigns (including, without limitation, any company into or with which the Company may merge or consolidate). 10. Effect of Prior Agreements: This Agreement contains the entire understanding between the parties hereto and supersedes any prior employment agreement or severance -4- agreement between the Company or any predecessor of the Company and the Employee, except that this Agreement shall not effect or operate to reduce any benefit or compensation enuring to the Employee of a kind elsewhere provided and not expressly provided or modified in this Agreement. 11. Amendment and Waiver: This Agreement may be amended or modified only upon the written consent of the Company and the Employee. The obligations of a party and the rights of any other party under this Agreement (including, without limitation, the obligations of the Employee under Section 3) may be waived only with the written consent of such other party. 12. Release of Claims: In consideration for the compensation and other benefits provided pursuant to this Agreement, Employee agrees to execute a "Waiver and Release" in substantially the form attached hereto as Exhibit B upon his termination of employment. The Company's obligation to pay the Severance Payments pursuant to Section 2 of this Agreement are expressly conditioned on Employee's execution of this Waiver and Release without revoking it for a period of 7 days, and Employee's failure to execute and deliver (without revoking) such Waiver and Release will void the Company's remaining obligations hereunder. -5- IN WITNESS WHEREOF, the parties have caused this Agreement to be executed and delivered as of the Effective Date. ENCORE ACQUISITION COMPANY By /s/ Jon S. Brumley ----------------------------------- Jon S. Brumley President EMPLOYEE /s/ Morris B. Smith -------------------------------------- Morris B. Smith -6- EXHIBIT A Unvested Options as of December 31, 2003:
Number of Unvested Shares Exercise Price ~~March 8, 2001 Grant 20,000 $14.00 November 22, 2002 Grant 29,032 $18.60~~
Restricted Shares as of December 31, 2003: 8,035 shares. -7- EXHIBIT B FORM OF WAIVER AND RELEASE ENCORE ACQUISITION COMPANY WAIVER AND RELEASE Encore Acquisition Company has offered to pay me certain benefits (the "Benefits") under my Severance Agreement with Encore Acquisition Company, dated as of _______ __, 2003 (the "Severance Agreement"), which are in addition to any remuneration or benefits to which I am already entitled. These Benefits were offered to me in exchange for my agreement, among other things, to waive all of my claims against and release Encore Acquisition Company and its predecessors, successors and assigns (collectively referred to as the "Company"), all of the affiliates (including parents and subsidiaries) of the Company (collectively referred to as the "Affiliates") and the Company's and Affiliates' directors and officers, employees and agents, insurers, employee benefit plans and the fiduciaries and agents of said plans (collectively, with the Company and Affiliates, referred to as the "Corporate Group") from any and all claims, demands, actions, liabilities and damages arising out of or relating in any way to my employment with or separation from the Company or the Affiliates; provided, however, that this Waiver and Release shall not apply to any claim or cause of action to enforce or interpret any provision contained in the Severance Agreement. I have read this Waiver and Release and the Severance Agreement (all of which I received together and which, together, are referred to herein as the "Severance Agreement Materials") and they are incorporated herein by reference. All payments under the Severance Agreement are voluntary on the part of the Company and are not required by any legal obligation other than the Severance Agreement. I choose to accept this offer. I UNDERSTAND THAT SIGNING THIS WAIVER AND RELEASE IS AN IMPORTANT LEGAL ACT. I ACKNOWLEDGE THAT THE COMPANY HAS ADVISED ME IN WRITING TO CONSULT AN ATTORNEY BEFORE SIGNING THIS WAIVER AND RELEASE. I UNDERSTAND THAT, IN ORDER TO BE ELIGIBLE FOR BENEFITS, I MUST SIGN (AND RETURN TO JON S. BRUMLEY, PRESIDENT) THIS WAIVER AND RELEASE ON OR AFTER DECEMBER 31, 2003 AND BEFORE 5 P.M. ON JANUARY 21, 2004. I ACKNOWLEDGE THAT I HAVE BEEN GIVEN AT LEAST 21 DAYS TO CONSIDER WHETHER TO SIGN THE SEVERANCE AGREEMENT AND WHETHER TO EXECUTE THIS WAIVER AND RELEASE. In exchange for the payment to me of Benefits, which are in addition to any remuneration or benefits to which I am already entitled, I, among other things, (1) agree not to sue in any local, state and/or federal court regarding or relating in any way to my employment with or separation from the Company or the Affiliates, and (2) knowingly and voluntarily waive all claims and release the Corporate Group from any and all claims, demands, actions, liabilities, and damages, whether known or unknown, arising out of or relating in any way to my employment with or separation from the Company or the Affiliates, except to the extent that my rights are vested under the terms of employee benefit plans sponsored by the Company or the Affiliates and except with respect to such rights or claims as may arise after the date this Waiver and Release is executed. This Waiver and Release includes, but is not limited to, claims and causes of action under: Title VII of the Civil Rights Act of 1964, as amended ("Title VII"); the Age Discrimination in Employment Act of 1967, as amended, including the Older Workers Benefit Protection Act of 1990 ("ADEA"); the Civil Rights Act of 1866, as amended; the Civil Rights Act of 1991; the Americans with Disabilities Act of 1990 ("ADA"); the Energy Reorganization Act, as amended, 42 U.S.C. ss 5851; the Workers Adjustment and Retraining Notification Act of 1988; the Pregnancy Discrimination Act of 1978; the Employee Retirement Income Security Act of 1974, as amended; the Family and Medical Leave Act of 1993; the Fair Labor Standards Act; the Occupational Safety and Health Act; claims in connection with workers' compensation or "whistle blower" statutes; and/or contract, tort, defamation, slander, wrongful termination or any other state or federal regulatory, statutory or common law. Further, I -8- expressly represent that no promise or agreement which is not expressed in the Severance Agreement Materials has been made to me in executing this Waiver and Release, and that I am relying on my own judgment in executing this Waiver and Release, and that I am not relying on any statement or representation of the Company, any of the Affiliates or any other member of the Corporate Group or any of their agents. I agree that this Waiver and Release is valid, fair, adequate and reasonable, is with my full knowledge and consent, was not procured through fraud, duress or mistake and has not had the effect of misleading, misinforming or failing to inform me. I acknowledge that payment of Benefits to me by the Company is not an admission by the Company or any other member of the Corporate Group that they engaged in any wrongful or unlawful act or that the Company or any member of the Corporate Group violated any federal or state law or regulation. Should any of the provisions set forth in this Waiver and Release be determined to be invalid by a court, agency or other tribunal of competent jurisdiction, it is agreed that such determination shall not affect the enforceability of other provisions of this Waiver and Release. I acknowledge that this Waiver and Release and the other Severance Agreement Materials set forth the entire understanding and agreement between me and the Company or any other member of the Corporate Group concerning the subject matter of this Waiver and Release and supersede any prior or contemporaneous oral and/or written agreements or representations, if any, between me and the Company or any other member of the Corporate Group. I understand that for a period of 7 calendar days following the date that I sign this Waiver and Release, I may revoke my acceptance of the offer, provided that my written statement of revocation is RECEIVED on or before that seventh day by Mr. Jon S. Brumley, President, Encore Acquisition Company, 777 Main Street, Suite 1400, Fort Worth, Texas 76102, facsimile number: 817-877-1655, in which case the Waiver and Release will not become effective. In the event I revoke my acceptance of this offer, the Company shall have no obligation to provide me Benefits. I understand that failure to revoke my acceptance of the offer within 7 calendar days from the date I sign this Waiver and Release will result in this Waiver and Release being permanent and irrevocable. I acknowledge that I have read this Waiver and Release, have had an opportunity to ask questions and have it explained to me and that I understand that this Waiver and Release will have the effect of knowingly and voluntarily waiving any action I might pursue, including breach of contract, personal injury, retaliation, discrimination on the basis of race, age, sex, national origin, or disability and any other claims arising prior to the date of this Waiver and Release. By execution of this document, I do not waive or release or otherwise relinquish any legal rights I may have which are attributable to or arise out of acts, omissions, or events of the Company or any other member of the Corporate Group which occur after the date of the execution of this Waiver and Release. - --------------------------------- --------------------------------- Employee's Printed Name Company Representative - --------------------------------- --------------------------------- Employee's Signature Company's Execution Date - --------------------------------- --------------------------------- Employee's Signature Date Employee's Social Security Number -9- EX-10.9 6 d12839exv10w9.txt STOCK PURCHASE AGREEMENT EXHIBIT 10.9 STOCK PURCHASE AGREEMENT BY AND AMONG CORTEZ OIL & GAS, INC., HRM RESOURCES, INC., THE SECURITYHOLDERS OF CORTEZ OIL & GAS, INC. AND ENCORE ACQUISITION COMPANY TABLE OF CONTENTS
Page ---- ARTICLE 1 DEFINITIONS 1.1 Defined Terms...................................................................... 1 1.2 References and Titles.............................................................. 13 ARTICLE 2 THE PURCHASE 2.1 Purchase and Sale.................................................................. 14 2.2 Time and Date of Closing........................................................... 15 2.3 Closing Obligations................................................................ 15 2.4 Adjustments to Aggregate Purchase Price for Breaches of Representations and Warranties......................................................................... 16 2.5 Additional Adjustments to Preliminary Aggregate Purchase Price..................... 19 2.6 Excluded Assets.................................................................... 20 ARTICLE 3 REPRESENTATIONS AND WARRANTIES OF THE SECURITYHOLDERS 3.1 Authority.......................................................................... 21 3.2 No Violations...................................................................... 21 3.3 Consents and Approvals............................................................. 22 3.4 Ownership of Securities............................................................ 22 3.5 Brokers............................................................................ 22 ARTICLE 4 REPRESENTATIONS AND WARRANTIES OF THE COMPANY 4.1 Organization....................................................................... 22 4.2 Authority and Enforceability....................................................... 23 4.3 No Violations...................................................................... 23 4.4 Consents and Approvals............................................................. 23 4.5 Financial Statements............................................................... 23 4.6 Capital Structure.................................................................. 24 4.7 Material Agreements................................................................ 25 4.8 Investments and Indebtedness....................................................... 25 4.9 Employment Matters; Independent Contractors........................................ 26 4.10 Employee Benefit Plans............................................................. 26 4.11 Litigation......................................................................... 28 4.12 Taxes and Tax Returns.............................................................. 28
i 4.13 Title to and Sufficiency of Assets................................................. 29 4.14 Compliance with Laws and Permits................................................... 29 4.15 Proprietary Rights................................................................. 30 4.16 Environmental Matters.............................................................. 30 4.17 Insurance.......................................................................... 31 4.18 Governmental Regulation............................................................ 32 4.19 Brokers............................................................................ 32 4.20 Oil and Gas Operations............................................................. 32 4.21 Gas Imbalances..................................................................... 33 4.22 Royalties and Rentals.............................................................. 33 4.23 Payout Balances.................................................................... 33 4.24 Prepayments........................................................................ 33 4.25 Capital Expenditures............................................................... 33 4.26 Financial and Product Hedging Contracts............................................ 33 4.27 Books and Records.................................................................. 33 4.28 Reserve Report..................................................................... 34 4.29 Powers of Attorney, Authorized Signatories, Registered Agents...................... 34 4.30 Absence of Certain Changes or Events............................................... 34 4.31 Related Party Transactions......................................................... 36 ARTICLE 5 REPRESENTATIONS AND WARRANTIES OF BUYER 5.1 Organization....................................................................... 37 5.2 Authority and Enforceability....................................................... 37 5.3 No Violations...................................................................... 37 5.4 Consents and Approvals............................................................. 38 5.5 Litigation......................................................................... 38 5.6 Funding............................................................................ 38 5.7 Brokers............................................................................ 38 ARTICLE 6 COVENANTS 6.1 Conduct of Business by the Company Pending Closing................................. 38 6.2 Access to Assets, Personnel and Information........................................ 41 6.3 Environmental Studies.............................................................. 42 6.4 Third Party Consents............................................................... 42 6.5 Public Announcements; Confidentiality.............................................. 43 6.6 Notification of Certain Matters.................................................... 43 6.7 No Negotiations.................................................................... 44 6.8 Access to Information.............................................................. 44 6.9 Investigation and Agreement by Buyer; No Other Representations or Warranties....... 44 6.10 Indemnification.................................................................... 45 6.11 Indemnification of Officers and Directors.......................................... 46 6.12 Compliance with Furst Ranch Exploration Agreement.................................. 46

ii ARTICLE 7 CONDITIONS 7.1 Conditions to Each Party's Obligation.............................................. 46 7.2 Conditions to Obligation of Buyer.................................................. 47 7.3 Conditions to Obligations of the Company and the Securityholders................... 47 ARTICLE 8 TERMINATION 8.1 Termination........................................................................ 48 8.2 Effect of Termination.............................................................. 49 8.3 Return of Documentation............................................................ 49 ARTICLE 9 LIMITATIONS ON COMPETITION 9.1 Prohibited Activities.............................................................. 49 9.2 Injunctions and Restraining Orders................................................. 50 9.3 Restraint.......................................................................... 50 9.4 Severability; Reformation.......................................................... 50 9.5 Independent Covenant............................................................... 50 9.6 Materiality........................................................................ 51 ARTICLE 10 MISCELLANEOUS 10.1 Survival of Representations and Warranties......................................... 51 10.2 Amendment and Modification......................................................... 51 10.3 Notices ........................................................................... 51 10.4 Counterparts....................................................................... 52 10.5 Severability....................................................................... 53 10.6 Attorneys' Fees.................................................................... 53 10.7 Time............................................................................... 53 10.8 Parties in Interest................................................................ 53 10.9 Entire Agreement................................................................... 53 10.10 Applicable Law..................................................................... 53 10.11 Assignment......................................................................... 53 10.12 Waivers ........................................................................... 53 10.13 Confidentiality Agreement.......................................................... 54 10.14 Incorporation...................................................................... 54 10.15 Cooperation After Closing.......................................................... 54 10.16 Rules of Construction.............................................................. 54 10.17 Expenses and Obligations........................................................... 55 10.18 Release ........................................................................... 55 10.19 Appointment of Attorney-in-Fact.................................................... 56 10.20 Arbitration........................................................................ 57

iii SCHEDULE A STOCKHOLDERS SCHEDULE B OPTIONHOLDERS SCHEDULE C-1 CLOSING AGGREGATE PURCHASE PRICE CALCULATION SCHEDULE C-2 PRELIMINARY AGGREGATE PURCHASE PRICE CALCULATION EXHIBIT 2.3(a)(ii) FORM OF OPTION SURRENDER AGREEMENT EXHIBIT 2.3(a)(iii) FORM OF OPINION OF SELLER'S COUNSEL EXHIBIT 2.3(a)(vi) FORM OF TERMINATION AGREEMENT EXHIBIT 2.3(a)(xi) FORM OF RELEASE AGREEMENT iv STOCK PURCHASE AGREEMENT THIS STOCK PURCHASE AGREEMENT (this "Agreement"), dated as of March 2, 2004, is made by and among Cortez Oil & Gas, Inc., a Delaware corporation (the "Company"), the securityholders of the Company identified on Schedule A and Schedule B hereto, Encore Acquisition Company, a Delaware corporation ("Buyer"), and HRM Resources Inc., a Delaware corporation ("HRM") (solely with respect to its obligations under Sections 2.1(g), 2.6, 6.1(a)(vi) and (xvi), 6.5(b) and 6.10(b)). PRELIMINARY STATEMENTS A. The stockholders identified on Schedule A hereto (collectively, the "Stockholders"), own all of the outstanding shares of capital stock of the Company. B. The optionholders identified on Schedule B hereto (collectively, the "Optionholders" and, together with the Stockholders, the "Securityholders") hold all of the outstanding options of the Company. C. The Stockholders desire to sell to Buyer, and Buyer desires to purchase from the Stockholders, 2,914 shares (the "Shares") of common stock, par value $0.01 per share (the "Common Stock"), representing all of the issued and outstanding shares of capital stock of the Company, upon the terms and subject to the conditions set forth herein. D. The Optionholders desire to surrender, and Buyer desires for the Optionholders to surrender, options to purchase 61 shares of Common Stock (the "Options"), representing all of the issued and outstanding options to purchase capital stock of the Company, upon the terms and subject to the conditions set forth herein. E. The Company, the Securityholders and Buyer desire to make certain representations, warranties, covenants and agreements in connection with the foregoing. AGREEMENTS NOW, THEREFORE, in consideration of the representations, warranties, covenants and agreements set forth herein, and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, and upon the terms and subject to the conditions hereinafter set forth, the parties hereto, intending to be legally bound, hereby agree as follows: ARTICLE 1 DEFINITIONS 1.1 DEFINED TERMS. As used in this Agreement, each of the following terms has the meaning given in this Section 1.1 or in the Sections referred to below: "AAA" means the American Arbitration Association. "Affiliate" means, with respect to any Person, each other Person that directly or indirectly (through one or more intermediaries or otherwise) controls, is controlled by, or is under common 1 control with such Person. A Person shall be deemed to control another Person if such Person possesses, directly or indirectly, the power to direct or cause the direction of the management and policies of such other Person, whether through the ownership of voting securities, by contract or otherwise. "Aggregate Defect Threshold" has the meaning set forth in Section 2.4(b)(i). "Agreement" means this Stock Purchase Agreement, as amended, supplemented or modified from time to time. "Allocated Values" means the allocation of values for the Ownership Interests as set forth on Schedule 1.1-A of the Company Disclosure Schedule. "Applicable Laws" means all laws (including common law), statutes, rules, regulations, ordinances, judgments, orders, decrees, injunctions and writs of any Governmental Authority having jurisdiction over the business or operations of the Company and its Subsidiaries, as may be in effect on the date of this Agreement or the Closing Date. "Arbitration Notice" has the meaning specified in Section 10.20. "Bank Credit Agreement" means the Credit Agreement, dated as of December 12, 2000 between the Company, as borrower, and Fleet National Bank, as Administrative Agent (as amended and supplemented as of the date hereof). "Borrowed Funds" has the meaning set forth in Section 2.1(g). "Business Day" means any day other than (i) Saturday, Sunday or federal holiday or (ii) a day on which commercial banks in Fort Worth, Texas are authorized or required to be closed. "Buyer" has the meaning specified in the first paragraph of this Agreement. "Buyer Damages" has the meaning specified in Section 6.10(a). "Buyer Indemnitees" has the meaning specified in Section 6.10(a). "Buyer Representative" means any director, officer, employee, agent, advisor (including legal, accounting and financial advisors) or other representative of Buyer. "Capital Budget (2004)" means the capital budget of the Company and its Subsidiaries for oil and gas drilling and exploitation projects to be undertaken in calendar year 2004, a copy of which is included in Schedule 1.1-B of the Company Disclosure Schedule. "CERCLA" means the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended, or any successor statutes and any regulations promulgated thereunder. "CERCLIS" means the Comprehensive Environmental Response, Compensation and Liability Information System List. 2 "Closing" means the closing and consummation of the transactions contemplated by this Agreement. "Closing Aggregate Purchase Price" means, with respect to a Securityholder, the amount calculated as of the Closing and set forth under the caption "Closing Aggregate Purchase Price" in the Closing Aggregate Purchase Price Calculation Schedule. "Closing Aggregate Purchase Price Calculation Schedule" means a calculation schedule delivered at Closing evidencing the Closing Aggregate Purchase Price and the calculation of its relevant components in the form attached hereto as Schedule C-1. "Closing Date" means the date on which the Closing occurs. "Code" means the United States Internal Revenue Code of 1986, as amended. All references to the Code, U.S. Treasury regulations or other governmental pronouncements shall be deemed to include references to any applicable successor regulations or amending pronouncement. "Common Stock" means the common stock, par value $.01 per share, of the Company. "Company" has the meaning specified in the first paragraph of this Agreement. "Company Advisor" means Richardson Barr & Co., Natural Gas Partners V, L.P. and any other agent, consultant or advisor to the Company with respect to the transactions contemplated by this Agreement. "Company Disclosure Schedule" shall mean that certain disclosure document of even date with this Agreement from the Company to Buyer delivered concurrently with the execution and delivery of this Agreement. "Company Employee Benefit Plans" has the meaning set forth in Section 4.10(a). "Company Financial Statements" means (i) the audited consolidated financial statements of the Company and its consolidated Subsidiaries (including the related notes) as of December 31, 2000, 2001 and 2002 and for the period from inception to December 31, 2000 and for the years ended December 31, 2001 and 2002 and (ii) the unaudited consolidated financial statements of the Company and its consolidated Subsidiaries for the twelve months ended December 31, 2003. "Company Legal Costs" means the fees, expense reimbursements and any and all other amounts due to Vinson & Elkins L.L.P. or any other outside counsel engaged by the Company or any of its Subsidiaries relating to its services after December 31, 2003 in connection with the negotiation, execution and delivery of this Agreement and the consummation of the transactions contemplated hereby. "Company Permits" has the meaning set forth in Section 4.14. "Company Privileged Information" has the meaning set forth in Section 6.2(b). 3 "Company Transaction Costs" means (i) the fees, expense reimbursements and any and all other amounts that would be due Company Advisors assuming the transactions contemplated under this Agreement, plus (ii) all amounts paid or payable to the officers and employees of HRM from and after December 31, 2003 for release and bonus payment amounts pursuant to Section 2.1(g). "Confidential Information" has the meaning set forth in Section 6.5. "Confidentiality Agreement" means the letter agreement dated October 3, 2003, between the Company and Buyer relating to the Company's furnishing of information to Buyer in connection with Buyer's evaluation of the possibility of acquiring the Company. "Debt" means, for any Person, without duplication, (a) all obligations of such Person for borrowed money, (b) all obligations of such Person evidenced by bonds, debentures, notes or other similar instruments, (c) all Guarantees of such Person, (d) the unfunded or unreimbursed portion of all letters of credit issued for the account of such Person, (e) the present value of all obligations in respect of leases that are capitalized on the books and records of such Person, (f) any obligation of such Person representing the deferred purchase price of property or services purchased by such Person other than trade payables incurred in the ordinary course of business, (g) any indebtedness for borrowed money secured by a Lien on the assets of such Person whether or not such indebtedness, liability or obligation is otherwise non-recourse to such Person; but specifically excluding any deferred tax items and amounts related to the fair value of hedging arrangements; notwithstanding the foregoing, "Debt" shall not include (i) letters of credit and performance or surety bonds listed on Schedule 4.17 of the Company Disclosure Schedule to the extent that such are not drawn upon, (ii) any letters of credit or performance or surety bonds, to the extent that such are not drawn upon, that were issued in replacement of any of the letters of credit or performance or surety bonds listed on Schedule 4.17 of the Company Disclosure Schedule and (iii) any letters of credit or performance or surety bonds that come into existence after the date of this Agreement to the extent that such are not drawn upon. "Debt Amount" means the total principal, interest, fees and other expenses, if any, unpaid and outstanding on all loans under the Bank Credit Agreement; notwithstanding the foregoing, "Debt Amount" shall not include (i) letters of credit and performance or surety bonds listed on Schedule 4.17 of the Company Disclosure Schedule to the extent that such are not drawn upon, (ii) any letters of credit or performance or surety bonds, to the extent that such are not drawn upon, that were issued in replacement of any of the letters of credit or performance or surety bonds listed on Schedule 4.17 of the Company Disclosure Schedule and (iii) any letters of credit or performance or surety bonds that come into existence after the date of this Agreement to the extent that such are not drawn upon. "December 31 Balance Sheet" means the final unaudited consolidated balance sheet of the Company and its Subsidiaries as of 11:59 p.m., central time, on December 31, 2003, as prepared by the Company in accordance with GAAP and the terms of this Agreement and as agreed to by Buyer. "Defect Notice" has the meaning set forth in Section 2.4(a). 4 "Defensible Title" means such right, title and interest that is (a) with respect to Ownership Interests of record, evidenced by an instrument or instruments filed of record in accordance with the conveyance and recording laws of the applicable jurisdiction to the extent necessary to give the Company and Buyer, through its ownership of the Common Stock, the right as against all third parties to directly or indirectly enjoy the benefits of ownership and possession of the Ownership Interests, (b) with respect to Ownership Interests not yet earned under a farmout agreement, described in and subject to a farmout agreement containing terms and provisions reasonably consistent with terms and provisions used in the domestic oil and gas business and under which there is exists no material default by the Company or a Subsidiary thereof, and (c) subject to Permitted Encumbrances, free and clear of all Liens. "Enbridge" means Enbridge Gathering (North Texas) L.P. "Environmental and Regulatory Assessment" shall mean one or more on-site inspections of the Operated Properties (or part thereof) together with review of pertinent records in the possession of the Company or any of its Subsidiaries relating to the environmental condition and regulatory compliance of the Operated Properties, it being understood that Buyer or Buyer's Representatives may conduct a Phase I environmental analysis (as contemplated by the most recent version of ASTM 1527E) of the Operated Properties to evaluate the environmental condition of the Operated Properties. "Environmental and Regulatory Assessment" shall also include such further inspections, including invasive or intrusive samplings or studies, as may be conducted in accordance with Section 6.3. "Environmental Law" means any law, ordinance or regulation of any Governmental Authority (including common law), as well as any order, decree, permit, judgment or injunction issued, promulgated, approved, or entered thereunder, relating to the environment, Hazardous Materials (including the use, handling, transportation, production, disposal, discharge or storage thereof or the exposure thereto), or the environmental conditions on, under, or about any real property owned, leased or operated at any time by the Company or any of its Subsidiaries, including soil, groundwater, and indoor and ambient air conditions or the reporting or remediation of environmental contamination. Environmental Laws include the Clean Air Act, as amended, the Federal Water Pollution Control Act, as amended, the Rivers and Harbors Act of 1899, as amended, the Safe Drinking Water Act, as amended, the Comprehensive Environmental Response, Compensation and Liability Act of 1980 ("CERCLA"), as amended, the Superfund Amendments and Reauthorization Act of 1986 ("SARA"), as amended, the Resource Conservation and Recovery Act of 1976 ("RCRA"), as amended, the Hazardous and Solid Waste Amendments Act of 1984, as amended, the Toxic Substances Control Act, as amended, the Hazardous Materials Transportation Act, as amended, and any other federal, state and local law whose purpose is to conserve or protect human health, the environment, wildlife or natural resources, in each case as in effect on the date of this Agreement. "ERISA" means the Employee Retirement Income Security Act of 1974, as amended from time to time and the regulations promulgated thereunder. "ERISA Affiliate" means any entity that is or ever was required to be aggregated with the Company or any of its Subsidiaries pursuant to section 414(b), 414(c), 414(m) or 414(o) of the Code or Section 4001 of ERISA. 5 "Excluded Assets" has the meaning specified in Section 2.6. "Final Aggregate Option Exercise Price" means, with respect to an Optionholder, the exercise price payable by an Optionholder upon exercise of such Optionholder's options as of the Closing Date. "Final Company Legal Costs" means the Company Legal Costs as of and through the Closing Date. "Final Company Transaction Costs" means Company Transaction Costs as of and through the Closing Date. "Final Debt Amount" means the Debt Amount reflected on the December 31 Balance Sheet. "Final Note Payoff Amount" means, with respect to a Securityholder, the total of all principal and interest due the Company or its Subsidiaries from such Securityholder under the Notes as of the Closing Date. "Final Working Capital" means the Working Capital as calculated in the Closing Aggregate Purchase Price Calculation Schedule and which is reflected on the December 31 Balance Sheet. "Furst Ranch Exploration Agreement" means The Exploration Agreement, dated effective as of October 1, 2002, between Cortez Operating Company and Old WR Ranch I L.P., et al., as amended. "Furst Ranch Oil and Gas Lease" means the Oil and Gas Lease, dated effective as of October 1, 2002, between Cortez Operating Company and Old WR Ranch I L.P., et al., as amended. "GAAP" means generally accepted accounting principles in the United States. "Governmental Authority" means any national, state, county or municipal government, domestic or foreign, any agency, board, bureau, commission, court, department or other instrumentality of any such government, or any arbitrator in any case that has jurisdiction over the Company, any of its Subsidiaries, Buyer, any Securityholder or any of their respective properties or assets. "Guaranty" by any Person means any obligation, contingent or otherwise, of such Person directly or indirectly guaranteeing any Debt or other obligation of any other Person; provided that, the term "Guaranty" shall not include endorsements for collection or deposit in the ordinary course of business. For purposes of this Agreement, the amount of any Guaranty shall be the maximum amount that the guarantor could be legally required to pay under such Guaranty. "Hazardous Material" means (a) any "hazardous substance," as defined by CERCLA, (b) any "hazardous waste," as defined by the Resource Conservation and Recovery Act, as amended, and as in effect on the date of this Agreement, (c) any chemical, material, waste or substance, in 6 any form or condition, the use, transportation, production, handling, storage, treatment, disposal or discharge of which, or the exposure thereto, is prohibited or regulated by any Applicable Law, (d) any radioactive material, including any naturally occurring radioactive material, and any source, special or byproduct material as defined in 42 U.S.C. 2011 et seq. and any amendments or authorizations thereof and as in effect on the date of this Agreement, (e) any asbestos-containing materials in any form or condition, (f) any polychlorinated biphenyls in any form or condition, and (g) Hydrocarbons and their derivatives. "HRM" has the meaning specified in the first paragraph of this Agreement. "HRM 401(k) Plan" means the 401(k) retirement plan of HRM currently in effect for the benefit of its employees, pursuant to which HRM automatically contributes 3% of each employee's cash compensation to the plan. "HRM Asset Transfer" has the meaning set forth in Section 2.6. "HRM Transfer" has the meaning set forth in Section 2.6. "Hydrocarbons" means oil, condensate, gas, casinghead gas and other liquid or gaseous hydrocarbons. "Investment" in any Person means any investment, whether by means of securities purchase (whether by direct purchase from such Person or from an existing holder of securities of such Person), loan, advance, extension of credit, capital contribution or otherwise, in or to such Person, the Guaranty of any Debt or other obligation of such Person, or the subordination of any claim against such Person to other Debt or other obligation of such Person; provided that, "Investments" shall not include advances made to employees of such Person for reasonable travel, entertainment and similar expenses incurred in the ordinary course of business. "Lien" means any lien, mortgage, security interest, pledge, deposit, restriction, burden, encumbrance, defect in title, rights of a vendor under any title retention or conditional sale agreement, or lease or other arrangement substantially equivalent thereto, but does not include any production payment obligation. "Material Adverse Effect" means (a) when used with respect to the Company, a material and adverse effect on the business, assets, financial condition or results of operations of the Company and its Subsidiaries taken as a whole; provided, however, that no change, effect or circumstance shall be deemed (either alone or in combination) to constitute, nor shall be taken into account in determining whether there has been or may be, a Material Adverse Effect to the extent that it arises out of, or relates to, (i) a general deterioration in the economy or in the industries in which the Company or any Subsidiary thereof operates, (ii) the outbreak or escalation of hostilities involving the United States, the declaration by the United States of a national emergency or war or the occurrence of any other calamity or crisis, including an act of terrorism, (iii) any change after the date of this Agreement in any laws, statutes, rules, regulations, ordinances, judgments, orders, decrees or the interpretation thereof, (iv) actions taken by Buyer or any of its Affiliates, or (v) compliance with the terms of, or the taking of any action required by, this Agreement, and (b) when used with respect to Buyer, a result or consequence that would materially adversely affect Buyer's ability to perform their respective 7 obligations hereunder or consummate the transactions contemplated hereby or prevent or materially delay the performance of this Agreement. "Material Agreement" means any written or oral agreement, contract, lease, easement, license, commitment, or understanding to which the Company or any of its Subsidiaries is a party, by which the Company or any of its Subsidiaries is directly or indirectly bound, or to which any assets of the Company or any of its Subsidiaries may be subject, (a) pursuant to which the Company or any of its Subsidiaries acquires any material portion of the raw materials, supplies or services used or consumed by the Company or any of its Subsidiaries in the operation of its business (unless such raw materials, supplies or services are readily available to the Company or any of its Subsidiaries from other sources on comparable terms), (b) pursuant to which the Company or any of its Subsidiaries derives any material part of its revenues, (c) containing any restriction on the Company or any of its Affiliates from competing in any line of business or with any Person in any geographical area; (d) involving (A) the acquisition, merger or purchase of all or substantially all the assets or business of a third party, (B) the sale of assets other than sales of produced Hydrocarbons or tangible equipment or inventory in the ordinary course of business, (C) the purchase of any real property or oil and gas properties or (D) the grant to any person of any preferential right to purchase any material asset or assets of the Company; (e) containing any "change in control" or similar provision pursuant to which the execution and delivery of this Agreement, or the consummation of the transactions contemplated hereby would give rise to any right (including any right of termination, cancellation, acceleration or vesting) or benefit; (f) including any mortgage or other grant of security interests, guarantee or note, relating to the borrowing of money; (g) any provision which would prohibit or materially delay the consummation of the transactions contemplated hereby; (h) not entered into in the ordinary course of business involving in excess of $100,000; (i) containing covenants purporting to limit the freedom of the Company or any of its Subsidiaries to hire an individual or group of individuals; (j) relating to any outstanding commitment for capital expenditures in excess of $100,000; (k) requiring contingent payments by the Company or any of its Subsidiaries in connection with the purchase of oil and gas properties; (l) involving confidentiality or standstill agreements with any Person (the effectiveness of which extends beyond the date that is six months following the date hereof) that restrict the Company or any of its Subsidiaries in the use of any information or the taking of any actions by the Company or its Subsidiaries entered into in connection with the consideration by the Company or any of its Subsidiaries of any acquisition of equity interests or assets; (m) in favor of directors or officers that provide rights to indemnification; (n) with respect to oil, gas and mineral leases and joint operating agreements, those oil, gas and mineral leases and joint operating agreements representing the top 90% of such leases and agreements ranked by Allocated Value and (o) that is material to the Company or any of its Subsidiaries, other than those that are covered by clauses (a) through (n) above. "Note" or collectively, the "Notes" means those three promissory notes dated as of April 1, 2002, executed by certain officers of the Company in favor of the Company, the collective principal amount of which is $6,079,878 and each of which shall be paid off by such officers at Closing. "Notice Date" means the later of (a) thirty (30) days after Buyer receives the initial December 31 Balance Sheet proposed by the Company and (b) April 16, 2004. 8 "Office Lease" means that certain Office Lease Agreement dated October 24, 2001, between Brangus, Ltd., as Landlord, and Cortez Oil & Gas, Inc., as Tenant, as amended from time to time. "Oil and Gas Interest(s)" means (a) direct and indirect interests in and rights with respect to oil, gas, mineral and related properties and assets of any kind and nature, direct or indirect, including working, royalty and overriding royalty interests, production payments, operating rights, net profits interests, other non-working interests and non-operating interests, (b) interests in and rights with respect to Hydrocarbons and other minerals or revenues therefrom and contracts in connection therewith and claims and rights thereto (including oil and gas leases, operating agreements, unitization and pooling agreements and orders, division orders, transfer orders, mineral deeds, royalty deeds, oil and gas sales, exchange and processing contracts and agreements and, in each case, interests thereunder), surface interests, fee interests, reversionary interests, reservations and concessions, (c) easements, rights of way, licenses, permits, leases, and other interests associated with, appurtenant to, or necessary for the operation of any of the foregoing, and (d) interests in equipment and machinery (including well equipment and machinery), oil and gas production, gathering, transmission, compression, treating, processing and storage facilities (including tanks, tank batteries, pipelines and gathering systems), pumps, water plants, electric plants, gasoline and gas processing plants, refineries and other tangible personal property and fixtures associated with, appurtenant to, or necessary for the operation of any of the foregoing, regardless of location. References in this Agreement to the "Oil and Gas Interests of the Company" or "the Company's Oil and Gas Interests" mean the collective Oil and Gas Interests of the Company or its Subsidiaries. "Operated Properties" means each Ownership Interest (a) that is subject to a joint operating agreement pursuant to which the Company or any of its Subsidiaries is designated as an operator thereunder and (b) to the extent not described in subclause (a), with respect to which the Company or any of its Subsidiaries is designated as an operator under a regulatory permit. "Optionholder" and "Optionholders" have the meaning set forth in the preliminary statements. "Options" means the collective reference to all options to purchase shares of capital stock of the Company. "Option Surrender Agreement" means the form of Agreement set forth in Exhibit 2.3(a)(ii) hereto. "Ownership Interests" means the collective ownership interests of the Company and its Subsidiaries in the Oil and Gas Interests, as set forth in Schedule 1.1-C of the Company Disclosure Schedule. "Payout Balance(s)" means the status, as of the dates of the Company's calculations, of the recovery by the Company or a third party of a cost amount specified in the contract relating to a well included in the Ownership Interests out of the revenue from such well where the working interest or the net revenue interest of the Company therein will be adjusted when such amount has been recovered. 9 "Permitted Encumbrances" means (a) Liens for Taxes, assessments or other governmental charges or levies if the same shall not at the particular time in question be due and delinquent or (if foreclosure, distraint, sale or other similar proceedings shall not have been commenced or, if commenced, shall have been stayed) are being contested in good faith by appropriate proceedings and if the Company shall have set aside on its books such reserves (segregated to the extent required by GAAP) as may be required by or consistent with GAAP, (b) Liens of carriers, warehousemen, mechanics, laborers, materialmen, landlords, vendors, workmen and operators arising by operation of law in the ordinary course of business or by a written agreement existing as of the date hereof and necessary or incident to the exploration, development, operation and maintenance of Hydrocarbon properties and related facilities and assets for sums not yet due or being contested in good faith by appropriate proceedings, if the Company shall have set aside on its books such reserves (segregated to the extent required by GAAP) as may be required by or consistent with GAAP, (c) Liens incurred in the ordinary course of business to secure the performance of bids, tenders, trade contracts, leases, statutory obligations, surety and appeal bonds, performance and repayment bonds and other obligations of a like nature for sums not yet due or being contested in good faith by appropriate proceedings, if the Company shall have set aside on its books such reserves (segregated to the extent required by GAAP) as may be required by or consistent with GAAP, (d) Liens, easements, rights-of-way, restrictions, servitudes, permits, conditions, covenants, exceptions, reservations and other similar encumbrances incurred in the ordinary course of business or existing on property (i) not reducing the Company's and its Subsidiaries collective net revenue interest in any Oil and Gas Interest below the applicable Ownership Interest, and (ii) not materially impairing the value of such property or interfering with the ordinary conduct of the business of the Company and its Subsidiaries with respect to such property or rights to any of their respective assets, (e) Liens arising pursuant to Section 9.319 of the Texas Business and Commerce Code and all other similar Liens created or arising by operation of law to secure a party's rights as a purchaser of oil and gas for sums not yet due or being contested in good faith by appropriate proceedings, if the Company shall have set aside on its books such reserves (segregated to the extent required by GAAP) as may be required by or consistent with GAAP, (f) all rights to consent by, required notices to, filings with, or other actions by Governmental Authorities to the extent customarily obtained subsequent to closing (g) farmout, carried working interest, joint operating, unitization, royalty, overriding royalty, sales and similar agreements relating to the exploration or development of, or production from, Hydrocarbon properties entered into in the ordinary course of business, provided the effect thereof on the collective working and net revenue interest, royalties and overriding royalties of the Company and its Subsidiaries has been properly reflected in the Ownership Interests, (h) any defects, irregularities or deficiencies in title to the Oil and Gas Interests that do not adversely affect the value of any individual asset of the Company or its Subsidiaries, (i) preferential rights to purchase and Third-Party Consents (to the extent not triggered by the consummation of the transaction contemplated herein or any prior transaction, event or circumstance), (j) Liens arising under or created pursuant to the Bank Credit Agreement, and (k) other Liens described in Schedule 1.1-D of the Company Disclosure Schedule. "Person" means any natural person, corporation, company, limited or general partnership, joint stock company, joint venture, association, limited liability company, trust, bank, trust company, land trust, business trust or other entity or organization, or Governmental Authority. 10 "Pre-Acquisition Claims" has the meaning set forth in Section 10.18. "Pre-Acquisition Matters" has the meaning set forth in Section 10.18. "Preliminary Aggregate Option Exercise Price" means, with respect to an Optionholder, the exercise price payable by an Optionholder upon exercise of such Optionholder's options as of March 31, 2004, which amount is set forth opposite such Optionholder's name under the caption "Preliminary Aggregate Option Exercise Price" on Schedule C-2 hereto. "Preliminary Aggregate Purchase Price" means, with respect to a Securityholder, the amount set forth opposite such Securityholder's name under the caption "Preliminary Aggregate Purchase Price" on Schedules C-1 and C-2 hereto. "Preliminary Balance Sheet" means the unaudited consolidated balance sheet for the twelve months ending December 31, 2003 and that is included in the Company Financial Statements. "Preliminary Company Legal Costs" means the Company Legal Costs estimated to be incurred as of March 31, 2004, which amount is estimated to be $250,000. "Preliminary Company Transaction Costs" means the Company Transaction Costs as of March 31, 2004, which amount is acknowledged and agreed to be $2,750,000. "Preliminary Debt Amount" means $37,343,328. "Preliminary Note Payoff Amount" means, with respect to a Securityholder, the total of all principal and interest due the Company from such Securityholder under the Notes as if the transactions contemplated under this Agreement closed on March 31, 2004, which amount is set forth opposite such Securityholder's name under the caption "Preliminary Note Payoff Amount" on Schedule C-2 hereto. "Preliminary Working Capital" means $3,852,909. "Product Hedging Contract" means any agreement providing for options, swaps, floors, caps, collars, forward sales or forward purchases involving commodities or commodity prices, or indexes based on any of the foregoing and any other similar agreement or arrangement to which the Company or any of its Subsidiaries is a party or by which any of them may be bound. "Product Hedging Termination Costs" means (i) the aggregate cost to the Company and its Subsidiaries associated with the termination of all Product Hedging Contracts, less (ii) the lesser of (A) 40% of such costs and (B) $500,000. "Release Agreements" has the meaning set forth in Section 2.3(a)(xi). "Released Parties" has the meaning set forth in Section 10.18. "Relevant Geographic Area" has the meaning set forth in Section 9.1(a). 11 "Rep and Warranty Defect" has the meaning set forth in Section 2.4(a). "Reserve Report" means the Company reserve report dated effective as of September 1, 2003 as audited by William M. Cobb & Associates, Inc. (the output pages for each category of reserves are attached as part of Schedule 1.1-E of the Company Disclosure Schedule). "Restricted Group" means, collectively, C. Randall Hill, R. Cory Richards and David C. Myers. "Restricted Party" means HRM and each Securityholder, other than Natural Gas Partners V, L.P. "Restricted Period" has the meaning set forth in Section 9.1. "Restricted Properties" has the meaning set forth in Section 9.1. "Seal Agreement" means that certain Retirement Agreement dated as of May 31, 1989 between Cortez Operating Company and William G. Seal. "Securityholders" means the Stockholders and the Optionholders, collectively. "Securityholder Representative" has the meaning set forth in Section 10.19. "Stockholder" and "Stockholders" have the meaning set forth in the preliminary statements. "Subsidiary" of any Person means another Person, an amount of the voting securities, other voting ownership or voting partnership interests of which is sufficient to elect at least a majority of its board of directors or other governing body (or, if there are no such voting interests, 50% or more of the equity interests of which) is owned directly or indirectly by such Person. "Tag-Along Rights" has the meaning set forth in Section 6.12. "Tax Partnership" means any entity that was treated before 2003 or is to be treated in 2003 as a partnership for federal income tax purposes (including any entity that has made an election to be excluded from all or some of the provisions of subchapter K of the Code) in which the Company directly or indirectly through another Person owns any interest. "Tax Returns" means any return, report, statement, information return or other document (including any related or supporting information) filed or required to be filed with any Governmental Authority in connection with the determination, assessment, collection or administration of any Taxes or the administration of any laws, regulations or administrative requirements relating to any Taxes. "Taxes" means taxes of any kind, levies or other like assessments, customs, duties, imposts, charges or fees, including income, gross receipts, ad valorem, value added, excise, real or personal property, asset, sales, use, federal royalty, license, payroll, transaction, capital, net 12 worth and franchise taxes, estimated taxes, withholding, employment, social security, workers compensation, utility, severance, production, unemployment compensation, occupation, premium, windfall profits, transfer and gains taxes or other governmental taxes imposed or payable to the United States or any state, local or foreign governmental subdivision or agency thereof, and in each instance such term shall include any interest, penalties or additions to tax attributable to any such Tax, including penalties for the failure to file any Tax Return or report. "Termination Date" has the meaning set forth in Section 8.1. "Third-Party Consent" means all authorizations, consents, permits, orders or approvals of, or declarations, registrations or filings with, or expirations of waiting periods imposed by, any Person other than the Company, any Subsidiary thereof or Buyer. "Total Preliminary Aggregate Purchase Price" means, with respect to all Securityholders, the sum of each Securityholder's Preliminary Aggregate Purchase Price as set forth on Schedules C-1 and C-2 hereto. "Underproduction Amount" has the meaning set forth in Section 2.4(b)(v). "Working Capital" means the Company's and its Subsidiaries' consolidated, aggregate cash, cash equivalents, accounts receivable and other current assets, less the Company's and its Subsidiaries' consolidated, aggregate accounts payable and other current liabilities (including liabilities for accrued taxes but excluding deferred taxes), in each case calculated in accordance with GAAP and the terms of this Agreement; provided, however, that Working Capital shall not include (i) any assets or liabilities arising under, or relating to, Product Hedging Contracts, or (ii) any liabilities in respect of the Debt Amount. In calculating Working Capital, no reserves reflected on the Preliminary Balance Sheet shall be increased, reduced or eliminated except in the case of a reduction or elimination by reason of a payment, settlement or credit in the ordinary course of business and consistent with past practices. 1.2 REFERENCES AND TITLES. (a) All references in this Agreement to Exhibits, Schedules, Articles, Sections, clauses, subsections and other subdivisions refer to the corresponding Exhibits, Schedules, Articles, Sections, clauses, subsections and other subdivisions of or to this Agreement unless expressly provided otherwise. Titles appearing at the beginning of any Articles, Sections, clauses, subsections or other subdivisions of this Agreement are for convenience only, do not constitute any part of this Agreement, and shall be disregarded in construing the language hereof. The words "this Agreement," "herein," "hereby," "hereunder" and "hereof," and words of similar import, refer to this Agreement as a whole and not to any particular subdivision unless expressly so limited. The words "this Article," "this Section" and "this subsection," and words of similar import, refer only to the Article, Section or subsection hereof in which such words occur. The word "or" is not exclusive, and the word "including" (in its various forms) means including without limitation. Pronouns in masculine, feminine or neuter genders shall be construed to state and include any other gender, and words, terms and titles (including terms defined herein) in the singular form shall be construed to include the plural and vice versa, unless 13 the context otherwise requires. In the event of any conflict between GAAP and the terms of this Agreement, the terms of this Agreement shall govern. (b) As used in or when referring to representations and warranties contained in this Agreement, the phrase "to the knowledge" (in its various forms) of the representing party shall mean the actual knowledge, after due investigation, of the directors and officers of the representing party. (c) All amounts payable hereunder shall be paid in United States Dollars. ARTICLE 2 THE PURCHASE 2.1 PURCHASE AND SALE. At the Closing and subject to the terms and conditions set forth in this Agreement: (a) each Stockholder shall sell and transfer to Buyer, and Buyer shall purchase from each Stockholder, the number of Shares set forth opposite such Stockholder's name on Schedule A hereto; (b) each Optionholder shall deliver, and the Company shall accept, a duly executed Option Surrender Agreement with respect to Options to purchase the number of shares of Common Stock set forth opposite such Optionholder's name on Schedule B hereto; (c) in exchange for the Shares and the surrender of Options as described above, Buyer shall pay to each Securityholder the Preliminary Aggregate Purchase Price, as such consideration may be adjusted pursuant to the terms of Sections 2.4 and 2.5 to arrive at the Closing Aggregate Purchase Price; (d) Buyer shall pay to Fleet National Bank, as Administrative Agent under the Bank Credit Agreement, all outstanding indebtedness under the Bank Credit Agreement by wire transfer of immediately available funds to an account designated by Fleet National Bank in writing; (e) Buyer shall pay the Final Company Transaction Costs that are not otherwise paid pursuant to Section 2.1(g) to each recipient thereof listed on Schedule 2.1(e) of the Company Disclosure Schedule by wire transfer of immediately available funds to an account designated by such recipient in writing; (f) Buyer shall pay the Final Company Legal Costs, to the extent outstanding, to Vinson & Elkins L.L.P. and any such other law firm, as applicable, by wire transfer of immediately available funds to an account designated by Vinson & Elkins L.L.P. or such other law firm, as the case may be, in writing; and (g) immediately prior to the Closing and prior to effecting the HRM Transfer, the Company shall (i) utilize its cash on hand and/or borrow under and pursuant to the Bank Credit Agreement an amount equal to $2,000,000 (the "Borrowed Funds") and (ii) cause such 14 Borrowed Funds to be contributed to HRM. At the Closing, HRM shall use the Borrowed Funds to pay all amounts due and owing at the Closing under the Release Agreements. 2.2 TIME AND DATE OF CLOSING. Unless this Agreement shall have been terminated and the transactions herein contemplated shall have been abandoned pursuant to Article 8, and subject to the satisfaction or waiver of the conditions set forth in Article 7 (other than conditions the fulfillment of which is to occur at the Closing), the Closing shall take place at 9:00 a.m., local time, on April 21, 2004, at the offices of Vinson & Elkins L.L.P., Dallas, Texas, unless another date, time or place is mutually agreed to in writing by Buyer and the Company. If any of the conditions (other than conditions the fulfillment of which is to occur at the Closing) set forth in Article 7 are not satisfied or waived at the time the Closing is to occur pursuant to this Section 2.2, then the Closing shall occur on a date that is the third Business Day after the satisfaction or waiver of all such conditions. 2.3 CLOSING OBLIGATIONS. (a) Subject to the terms and conditions hereof, at the Closing, the Company and the Securityholders, as applicable, will deliver to Buyer: (i) certificates representing the Shares, accompanied by stock powers duly endorsed in blank or accompanied by duly executed instruments of transfer; (ii) an Option Surrender Agreement executed on behalf of each Optionholder, dated the Closing Date in the form of Exhibit 2.3(a)(ii) hereto; (iii) an opinion of Vinson & Elkins L.L.P., dated the Closing Date, in the form of Exhibit 2.3(a)(iii) hereto; (iv) written resignations of the officers and directors of the Company and its Subsidiaries; (v) evidence reasonably satisfactory to Buyer of the termination of those certain Confidentiality and Non-Compete Agreements, dated March 10, 2000, with each officer of the Company; (vi) an executed termination agreement, substantially in the form attached hereto as Exhibit 2.3(a)(vi), relating to (A) the termination of that certain Advisory Services and Indemnification Agreement, dated March 10, 2000, between the Company and Natural Gas Partners V, L.P. (except with respect to the indemnity provisions contained therein which shall remain in full force and effect), and (B) evidence reasonably satisfactory to Buyer of the payment by the Company of all amounts due under such agreement; (vii) evidence reasonably satisfactory to Buyer of the termination of that certain Voting and Shareholders Agreement, dated March 10, 2000, between the Company and the other parties thereto; 15 (viii) evidence reasonably satisfactory to Buyer of the termination of that certain Registration Rights Agreement, dated March 10, 2000, between the Company and the other parties thereto; (ix) evidence reasonably satisfactory to Buyer that (A) HRM is no longer a subsidiary or otherwise affiliated with the Company, (B) HRM has assumed all rights, obligations and liabilities with respect to the Excluded Assets and (C) the Company has been fully and unconditionally released from all obligations and liabilities with respect to the Excluded Assets; (x) evidence reasonably satisfactory to Buyer that the Company has been fully and unconditionally released from all obligations and liabilities with respect to the Office Lease; (xi) a release executed by each individual who is an employee of HRM as of the date hereof, in the form attached hereto as Exhibit 2.3(a)(xi) (collectively, the "Release Agreements"); (xii) evidence reasonably satisfactory to Buyer that all rights, obligations and liabilities of the Company and any of its Subsidiaries under all Product Hedging Contracts have expired or been terminated and that the Company and its Subsidiaries have fully performed all of their respective obligations thereunder; (xiii) one or more statements (in form and substance reasonably satisfactory to Buyer) that satisfies Buyer's obligations under Treasury Regulation section 1.1445-2(b)(2); (xiv) one or more agreements in form and substance reasonably satisfactory to Buyer evidencing the termination of all intercompany agreements and arrangements between or involving the Company and HRM; and (xv) all other documents, instruments, certificates or other items required to be delivered at the Closing by the Company pursuant to this Agreement. (b) Subject to the terms and conditions hereof, at the Closing, Buyer will deliver to the Securityholders or other Persons designated in this Agreement, as applicable: (i) such Securityholder's allocable share of the Closing Aggregate Purchase Price; and (ii) all other payments, documents, instruments, certificates or other items required to be delivered at the Closing by Buyer pursuant to this Agreement. 2.4 ADJUSTMENTS TO AGGREGATE PURCHASE PRICE FOR BREACHES OF REPRESENTATIONS AND WARRANTIES. (a) Buyer may conduct, at its sole cost, such examinations and investigations (including title examinations and investigations), as it may in its sole discretion choose to 16 conduct to determine if any violations of the representations or warranties in Article 3 and Article 4 exist. In order to be entitled to assert the existence of any violation of a representation or warranty in Article 3 or Article 4 under this Section 2.4, Buyer must deliver to the Company and the Securityholder Representative on or before the Notice Date a written notice (the "Defect Notice") specifying each defect that it asserts constitutes a violation of the representations set forth in Article 3 or Article 4 (a "Rep and Warranty Defect"), a description of each such Rep and Warranty Defect, the amount of the adjustment to the Total Preliminary Aggregate Purchase Price that it asserts based on such defect and its method of calculating such adjustment. If such Defect Notice is not timely submitted, Buyer will be deemed to have waived all rights under this Section 2.4. (b) Upon timely delivery of the Defect Notice, Buyer and the Securityholders shall in good faith negotiate the validity of the claim and the amount of any adjustment to the Total Preliminary Aggregate Purchase Price using the following criteria: (i) No adjustment will be made to the Total Preliminary Aggregate Purchase Price under this Section 2.4 except to the extent that the net total of all adjustments exceeds $1,250,000 in the aggregate (the "Aggregate Defect Threshold"); by way of example, if the net total of all adjustments under this Section 2.4 equals $1,300,000, then an adjustment of $50,000 shall, subject to subsection (c) of this Section 2.4, be made to the Total Preliminary Aggregate Purchase Price. The amount of any adjustment for a Rep and Warranty Defect shall be determined without giving effect to the knowledge qualifications contained in Article 3 and Article 4 and without giving effect to the materiality qualifications contained in Section 3.2; Section 4.1; Section 4.3 (but giving effect to the use of the term "Material Agreements" therein); Section 4.9; Sections 4.10(c) and (d); Section 4.13(b); Section 4.14; Sections 4.16(a), (b), (c), (e) and (g); Section 4.17; Section 4.20; Section 4.22; Section 4.23; Section 4.28; and Sections 4.30(f), (g), (k) (but giving effect to the use of the term "Material Agreements" therein and to materiality qualifications in subclause (iv) thereof), (l) and (m). In addition, the amount of any adjustment for a Rep and Warranty Defect with respect to Section 4.16 shall be determined without giving effect to any disclosures made on Schedule 4.16 of the Company Disclosure Schedule; provided, however, that effect shall be given to disclosures on Schedule 4.16 of the Company Disclosure Schedule of past environmental matters that have been remediated in accordance with applicable Environmental Law. (ii) If the requested adjustment is based on the Company owning a net revenue interest as to a particular Ownership Interest less than that shown in the Schedule 1.1-C of the Company Disclosure Schedule, then a downward adjustment shall be calculated by multiplying the Allocated Value set forth for such Ownership Interest by a fraction (A) the numerator of which is an amount equal to the net revenue interest shown on Schedule 1.1-C of the Company Disclosure Schedule for such Ownership Interest less the decimal share to which the Company would be entitled as a result of its Ownership Interest which is unaffected by such Rep and Warranty Defect and (B) the denominator of which is the net revenue interest shown on Schedule 1.1-C of the Company Disclosure Schedule for such Ownership Interest. Any downward adjustments requested by Buyer may be offset by upward adjustments if it is determined that the Company's net revenue interest for all or part of any Ownership Interests is greater than that shown in Schedule 1.1-C of the Company Disclosure Schedule. 17 (iii) If the requested adjustment is based on the Company owning a working interest as to a particular Ownership Interest that is larger than the working interest shown in Schedule 1.1-C of the Company Disclosure Schedule, but without a proportionate increase in the Company's net revenue interest as to such Ownership Interest, then the adjustment is calculated by (x) determining the effective net revenue interest that results from such larger working interest, (y) determining what the net revenue interest would be using such effective net revenue interest and the working interest shown in Schedule 1.1-C of the Company Disclosure Schedule and (z) then calculating the adjustment in the manner set forth in clause (ii) preceding (including the effect of any offsets due to upward adjustments). By way of example, with respect to an Ownership Interest with an Allocated Value of $1,000,000, if the Company owns a 60% working interest instead of a 50% working interest and a 45% net revenue interest instead of a 40% net revenue interest, then the downward adjustment of $62,500.00 to the Total Preliminary Aggregate Purchase Price (assuming the Aggregate Defect Threshold had been exceeded) would be calculated as follows: (w) Ownership Interest: 50% WI, 40% NRI, 80% Effective NRI (x) Defect Interest: 60% WI, 45% NRI, 75% Effective NRI (y) Adjustment Percentage: (.80 - .75)/.80 = .0625 (z) Downward Adjustment: .0625 x $1,000,000 = $62,500.00 (iv) If the requested adjustment is based on a Lien or other monetary charge upon a particular Ownership Interest that is liquidated in amount, then the adjustment is the amount necessary to remove such Lien or other monetary charge from the affected Ownership Interest. (v) In respect of the representation and warranty contained in Section 4.21, if the Company's net gas underproduced position as to its Ownership Interests is equal to or greater than 100,000 Mcf, then no adjustment shall be made to the Total Preliminary Aggregate Purchase Price. If the Company's net gas underproduced position as to its Ownership Interests is less than 100,000 Mcf (such amount shall be referred to as the "Underproduction Amount"), then the Total Preliminary Aggregate Purchase Price shall be adjusted by the amount equal to the product derived from multiplying $1.50 by the sum of 100,000 minus the Underproduction Amount. (vi) If the requested adjustment is based on a violation of a representation or warranty that is not adjusted pursuant to clauses (ii), (iii), (iv) or (v) of this Section 2.4(b), then the Parties shall negotiate in good faith regarding the validity of the claim and the amount of any adjustment to the Total Preliminary Aggregate Purchase Price. (vii) No fact, circumstance or condition of the title to an Ownership Interest shall be considered to effect a reduction in the value of the Ownership Interest, unless due consideration has been given to (x) the length of time that such Ownership Interest has been producing Hydrocarbon substances and has been credited to and accounted for by the Company 18 and its predecessors in title, if any, and (y) whether any such fact, circumstance or condition is of the type that can generally be expected to be encountered in the area involved and is usually and customarily acceptable to (and thus not considered to create an adverse effect on value by) reasonable and prudent operators, interest owners and purchasers engaged in the business of the ownership, development and operation of oil and gas properties. (c) As an alternative to adjusting the Total Preliminary Aggregate Purchase Price, the Company may elect to cure all or certain of the asserted Rep and Warranty Defects, provided that such cure period shall only extend until the fifth calendar day after the Notice Date. (d) If Buyer and the Company are unable to reach agreement within five (5) calendar days after the Notice Date as to the validity of claims and amounts for adjustments to the Total Preliminary Aggregate Purchase Price, or as to the sufficiency of any cure pursuant to Section 2.4(c), then such disagreement shall be resolved by binding arbitration in accordance with Section 10.20. (e) Any adjustment made to the Total Preliminary Aggregate Purchase Price pursuant to this Section 2.4 shall only be enforceable when evidenced by (i) an amendment to this Agreement executed by Buyer and the Securityholders acting through the Securityholder Representative or (ii) by arbitrative order rendered in accordance with Section 10.20. With respect to determining the adjustment under this Section 2.4 to the Closing Aggregate Purchase Price payable to a Securityholder, the amount of any such adjustment shall be allocated on a pro rata basis to all Securityholders based on the number set forth with respect to each Securityholder under the column entitled "Number of Shares Owned and Subject to Options" in Schedule C-1. 2.5 ADDITIONAL ADJUSTMENTS TO PRELIMINARY AGGREGATE PURCHASE PRICE. (a) To arrive at the Closing Aggregate Purchase Price payable to a Securityholder, the Preliminary Aggregate Purchase Price payable to such Securityholder shall be adjusted (in addition to any adjustments made as a result of Rep and Warranty Defects) as follows: (i) upward or downward by (A) taking the positive or negative difference between Final Working Capital and Preliminary Working Capital and dividing the amount by 2,975 and (B) multiplying the result under the preceding clause (A) by the sum of (x) number of Shares owned by the Securityholder as set forth on Schedule A and (y) the number of shares of Common Stock issuable upon exercise of Options held by the Securityholder as set forth on Schedule B; (ii) upward or downward by (A) taking the positive or negative difference between the Preliminary Debt Amount and the Final Debt Amount and dividing the amount by 2,975, and (B) multiplying the result under the preceding clause (A) by the sum of (x) number of Shares owned by the Securityholder as set forth on Schedule A and (y) the number of shares of Common Stock issuable upon exercise of Options held by the Securityholder as set forth on Schedule B; 19 (iii) upward or downward by (A) taking the positive or negative difference between the Preliminary Company Transaction Costs and Final Company Transaction Costs and dividing the amount by 2,975, and (B) multiplying the result under the preceding clause (A) by the sum of (x) the number of Shares owned by the Securityholder as set forth on Schedule A and (y) the number of shares of Common Stock issuable upon exercise of Options held by the Securityholder as set forth on Schedule B; (iv) upward or downward by (A) taking the positive or negative difference between the Preliminary Company Legal Costs and the Final Company Legal Costs and dividing the amount by 2,975, and (B) multiplying the result under the preceding clause (A) by the sum of (x) the number of Shares owned by the Securityholder as set forth on Schedule A and (y) the number of shares of Common Stock issuable upon exercise of Options held by the Securityholder as set forth on Schedule B; (v) if applicable, upward or downward by taking the positive or negative difference between the Preliminary Note Payoff Amount and Final Note Payoff Amount; (vi) if applicable, upward or downward by taking the positive or negative difference between the Preliminary Aggregate Option Exercise Price and Final Aggregate Option Exercise Price; and (vii) downward by (A) the quotient obtained by dividing Product Hedging Termination Costs by 2,975, multiplied by (B) the sum of (x) the number of Shares owned by the Securityholder as set forth on Schedule A and (y) the number of shares of Common Stock issuable upon exercise of Options held by the Securityholder as set forth on Schedule B. (b) The calculations required by Section 2.5(a) shall be evidenced on the Closing Aggregate Purchase Price Calculation Schedule and agreed to by Buyer and the Securityholder Representative. The provisions of Section 2.4 and Section 2.5(a) shall apply in such a manner as not to give duplicative effect to any item of adjustment. (c) To facilitate the calculation of the Closing Aggregate Purchase Price payable to each Securityholder, the Securityholder Representative and Buyer shall agree, on or before the Notice Date, upon the December 31 Balance Sheet, along with copies of the back up schedules of all components of the adjustments contemplated by this Section 2.5 (including an estimated payoff schedule from the Company's lenders under the Bank Credit Agreement). The Securityholder Representative and Buyer shall work in good faith from and after the delivery of these items to prepare the Closing Aggregate Purchase Price Calculation Schedule and deliver an agreed upon final version thereof which shall be executed and delivered by the Securityholders and Buyer at Closing. If Buyer and the Securityholder Representative are unable to agree on the December 31 Balance Sheet by the Notice Date, any such disagreement shall be resolved by binding arbitration in accordance with Section 10.20. 2.6 EXCLUDED ASSETS. (a) At the Closing, the Company shall sell and transfer to one or more members of the Restricted Group all of the outstanding equity securities of HRM for an 20 aggregate purchase price of $10,000 (the "HRM Transfer"). Prior to the HRM Transfer, HRM shall transfer to the Company the assets designated for such transfer on Schedule 2.6 of the Company Disclosure Schedule (the "HRM Asset Transfer"). At the time of the HRM Transfer, all of the assets and properties of HRM shall consist entirely of the items designated as "Excluded Assets" on Schedule 2.6 of the Company Disclosure Schedule (the "Excluded Assets"), and the Excluded Assets shall not include any seismic, geological, engineering or technical data, licenses, devices and data relating to field reporting or any other property or information (other than generic land or technical information) relating to or necessary for the conduct of the Company's or its Subsidiaries' oil and gas business, it being acknowledged that all such data, property and information (other than generic land or technical information) are assets of the Company and its Subsidiaries. Notwithstanding any provisions contained herein to the contrary, none of the representations, warranties or covenants (other than those contained in Sections 2.1(g), 2.6, 4.10, 6.1(a)(vi) and (xvi), 6.5(b) and 6.10(b) and any other provisions specifically referencing the inclusion of HRM) set forth in this Agreement nor any of the other provisions of this Agreement shall be applicable to HRM or the Excluded Assets and no breach of this Agreement or adjustment to the Preliminary Aggregate Purchase Price or the Closing Aggregate Purchase Price may be asserted as a result of the liabilities or obligations of HRM, the HRM Transfer or the transfer of the Excluded Assets. ARTICLE 3 REPRESENTATIONS AND WARRANTIES OF THE SECURITYHOLDERS REPRESENTATIONS AND WARRANTIES OF THE SECURITYHOLDERS. Each Securityholder, severally and not jointly, represents and warrants to Buyer as follows: 3.1 AUTHORITY. The Securityholder has the requisite legal capacity to execute and deliver this Agreement and to consummate the transactions contemplated herein. This Agreement has been duly executed and delivered by the Securityholder and, assuming that this Agreement constitutes the valid and binding agreement of the other parties hereto, constitutes the valid and binding obligations of the Securityholder, enforceable against the Securityholder in accordance with its terms and conditions, except that the enforcement hereof may be limited by (i) applicable bankruptcy, insolvency, reorganization, moratorium, fraudulent conveyance or other similar laws now or hereafter in effect relating to creditors' rights generally and (ii) general principles of equity (regardless of whether enforceability is considered in a proceeding at law or in equity). 3.2 NO VIOLATIONS. The execution and delivery of this Agreement do not, and the consummation of the transactions contemplated hereby and compliance by the Securityholder with the provisions hereof will not, conflict with, result in any violation of or default (with or without notice or lapse of time or both) under, give rise to a right of termination, cancellation or acceleration of any obligation or to the loss of a material benefit under, or result in the creation of any Lien on any of the properties or assets of the Securityholder under any provision of (a) any loan or credit agreement, note, bond, mortgage, indenture, license, contract, agreement or other instrument or obligation to which the Securityholder is a party or by which any of its properties or assets is bound or affected, or (b) assuming the consents, approvals, authorizations or permits and filings or notifications referred to in Section 4.4 are duly and timely obtained or 21 made, any judgment, order, decree, statute, law, ordinance, rule or regulation applicable to the Securityholder or its properties or assets. 3.3 CONSENTS AND APPROVALS. No Third-Party Consent is required to be obtained or made by the Securityholder in connection with the execution, delivery and performance by the Securityholder of this Agreement or the consummation by the Securityholder of the transactions contemplated herein. 3.4 OWNERSHIP OF SECURITIES. (a) The Securityholder is the sole record and beneficial owner of the number of Shares set forth opposite such Securityholder's name on Schedule A hereto. At the Closing, Buyer will acquire record and beneficial ownership of the Securityholder's Shares free and clear of all Liens (including, in the case any Securityholder that is an individual, any claims of spouses under applicable community property laws), except those Liens that may arise as a result of (i) any actions taken by or on behalf of Buyer and its Affiliates or (ii) applicable securities laws. (b) The Securityholder is the grantee of the Options, if any, set forth opposite such Securityholder's name on Schedule B hereto. (c) Except for the Shares and Options, if any, owned by Securityholder and listed in Schedule A and Schedule B hereto, the Securityholder does not own any shares of capital stock or other securities of the Company or any options, warrants, equity securities, calls, rights or other securities convertible into or exchangeable or exercisable for shares of capital stock or other equity securities of the Company. 3.5 BROKERS. The Securityholder is not a party to any agreement or other arrangement (whether written or oral) with a broker, finder, investment banker or other Person who is or will be, as a result of the Closing of the transactions contemplated by this Agreement, entitled to any brokerage, finder's or other fee or compensation, other than the fees owed by the Company and contemplated to be included in the Company Transaction Costs, and for which Buyer, the Company or any of its Subsidiaries will have any obligation or liability. ARTICLE 4 REPRESENTATIONS AND WARRANTIES OF THE COMPANY REPRESENTATIONS AND WARRANTIES OF THE COMPANY. The Company represents and warrants to Buyer as follows: 4.1 ORGANIZATION. Each of the Company and its Subsidiaries (a) is a corporation duly organized, validly existing and in good standing under the laws of its jurisdiction of incorporation, (b) has the requisite power and authority to own, lease and operate its properties and to conduct its business as it is presently being conducted, and (c) is duly qualified to do business as a foreign corporation and is in good standing, in each jurisdiction where the character of the properties owned or leased by it or the nature of its activities makes such qualification necessary (except where the failure to be so qualified or to be in good standing would not be reasonably likely to have a Material Adverse Effect on the Company). The Company has furnished to Buyer copies of the articles of incorporation and by-laws of the Company and each 22 of its Subsidiaries, and such copies are accurate and complete. The Company has no Subsidiaries other than as set forth on Schedule 4.1 of the Company Disclosure Schedule. Except as set forth on Schedule 4.1 of the Company Disclosure Schedule, the Company does not own, directly or indirectly (including through ownership in a Subsidiary or other Person), nor is it a party to any agreement or other instrument to acquire, any shares of capital stock, partnership interests, limited liability company interests, voting rights or other securities in any other Person. 4.2 AUTHORITY AND ENFORCEABILITY. The Company has the requisite power and authority to execute and deliver this Agreement and to consummate the transactions contemplated herein. The execution and delivery of this Agreement by the Company and the consummation by the Company of the transactions contemplated herein have been duly authorized by all necessary corporate action on the part of the Company. This Agreement has been duly executed and delivered by the Company and, assuming that this Agreement constitutes the valid and binding agreement of the other parties hereto, constitutes the valid and binding obligations of the Company, enforceable against the Company in accordance with its terms and conditions, except that the enforcement hereof may be limited by (a) applicable bankruptcy, insolvency, reorganization, moratorium, fraudulent conveyance or other similar laws now or hereafter in effect relating to creditors' rights generally and (b) general principles of equity (regardless of whether enforceability is considered in a proceeding at law or in equity). 4.3 NO VIOLATIONS. The execution and delivery of this Agreement do not, and the consummation of the transactions contemplated hereby and compliance by the Company with the provisions hereof will not, conflict with, result in any violation of or default (with or without notice or lapse of time or both) under, give rise to a right of termination, cancellation or acceleration of any obligation or to the loss of a material benefit under, or result in the creation of any Lien on any of the properties or assets of the Company or any Subsidiary thereof under any provision of (a) such entity's articles of incorporation or by-laws or comparable organizational documents, (b) any Material Agreement, (c) any loan or credit agreement, note, bond, mortgage, indenture, license, contract, agreement or other instrument or obligation not described in subclause (b) to which the Company or any of its Subsidiaries is a party or by which any of its or their properties or assets is bound or affected, except for such conflicts, violations, defaults, rights, losses or Liens as are not material to the business of the Company and its Subsidiaries, taken as a whole or (d) assuming the consents, approvals, authorizations or permits and filings or notifications referred to in Section 4.4 are duly and timely obtained or made, any Applicable Law, in each case other than as set forth on Schedule 4.3 of the Company Disclosure Schedule. 4.4 CONSENTS AND APPROVALS. No Third-Party Consent is required to be obtained or made by the Company or any of its Subsidiaries in connection with the execution, delivery and performance by the Company of this Agreement or the consummation by the Company of the transactions contemplated herein, except for such Third-Party Consents, the failure of which to be obtained would not result in a loss of an Ownership Interest. 4.5 FINANCIAL STATEMENTS. (a) The Company Financial Statements were, and at the Closing (except with respect to FASB Rule 143) the December 31 Balance Sheet will have been, prepared in 23 accordance with GAAP applied on a consistent basis during the periods involved (except as may be indicated in the notes thereto and the unaudited interim financial statements are not accompanied by notes or other textual disclosure required by GAAP) and fairly present in all material respects the consolidated financial position of the Company and its consolidated Subsidiaries as of their respective dates and the consolidated results of operations and the consolidated cash flows of the Company and its consolidated Subsidiaries for the periods presented therein. No financial statements of any Person other than the Company and the Subsidiaries included in the Company Financial Statements are required by GAAP to be included in the consolidated financial statements of the Company. (b) Except as set forth in the Company Financial Statements or the December 31 Balance Sheet, the Company and its Subsidiaries have no liabilities or obligations of any nature (whether accrued, absolute, contingent or otherwise) required by GAAP to be set forth in a financial statement or in the notes thereto except liabilities, obligations or contingencies that (i) are accrued or reserved against in the December 31 Balance Sheet, (ii) were incurred after December 31, 2003 in the ordinary course of business and consistent with past practices (other than such liabilities arising from breach of contract, breach of warranty, tort, infringement or violation of any Applicable Law), or (iii) constitute Company Legal Fees or Company Transaction Costs. 4.6 CAPITAL STRUCTURE. (a) The authorized capital stock of the Company consists of 3,500 shares of Common Stock, par value $.01 per share. (b) There are issued and outstanding (i) 2,914 shares of Common Stock, and (ii) the Options relating to 61 shares of Common Stock. No shares of Common Stock are held by the Company as treasury stock. Schedule A and Schedule B set forth the name and number of shares of Common Stock or Options, respectively, beneficially owned or held of record by any Person. (c) Except as set forth in or pursuant to Section 4.6(b), there are issued and outstanding or reserved for issuance (i) no shares of capital stock or other voting or equity securities of the Company, (ii) no securities of the Company or any other Person convertible into or exchangeable or exercisable for shares of capital stock or other voting or equity securities of the Company and (iii) no subscriptions, options, warrants, calls, rights (including preemptive rights), commitments, understandings or agreements to which the Company is a party or by which it is bound obligating the Company to issue, deliver, sell, purchase, redeem or acquire shares of capital stock or other voting or equity securities of the Company (or securities convertible into or exchangeable or exercisable for shares of capital stock or other voting or equity securities of the Company) or obligating the Company to grant, extend or enter into any such subscription, option, warrant, call, right, commitment, understanding or agreement. (d) All outstanding equity securities of the Company are validly issued, fully paid and nonassessable and not subject to or issued in violation of any preemptive rights or similar rights of any past or present stockholder of the Company. 24 (e) Except as otherwise set forth on Schedule 4.6(e) of the Company Disclosure Schedule, at the Closing there will be no stockholder agreement, voting trust or other agreement or understanding to which the Company or any of its Subsidiaries is a party or by which any of them is bound relating to the voting of any shares of the capital stock of the Company or any of its Subsidiaries. (f) There are no outstanding or authorized stock appreciation, phantom stock, profit participation, or similar rights with respect to the Company or any of its Subsidiaries. (g) The authorized capital stock and the issued and outstanding capital stock of each Subsidiary of the Company is listed on Schedule 4.6(g) of the Company Disclosure Schedule. Except as set forth on Schedule 4.6(g) of the Company Disclosure Schedule and as contemplated by the HRM Transfer, the Company directly or indirectly is the beneficial and record owner of all issued and outstanding equity securities of each such Subsidiary, and such ownership is free and clear of all Liens other than Liens under the Bank Credit Agreement. All outstanding equity securities of each such Subsidiary have been duly authorized and validly issued and are fully paid and nonassessable and not subject to or issued in violation of any preemptive or similar rights of any past or present stockholder of such Subsidiary. There are issued and outstanding or reserved for issuance (i) no shares of capital stock or other voting or equity securities of any Subsidiary of the Company, (ii) no securities of any Subsidiary of the Company or any other Person convertible into or exchangeable or exerciseable for shares of capital stock or other voting or equity securities of any Subsidiary of the Company and (iii) no subscriptions, options, warrants, calls, rights (including preemptive rights), commitments, understandings or agreements to which any Subsidiary of the Company is a party or by which any of them is bound obligating any such Subsidiary to issue, deliver, sell, purchase, redeem or acquire shares of capital stock or other voting or equity securities of such Subsidiary (or securities convertible into or exchangeable or exercisable for shares of capital stock or other voting or equity securities of such Subsidiary) or obligating any such Subsidiary to grant, extend or enter into any such subscription, option, warrant, call, right, commitment, understanding or agreement. 4.7 MATERIAL AGREEMENTS. Schedule 4.7 of the Company Disclosure Schedule sets forth as of the date of this Agreement all Material Agreements to which either the Company or any of its Subsidiaries is a party or by which any of them are otherwise bound. Neither the Company nor any of its Subsidiaries is in breach or default under any such Material Agreement, except as set forth on Schedule 4.7 of the Company Disclosure Schedule. To the Company's knowledge, no other party to a Material Agreement is in breach or default under a Material Agreement, nor has there occurred any event or events that with the lapse of time or the giving of notice or both would constitute a breach or default by the Company or any Subsidiary or any other party under the terms of any Material Agreement, in either case except as set forth on Schedule 4.7 of the Company Disclosure Schedule. 4.8 INVESTMENTS AND INDEBTEDNESS. Except as set forth on Schedule 4.8 of the Company Disclosure Schedule, neither the Company nor any of its Subsidiaries has any outstanding Investments that are not disclosed in the Company Financial Statements. As of the date of this Agreement, the total amount of indebtedness outstanding under the Bank Credit Agreement is $ 37,337,247. 25 4.9 EMPLOYMENT MATTERS; INDEPENDENT CONTRACTORS. Except as set forth on Schedule 4.9 of the Company Disclosure Schedule and except for individuals that are solely employed by HRM and for related liabilities for which HRM will be solely responsible as of the Closing Date, (i) neither the Company nor any Subsidiary employs any employees, (ii) all employment-related obligations related to any former employees of the Company or any Subsidiary have been satisfied in full and (iii) there are no employment-related contingencies which could result in imposition of any liability on the Company or any of its Subsidiaries. Schedule 4.9 of the Company Disclosure Schedule lists the name of each independent contractor and temporary or leased worker of any of the Company and its Subsidiaries and the agreements or commitments to which any of them are bound with respect thereto, specifying in each case which entity is a party thereto. Except as set forth on Schedule 4.9 of the Company Disclosure Schedule, neither the Company nor any Subsidiary thereof is a party to or obligated under any consulting or other arrangement entered into or maintained for the benefit of its current or former temporary or leased workers or independent contractors. The Company has made available to Buyer a true and correct copy of each written arrangement described on Schedule 4.9 of the Company Disclosure Schedule. Neither the Company nor any Subsidiary thereof is or has been a party to or obligated under any collective bargaining agreement. Each of the Company and its Subsidiaries is and has been in material compliance with all Applicable Laws relating to the employment of labor, including all such Applicable Laws relating to wages, hours, collective bargaining, discrimination, civil rights, safety and health and workers' compensation. 4.10 EMPLOYEE BENEFIT PLANS. (a) Schedule 4.10(a) of the Company Disclosure Schedule sets forth a complete and accurate list of all "employee benefit plans," as defined in Section 3(3) of ERISA, as well as severance pay, sick leave, vacation pay, salary continuation for disability, compensation agreements, retirement, deferred compensation, profit-sharing, pension, bonus, long-term incentive, stock option, stock purchase, hospitalization, medical insurance, life insurance, fringe benefit and scholarship programs, practices or arrangements not subject to ERISA maintained by the Company or its Subsidiaries or to which the Company or its Subsidiaries contributes or is obligated to contribute (the "Company Employee Benefit Plans"). Except for the Company Employee Benefit Plans, neither the Company nor its Subsidiaries maintain, or has any fixed or contingent liability with respect to, any employee benefit plan that is subject to ERISA. The list of Company Employee Benefit Plans identifies the type of each such plan, whether it is maintained outside the jurisdiction of the United States and whether any Company Employee Benefit Plan holds any equity interest in the Company or any of its Subsidiaries. Except as set forth on Schedule 4.10(a) of the Company Disclosure Schedule, neither the Company nor any Subsidiary thereof is subject to any legal, contractual, equitable or other obligation (nor have they any formal plan or commitment, whether legally binding or not) to enter into any form of compensation or employment agreement or to establish any employee benefit plan of any nature, including any pension, profit sharing, welfare, post-retirement welfare, stock option, stock or cash award, non-qualified deferred compensation or executive compensation plan, policy or practice or to modify or change any existing Company Employee Benefit Plan. Except as set forth on Schedule 4.10(a) of the Company Disclosure Schedule, each and every Company Employee Benefit Plan is solely an obligation of HRM, and neither the Company nor any of its other Subsidiaries has or will have any fixed or contingent liability with respect to any Company Employee Benefit Plan. 26 (b) To the Company's knowledge, since 1994 neither the Company, its Subsidiaries nor any ERISA Affiliate has maintained or been obligated to contribute to an employee benefit plan that (i) is subject to Title IV of ERISA or the minimum funding requirements of Section 412 of the Code or Section 302 of ERISA, (ii) is a plan of the type described in Section 4063 of ERISA or Section 413(c) of the Code, or (iii) is a "multiemployer plan" (as defined in Section 3(37) of ERISA). (c) There is and has been no material violation of ERISA with respect to any Company Employee Benefit Plan. Except for the Seal Agreement, with respect to the Company Employee Benefit Plans, there exists no condition or set of circumstances in connection with the Company or any of its Subsidiaries that would result in any liability to the Company or any of its Subsidiaries other than HRM. Except for the Seal Agreement, with respect to the Company Employee Benefit Plans, individually and in the aggregate, there are no unfunded benefit obligations which have not been accounted for in accordance with GAAP on the financial statements of the Company and its Subsidiaries. The Company has made the required top hat plan informational filing with the Department of Labor with respect to the Seal Agreement, and has made the corresponding filings and payment necessary to satisfy the requirements of the Department of Labor's Delinquent Filer Voluntary Compliance Program with respect to such top hat filing. (d) The Company Employee Benefit Plans have been maintained, in all material respects, in accordance with their terms and in accordance with all Applicable Laws, and neither the Company, its Subsidiaries nor any "party in interest" or "disqualified person" with respect to the Company Employee Benefit Plans, has engaged in any "prohibited transaction" within the meaning of Section 4975 of the Code or Section 406 of ERISA that would subject the Company or any Subsidiary thereof, any officer of the Company or any of such plans or any trust to any Tax or penalty on prohibited transactions imposed by Section 4975 of the Code or any penalties or remedies imposed by ERISA. Each Company Employee Benefit Plan intended to be qualified under Section 401 of the Code has been the subject of a favorable determination letter with respect to such qualified status and has been maintained in material compliance with, and currently complies in all material respects with, all qualification requirements of the Code in form and operation. All liabilities associated with any Company Employee Benefit Plan which was intended to qualify under Section 401(a) of the Code that has been terminated within the last six years have been satisfied in full. (e) Neither the execution and delivery of this Agreement nor the consummation of the transactions contemplated hereby (either alone or in combination with any other event) (i) will result in any payment becoming due, increase the amount of any payment, or accelerate the timing or vesting of any payment to any current or former employee or independent contractor or group of employees or independent contractors of the Company or any Subsidiary, other than such payments or benefits which are solely the responsibility of HRM, or (ii) is reasonably expected to result in the imposition of any excise tax under Section 4999 of the Code or the denial of any deduction under Section 280G of the Code. (f) There are no pending or, to the Company's knowledge, threatened claims against the assets of any of the Company Employee Benefit Plans or the trusts established to hold the assets of those plans or the fiduciaries of such plans. To the Company's knowledge, no 27 Company Employee Benefit Plan is subject to ongoing audit, investigation or other administrative proceeding of the Internal Revenue Service, the Department of Labor or any other Governmental Authority, and no Company Employee Benefit Plan is the subject of any pending application for administrative relief under any voluntary compliance program of the Internal Revenue Service, the Department of Labor or any other Governmental Authority. (g) Except for the Seal Agreement, to the Company's knowledge neither the Company nor any Subsidiary maintains or has ever maintained any welfare benefit plan which provides for retiree medical liabilities or continuing benefits or coverage for any participant or any beneficiary of any participant after such participant termination of employment except as may be required by COBRA. No plan or arrangement listed as an exception to the representations in this Section 4.10(g) provides post-employment welfare benefit coverage of any kind as of the date of this Agreement (or will provide any such coverage as of any time thereafter) other than post-employment coverage as required by COBRA. (h) To the Company's knowledge, neither the Company nor any of its Subsidiaries has maintained, established, or ever participated in, a multiple employer welfare benefit arrangement within the meaning of Section 3(40)(A) of ERISA. 4.11 LITIGATION. Except as set forth on Schedule 4.11 of the Company Disclosure Schedule, there is (a) no claim, action, suit, inquiry, judicial or administrative proceeding, grievance or arbitration pending or, to the knowledge of the Company, threatened against the Company or any of its Subsidiaries or involving any of their respective properties or assets by or before any arbitrator or Governmental Authority; (b) no order, judgment, injunction or decree of any Governmental Authority outstanding against the Company or any of its Subsidiaries or any of their respective properties or assets; and (c) no investigation or review relating to the Company or any of its Subsidiaries or involving any of their respective properties or assets pending or, to the knowledge of the Company, threatened by or before any arbitrator or any Governmental Authority. 4.12 TAXES AND TAX RETURNS. Except as set forth on Schedule 4.12 of the Company Disclosure Schedule: (a) All Tax Returns which are required to be filed by or with respect to the Company, any Subsidiary thereof or any Tax Partnership have been timely filed. All Taxes which are due and for which the Company, any Subsidiary of the Company or any Tax Partnership is liable under Applicable Laws have been paid. All withholding Tax requirements imposed on or with respect to the Company, any Subsidiary thereof or any Tax Partnership have been satisfied in full. No penalty, interest, other charge or Tax is payable by the Company, any Subsidiary of the Company, or any Tax Partnership by reason of the late filing of any Tax Return or late payment of any Tax. The accruals for Taxes in the December 31 Balance Sheet are sufficient to pay all Taxes for which the Company, any Subsidiary of the Company or any Tax Partnership is liable and that have accrued through the end of 2003 (including income Taxes for 2003 income) and have not been paid at that time. (b) There is not in force (i) any extension of time with respect to the due date for the filing of any Tax Return by the Company, any Subsidiary of the Company or any Tax 28 Partnership or (ii) any waiver or agreement for any extension of time for the assessment against or payment of any Tax by the Company, any Subsidiary of the Company, or any Tax Partnership. (c) There is no claim pending against the Company, any Subsidiary thereof or any Tax Partnership for the payment of any Tax. No assessment of any Tax has been made against the Company, any Subsidiary of the Company or any Tax Partnership that has not been paid. No deficiency has been proposed and no adjustment has been asserted with respect to any Tax Return of the Company, any Subsidiary of the Company or any Tax Partnership. (d) There is in effect no Tax sharing agreement to which the Company, any Subsidiary of the Company or any Tax Partnership is a party. There is in effect no agreement that requires that any payment be made by the Company, any Subsidiary thereof or any Tax Partnership to or for the benefit of a person upon whom Tax is imposed by reason of the amount of such Tax. (e) No payment that is made by reason of the transactions contemplated by this Agreement will not be deductible by reason of Section 280G of the Code. (f) None of the Company, any of its Subsidiaries (excluding HRM) or any Tax Partnership will be required to pay any Taxes greater than $10,000 in the aggregate by reason of the HRM Transfer, the HRM Asset Transfer or any transfer of the Excluded Assets to HRM. None of the Company, any of its Subsidiaries (including HRM) or any Tax Partnership will be required to pay any Tax by reason of the sale of the Shares and surrender of the Options provided for in this Agreement. 4.13 TITLE TO AND SUFFICIENCY OF ASSETS. (a) Except as set forth on Schedule 4.13 of the Company Disclosure Schedule, the Company has Defensible Title to all Oil and Gas Interests included or reflected in the Ownership Interests. Each Oil and Gas Interest included or reflected in the Ownership Interests entitles the Company or its Subsidiaries to receive throughout the duration of the productive life of such Oil and Gas Interest (after satisfaction of all royalties, overriding royalties, nonparticipating royalties, net profits interests or other similar burdens on or measured by production of Hydrocarbons) not less than the undivided interest set forth in (or derived from) the Ownership Interests of all Hydrocarbons produced, saved and sold from or attributable to such Oil and Gas Interest, and the portion of the costs and expenses of operation and development of such Oil and Gas Interest that is borne or to be borne by the Company and its Subsidiaries throughout the duration of the productive life of such Oil and Gas Interest is not greater than the undivided interest set forth in the Ownership Interests. (b) All material operating equipment of the Company and its Subsidiaries is in good operating condition and in a state of reasonable maintenance and repair, ordinary wear and tear excepted, and suitable for the purposes for which such equipment was constructed, obtained or being used. 4.14 COMPLIANCE WITH LAWS AND PERMITS. The Company and each of its Subsidiaries are, and their businesses and operations have been conducted, in material compliance with all 29 Applicable Laws. Neither the Company nor any of its Subsidiaries has received written notice of any actual, alleged or potential violation of any Applicable Law that has not otherwise been cured to the satisfaction of the Governmental Authority issuing such notice. Except as set forth on Schedule 4.14 of the Company Disclosure Schedule, the Company and its Subsidiaries hold and have in full force and effect all permits, licenses, variances, exemptions, orders, franchises and approvals of all Governmental Authorities necessary for the lawful conduct of their respective businesses and the ownership and operation of their respective assets (the "Company Permits"). Except as set forth on Schedule 4.14 of the Company Disclosure Schedule, the Company and its Subsidiaries are, and their businesses and operations have been conducted, in material compliance with the terms of the Company Permits. To the knowledge of the Company, no event has occurred or circumstance exists that would reasonably be expected to constitute or result in the revocation, withdrawal, suspension, cancellation, modification or termination of any Company Permits or to result in any fine or other enforcement action. All applications required to have been filed for the renewal of any Company Permits that expire on or prior to the Closing Date have been timely filed with the appropriate Governmental Authorities. Schedule 4.14 of the Company Disclosure Schedule lists each Company Permit that, to the Company's knowledge, expires within 120 days of the date of this Agreement. 4.15 PROPRIETARY RIGHTS. The Company and its Subsidiaries have ownership of, or valid licenses to use, all trademarks, copyrights, patents and other proprietary rights and intellectual property used in their respective business. To the knowledge of the Company, the operation of the respective business of the Company and its Subsidiaries does not infringe any patent, copyright, trademark or other proprietary rights of others, and, the Company has not received any notice from any third party of any such alleged infringement by the Company or its Subsidiaries. The Company has taken reasonable steps to establish and preserve the respective ownership rights of the Company and its Subsidiaries in all patents, copyrights, trademarks, trade secrets and other proprietary rights. To the knowledge of the Company, no other Person is interfering with, infringing upon, misappropriating or otherwise coming into conflict with any intellectual property of the Company or any of its Subsidiaries. 4.16 ENVIRONMENTAL MATTERS. The sole representations and warranties of the Company with respect to compliance with Environmental Laws and other environmental matters are set forth in this Section 4.16. In the event that representations or warranties of the Company in other Sections of this Agreement or related transaction documents could be construed to relate to compliance with Environmental Laws or other environmental matters, such representations and warranties shall be construed to exclude all environmental matters. Except as set forth on Schedule 4.16 of the Company Disclosure Schedule: (a) To the knowledge of the Company, the Company and its Subsidiaries have, at all times in the past, conducted and are conducting their respective businesses and operating their respective assets, and the condition of all facilities and properties formerly or currently owned, leased or operated by the Company and its Subsidiaries has at all times in the past been, and currently is, in material compliance with all Environmental Laws; (b) The Company has not been notified by any Governmental Authority or other third party that any of the former or present operations or assets of the Company and its Subsidiaries is the subject of any investigation or inquiry by any Governmental Authority or 30 other third party evaluating whether any material investigative or remedial action is needed to respond to a release or threatened release of any Hazardous Material or to the improper storage or disposal (including storage or disposal at offsite locations) of any Hazardous Material; (c) To the knowledge of the Company, neither the Company nor its Subsidiaries has any material contingent liability in connection with (i) the release or threatened release of any Hazardous Material into the environment at, beneath or on any property formerly or currently owned, leased or operated by the Company or any of its Subsidiaries or (ii) the storage or disposal of any Hazardous Material; (d) To the knowledge of the Company, no property now or previously owned, leased or operated by the Company or its Subsidiaries is listed on the National Priorities List pursuant to CERCLA or on the CERCLIS or on any other federal or state list as sites requiring environmental investigation or cleanup; (e) To the knowledge of the Company, neither the Company nor its Subsidiaries has transported or has arranged for the transportation of any Hazardous Material to any location which is (i) listed on the National Priorities List pursuant to CERCLA, on the CERCLIS, or on any similar federal or state list or which is the subject of federal, state or local enforcement actions or other investigations that may lead to material claims against the Company or its Subsidiaries for remedial work, damage to natural resources or personal injury, including claims under CERCLA or (ii) subject to a claim that may lead to material claims against the Company or any of its Subsidiaries for remediation work, damage to natural resources or personal injury, including claims under CERCLA; (f) There are no sites, locations or operations at which the Company or its Subsidiaries is currently undertaking any remedial or response action relating to the disposal or release of Hazardous Materials, which remedial or response action is required by Environmental Laws; and (g) To the knowledge of the Company, all underground or above ground storage tanks and Hazardous Material waste disposal facilities owned or operated by the Company or its Subsidiaries are used and operated in material compliance with Environmental Laws. 4.17 INSURANCE. The Company and its Subsidiaries own and are beneficiaries under insurance policies underwritten by reputable insurers that, as to risks insured, coverages and related limits and deductibles, are customary in the industry in which the Company and its Subsidiaries operate. Schedule 4.17 of the Company Disclosure Schedule sets forth a list of all such insurance policies. All material premiums due with respect to all insurance policies have been paid and, to the knowledge of the Company, all such policies are in full force and effect. There is no claim in excess of $250,000 by the Company or any of its Subsidiaries pending under any of the Company's insurance policies as to which coverage has been questioned, denied or disputed by the underwriters of such policies or bonds. Neither the Company nor any of its Subsidiaries has received any notice, which remains outstanding, of cancellation or termination with respect to any material insurance policy. 31 4.18 GOVERNMENTAL REGULATION. Neither the Company nor its Subsidiaries is subject to regulation under the Public Utility Holding Company Act of 1935, the Investment Company Act of 1940 or any state public utilities laws. 4.19 BROKERS. Except as set forth on Schedule 4.19 of the Company Disclosure Schedule, no broker, finder, investment banker or other Person is or will be, in connection with the transactions contemplated by this Agreement, entitled to any brokerage, finder's or other fee or compensation based on any arrangement or agreement made by or on behalf of the Company or any of its Subsidiaries and for which Buyer, the Company or any of its Subsidiaries will have any obligation or liability. 4.20 OIL AND GAS OPERATIONS. (a) Schedule 4.20 of the Company Disclosure Schedule sets forth all preferential rights (including any calls upon, options to purchase, rights of first or last refusal or offer or similar rights) to purchase the Ownership Interests and any such preferential rights to purchase production from any such Ownership Interests, other than such rights with respect to oil, gas and mineral leases and joint operating agreements representing the bottom 10% of such leases and agreements ranked by Allocated Value. Except as otherwise set forth on Schedule 4.20 of the Company Disclosure Schedule, to the knowledge of the Company, all wells included in the Ownership Interests have been drilled and (if completed) completed, operated and produced in accordance with generally accepted oil and gas field practices and in compliance in all material respects with applicable oil and gas leases, pooling and unit agreements, and Applicable Laws. Except as otherwise set forth on Schedule 4.20 of the Company Disclosure Schedule, to the knowledge of the Company, in respect of the Ownership Interests: (i) There are no wells that the Company or a Subsidiary thereof is currently obligated by Applicable Law or contract to plug and abandon; (ii) There are no wells that are subject to exceptions to a requirement to plug and abandon issued by a Governmental Authority having jurisdiction over the applicable lease; and (iii) Proceeds from the sale of Hydrocarbons attributable to the Ownership Interests are being received by the Company or a Subsidiary thereof in a timely manner and are not being held in suspense for any reason (except for amounts held in suspense in the ordinary course of business). (b) Except as set forth on Schedule 4.20 of the Company Disclosure Schedule, there are no obligations of the Company or any of its Subsidiaries (other than implied obligations under leases concerning protection from drainage and further development that are customary in the oil and gas industry) that require the drilling of additional wells or other material development operations in order to earn or to continue to hold all or any portion of the Ownership Interests, and neither the Company nor any of its Subsidiaries have been advised by a lessor of any requirements or demands to drill additional wells on any of the real property relating to the Ownership Interests, which requirements or demands have not been resolved. 32 4.21 GAS IMBALANCES. To the knowledge of the Company, except as is reflected on Schedule 4.21 of the Company Disclosure Schedule, as of December 31, 2003, (a) there are no production, transportation or processing imbalances existing with respect to the Ownership Interests, and (b) neither the Company nor any Subsidiary thereof has received any deficiency payments under gas contracts for which any party has a right to take deficiency gas from the Ownership Interests without further payment. As of the date of this Agreement, it is estimated that the Company's net gas underproduced position as to its Ownership Interests is at least 100,000 Mcf. 4.22 ROYALTIES AND RENTALS. Except as set forth on Schedule 4.22 of the Company Disclosure Schedule, all royalties, overriding royalties, compensatory royalties, rentals and other payments due and payable from or in respect of production of Hydrocarbons from the Ownership Interests have been or will be, prior to the Closing, properly and correctly paid or provided for in all material respects. 4.23 PAYOUT BALANCES. The Payout Balance for each well included in the Ownership Interest that is operated by the Company and has a payout consequence is properly reflected in all material respects in the Reserve Report and on Schedule 4.23 of the Company Disclosure Schedule as of the respective dates shown thereon. To the knowledge of the Company, based on information given to the Company by third-party operators for each well not operated by the Company, the payout consequence for any such well is properly reflected in all material respects in the Reserve Report and on Schedule 4.23 of the Company Disclosure Schedule as of the respective dates shown thereon. 4.24 PREPAYMENTS. Except as reflected on Schedule 4.24 of the Company Disclosure Schedule, no prepayment for Hydrocarbon sales has been received by the Company for Hydrocarbons which have not been delivered. 4.25 CAPITAL EXPENDITURES. Except as set forth on Schedule 4.25 of the Company Disclosure Schedule, as of the date of this Agreement, the presently approved face amount of any currently outstanding and effective authorities for expenditure with respect to the Ownership Interests would not require the Company to make or incur after the Closing capital expenditures under the terms of any such authority for expenditure in excess of $100,000 or $1.0 million in the aggregate for all such authorities for expenditures. 4.26 FINANCIAL AND PRODUCT HEDGING CONTRACTS. Schedule 4.26 of the Company Disclosure Schedule accurately summarizes in all material respects the outstanding hedging positions under all outstanding Product Hedging Contracts and financial hedging positions of the Company (including fixed price controls, collars, swaps, caps, hedges and puts) as of the date reflected on Schedule 4.26 of the Company Disclosure Schedule. 4.27 BOOKS AND RECORDS. All books, records and files of the Company and its Subsidiaries (including those pertaining to the Ownership Interests), all of which have been made available to Buyer, have been prepared, assembled and maintained in accordance with usual and customary policies and procedures. The books, records and accounts of the Company and its Subsidiaries accurately and fairly reflect in reasonable detail the transactions and dispositions of the assets of the Company and it Subsidiaries. The Company and its Subsidiaries have devised 33 and maintain a system of internal accounting controls sufficient to provide reasonable assurances that (i) transactions are executed in accordance with management's general or specific authorization; (ii) transactions are recorded as necessary (a) to permit preparation of financial statements in conformity with generally accepted accounting principles or any other criteria applicable to such statements and (b) to maintain accountability for assets; (iii) access to assets is permitted only in accordance with management's general or specific authorization and (iv) the recorded accountability for assets is compared with the existing assets at reasonable intervals and appropriate action is taken with respect to any differences. The minute books of the Company and its Subsidiaries contain accurate and complete records of all meetings held of, and corporate action taken by, the stockholders, Boards of Directors and committees of the Boards of Directors of each of the Company and its Subsidiaries, and no meeting or other corporate action by any of the stockholders, Boards of Directors or committees of the Boards of Directors of the Company or its Subsidiaries has been held or taken for which minutes or written consents have not been prepared and are not contained in such minute books. 4.28 RESERVE REPORT. Except as set forth on Schedule 4.28 of the Company Disclosure Schedule: (a) to the knowledge of the Company, the estimates of recoverable reserves attributable to the Ownership Interests which are set forth in the Reserve Report have been prepared in accordance with generally accepted petroleum engineering and evaluation principles as set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserve Information promulgated by the Society of Petroleum Engineers, and (b) the factual information underlying the estimates of reserves in the Reserve Report (including production, volumes, sales prices for production, contractual pricing provisions under oil or gas sales or marketing contracts under hedging arrangements, costs of operations and development, and working interest and net revenue information relating to the Ownership Interests) was true and correct in all material respects on the date of the Reserve Report; provided, however the foregoing representation and warranty is expressly subject to the following exceptions: (i) the reserves included in the Reserve Report are estimates only and should not be construed as exact quantities, (ii) such reserves may or may not be recovered and, if recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts, (iii) the sales rates, prices received for the reserves, and costs incurred in recovering such reserves may vary from assumptions included in such report due to governmental policies and uncertainties of supply and demand, and (iv) estimates of such reserves may increase or decrease as a result of future operations. 4.29 POWERS OF ATTORNEY, AUTHORIZED SIGNATORIES, REGISTERED AGENTS. Schedule 4.29 of the Company Disclosure Schedule lists (a) the names and addresses of all Persons holding powers of attorney on behalf of the Company or any of its Subsidiaries, (b) the names of all banks and other financial institutions in which the Company or any of its Subsidiaries currently has one or more bank accounts or safe deposit boxes, along with the account numbers and the names of all persons authorized to draw on such accounts or to have access to such safe deposit boxes, and (c) all registered agents of the Company and its Subsidiaries by jurisdiction. 4.30 ABSENCE OF CERTAIN CHANGES OR EVENTS. Except as set forth on Schedule 4.30 of the Company Disclosure Schedule, since December 31, 2003, each of the Company and its Subsidiaries have conducted their business only in the ordinary course of business, and there has not been: 34 (a) any event, change, effect or development that, individually or in the aggregate, has had or would reasonably be expected to have a Material Adverse Effect on the Company; (b) any declaration, setting aside or payment of any dividend or other distribution (whether in cash, stock, property or otherwise) with respect to any capital stock of the Company or any of its Subsidiaries (other than dividends or distributions by a Subsidiary to the Company) or any repurchase, redemption or other acquisition or offer to do so by the Company or any of its Subsidiaries of any capital stock or other equity securities of, or other ownership interests in, the Company or any of its Subsidiaries; (c) any split, combination or reclassification of any Company capital stock or any issuance of or the authorization of any issuance of any other securities in respect of, in lieu of or in substitution for, shares of such capital stock; (d) other than the $2,000,000 of release and bonus payment amounts included in the Company Transaction Costs, any grant by the Company or any of its Subsidiaries (including HRM) of any increase in compensation to any director, officer, stockholder or (except in the ordinary course of business) employee, any payment of any bonus or other benefit to any director, officer, stockholder or employee or any adoption or modification of any profit sharing, bonus, deferred compensation, savings, insurance, retirement or other employee benefit plan for or with any employees of the Company or any of its Subsidiaries; (e) any change in accounting methods, principles or practices, except for such changes as may have been required by a change in GAAP; (f) any (i) material elections with respect to Taxes by the Company or any of its Subsidiaries, (ii) settlement or compromise by the Company or any of its Subsidiaries of any material Tax liability or refund or (iii) assessment of a material Tax against the Company or any of its Subsidiaries by any Governmental Entity; (g) any amendment of any term of any outstanding security of the Company or any of its Subsidiaries that would materially increase the obligations of the Company or any of its Subsidiaries under such security; (h) any incurrence, assumption or guarantee by the Company or any of its Subsidiaries of any indebtedness for borrowed money except for borrowings under the Bank Credit Agreement; (i) any creation or assumption by the Company of any of its Subsidiaries of any Lien other than Permitted Encumbrances on any asset of the Company or any of its Subsidiaries; (j) any making of any loan, advance or capital contribution to or investment in any person by the Company or any of its Subsidiaries other than (i) in connection with any acquisition or capital expenditure permitted by Section 6.1, or (ii) loans or advances to employees of the Company or any of its Subsidiaries made in the ordinary course of business; 35 (k) (i) any acquisition by the Company or any of its Subsidiaries by merging or consolidating with, or by purchasing a substantial equity interest in or a substantial portion of the assets of, or by any other manner, any business or any corporation, partnership, joint venture, association or other business organization or division thereof, (ii) any sale, lease, license, encumbrance or other disposition of material assets of the Company or any of its Subsidiaries, other than sales of produced Hydrocarbons or tangible equipment and inventory in the ordinary course of business and the Lien securing the Bank Credit Agreement, (iii) any capital expenditures by the Company or any of its Subsidiaries, other than (A) in connection with its drilling and completion activities (both on Company-operated and non-operated properties), new oil and gas leases, renewals of oil and gas leases, non-producing leasehold acquisitions, acquisitions of producing oil and gas properties and otherwise in the ordinary course of business, or (B) capital expenditures contained in the Capital Budget (2004), or (iv) any modification, amendment, assignment, cancellation, waiver or termination by the Company or any of its Subsidiaries of any Material Agreement, material license or other material right (other than oil and gas leases or other agreements or contracts expiring pursuant to their terms or the Bank Credit Agreement); (l) any material damage, destruction or loss (whether or not covered by insurance) with respect to any assets of the Company or any of its Subsidiaries; (m) any downward revaluation by the Company or any of its Subsidiaries of any of its material assets, including but not limited to writing down the value of its oil and gas properties as a whole or writing off notes or accounts receivable, other than in the ordinary course of business; (n) except as set forth in Schedule 4.26 of the Company Disclosure Schedule, any agreement or arrangement by or involving the Company or any of its Subsidiaries providing for options, swaps, floors, caps, collars, forward sales or forward purchases involving commodities or commodity prices, or indexes based on any of the foregoing and any other similar agreement or arrangement or other derivative security; or (o) any agreement, commitment or undertaking to take any action referred to in Sections 4.30(a) through 4.30(n). 4.31 RELATED PARTY TRANSACTIONS. Except as set forth in Schedule 4.31 of the Company Disclosure Schedule, to the knowledge of the Company no stockholder or any officer or director of the Company or any of its Subsidiaries owns or holds, directly or indirectly, any interest in (excepting holdings solely for passive investment purposes of securities of publicly held and traded entities constituting less than 5% of the equity of any such entity), or is an officer, director, employee or consultant of any Person that is, a competitor, lessor, lessee, customer or supplier of the Company or any of its Subsidiaries. No stockholder, officer or director of the Company or any of its Subsidiaries (a) to the knowledge of the Company has any claim, charge, action or cause of action against the Company or any of its Subsidiaries, except for claims for reasonable unreimbursed travel or entertainment expenses, accrued vacation payor accrued benefits under any Company Employee Benefit Plan existing on the date hereof, (b) to the knowledge of the Company, has made, on behalf of the Company or any of its Subsidiaries, any payment or commitment to pay any commission, fee or other amount to, or to purchase or 36 obtain or otherwise contract to purchase or obtain any goods or services from, any other person of which any stockholder owning more than 1% of the outstanding common stock of the Company or any officer or director of the Company or any of its Subsidiaries is a partner or stockholder (except holdings solely for passive investment purposes of securities of publicly held and traded entities constituting less than 5% of the equity of any such entity), (c) owes any money to, the Company or any of its Subsidiaries or (d) has any interest in any property, real or personal, tangible or intangible, used in or pertaining to the business of the Company or any of its Subsidiaries. ARTICLE 5 REPRESENTATIONS AND WARRANTIES OF BUYER Buyer represents and warrants to the Company and the Securityholders as follows: 5.1 ORGANIZATION. Buyer (a) is a corporation duly incorporated, validly existing and in good standing under the laws of the State of Delaware, (b) has the requisite power and authority to own, lease and operate its properties and to conduct its business as it is presently being conducted, and (c) is duly qualified to do business as a foreign corporation, and is in good standing, in each jurisdiction where the character of the properties owned or leased by it or the nature of its activities makes such qualification necessary (except where any failure to be so qualified as a foreign corporation or to be in good standing would not be reasonably likely to have a Material Adverse Effect on Buyer). 5.2 AUTHORITY AND ENFORCEABILITY. Buyer has all requisite power and authority to enter into this Agreement and to consummate the transactions contemplated herein. The execution and delivery of this Agreement by Buyer and the consummation of the transactions contemplated herein have been duly authorized by all necessary corporate action on the part of Buyer. This Agreement has been duly executed and delivered by Buyer and, assuming that this Agreement constitutes the valid and binding agreement of the other parties hereto, constitutes the valid and binding obligations of Buyer, enforceable against Buyer in accordance with its terms and conditions, except that the enforcement hereof may be limited by (i) applicable bankruptcy, insolvency, reorganization, moratorium, fraudulent conveyance or other similar laws now or hereafter in effect relating to creditors' rights generally and (ii) general principles of equity (regardless of whether enforceability is considered in a proceeding at law or in equity). 5.3 NO VIOLATIONS. The execution and delivery of this Agreement does not, and the consummation of the transactions contemplated hereby and compliance by Buyer with the provisions hereof will not, conflict with, result in any violation of or default (with or without notice or lapse of time or both) under, give rise to a right of termination, cancellation or acceleration of any obligation or to the loss of a material benefit under, or result in the creation of any Lien on any of the properties or assets of Buyer under, any provision of (a) the certificate of incorporation or bylaws of Buyer, (b) any loan or credit agreement, note, bond, mortgage, indenture applicable to Buyer or (c) assuming the consents, approvals, authorizations or permits and filings or notifications referred to in Section 5.4 are duly and timely obtained or made, any laws (including common law), statutes, rules, regulations, ordinances, judgments, orders, decrees, injunctions and writs of any Governmental Authority having jurisdiction over the business or operations of Buyer, as may be in effect on the date of this Agreement or the Closing 37 Date, other than any such conflict, violation, default, right, loss or Lien that, individually or in the aggregate, would not have a Material Adverse Effect on Buyer. 5.4 CONSENTS AND APPROVALS. No Third-Party Consent of, or registration, declaration or filing with, any Person is required by or with respect to Buyer in connection with the execution and delivery by Buyer of this Agreement or the consummation of the transactions contemplated herein, except for (a) such Third-Party Consents as may be required under any environmental, health or safety law or regulation pertaining to any notification, disclosure or required approval necessitated by the transactions contemplated by this Agreement and (b) such other Third-Party Consents, the failure of which to obtain would not be reasonably likely to have a Material Adverse Effect on Buyer. 5.5 LITIGATION. There is no action, suit or judicial or administrative proceeding pending or, to the knowledge of Buyer, threatened against Buyer relating to the transactions contemplated by this Agreement or which, if adversely determined, would be reasonably likely to have a Material Adverse Effect on Buyer. 5.6 FUNDING. Buyer has available adequate funds or the means to obtain adequate funds in an aggregate amount sufficient to pay (i) the Closing Aggregate Purchase Price to each Securityholder and (ii) all expenses incurred in connection with this Agreement and the transactions contemplated hereby. 5.7 BROKERS. No broker, finder, investment banker or other Person is or will be, in connection with the transactions contemplated by this Agreement, entitled to any brokerage, finder's or other fee or compensation based on any arrangement or agreement made by or on behalf of Buyer and for which the Company will have any obligation or liability. ARTICLE 6 COVENANTS 6.1 CONDUCT OF BUSINESS BY THE COMPANY PENDING CLOSING. (a) Except as contemplated by this Agreement or the matters disclosed on the Company Disclosure Schedule or to the extent that Buyer shall otherwise consent in writing (which consent will not be unreasonably withheld), during the period from the date of this Agreement to the Closing, the Company shall not, and shall not permit any of its Subsidiaries to take any action except in the ordinary course of business and the Company shall, and shall cause its Subsidiaries to use all reasonable efforts to preserve intact in all material respects the respective business organizations, assets, prospects and advantageous business relationships of the Company and its Subsidiaries and to maintain satisfactory relationships with their respective licensors, licensees, suppliers, contractors, distributors and customers. Without limiting the generality of the foregoing, except as contemplated by this Agreement or the matters disclosed on the Company Disclosure Schedule, the Company shall not, and shall not cause or permit any of its Subsidiaries to engage in any practice, take any action, or enter into any transaction outside the ordinary course of business. Without limiting the generality of the foregoing and except as set forth on the Company Disclosure Schedule or the transactions contemplated by this Agreement, the Company shall not, and shall not cause or permit any of its Subsidiaries to: 38 (i) (A) declare, set aside or pay any dividends on, or make any other distributions (whether in cash, stock, property or otherwise) in respect of, any of the Company's or any of its Subsidiary's capital stock (other than dividends or distributions by a Subsidiary to the Company), (B) effect any reorganization or recapitalization or split, combine or reclassify any of its capital stock or issue or authorize the issuance of any other securities in respect of, in lieu of or in substitution for shares of its capital stock, or (C) except for repurchases pursuant to the Company's Option Plan effective as of March 10, 2000, as amended, directly or indirectly offer to or purchase, redeem or otherwise acquire any shares of its capital stock or any other securities thereof or any rights, warrants or options to acquire any such shares or other securities; (ii) offer, issue, deliver, sell, grant, pledge, transfer or otherwise encumber or dispose of or subject to any Lien or limitation on voting rights (A) any shares of the Company's or any of its Subsidiary's capital stock, (B) any securities convertible into or exchangeable for, or any options, warrants, commitments or rights of any kind to acquire, any such shares, voting securities or convertible or exchangeable securities or (C) any "phantom" stock, "phantom" stock rights, stock appreciation rights or stock-based performance units, other than the issuance of Company common stock upon the exercise of Options outstanding on the date of this Agreement and in accordance with their terms as in effect on the date of this Agreement; (iii) propose or adopt any amendments to its articles of incorporation or bylaws or amend or otherwise modify the terms of any outstanding capital stock, securities convertible into or exchangeable for, or any options, warrants, commitments or rights of any kind to acquire such securities of the Company or any of its Subsidiaries the effect of which will make such terms more favorable to the holders thereof; (iv) expand, or fail to maintain, its planned level of drilling and completion activities with respect to properties that it operates in accordance with the drilling schedule covering the next 90 days that the Company has provided to Buyer and that identifies the wells to be drilled during such period, except to the extent the Company reasonably believes such activities would result in a default of a covenant under the Bank Credit Agreement or where it would be reasonable for a prudent operator to change drilling locations, delay or accelerate drilling of specific wells or change the order of drilling of wells to maximize the efficiency of the drilling program and/or to minimize risks and/or costs of such program, provided that such change, delay or acceleration in such program is discussed at an operational meeting of the Company at which Buyer has a representative and reasonable operational consensus is achieved, or fail to continue to participate in the ordinary course of business in drilling, workover, completion and recompletion activities with respect to properties it does not operate without prior notification to Buyer; (v) (A) merge, consolidate, combine, dissolve or liquidate or resolve to or publicly announce an intention to do any of the foregoing, (B) (other than through the exercise of a consent right under the terms of a joint operating agreement) acquire or agree to acquire, directly or indirectly by merger, consolidation, equity interest purchase or otherwise, any producing oil and gas properties, or enter into or acquire any new non-producing oil and gas leases, or (C) enter into or acquire any renewals of non-producing oil and gas leases; 39 (vi) (A) grant to any employee, officer or director of the Company or any Subsidiaries (including HRM) any increase in compensation or pay any bonus or other benefit (other than the $2,000,000 of release and bonus payment amounts included in the Company Transaction Costs), (B) establish, adopt or enter into any agreement or plan that would constitute a Company Employee Benefit Plan (if it had been in effect on the date hereof), any collective bargaining agreement, or other labor union agreement or amend any Company Employee Benefit Plan, collective bargaining agreement or other labor union agreement or (C) grant any severance or termination pay; (vii) make any change in accounting methods, principles or practices in effect at December 31, 2003, except as required by a change in GAAP; (viii) sell, lease (as lessor), license, farm out, encumber or otherwise dispose of (other than through the exercise of a non-consent right under the terms of a joint operating agreement) or subject to any Lien other than Permitted Encumbrances any properties or assets, except for sales of produced Hydrocarbons or for sales of tangible equipment or inventory of not more than $50,000; (ix) (A) incur, create, assume, guarantee or otherwise become liable for any indebtedness except (x) trade debt in the ordinary course of business and (y) pursuant to existing credit facilities or arrangements or any extensions, renewals or redeterminations thereof, or (B) make or forgive any loans, advances or capital contributions to, or investments in, any other Person; (x) make or change any material Tax election or settle or compromise any material Tax liability or refund or change any of its methods of reporting income or deductions for U.S. federal tax purposes except as may be required by Applicable Law; (xi) (A) pay, discharge, settle or satisfy any claims, liabilities, obligations or litigation other than insured claims or liabilities, repayments of borrowings under the Bank Credit Agreement or the payment, discharge, settlement or satisfaction, in accordance with their terms, of liabilities reflected or reserved against in the most recent financial statements (or the notes thereto) of the Company provided to Buyer prior to the date hereof or incurred since the date of such financial statements in the ordinary course of business or (B) cancel or forgive any indebtedness to the Company or any Subsidiary; (xii) permit any material insurance policy naming it as a beneficiary or a loss payable payee to lapse, be cancelled or expire unless a new policy with substantially identical coverage is in effect as of the date of lapse, cancellation or expiration; (xiii) enter into any material renewal of, modification to or amendment to, or terminate any Material Agreement, or waive, delay the exercise of, assign or release any material rights or claims thereunder, except as otherwise permitted above in this Section 6.1, or enter into or amend in any material manner any agreement or commitment with any former or present director, officer or employee of the Company or any Subsidiary or with any affiliate of any of the foregoing persons; 40 (xiv) except as contemplated in the Capital Budget (2004), none of the Company and its Subsidiaries shall make any capital expenditure without the prior consent of Buyer; (xv) none of the Company and its Subsidiaries will modify, renew or amend the terms of or close out any of its positions under its existing Product Hedging Contracts or enter into any new hedging position or any other agreement providing for options, swaps, floors, caps, collars, forward sales or forward purchases involving commodities or commodity prices, or indexes based on any of the foregoing and any other similar agreement or arrangement or other derivative security; (xvi) transfer or assign to HRM, or cause or allow HRM to transfer or assign to the Company or any of its Subsidiaries, any assets, properties, rights or obligations other than as specifically provided in Section 2.6; or (xvii) authorize, or commit or agree to take, any of the foregoing actions or take any action that would (y) make any representation or warranty in Article 3 or Article 4 hereof untrue or incorrect in any material respect, or (z) result in any of the conditions set forth in Article 7 hereof not being satisfied. (b) Notwithstanding anything in Section 6.1(a) to the contrary, in the event of an emergency with respect to the Ownership Interests, the Company and its Subsidiaries may take such action as a prudent operator would take to protect life, health, the environment or property and shall notify Buyer of such action promptly thereafter. (c) Notwithstanding anything in Section 6.1(a) to the contrary, prior to the Closing the Company and its Subsidiaries shall, with respect to their respective obligations under the Furst Ranch Exploration Agreement and the Furst Ranch Oil and Gas Lease that are necessary to extend such agreements to the second phase of drilling commitments, (i) obtain all necessary Third-Party Consents for the drilling of two additional wells and (ii) drill and case such wells in accordance with the drilling plans therefor so that such wells may be subsequently completed. In addition, the Company and its Subsidiaries shall use their reasonable best efforts to cause Enbridge to begin in earnest its work (including clearing and trenching operations and laying pipe) such that it is reasonably certain that the Furst Ranch Exploration Agreement and the Furst Ranch Oil and Gas Lease will be extended to the second phase of drilling commitments. (d) Notwithstanding anything in Section 6.1(a) to the contrary, prior to the Closing the Company shall cause its Subsidiary Cortez Operating Company to further amend its amended certificate of incorporation to delete Article XI thereof relating to "Control Share Acquisitions" and any related provisions. (e) The Company and its Subsidiaries shall report periodically to Buyer regarding the status of their business, operations and financial condition, such reporting to include any changes in production, transportation or processing imbalances with respect to the Ownership Interests. 6.2 ACCESS TO ASSETS, PERSONNEL AND INFORMATION. 41 (a) From the date hereof until the Closing, the Company shall afford to Buyer and the Buyer Representatives, at Buyer's sole risk and expense, reasonable access, during normal business hours, upon reasonable prior notice and in such manner as will not unreasonably interfere with the conduct of business of the Company or any of its Subsidiaries, to all of the assets, properties, books and records, contracts, facilities, audit and tax work papers, information systems and computer networks, and payroll records of the Company or any of its Subsidiaries (including access to the Operated Properties to conduct Environmental and Regulatory Assessments) and to any of the directors, officers, personnel or professional advisors (including the Company's independent public accountants) of the Company or any of its Subsidiaries and shall, upon reasonable request, furnish promptly to Buyer (at Buyer's expense) a copy of any file, book, record, contract, permit, correspondence, or other written information, document or data concerning the Company or any of its Subsidiaries (or any of their respective assets) that is within the possession or control of the Company or any of its Subsidiaries. The Company and its Subsidiaries shall instruct Ernst & Young LLP, the Company's independent accountants, to reasonably cooperate with Buyer in connection with Buyer's evaluation of the business, operations and financial condition of the Company and its Subsidiaries. In that connection, the Company and its Subsidiaries shall promptly provide to Ernst & Young LLP such waivers, releases or other documentation as may be reasonably necessary to effectuate the purposes and intents of the preceding sentence. (b) Notwithstanding anything in this Section 6.2 to the contrary, (i) the Company shall not be obligated under the terms of this Section 6.2 to disclose to Buyer or the Buyer Representatives, or grant Buyer or the Buyer Representatives access to, information that is within the Company's possession or control but subject to a valid and binding confidentiality agreement with a third party that prohibits such disclosure without first obtaining the consent of such third party, and the Company, to the extent reasonably requested by Buyer, will use its reasonable efforts to obtain any such consent and (ii) is subject to an attorney/client or attorney work product privilege ("Company Privileged Information"); provided, however, that with respect to any information that the Company claims is Company Privileged Information, the Company agrees to describe such information as fully and completely as reasonably possible without resulting in the loss of such privilege or disclosing specific legal advice and to reasonably cooperate with Buyer in providing additional information reasonably requested by Buyer, in as much detail as reasonably possible while maintaining the confidential or privileged nature of such information. 6.3 ENVIRONMENTAL STUDIES. The Company hereby acknowledges Buyer's right to conduct a Phase I environmental analysis (as contemplated by the most recent version of ASTM 1527E) of the Operating Properties. Notwithstanding anything to the contrary contained herein, prior to the Closing, no further inspections, including invasive or intrusive samplings or studies, may be conducted by Buyer, its Affiliates or any of their respective representatives with respect to any properties of the Company or its Subsidiaries without the consent of the Company, which consent may be withheld in the Company's sole and absolute discretion. The Company shall advise Buyer as to whether it consents to such further inspections within three calendar days of Buyer's written request to conduct same. 6.4 THIRD PARTY CONSENTS. After the date hereof and prior to the Closing, the Company shall use its commercially reasonable efforts, but excluding any obligation to make 42 any payments, to obtain Third-Party Consents under the Material Agreements that are required to permit the consummation of the transactions contemplated by this Agreement. 6.5 PUBLIC ANNOUNCEMENTS; CONFIDENTIALITY. (a) Prior to the Closing, the Company and Buyer shall consult with each other before any of them issues any press release or otherwise makes any public statements with respect to the transactions contemplated by this Agreement; provided, however, that such approval shall not be required where such release or announcement is required by any laws (including common law), statutes, rules, regulations, ordinances, judgments, orders, decrees, injunctions and writs of any Governmental Authority having jurisdiction over the business or operations of the Company or Buyer; and provided further, that either the Company or Buyer may respond to inquiries by the press or others regarding the transactions contemplated by this Agreement, so long as such responses are consistent with such party's previously issued press releases. (b) From and after the date hereof, each Restricted Party agrees, severally and not jointly with any other Person, to keep confidential and protect, and not divulge or otherwise allow access to any and all information of the Company or any of its Subsidiaries relating to or arising out of the business or operations of the Company and its Subsidiaries, including any and all notes, analyses, compilations, studies, summaries and other material containing or based, in whole or in part, on any such information (the "Confidential Information"). Each Restricted Party agrees, severally and not jointly with any other Person, that such Confidential Information constitutes a unique and valuable asset, and that any disclosure of such Confidential Information in breach of this Section 6.5(b) would be wrongful and would cause irreparable harm to Buyer. The foregoing obligations of confidentiality will not apply to any Confidential Information (i) that is now or subsequently becomes generally publicly known, other than as a direct or indirect result of the breach of this Agreement by any Restricted Party, (ii) that a Restricted Party receives from a third party without obligation of confidentiality, (iii) that a Restricted Party independently develops after Closing or (iv) that is learned or developed by a Restricted Party as a result of his or its general experience in the oil and gas business. Each Restricted Party agrees, severally and not jointly with any other Person, that the provisions and restrictions contained in this Section 6.5(b) are necessary to protect the legitimate continuing interests of Buyer in acquiring the Company and entering into this Agreement, that the covenants in this Section 6.5(b) have been specifically bargained for, that any violation or breach of such provisions and restrictions will result in irreparable injury to Buyer for which a remedy at law would be inadequate and that, in addition to any relief at law that may be available to Buyer for such violation or breach and regardless of any other provision contained in this Agreement, Buyer will be entitled to injunctive or other equitable relief restraining such violation or breach (without any requirement that Buyer provide any bond or other security). All obligations arising under this Section 6.5(b) shall terminate in full as of the first anniversary of the Closing Date. 6.6 NOTIFICATION OF CERTAIN MATTERS. The Company shall give prompt written notice to Buyer of (a) the occurrence, or failure to occur, of any event of which it has knowledge that has caused any representation or warranty of the Company contained in this Agreement to be untrue or inaccurate in any material respect as of the date of this Agreement and (b) the failure of the Company to comply with or satisfy in any material respect any covenant to be complied with 43 by it hereunder. No such notification shall affect the representations or warranties of the parties or the conditions to their respective obligations hereunder. 6.7 NO NEGOTIATIONS. None of the Securityholders, the Company, its Subsidiaries nor their officers, directors, employees, Affiliates, stockholders, representatives, agents, nor anyone acting on behalf of any of them shall, directly or indirectly, encourage, solicit, initiate or engage in discussions or negotiations with, provide any nonpublic information or assistance to, or consider the merits of any unsolicited inquiries or proposals from, any Person (other than Buyer) concerning any merger, sale of assets, purchase or sale of equity securities or similar transaction involving, directly or indirectly, the Company or its Subsidiaries unless this Agreement is terminated pursuant to and in accordance with Article 8. The Company shall notify Buyer of such inquiries or proposals (including in such notification the identity of the Person making the inquiry or proposal and the terms thereof), if any, and of any subsequent communications by the Person making such inquiry or proposal, in each case within 24 hours of the making thereof. 6.8 ACCESS TO INFORMATION. From and after the Closing Date, Buyer shall, and shall cause the Company and each of its Subsidiaries to, during normal business hours and upon reasonable notice, make available to each Securityholder and their respective representatives (including counsel and independent auditors) reasonable access to all financial and Tax information, files, documents and records (written and computer) of the Company and its Subsidiaries, to the extent that such access is reasonably required in order for a Securityholder to comply with a Tax or other legally required reporting obligation or Tax or legal dispute (excluding any such dispute in which the Company, Buyer or any of their Affiliates may be an adverse party) arising out of any period prior to and including the Closing Date. Any such access shall be at the sole cost and expense of the respective Securityholder. 6.9 INVESTIGATION AND AGREEMENT BY BUYER; NO OTHER REPRESENTATIONS OR WARRANTIES. (a) Buyer acknowledges and agrees that it has made its own inquiry and investigation into, and, based thereon, has formed an independent judgment concerning, the Company and its Subsidiaries and their respective businesses and operations, and Buyer has been furnished with or given full access to such information about the Company and its Subsidiaries and their respective businesses and operations as they requested. In connection with Buyer's investigation of the Company and its Subsidiaries and their respective businesses and operations, Buyer and its representatives have received from the Company or its representatives certain projections and other forecasts for the Company and its Subsidiaries and certain estimates, plans and budget information. Buyer acknowledges and agrees that (i) there are uncertainties inherent in attempting to make such projections, forecasts, estimates, plans and budgets, (ii) Buyer is familiar with such uncertainties, (iii) Buyer is taking full responsibility for making its own evaluations of the adequacy and accuracy of all estimates, projections, forecasts, plans and budgets so furnished to them or its representatives and (iv) Buyer will not (and will cause all of its Subsidiaries and other Affiliates and all other Persons acting on its behalf to not) assert any claim or cause of action against the Company, its Subsidiaries or any of the Company's direct or indirect directors, officers, employees, agents, stockholders, Affiliates, consultants, counsel, accountants, investment bankers or representatives with respect thereto, or hold any such other Person liable with respect thereto. 44 (b) Buyer agrees that, except for the representations and warranties in Articles 3 and 4 of this Agreement, neither the Company nor any of its respective Affiliates has made and shall not be deemed to have made to Buyer or to any of its representatives or Affiliates any representation or warranty of any kind. Without limiting the generality of the foregoing, Buyer is not relying upon any projections, forecasts, estimates, plans or budgets of future revenues, expenses or expenditures, future results of operations (or any component thereof), future cash flows (or any component thereof) or future financial condition (or any component thereof) of the Company or any of its Subsidiaries or the future business, operations or affairs of the Company or any of its Subsidiaries heretofore or hereafter delivered to or made available to Buyer, its Affiliates or their respective counsel, accountants, advisors, lenders or other representatives. (c) The Company acknowledges and agrees that except for the representations and warranties made by Buyer as expressly set forth in this Agreement, neither Buyer nor any of its Affiliates has made and shall not be construed as having made to the Company or any Affiliate thereof any representation or warranty of any kind. 6.10 INDEMNIFICATION. (a) From and after the Closing, each of the Securityholders shall, severally and not jointly, indemnify, defend and hold harmless the Company, Buyer and their Affiliates and each of their respective directors, officers, employees, controlling persons, agents and representatives (the foregoing references to Affiliates, directors, officers, employees, controlling persons, agents and representatives being only to such Persons having such relationships or acting in such capacities after the Closing) and their successors and assigns (collectively, the "Buyer Indemnitees") from and against all liability, demands, claims, actions or causes of action, assessments, losses, damages, costs and expenses (including reasonable attorneys', experts' and consultants' fees and expenses as well as reasonable costs of investigation, sampling and defense) (collectively, "Buyer Damages") asserted against or incurred by any Buyer Indemnitee as a result or arising out of any breach of any representation or warranty contained in Article 3. (b) HRM hereby acknowledges and agrees that it is responsible for all employment and employee benefit-related liabilities and obligations (other than the obligation to make monthly payments pursuant to the Seal Agreement), whenever arising, related to (i) individuals performing services for the Company, any of its Subsidiaries or any ERISA Affiliate at any time prior to the Closing and (ii) employee benefit plans or arrangements of any kind with respect to any such individuals, including for purposes of clauses (i) and (ii), (A) any obligation pursuant to COBRA (or any equivalent state continuation coverage requirement) to provide post-employment group health plan coverage to any employee or former employee of the Company or any Subsidiary, and (B) any obligation for any income and employment Tax withholding, reporting or payment obligations (including FICA, Medicare and FUTA) and any contributions to the HRM 401(k) Plan, in each case relating to the payment(s) provided for in Section 2.1(g). From and after the Closing, HRM shall indemnify, defend and hold harmless the Buyer Indemnitees from and against all Buyer Damages asserted against or incurred by any Buyer Indemnitee as a result or arising out of (I) the matters described in the preceding sentence, (II) any other liability or obligation of HRM and (III) any of the Excluded Assets. 45 6.11 INDEMNIFICATION OF OFFICERS AND DIRECTORS. (a) On and following the Closing, Buyer shall cause the Company (or its successors and assigns) to indemnify the officers and directors of the Company and its Subsidiaries to the same extent as any such entity is required to indemnify any such person pursuant to its certificate of incorporation or by-laws as in effect on the date of this Agreement. (b) On and following the Closing, Buyer shall cause the Company (or its successors and assigns) to perform the indemnification obligations under the agreements identified on Schedule 6.11(b) of the Company Disclosure Schedule. 6.12 COMPLIANCE WITH FURST RANCH EXPLORATION AGREEMENT. Buyer acknowledges and understands the "tag along" and related rights (the "Tag-Along Rights") of Jack D. Furst pursuant to Section 8 of the Furst Ranch Exploration Agreement that are triggered upon execution of this Agreement and in connection therewith Buyer hereby agrees as follows: (a) Buyer hereby acknowledges that Schedule 1.1-A sets forth the Allocated Value of the Company's 50% working interest in the Furst Ranch Oil and Gas Lease; and (b) on and following the Closing Date, Buyer shall cause the Company to comply in all respects with the Tag-Along Rights. ARTICLE 7 CONDITIONS 7.1 CONDITIONS TO EACH PARTY'S OBLIGATION. The respective obligations of the Company, Securityholders and Buyer to effect the transactions contemplated hereby are subject to the satisfaction on or prior to the Closing Date of the following conditions: (a) Consents and Approvals. All Third-Party Consents imposed by any Governmental Authority necessary for the consummation of the transactions contemplated by this Agreement shall have been obtained, occurred or been filed. (b) No Injunctions or Restraints. No temporary restraining order, preliminary or permanent injunction or other order issued by any court of competent jurisdiction or other legal restraint or prohibition preventing the consummation of the transactions contemplated by this Agreement shall be in effect. (c) No Action. No action shall have been taken nor any statute, rule or regulation shall have been enacted by any Governmental Authority that makes the consummation of the transactions contemplated hereby illegal. (d) Adjustments. Buyer and the Company shall have reached an agreement or an arbitrative order shall have been obtained as to amounts for adjustment pursuant to Section 2.4 (including the sufficiency of any cure pursuant to Section 2.4(c)) and Section 2.5(c). 46 7.2 CONDITIONS TO OBLIGATION OF BUYER. The obligation of Buyer to effect the transactions contemplated hereby is subject to the satisfaction of the following conditions unless waived, in whole or in part, by Buyer: (a) Representations and Warranties. Each of the representations and warranties of the Company and the Securityholders set forth in this Agreement shall be true and correct in all material respects as of the date of this Agreement (except for any representations or warranties that are qualified by the concept of materiality, which shall be true and correct in all respects) and (except to the extent such representations and warranties speak expressly as of an earlier date) as of the Closing Date as though made on and as of the Closing Date; provided, however, that the requirements of the preceding clause shall be deemed to have been satisfied (i) with respect to the first $1,250,000 of value attributed to breaches of representations and warranties (without giving effect to knowledge qualifications or the materiality qualifications described in Section 2.4(b)(i) or disclosures made on Schedule 4.16 of the Company Disclosure Schedule as provided in Section 2.4(b)(i)), (ii) to the extent that an adjustment to the Total Preliminary Aggregate Purchase Price has been made in respect of an asserted Rep and Warranty Defect in accordance with Section 2.4 or (iii) with respect to a breach of a representation or warranty that was made known in writing to Buyer by the Company not later than the fifth calendar day prior to the Notice Date and was not raised in a Defect Notice. Buyer shall have received a certificate signed on behalf of each Securityholder to such effect with respect to such Securityholder's representations and warranties in Article 3. Buyer shall have received a certificate signed on behalf of the Company by the Chief Executive Officer or the Chief Financial Officer of the Company to such effect with respect to the representations and warranties in Article 4. (b) Covenants of the Company and the Securityholders. The Company and the Securityholders shall have performed in all material respects all of their respective obligations required to be performed by them under this Agreement at or prior to the Closing Date, and Buyer shall have received a certificate signed on behalf of the Company by the Chief Executive Officer or the Chief Financial Officer of the Company to such effect. (c) Furst Ranch Matters. The covenant in Section 6.1(c) shall have been performed in all respects, and Enbridge shall have begun in earnest its work (including clearing and trenching operations and laying pipe) such that it is reasonably certain that the Furst Ranch Exploration Agreement and the Furst Ranch Oil and Gas Lease will be extended to the second phase of drilling commitments. (d) Closing Deliveries. The Company and the Securityholders, as applicable, shall have delivered to Buyer all documents, instruments, certificates or other items required to be delivered at the Closing by the Company and the Securityholders, as applicable, pursuant to this Agreement. 7.3 CONDITIONS TO OBLIGATIONS OF THE COMPANY AND THE SECURITYHOLDERS. The obligation of the Company and Securityholders to effect the transactions contemplated hereby is subject to the satisfaction of the following conditions unless waived, in whole or in part, by the Company: 47 (a) Representations and Warranties. Each of the representations and warranties of Buyer set forth in this Agreement shall be true and correct in all material respects as of the date of this Agreement (except for any representations and warranties that are qualified by the concept of materiality, which shall be true and correct in all respects) and (except to the extent such representations and warranties speak as of an earlier date) as of the Closing Date as though made on and as of the Closing Date. The Company shall have received a certificate signed on behalf of Buyer by the President or the Chief Financial Officer of Buyer to such effect. (b) Covenants of Buyer. Buyer shall have performed in all material respects all obligations required to be performed by Buyer under this Agreement at or prior to the Closing Date, and the Securityholders shall have received a certificate signed on behalf of Buyer by the President or the Chief Financial Officer of Buyer to such effect. (c) Closing Deliveries. Buyer shall have delivered to the Securityholders all documents, instruments, certificates or other items (including the Closing Aggregate Purchase Price) required to be delivered at the Closing by Buyer pursuant to this Agreement. ARTICLE 8 TERMINATION 8.1 TERMINATION. This Agreement may be terminated prior to the Closing and the transactions contemplated hereunder may be abandoned at any time prior to the Closing Date: (a) by mutual written consent of Buyer and the Company; (b) by Buyer if the Company refuses to consent to Buyer's conducting further inspections, including invasive or intrusive samplings and studies, as contemplated by Section 6.3 hereof; (c) by either Buyer or the Company: (i) if the aggregate of all adjustments pursuant to Sections 2.4 and 2.5(a)(i) would result in a reduction to the Total Preliminary Aggregate Purchase Price by more than $5,000,000; (ii) if there shall have been any breach by the other party of any representation, warranty, covenant or agreement set forth in this Agreement, which breach would give rise to the failure of a condition to the Closing hereunder; (iii) if a court of competent jurisdiction or other Governmental Authority shall have issued an order, decree or ruling or taken any other action (which order, decree or ruling Buyer and the Company shall use their reasonable best efforts to lift), in each case permanently restraining, enjoining or otherwise prohibiting the transactions contemplated by this Agreement and such order, decree, ruling or other action shall have become final and nonappealable; (iv) if the Closing shall not have occurred on or before June 30, 2004 (the "Termination Date"); provided, however, that the right to terminate this Agreement under 48 this clause (iv) shall not be available to any party whose breach of this Agreement has been the cause of, or resulted in, the failure of the Closing to occur on or before such date. 8.2 EFFECT OF TERMINATION. In the event of the termination of this Agreement by either the Company or Buyer as provided in Section 8.1, this Agreement shall forthwith become void and there shall be no liability or obligation hereunder on the part of Buyer, the Company or any Securityholder or their respective Affiliates, officers, directors, employees or stockholders, except (a) Article 8 and Article 10 shall survive such termination and (b) no such termination shall relieve any party from liability for breach of any term or provision hereof, provided that no party shall have any liability or obligation hereunder in the event of a termination of this Agreement pursuant to Section 8.1(b) or 8.1(c)(i). 8.3 RETURN OF DOCUMENTATION. Following termination of this Agreement in accordance with Section 8.1, Buyer shall return to the Company all agreements, documents, contracts, instruments, books, records, materials and all other information regarding the Company or any of its Subsidiaries or other Affiliates provided to Buyer or any Buyer Representatives in connection with the transactions contemplated by this Agreement. ARTICLE 9 LIMITATIONS ON COMPETITION 9.1 PROHIBITED ACTIVITIES. Each member of the Restricted Group agrees, severally and not jointly with any other Person, that except as otherwise provided herein such member of the Restricted Group will not, during the period beginning on the date hereof and ending with respect to the covenants set forth in Sections 9.1(a)(i), 9.1(a)(ii), 9.1(b) (insofar as it pertains to a Relevant Geographic Area described in Section 9.1(a)(i) or 9.1(a)(ii)) and 9.1(c) (insofar as it pertains to a Relevant Geographic Area described in Section 9.1(a)(i) or 9.1(a)(ii)), on the first anniversary of the Closing Date, and with respect to the covenants set forth in Section 9.1(a)(iii), 9.1(b) (insofar as it pertains to a Relevant Geographic Area described in Section 9.1(a)(iii)) and 9.1(c) (insofar as it pertains to a Relevant Geographic Area described in Section 9.1(a)(iii)) below, on the date six months immediately following the Closing Date (as applicable, the "Restricted Period"), directly or indirectly, for any reason, for such member's own account or on behalf of or together with any other Person: (a) acquire, for such member's own account or the account of any business in which he owns more than 1% of the outstanding capital stock, (i) in the case of Ownership Interests in Operated Properties in Denton County, Texas and Tarrant County, Texas, any interest in any oil or natural gas property within a one-mile radius of any such Operated Properties, (ii) in the case of all other Ownership Interests in Operated Properties, any interest in any oil or natural gas property on which such Ownership Interests are located or (iii) in the case of Ownership Interests that are not in Operated Properties, any interest in any oil or natural gas property on which such Ownership Interests are located (collectively, the "Relevant Geographic Area"), (b) accept employment, advise, assist or render service in any way to any Person that competes directly with the Company in the acquisition, exploration, development, exploitation or production of oil and natural gas in the Relevant Geographic Area or (c) enter into or take part in or lend his name, counsel or assistance to any business, either as proprietor, principal, investor, partner, director, officer, executive, consultant, advisor, agent, independent contractor, or in any other capacity whatsoever, for any purpose that would be directly competitive with the acquisition, exploration, development, exploitation or production 49 activities of the Company or any of its affiliated companies in the Relevant Geographic Area. Notwithstanding the foregoing, the provisions set forth in this Section 9.1 shall not apply or otherwise restrict any member of the Restricted Group from acquiring any ownership interest in property included in the Relevant Geographic Area and otherwise restricted pursuant to this Section 9.1 if such property (A) is not an Operated Property or the acquired ownership is in the form of a royalty interest and (B) does not have a PV-10% value in the Reserve Report of greater than $250,000. Notwithstanding the foregoing, any member of the Restricted Group may own and hold as a passive investment up to 5% of the outstanding capital stock of a competing Person if that class of capital stock is listed on a national stock exchange or included in the Nasdaq National Market. Further, notwithstanding the foregoing, each member of the Restricted Group may acquire interests in properties that are within the Relevant Geographic Area (other than properties within the boundaries of the real property described in the Furst Ranch Oil and Gas Lease) and otherwise restricted pursuant to this Section 9.1(a) (collectively, the "Restricted Properties") if such acquisition transaction is with one or more third parties and the Restricted Properties do not constitute more than 20% of the aggregate value of such acquisition transaction. For purposes of this Section 9.1, the word "acquire" and correlative terms shall mean and include all direct and indirect acquisitions, whether individually or through or in combination with another Person, and whether consummated through a purchase, lease, merger, consolidation, exchange, business combination or other transaction, in a single transaction or series of transactions. 9.2 INJUNCTIONS AND RESTRAINING ORDERS. Because of the difficulty of measuring economic losses to Buyer as a result of any breach by a member of the Restricted Group of such member's covenants in Section 9.1, and because of the immediate and irreparable damage that could be caused to Buyer for which it would have no other adequate remedy, each member of the Restricted Group agrees that Buyer may enforce the provisions of Section 9.1 by injunctions and restraining orders against that member if such member breaches any of those provisions. 9.3 RESTRAINT. The parties hereto each agree that Sections 9.1 and 9.2 impose a reasonable restraint on the Restricted Group in light of the activities and business of Buyer on the date hereof and the current business plans of Buyer. 9.4 SEVERABILITY; REFORMATION. The covenants in this Article 9 are severable and separate, and the unenforceability of any specific covenant in this Article 9 is not intended by any party hereto to, and shall not, affect the provisions of any other covenant in this Article 9. If any court of competent jurisdiction shall determine that the scope, time or territorial restrictions set forth in Section 9.1 are unreasonable as applied to any member of the Restricted Group, the parties hereto, including that member of the Restricted Group, acknowledge their mutual intention and agreement that those restrictions be enforced to the fullest extent the court deems reasonable, and thereby shall be reformed to that extent as applied to that member and any other member of the Restricted Group similarly situated. 9.5 INDEPENDENT COVENANT. All the covenants in this Article 9 are intended by each party hereto to, and shall, be construed as an agreement independent of any other provision in this Agreement, and the existence of any claim or cause of action of any member of the Restricted Group against Buyer, whether predicated on this Agreement or otherwise, shall not constitute a defense to the enforcement by Buyer of any covenant in this Article 9. It is 50 specifically agreed that the period specified in Section 9.1 shall be extended in the case of each member of the Restricted Group by the time during which that member is in violation of any provision of Section 9.1. The covenants contained in this Article 9 shall not be affected by any breach of any other provision hereof by any party hereto. 9.6 MATERIALITY. The Company and each member of the Restricted Group, severally and not jointly with any other Person, hereby agree that this Article 9 is a material and substantial part of the transactions contemplated hereby. ARTICLE 10 MISCELLANEOUS 10.1 SURVIVAL OF REPRESENTATIONS AND WARRANTIES. Except as expressly provided in Section 6.10, none of the representations or warranties contained in this Agreement or in any instrument delivered pursuant to this Agreement shall survive the Closing. Except as expressly provided in Section 2.4 and Section 6.10, the representations and warranties contained herein are to serve only as a basis for a party to assert, under Article 7, that the conditions to Closing have not been met and, under Article 8, that it has a specified termination right. Accordingly, after Closing and except as provided in Section 6.10 no party hereto shall have any liability to any other party hereto based upon any representation or warranty made herein or in any instrument delivered pursuant to or in connection with this Agreement. After the Closing, the provisions of Section 6.10 shall be Buyer's sole and exclusive remedy with respect to any breach of any representation, warranty or covenant of the Company, HRM or any Securityholder. 10.2 AMENDMENT AND MODIFICATION. This Agreement may only be amended by written agreement of the Company, Buyer and the Securityholder Representative or, as provided in Section 10.19, the applicable Securityholder. 10.3 NOTICES. (a) Any notice or other communication required or permitted hereunder shall be in writing and either delivered personally, by facsimile transmission, by a reputable overnight delivery service company or by registered or certified mail (postage prepaid and return receipt requested) and shall be deemed given upon receipt or written evidence of transmission by the sending party (or, if mailed, five Business Days after the date of mailing) at the following addresses or facsimile transmission numbers (or at such other address or facsimile transmission number for a party as shall be specified by like notice): (i) If to Buyer: Encore Acquisition Company 777 Main Street, Suite 1400 Ft. Worth, Texas 76102 Attention: President Facsimile: 817-877-1655 with a copy to: 51 Baker Botts L.L.P. 910 Louisiana Street Houston, Texas 77002 Attention: Sean T. Wheeler Facsimile: 713-229-7868 (ii) If to the Company: Cortez Oil & Gas, Inc. 2745 Dallas Parkway, Suite 220 Plano, Texas 75093 Attention: Chief Executive Officer Facsimile: 972-781-6505 with a copy to: Vinson & Elkins L.L.P. 2001 Ross Avenue, Suite 3700 Dallas, Texas 75201 Attention: A. Winston Oxley Facsimile: 214-999-7891 (iii) If to Securityholders or the Securityholder Representative: c/o C. Randall Hill Cortez Oil & Gas, Inc. 2745 Dallas Parkway, Suite 220 Plano, Texas 75093 Facsimile: 972-781-6505 with a copy to: Vinson & Elkins L.L.P. 2001 Ross Avenue, Suite 3700 Dallas, Texas 75201 Attention: A. Winston Oxley Facsimile: 214-999-7891 (b) Any of the above addresses may be changed at any time by notice given as provided above; provided, however, that any such notice of change of address shall be effective only upon receipt. 10.4 COUNTERPARTS. This Agreement may be executed in one or more counterparts, all of which shall be considered one and the same agreement and shall become effective when one or more counterparts have been signed by each of the parties and delivered to the other parties, it being understood that all parties need not sign the same counterpart. 52 10.5 SEVERABILITY. Any term or provision of this Agreement that is invalid or unenforceable in any jurisdiction shall, as to such jurisdiction, be ineffective to the extent of such invalidity or unenforceability without rendering invalid or unenforceable the remaining terms and provisions of this Agreement or affecting the validity or enforceability of any of the terms or provisions of this Agreement in any other jurisdiction. If any provision of this Agreement is so broad as to be unenforceable, such provision shall be interpreted to be only so broad as is enforceable. 10.6 ATTORNEYS' FEES. In any action or proceeding instituted by a party arising in whole or in part under, related to, based on, or in connection with, this Agreement or the subject matter hereof, the prevailing party shall be entitled to receive from the losing party reasonable attorney's fees, costs and expenses incurred in connection therewith, including any appeals therefrom. 10.7 TIME. Time is of the essence in each and every provision of this Agreement. 10.8 PARTIES IN INTEREST. This Agreement shall be binding upon and inure solely to the benefit of each party hereto and its successors and permitted assigns. Nothing in this Agreement is intended to confer upon any other Person any rights or remedies of any nature whatsoever under or by reason of this Agreement except as expressly set forth herein. 10.9 ENTIRE AGREEMENT. This Agreement (which term shall be deemed to include the exhibits and schedules hereto and the other certificates, documents and instruments delivered hereunder) and the Confidentiality Agreement constitute the entire agreement of the parties hereto and supersede all prior agreements, letters of intent and understandings, both written and oral, among the parties with respect to the subject matter hereof. There are no representations or warranties, agreements or covenants other than those expressly set forth in this Agreement and the Confidentiality Agreement. 10.10 APPLICABLE LAW. THIS AGREEMENT SHALL BE GOVERNED BY AND CONSTRUED IN ACCORDANCE WITH THE LAWS OF THE STATE OF TEXAS, WITHOUT GIVING EFFECT TO ANY CONFLICTS OF LAW PROVISIONS. 10.11 ASSIGNMENT. Except with respect to certain rights and obligations assigned to the Securityholder Representative as provided by this Agreement, neither this Agreement nor any of the rights, interests or obligations hereunder shall be assigned by any of the parties hereto (whether by operation of law or otherwise) without the prior written consent of the other parties. Subject to the preceding sentence, this Agreement will be binding upon, inure to the benefit of and be enforceable by the parties and their respective successors and assigns. 10.12 WAIVERS. At any time prior to the Closing, the parties hereto may, to the extent legally allowed, (a) extend the time for the performance of any of the obligations or other acts of the other parties hereto, (b) waive any inaccuracies in the representations and warranties contained herein or in any document delivered pursuant hereto and (c) waive performance of any of the covenants or agreements, or satisfaction of any of the conditions, contained herein. Any agreement on the part of a party hereto to any such extension or waiver shall be valid only if set forth in a written instrument signed on behalf of such party. Except as provided in this 53 Agreement, no action taken pursuant to this Agreement shall be deemed to constitute a waiver by the party taking such action of compliance with any representations, warranties, covenants or agreements contained in this Agreement. The waiver by any party hereto of a breach of any provision hereof shall not operate or be construed as a waiver of any prior or subsequent breach of the same or any other provisions hereof. 10.13 CONFIDENTIALITY AGREEMENT. The Confidentiality Agreement is hereby incorporated herein by reference and shall constitute a part of this Agreement for all purpose and shall remain in full force and effect following the execution of this Agreement until terminated in accordance with its terms; provided, however, immediately after the Closing Date, the Confidentiality Agreement shall automatically terminate without any further action by any party thereto. 10.14 INCORPORATION. Exhibits and Schedules referred to herein are attached to and by this reference incorporated herein for all purposes. 10.15 COOPERATION AFTER CLOSING. Each party shall, at any time and from time to time after Closing, execute, acknowledge where appropriate and deliver such further instruments and documents and take such other action as may be reasonably requested by another party in order to carry out the intent and purpose of this Agreement. 10.16 RULES OF CONSTRUCTION. (a) Each of the parties acknowledges that it has been represented, or has been advised of its right to be represented, by independent counsel of its choice throughout all negotiations that have preceded the execution of this Agreement. Each party and its counsel cooperated in the drafting and preparation of this Agreement and the documents referred to herein, and any and all drafts relating thereto shall be deemed the work product of the parties and may not be construed against any party by reason of its preparation. Accordingly, any rule of law or any legal decision that would require interpretation of any ambiguities in this Agreement against any party that draft it is of no application and is hereby expressly waived. (b) The inclusion of any information in the Company Disclosure Schedule shall not be deemed an admission or acknowledgment, in and of itself and solely by virtue of the inclusion of such information in the Company Disclosure Schedule, that such information is required to be listed in the Company Disclosure Schedule or that such items are material to the Company or its Subsidiaries. Any headers, footers or other references indicating a date as of which any schedule or any list, memorandum, spreadsheet or other attachment to any schedule was prepared or otherwise purporting to indicate any date as of which any such information speaks shall have no effect on the dates or times as of which any representation or warranty in this Agreement is made. The headings, if any, of the individual sections of each of the Company Disclosure Schedules are inserted for convenience only and shall not be deemed to constitute a part thereof or a part of this Agreement. The Company Disclosure Schedule is arranged in sections corresponding to those contained in this Agreement merely for convenience, and the disclosure of an item in one section of the Company Disclosure Schedule as an exception to a particular representation or warranty shall be deemed adequately disclosed as an exception with respect to all other representations or warranties to the extent that the relevance of such item to 54 such representations or warranties is readily apparent on the face of such item, notwithstanding the presence or absence of an appropriate section of the Company Disclosure Schedule with respect to such other representations or warranties or an appropriate cross reference thereto. (c) The specification of any dollar amount in the representations and warranties or otherwise in this Agreement or in the Company Disclosure Schedule is not intended and shall not be deemed to be an admission or acknowledgment of the materiality of such amounts or items, nor shall the same be used in any dispute or controversy between the parties to determine whether any obligation, item or matter (whether or not described herein or included in any schedule) is or is not material for purposes of this Agreement. 10.17 EXPENSES AND OBLIGATIONS. Except as otherwise set forth herein, all costs and expenses incurred by the parties hereto in connection with the transactions contemplated by this Agreement shall be borne solely and entirely by the party that has incurred such expenses. As provided in Section 2.1, Buyer shall pay the Company Legal Costs on the Closing Date. If any Company Legal Costs are submitted to the Company after the Closing Date, such fees shall be paid by the Securityholders, pro rata in accordance with their ownership of the Shares immediately prior to Closing. 10.18 RELEASE. Subject to the limitations set forth in the last sentence in this Section 10.18, as of the Closing Date each Securityholder shall be deemed to unconditionally and irrevocably release and forever discharge, effective as of and forever after the Closing Date, to the fullest extent permitted by laws (including common law), statutes, rules, regulations, ordinances, judgments, orders, decrees, injunctions and writs of any Governmental Authority having jurisdiction over the Securityholder, each of Buyer and its Subsidiaries, the Company and its Subsidiaries (other than HRM) and their respective officers, directors, employees, agents, counsel and representatives (collectively, the "Released Parties") from any and all debts, liabilities, obligations, claims, demands, actions or causes of action, suits, judgments or controversies of any kind whatsoever that Securityholder may possess (collectively, "Pre-Acquisition Claims") against the Company and its Subsidiaries (other than HRM), if any, or any of them that arises out of or is based on any agreement or understanding or act or failure to act (including any act or failure to act that constitutes ordinary or gross negligence or reckless or willful, wanton misconduct), misrepresentation, omission, transaction, fact, event or other matter occurring on or prior to the Closing Date (whether based at law or in equity or otherwise, foreseen or unforeseen, matured or unmatured, known or unknown, accrued or not accrued) (collectively, "Pre-Acquisition Matters"), including: (a) claims by the Securityholder with respect to repayment of loans or indebtedness; (b) any rights, titles and interests in, to or under any agreements, arrangements or understandings to which the Securityholder is a party; and (c) claims by the Securityholder with respect to dividends, violation of preemptive rights, or payment of salaries or other compensation or in any way arising out of or in connection with the Securityholder's employment with the Company or any of its Subsidiaries (other than HRM), the cessation of that employment, the Securityholder's status as an officer, director, stockholder or optionholder of the Company or otherwise. Each Securityholder further agrees, from and after the Closing Date, not to file or bring any claim before any Governmental Authority on the basis of or respecting any Pre-Acquisition Claim concerning any Pre-Acquisition Matter against any Released Party. Each Securityholder (a) acknowledges that such Securityholder fully comprehends and understands all the terms of this Section 10.18 and their legal effects and (b) 55 expressly represents and warrants that (i) such Securityholder is competent to effect the release made in this Section 10.18 knowingly and voluntarily and without reliance on any statement or representation of any Released Party or its representatives and (ii) such Securityholder had the opportunity to consult with an attorney of such Securityholder's choice regarding this Section 10.18. Notwithstanding the foregoing, this Section 10.18 shall not affect the rights and remedies of the Securityholders with respect to (A) this Agreement, including Section 6.11 and (B) any rights against HRM. 10.19 APPOINTMENT OF ATTORNEY-IN-FACT. (a) C. Randall Hill (the "Securityholder Representative") (and any successor appointed to act on its behalf in accordance with this Section 10.19), hereby is appointed, authorized and empowered to act, on behalf of the Securityholders, in connection with, and to facilitate the consummation of the transactions contemplated by, this Agreement and the related transaction documents, and in connection with the activities to be performed on behalf of the Securityholders under this Agreement. (b) Buyer and its Subsidiaries shall be entitled to rely exclusively upon the communications of the Securityholder Representative relating to the communications of the Securityholders. Buyer need not be concerned with, and shall be entitled to rely on, the authority of the Securityholder Representative to act on behalf of all Securityholders hereunder, and shall not be held liable or accountable in any manner for any act or omission of the Securityholder Representative in such capacity. (c) Except as set forth in the following sentence, the Securityholder Representative may enter into and grant any amendments, modifications, waivers or consents with respect to this Agreement and the related transaction documents. Notwithstanding the foregoing, the parties acknowledge and agree that (i) the Securityholder Representative may not enter into or grant any amendments, modifications, waivers or consents with respect to this Agreement unless such amendments, modifications, waivers or consents shall affect each Securityholder similarly and to the same relative extent, and (ii) any such amendment, modification, waiver or consent which does not affect any Securityholder similarly and to the same relative extent as it affects other Securityholders must be executed by such Securityholder to be binding on such Securityholder. (d) Notwithstanding anything to the contrary herein, the Securityholders Representative in its role as Securityholder Representative shall have no liability whatsoever to the Company or Buyer. (e) In the event of the death, disability or incapacity of the Securityholder Representative, the Securityholders may appoint a substitute therefor. The Securityholders shall act by majority vote in interest. Each Securityholder, by his or her execution of this Agreement, hereby irrevocably appoints the Securityholder Representative as his or her agent, proxy and attorney-in-fact for all purposes of this Agreement. (f) The grant of authority provided for in this Section 10.19 is coupled with an interest and is being granted, in part, as an inducement to the parties to enter into this 56 Agreement and shall be irrevocable and survive the death, incompetency, bankruptcy or liquidation of any Securityholder and shall be binding on any successor thereto. 10.20 ARBITRATION. (a) Any dispute arising under Sections 2.4 or 2.5(c), which cannot be resolved by mutual agreement, shall be resolved exclusively by final and binding arbitration in the State of Texas, County of Tarrant, in accordance with the commercial arbitration rules of the AAA, except as otherwise provided herein. Either Buyer or the Company may invoke arbitration of such issue by serving on the other party a written notice of arbitration (the "Arbitration Notice"), which shall specify with reasonable detail (i) the issues in dispute, (ii) the claims asserted, (iii) the remedies sought by the party invoking arbitration and (iv) the name of such party's chosen arbitrator. Within five (5) Business Day of receipt of the notice, the receiving party shall (A) select its arbitrator and (B) notify the party who shall have given the Arbitration Notice. Within five (5) Business Days thereafter, the two arbitrators so chosen shall choose a third arbitrator. Each arbitrator shall have general experience in the oil and gas industry. (b) The decision of the arbitrators shall be rendered within fifteen (15) days following the appointment of the third arbitrator. All decisions of the arbitrators shall be by a majority vote. Each of Buyer and the Company shall pay the fees and expenses of the arbitrator chosen by such party and shall pay one-half of the fees and expenses of the third arbitrator. (c) A judgment on the award by the arbitrators may be entered by any court having jurisdiction thereof. (d) All aspects of the arbitration shall be confidential, and the parties and arbitrators shall not disclose to others (other than the Securityholders and their respective representatives), or permit disclosure of, any information related to the proceedings, including but not limited to discovery, testimony and other evidence, briefs and the award. [Signature Page Follows] 57 IN WITNESS WHEREOF, the parties have executed, or caused this Agreement to be executed by their duly authorized representatives, as of the date first written above. ENCORE ACQUISITION COMPANY By: /s/ Robert S. Jacobs ------------------------------------------- Name: Robert S. Jacobs Title: Senior Vice President CORTEZ OIL & GAS, INC. By: /s/ C. Randall Hill ------------------------------------------- C. Randall Hill Chief Executive Officer NATURAL GAS PARTNERS V, L.P. By: G.F.W. Energy V, L.P., its general partner By: GFW V L.L.C., its general partner By: /s/ Kenneth A. Hersh ---------------------------------- Kenneth A. Hersh Authorized Member /s/ C. Randall Hill ---------------------------------------------- C. Randall Hill /s/ R. Cory Richards ---------------------------------------------- R. Cory Richards /s/ David C. Myers ---------------------------------------------- David C. Myers /s/ Randall K. Click ---------------------------------------------- Randall K. Click /s/ Todd G. Laney ---------------------------------------------- Todd G. Laney /s/ Roxanne W. Hicks ---------------------------------------------- Roxanne W. Hicks /s/ Robert Brandon Hussing ---------------------------------------------- Robert Brandon Hussing /s/ James A. Smith ---------------------------------------------- James A. Smith HRM RESOURCES, INC., SOLELY FOR PURPOSES OF SECTIONS 2.1(g), 2.6, 6.1(a)(vi) AND (xvi), 6.5(b) AND 6.10(b) By: /s/ C. Randall Hill ------------------------------------------- C. Randall Hill Chief Executive Officer ~~EX-21.1 7 d12839exv21w1.htm SUBSIDIARIES OF THE COMPANY exv21w1~~

Exhibit 21.1
Subsidiaries of Encore Acquisition Company

Name of Subsidiary State or other Jurisdiction of
Incorporation or Organization

EAP Energy, Inc.
Delaware

EAP Properties, Inc.
Delaware

EAP Operating, Inc.
Delaware

EAP Energy Services, L.P.
Texas

Encore Operating, L.P.
Texas

Encore Operating Louisiana LLC
Delaware

EX-23.1 8 d12839exv23w1.htm CONSENT OF ERNST & YOUNG LLP exv23w1

Exhibit 23.1
Consent of Independent Auditors
We consent to the incorporation by reference in the Registration Statements on Form S-8 (File No. 333-83766) and Form S-3 (File No. 333-106943) of Encore Acquisition Company and in the related prospectuses of our report dated February 6, 2004, with respect to the consolidated financial statements of Encore Acquisition Company included in this Annual Report on Form 10-K for the year ended December 31, 2003.
/s/ Ernst & Young LLP
Fort Worth, Texas
March 10, 2004

EX-23.2 9 d12839exv23w2.htm CONSENT OF MILLER AND LENTS, LTD. exv23w2

Exhibit 23.2
MILLER AND LENTS, LTD.
Consent of Independent Petroleum Engineers
Encore Acquisition Company
777 Main Street, Suite 1400
Fort Worth, Texas 76102
     The firm of Miller and Lents, Ltd. hereby consents to the use of its name and to the reference to its report regarding the Encore Acquisition Company Proved Reserves and Future Net Revenues as of December 31, 2003, in the annual report on Form 10-K for the year ended December 31, 2003 filed by Encore Acquisition Company with the Securities and Exchange Commission.

Very truly yours,

MILLER AND LENTS, LTD.

By:    /s/ CARL D. RICHARD

Carl D. Richard

Vice President

Houston, Texas
March 9, 2004

EX-31.1 10 d12839exv31w1.htm RULE 13A-14(A)/15D-14(A) CERTIFICATION exv31w1

Exhibit 31.1
Rule 13a-14(a)/15d-14(a) Certification
I, I. Jon Brumley, certify that:

1. I have reviewed this annual report on Form 10-K of Encore Acquisition Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(c) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: March 11, 2004
By:    /s/ I. Jon Brumley

I. Jon Brumley

Chairman and Chief Executive Officer

EX-31.2 11 d12839exv31w2.htm RULE 13A-14(A)/15D-14(A) CERTIFICATION exv31w2

Exhibit 31.2
13a-14(a)/15d-14(a) Certification
I, Roy W. Jageman, certify that:

1. I have reviewed this annual report on Form 10-K of Encore Acquisition Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(c) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: March 11, 2004
By:    /s/ Roy W. Jageman

Roy W. Jageman

Chief Financial Officer, Treasurer, Executive Vice President and Corporate Secretary

EX-32.1 12 d12839exv32w1.htm CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350 exv32w1

EXHIBIT 32.1
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
I, I. Jon Brumley, Chief Executive Officer of Encore Acquisition Company (the “Company”), in connection with the filing of the Company’s Annual Report of Company on Form 10-K with the Securities and Exchange Commission on the date hereof (the “Report”), for the period ending December 31, 2003, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, certify that:
     (1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
     (2) The information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Company.
/s/ I. Jon Brumley
I. Jon Brumley
Chief Executive Officer
March 11, 2004

EX-32.2 13 d12839exv32w2.htm CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350 exv32w2

EXHIBIT 32.2
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
I, Roy W. Jageman, Chief Financial Officer of Encore Acquisition Company (the “Company”), in connection with the filing of the Company’s Annual Report of on Form 10-K with the Securities and Exchange Commission on the date hereof (the “Report”), for the period ending December 31, 2003, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, certify that::
     (1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
     (2) The information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Company.
/s/ Roy W. Jageman
Roy W. Jageman
Chief Financial Officer
March 11, 2004

GRAPHIC 14 d12839d1283946.jpg GRAPHIC begin 644 d12839d1283946.jpg M_]C_X``02D9)1@`!`@``9`!D``#_[``11'5C:WD``0`$````4```_^X`#D%D M;V)E`&3``````?_;`(0``@("`@("`@("`@,"`@(#!`,"`@,$!00$!`0$!08% M!04%!04&!@<'"`<'!@D)"@H)"0P,#`P,#`P,#`P,#`P,#`$#`P,%!`4)!@8) M#0L)"PT/#@X.#@\/#`P,#`P/#PP,#`P,#`\,#`P,#`P,#`P,#`P,#`P,#`P, M#`P,#`P,#`P,_\``$0@!@P(_`P$1``(1`0,1`?_$`:(````'`0$!`0$````` M``````0%`P(&`0`'"`D*"P$``@(#`0$!`0$``````````0`"`P0%!@<("0H+ M$``"`0,#`@0"!@<#!`(&`G,!`@,1!``%(1(Q05$&$V$B<8$4,I&A!Q6Q0B/! M4M'A,Q9B\"1R@O$E0S13DJ*R8W/"-40GDZ.S-A=49'3#TN(()H,)"A@9A)1% M1J2T5M-5*!KRX_/$U.3T976%E:6UQ=7E]69VAI:FML;6YO8W1U=G=X>7I[?' MU^?W.$A8:'B(F*BXR-CH^"DY25EI>8F9J;G)V>GY*CI*6FIZBIJJNLK:ZOH1 M``("`0(#!04$!08$"`,#;0$``A$#!"$2,4$%41-A(@9Q@9$RH;'P%,'1X2-" M%5)B)$@Q=4DP@)"A@9)C9%&B=D=%4W\J.S MPR@IT^/SA)2DM,34Y/1E=865I;7%U>7U1E9F=H:6IK;&UN;V1U=G=X>7I[?' MU^?W.$A8:'B(F*BXR-CH^#E)66EYB9FIN15V*NQ2[%#L5=BKL5=BKJ^^*M5]\4NK[XJWBAV-I= MBAV*78H:Q2WBKL4.Q2[%78H=BEV-H=C:78H=BEV*NQ5U<5=C:'8J[%78I=BK ML5=BAV*78J[%#L;5V*NQ5V*78J[%#M\4NQ5V*NQ5V*NQ5V*NQ0[&U=BEV*NQ M5V*'8J[%78I=BAV-J[%+L4.Q2[%#OIQM+L4.Q5V*NQ5V!+L5=A5JN*M5Q5KE M3%"PN!WP):]08VJTRKBKA*#BJX2#QQ5<),57!L575&%78JWBKL5=@0UA2W@5 MV*'84NQ5V!78H=BEV%78J[`KL*NQ5V*NP(=BKL*78%=A5V*NQ5V!78H:PI;Q M5V!785=BKL"NQ5V*'8I=BKL5=A5V!#L*78%=BAK"EO`KL5=BKL5=A5V*NP(= MA2[`KL*NP*[%#L*NQ5V*78$+?'"E8S4^>!5!I@.^-JH/<`#K@M4(]V!WP6E# M-?+_`#8+52.H*.XQM7?I!:]<;552_4]\;5%I=J>^&U1*W(/?#:%83#&U5!*# MAM5PD'CBJX/[XJNYXH;#`X4KJX$.PI:Q5O`KL*NP*[%78H=A2[%6L5;P(:PI M;Q5V!785=BKN^*NQ5V!#L*78$-84MX$.PI=@5V%78$.Q2["KL5:Q5O%78%=A M5V!78J["KL"NPJ[`KL*NP*[%785=@0[%784NP*["KL5=BAV*78%:\<*K'-!7 M%4OFEI7?(DI2*35;47+V2W41O(XUFDM`X]18V)57*5J%)!`-.V0M4'-J!H=Z M>^`R2!;S;SYYHU/0K31[VSO(].L#JB0^8=5EL9M22ULWMY^,C6]O+%*0;D0H MS*?A5BQHH+"N^4_F1=%-),?S02!V36/*'FK1_30O-.-+DU.!$7J[3:0U\BIMU8C;< MT&2&:,N194B=%_-+R/YBG6VT3SAI6H7Q7U#IL=W$+I5V%7MV82KU[KDN+JBF M;)J3`_:H^&T(A M;Q?&F&U51=K_`#8VJJMRIZ'#:JHG'C7&T*JSCQQM583#QPVJ[U!BJ[F,*MU& M*MU]\"MXH=BEV%78$.PI=@5V*'8I=A5V*'8$NPJ[%78$.PJ[`KL4NQ5V%#L4 MNQ5V!78J["KL5=BKL"&L*6\5=BKL5=BKL"'84NP(=A2[%78JU7%6N6*&N0\< M4NY8H75&*MX%=A2[%78JUBKCT.*J$II7`J1W9_/&C^:?(TU[I*73Z?/IU!-!TKF'0NUMYO\`G/Y[/D_0 M%L+2Q^L2^9[6ZM8KOEQ2`!%4GB`>1I)L/;!.5,\<>(O@D,':Y@:T@O([^(VT MEO/"DP9&96H%=30U4=-\J!(Y.20"]*TGRG-Y-\GZW/-+K?E+7=1N[']#6UG> MW%LT5L1)(\PL@_I$-3B`Z4KE@S2'5J,03LS_`,L:O^80UO1?*I\WPM=+;@:_ M>^8M-BNFBG,A58T^H2Z;2O.-"6YD,3URV.H-[AA*&UAFNM_F+K?E/7=6TK6? M+45]8Z'!:R7VI:1?B2=GN[B&UA46EW#:HI:2X04^L-0>.71S`FF'":M$G\[? M)FGS1VWF>>]\E7,D<,D::_:O:1LLX#14N1SMR6Y``"2I.V3&0'DI!IZ!I/G3 MR]K4:3:+YATW6(I/[N6QNX;A33K0Q.PVKD^)#(1J3#J_WX>)&RLNJD?M8>-% M!$KJI\<>-:"+CU4']KVPB:*1T>I@_M9+C12,2_!_:&$25%K=CQ_')6JLMT/' M&U5A<#QPVJH)_?&T4J"8>.^&U7B;WQM5PE&*M^H,4-^H,4M\QBKN8Q5OD,4. MY#QQ2[D/'"K7(>.*M\A@0W7Z<*6\5:Q5O%78J[`AV%+L5=BKL"NPJ[%78J[% M78$.PI=@5V*NPH=@5V*785=BKL"NQ0["E29J8JAGF`R-K2'-R/$8VEL7(VWQ MM42DP.$%")!KBJ_"KL5=BAV!+1Z84(6<['`4ACMZU`?IR!2\#\U7>M6?Y@:> M-$@1]7U/RS?0:1>RM^ZMEBOK+ZZ\B]22)8>&W9LP=22!LVQIY5IGY?:;?:GJ M=AKNJSZF=.<1QI&Y'-B"S$$5-.1-`,U]MQGMLG_FK0-"T+S'^5OE;2+2:QN/ MS$YZ?KVDF6465QIVF/9W=Q-4*+8NC.HN96; MXB(R>04#<@8.+J6(VV2FW\HKY4\B:OYG\T,T_F;5;N*30M/=WEY7:%FMBR*? MCD MY*C^;U=/103W\P0WFSR]J/F3SSY`\T:I&]O=WWG.$^5M#8?&EI MHEI=7IDF'4$O:J0OB:GJ,,+WDI(`IZWKWE'RG^9EY#::SY;TC45MHRTB:I9P MW;*>7[QE]5&J22-\`))V-,.2G8?E9Y!@T22UTR+5?+XTX23"ST?6-1TZ%&!8 M?[S6MQ'`:\.\9&60R$#F@I>WY?>8$M;E]#_,;6K1$5VLH=3M['4%=VB215YM M;Q3&AJ-Y3DAF*L3M+C\T;:6&!=2\M^8?4/'_`$F"[T<@]JRQ/J`-?:(8C4#J M$F+)I=9\]Z<8X[OR!-K$[?WB>7=4L;I$IU/+4WTIC]"Y8,T44Z;\Q[+2HXWU MW1/,FB.Y(:.71+^Z1*=>=Q80W5N/^1N3&0'JBDVT[\S/)=_Z(M?-VDR2R_9M M6O(4G'LT+LLBGV90C@_(X1-:1B:@I_:R7$$(E;U3O7&U51>+XX;5?\` M6U\<-JV+I?YL;5<+H?S8VM+OK(\<;5=]97QQM5WU@?S#&U=]9'\V&T-&Y'C@ MM+8N1_-AM5=)@>^-H1"R`]\-JJ!AXXH;KA5O%+L"'84NP(=BKL5=A5V*78J[ M%78%=A5V*NQ5V*NQ5V*M=,5;Q5V*NP*M)H#^&%4#-)0=X-32D*.F%4!<-0$^&1*AC%^_45RN19/D/\\+J M.W\[_ES-#K-QHUZT&I6?UW3[AFOHTN);.2J6*74/J1\;>1WEDAGB01TD2CF06UYJ]LZO/&25O6%1*&^/E\SRHW:6>6*[AF8)]9MEY42ZA5BO)5-*BE0,QR=W($00\VU:TB\Q^:5B\D M:?*5U-E>TTN,;Q2!0TBU/P\0P+5Z`8LP:&[Z1O?*B:^UM?\`G".:YU6A$T:4,4:J0H7QIU\<3=[M'%7)G26;:G)9+;S-8PZ;P6RMK1`HINICV'0 MCK7;#S8W2)U!;S5)5M(Y"GZ+D65)I%5B&C%!Q6E`PJ0*8390-F(:E!IOG+SY MY)T.[GGEL?*5GJ^NWUS&"JO>Q2V=K;QAUI7:XF)I_+3N3_/'F339K9N,D?UR'4U-. MSOJT%]*?H<9#\U(-T,5[O)+_`/-'\TVBC:Q\S6$L:[.EUI["9_;_0DT,7_`!/)1SCO*G'Y,^L/ M^8^[[V!Q!Z!9?\Y1_E^/275-7C MT663[,.I$V;G_87`C;\,MCF)Z?+=@<;,[+_G(#\O;X#ZOYHL)N73A.C?J)R7 MCTCPRR:W_-CRM<"L>K0$;;\QM7'\Q'O1X13ZT\]:)=FD&HPN?`.#DAF!ZHX" MR"'6(I@&CE#CQ!KE@G;&D2-2/\_XX>(HI4&I_P"5AXBM+AJ?^5^./$M+OTE_ ME?CCQK2TZB3^UCQK3#G_`#*T>#SE!Y)F2YCU*Y2,V]X47ZL\TL-Q<);A@_/F M8;25]TXT4_%RH"/$WI>%Z+!?`]3E@DA-([H$#?)6J*6X![X;576;WQM%*HE& M&U7AP>^*KP1XUPJW7%78JW@5V*'84NP*[%#L*78$.PI=BKL"NPJ[%78J[%78 M%=BJA(U!BJ3WICC6^B>,@>\ZQ(?`, M3VS%U!]!9Q236)4CBMB]']2\MX^'B&D`_CFG;0\Q_--=4U[7-2OM'NW74_*U MH]UY37C_`+S:I;Q\X^`%"5DD0*XZ.O)&JIIET(T'Q1YKU6?S#K M6I>8FM9;>#5[N6:'F"5W->(:@!*C8TRIR8BA3U'RQK'^%KO\MO-.HH)]/O+* M\@F9:"0.DTML>87T@=%*QNY9;>)+(,&EHQG%5VWJ0<`*D,K\N:5"MG&LZ\47E%"(Z@L6))) M/4_,Y9".V[$EYK$+M_S-\WZ7;1_4[#3[#2+!Y(5^$B0W=TZ%JU4D3H6IUVPR M!``2"K^M[M(Y9+H^7M?8L/3?3M1@G]&.>G7_`$U+<1D]';C^ MV:RCL"/)#(]*O;N&Z-B(^:7:,;B`T'[!/(5-*@??E09%D&D:;#:";7+N['U2 M%S);QJ:QNKEXR;B]TZVB4C8+ZTKJ:_0PKALTK"; MFWDD6!;AE5[6%8HD4@\U5CNI_P!ED"FT_P!.M6M6AMI`68.&11U0LM:_3BAD M36\HN1]-\QYRLM^*'5\GW-V]W<.TKF20FKU]\@Y`V M4A3O04P*@M1LTU33KO3WGN+1;N-XC2R:CY(\S78N/.7E1Q#=W#@(;^T8M]7O46NYDC`+@?98T.1$P21U;8Z7+CP MQR3W!O<>7?W%DWGEV_POJL%:+>B"S/\`T=SQP?\`,S+\/U!IGR9!)86,S4EL M+>13]HO$C#\1D.(CJF@ES^5/+=PW[_RSI;[[M)90$]]ZE,D,LQU/S7@!0;>4 M/+4,T=Q;^7[&%H]F$,*Q;?[`+A\:?>4<`[GJGDC4-$TJ[A%Q#>I;N0LC6NIZ MA;,H]C!<)TP^-,=6$L8K9]F:7Y,\LZ[8PW=EK?F>..90?W7F76"/;9[MA^&9 M$,\BXQ%*Y_*VV#EH/._G"V\%&KR3#Y_Z0LN6#-)%*\?Y>WUOO'^97FP>`=M* ME'_)737.)S%7C,>L>>8_S'\U>4CYZU.73=#N+/ZC.]KI1E>"YL89R)"M@%+" M4R`4`^&G??&6>0`/>R$00])CL/-DK2^GY[O1Q1G42V6GON!7?A;QX!J9=R*# M`-;TW5-%6_\`.5_JYUK5+2_T2[GN6MX[=;>QTZZK=%!'W-K/.K-X'!'-Q3%I M(V>^Z7YDTC5$:72M7L]3BC8(\EI<1SJ&(!"DQLP!((.9MM:?'5HK:)IKB9(( M4^W+(P517I4D@9+BI:3.+400"&J"*@@Y+C1281Z@#2IR8DA&)>@]ZX;5$+=J M>^&U1*W0/?;#:JRS@XVA764'OAM5X<>-,*KN0/?`K=??"K=<4.Q2W@5V*NQ5 MV*NPJ[`AV*785:Q5U1@0L9P,4H&:44.`JQV^N*`[Y7(I>-?F&[7EOY>T_-*L8;>.:_P""FNW-[54)_E)IO0YBYY5`EF$IO+?A=VJRU>"W83JU M:TDCJ4^>],U0;4)YV2]2VCFT*VAM1"ZRW5ZRUED:^;O,%AY M:T/6?,.J2&/3]%M)KV\915N$*%R%`ZL:4`'4[93,L@'RQY$\O:EY@\OS0:K; ML][YFU9=1OH(2XC:YN)#<7TH':(222<*_LT&:FB22`.>Y'7,B-T::'@^N)Y9FUZYN?- MWGD7>JF1H'NM041VL!D!*F,5X%14\16E:9C;DMX)`V&S/_.]C9>9O*^D^6M# MTR._&D,IM=0$T:A%6,ACQB;JW4[?CDI&A5,8&C:0_E]Y>O[.UNM&\P:*MQ:V M`DGL/54,OK.:@J#N3\(Z9`)G(W/)KB4Z7;P:?(B(*$4DMW85/V2#T.2D#L"Q!'.GJ5M^ M7GE^T\O>9O*NIRG4KWS%I[VVM:W?F6JO$@@@$&H!R4?3[T2 ME;'/*%MJCSZSY-\QWS3^;_*<<4UMJS`H^L:9+5+:^I14#U4I.JCX)!6@61*F M4.H1;/;6XEU33X]`>XB@EAGY/<25HPJ6H*=6Y'(`V*5E31#3[./28W-S+/`\ M44K*2!_-RX]`.6V3Y;(>?:M8"P:"`7<4TJ5:;TZTB8D"E/HJ*GU"] MU...D]W)8_683U8NB\:!3V)I3+*HL4#>33IY76!F_?F%O69CNQK4C[JX"=DC MF@-#0"V:",\C;1F6XE[<74E0/OR(%J7P+^8VIM<^;]0B#$M%(YGIW`;B*5\` M,Q2YD.3"XX[65WD1VD:(CD5V'XC%DKA8!7DA8UY*.@K7O@5<]'(HH5J48`4' M7%>3P_\`-+RW;V.HZ-^:^F6LDVO^1W7Z[;PT_P!*TYV,#$M&DKE2*;$_ MY-*,T:(F.8=KV?G,HRTTCZ9\O*73YTS+S7'5-5T9K>5#57C- M]!*&!\"JUS+PG>QW'[G4Y(D;'G;-Q*T40JQ9ANWA]V5I:620LS%^"%:$&IKN M,44ND`4@E@5?H1WKTQ2AI%^KNDJ["0[I[^.%7TI^2OG*ZAOX]%N)"T$U?2!- M:$;_`(X8&BTY8]7UZIJV[;`5`]LRAS<=>QJI)Q5\L7UO-:_G9YSYCBE];:)? M0`]3&T,]J"/;G`PP9.09QY%[+:J"+DTH/396^GL,@&)2L,-U.]3^KO@2QO7/ M(/DSS.+I->\KZ7JCW-L]J;R>UC:Y6)U;:.?CZD9'(D%6!4[BAR<9RCR*"I2^ M2-)OI$O?,RR>:OZWE.&XUOR]KESQD\F22A+;2T6S].%[)G>EM!Z\:>HB(P42.P0T`% M^/4=)((>A:1^8427$&D^;EM?*^O7!E^HPR74;6M\L1!+V4S^FST5@61D5UW^ M$J`QR(9!,;,2$)>?G!I-O?Q+IVG:AK_EZ&00ZOYKTJ%[RUMI'1F18T@626Y' M)0CM`KB,L.1V?@3E`-6M)WI?YL^4M4O8-/@O;VSN;D/]6&I:9J&FQRF-&E98 MY;VW@C=@BLW%6)X@FE`0!BIF@D61>0I4!785:Q5HG`A2:0#%*@\].II@M4')<@5- M<%I2FYO@`=ZGPR)E2L7O+OD2`=SE)-L@\'O=8A\T^>O*5UI5O>ZEH&DVFL\M M:2-_T8;UA:I%)'*2%E94]5$D4%*.X1B0X&'J9CAKJR`97JOJ1V(U'ZQ%9VFG MAVF>3=I&'10.^X&V80#,.0,C4%5)"D3QY#$[ M(D++TGR[YXN8K[2]!\WZ1+H6NWS_`%6UO8BMQIE]3+&5S#<7$FO:_;)P*RVVG/&+>"8,"0LEQ*KBE*^DPZ5& M86HG46V&[VWRGID=M;?7?JQ:9?W<,2@*`HV-.V8N,=4$I9^8OF&V\M>7-5>_ M@2YL[R!+=-,^%F8S$HP<-4%'&QJ.QPS)"QC9?*?Y>_EOY4\Y^<-0NM4\O:7I MEGY;@^O7%O8VL2B1@_PQ\@G%00#6E"1T[Y"))YDMTZB-GH/ESR]H_G74-7\X M:5:CR92>31--CT1(;0R6\8BN)#-QC*N6)7JM5WXD5.'C)YM ML:7+9>9_-$6G7L`.IP07@G660U1E+W,4]Q;BG_+-+%XC??$SX3R"`+#)D_+W MR+;6,VJ^:;G5C%;@^E=:GY@UB8Q*>\;SWKF,FM/@(KMX#+(S-66-6\#U?0-( M_,.>P\J^1M%N[>RBGC-[YDEO]06Y/-B5-S=?6`\B*OV$6R+2+4';X`HI4F,;FH[X3SY-;R'\_;W0= M+\B7/G>ZFEFU'36]#0=6TNYFL[N*2=@I@MYK5XY'$[JJM&S%'8+R4T%)63RZ MIB-]V3^0M#\P6?E'RKH7G.M[YHN-+M;CS1J:<:PWPA43590%KR&Y&U:T%,C( M"Z');9U;ZI)17MKYCZT MRFH$J'XP!UR,F09+K+RRS:)J6GR"-;UX[:2<;D>H:4;\1\\E+>B@(778+:]# M&*Z,:6BN+J/JRL:4KX"F1*A!OJ4-EH:VME:22S7$1'(#XG8)^H8DU%:W?G+Y MJCN'\U:O+<@)-++,A0$&F^P.8KF12W3PJ->0J*Q(H*GP)ZBN+)5W:1`:!!5G M/R[8$NGD:C%3Q#=3X`]\4.C'IFIWZFN*E\R277F3RA^8/ESR5J\OUSR1K6K+ M>>3=7N9#ZEOZ",PTYG8GEQ?B(PQY4XTK6@JQ2.*1B>1&WZG;9\4-5@\:`J3[GS+8V4.H7$%Q!$;6X+*A25PA-5WVJ,66^@N7;@(8F_S M.MUT;SQ^7_F:-2;CS$]WY:O$K\)$=O/J=J]/&,VTJCVD.$[Q/EO^A,>;TFT8 MQ67KN:F92%3P--S^.5A2A;>V619)F8+%$?C/?`DE5DF0'G$H"S['V512GTX4 M(:>7T&9W(],#D!78+VP)"4QWLFHJUV:H)794K_(#0'Z:8.::I1O].T_58/J> MJ6%OJ-H&5_JUU$DT?)?LG@X(J.QP@D MXEXDB*"(4KQ169CLJ(K.Q5%9@81,SLIV2V?1->\UV8L/,45CHNA3\'N-(CCC MOM0QYH_ZSH/Y=:;8>6O)^@6\=_? M\WTCR]9KZ2RLI1)KN[F57*HM5]69^3$T'QNRJ;I3`%E:8=^7GE;4-=\X7OGO MS7J\.NRZ#>W$'ERXACN8&:X*B">?C),ZI#&1+#!'&`I4LTAF>DI8&]T%]/P7 MI%-\M$F-)E'?FG7)B:*8GYK_`#-\I>28)9O,FM1V&7 ME3?)`H1ZFHR2JF*NP(=A2[%78%6DX4(:22F"TI=-<\>^1M*537H'>N1,E2B: M^)K\60,DT\\\R?F+Y1\MSM9:UYCL;+41&9AI'JB2^>,?M):1\IW'^JARLRK< ML@+8)=?F<]WI1UGR_P"5-4U*Q6[M+4WFH&/28ZW=Q';HWIW1^MT#R+TMB3^R M&:@-7BQ.UIJE/R&;[2;2^\DZQ)!)JWE(I]7-N7].32[HNUDZ!R6"Q\)+8 MYT>PMYHH887DCNK>,AF,D;'F[D$[U-/88&:>7^M:)H\<:ZKJ]GID]U,L.G-> MW$=NTSJ*\8_49>1`!-!\\D(D\F+)/+$&I^=+S3-;,@T_RAI]TM[I(6/_`$K6 M)%4\+AI'/[NUY4>,*O*7BK\Q$>,FPP8.&B>;42^B+)2`,SPUI\@^!O\`5/ZL MFA$84*+M08$I5-^; MT+`0*IV+>_0]@,C]*'R+^?6IW4GGB2QF(CM;:TMY8E#5YU4D!@#L02U*Y5/Z MG(Q#9[7Y6\JR>5_RUNK#2T2?S!K&GS7&JW*GDOUAXC1"_A&#Q`'S[Y,"H[-4 MI7)Y[^6FLVOEK\NKC4KYS+.NLRFWTV!5,ZM,(KW,6J>8?,$O)+KU+?2K552..-6J5E9@Q8D=@`,D($[EK,AT2;\Y-&TZX M\NW-U)=2*+2(NL2FH$B;1LPZ]Z8Y`G&=V$_D9KMA)I?FCRA';HNJP!]1M+OH MT]46,$L:T,;<:>QQ@=B&>4;V^?--O_,`U*\T:.W-WK?F.ZMXC<']Y=*X9PP1 MJ[6_;*ZMM('-[7^4/F-/+EEYO_+:&,7NBV/F*^T_RKKFH-Z=I-&O%+FV MYJ#O#*&`IM^S6JY=*5"NI:"+W9TFO>=-"\WPZ?8::U]H+S1VUT(W,L,<;D+Z MT;$[%`:D=\KC(Q*T"$A_,[]'/JGY3>2H/]Q3Z5YE;S+=Z]=`06-O:Z1%)OPT-T.5!AYO4;?SOI_GO3(;OR-?PZUI-WZMN=1MZE))(V M:.55+<2.#(P-1VR$[NE")\KVTD::E>2W`AA@@E@NHE-)`1N"/#O3WP04L:TT MB6X6T_>,MQ7@JT+"3M0GMXTR'-)>HQV$%EI-M"(A)':TFF):O[Q3R8^YY=,M MK9BPG7[_`.K7+001HMO^^5R2!:G`LUY';NTGIVTL/IHI?3T$A5UH?@-?B]M^V1RPB<9D>E.R[*R\.H$"?3,&)^/Z M4^T>?0OSV_+2"35D>WM]7XKJ]I9S?';75JZLR*[*:"H#"J[J1D/3F@G*)]FZ MD\.]-(^@6E*=\ MCCTXA*PV:SM?)JL7!,`;WM^"]K=MA&@(9C0@?CE[J%8<5)1?V:5^G%7KGY9: M5/?:_8R11$H''KL!T%*'"!9:YF@^WK5`#J`1I_G*WDD)\)M,U&VW^F88>A]WZ0RCS98)4;2[9TW5FJ# M[4&5]%ZKX!Z5C>2'=9E"JOO6I_5CT5(X+Q;FXBM8S4`/ZT@^RA4"BD^^1ME2 M4(LVHQ'ZV617:IMU^&@KL">]<">2:*@0*J"BKL`-J86+"-?_`#+\D>5[S4K3 M6-<1;W2K=9KBPA1I9.3T]*`$#AZTE05C+!N/Q4"?%ED<4I;K;"9/,'FF#2O, M'GV/0XK>_M],GN5UK7"\-II]DB?6#:V=F3'/*"(E]621H/4D"L/@5%7)C*,? M2.;%F^A>;KGSS%I#^6Y7M-*F02:SYJCB4Q%U!5[;3UNE)=_5ZR/$8PJFG)F! M4Y,@C[U9E9:'I>BB=>5QJ.J7AI?ZQ>2>M"-)10J+4\40*BU)"@DUQ9S M,N:0'GGE_P#*GR5Y>T[3;"TT]DNM(MVAL_,W,1ZLI"A5<7L*QR`JH"A11`H" M<>(IA\:5W::9)9^;/..E(FEOH:^;Y8I?W.O1W,-DLMF-SZ\;`TNE'PA47TI# M1B\/(HF1'4QK=B8H22X\S^:[^X;S5!+Y=\OPU&E>5[#4&^L74;UK+J9_8QV8M^2^C:U9>:=5M4_,#4-6\M>3U^IZ;HT M4RWNGS6L[31V*&Z>ZN',D%O$C2)Z41#L*,Z?:S\4B1;`OK^SGJ!OF2"Q3V)Z M@;Y,(1(PJNP*[%784-$XJAI'H,!2E-Q/0'?(E+S[S9YKA\OVD++;OJ6JZE-] M4T/1H6"R7=RRE@@8U"(J@M([;(H+'L#5.8B$@/.YX?/-S;W%UK/G>*SC^S'9 M^7M-BMRK$5(]:_>_+TZ5"I7K0=,P):DUL&8#$O,7DJ&^\I>9R-2UWS-JL5B] MUI.G:CJEP8;J[BI+';26Z21VW&4KP-8Z4.0CF).Y32M:Z?Y=U_2[.U\LZ?:V M7EK4O0N[2STZ!+:*2S*JZ,JQA0%<$$FF42),MV8V8+<:LNMZGJ/Y?Z;;"YU+ M75CE\N3PJP33A"RSV^J.^R@6DL23(":NZA!N:B6(4;Z+,;/5/S)!\OWND>#S1K:M9K]4$M];RU1+=[=V]1@#1A\2U MW[4R0-BRI&]/D4Z!JGYT><=>UN`KHVCQ\6O=2E#-$@B14CC3I5RJU(!V^[*J M,C;D7P"GMOY;^I\0F4='C/4@@@XPG6S5./5@.I^1 MYG\QZA+H=VT>A:D5>_MW9N6S!BZ*H-&0CDI)]L@60GMN^@].U3U+&=+V_@LS M:?*L&E^1?+\?E"%WDLM<_-*[]"2^F,; M/#>2:;$/5?D74JC3%`G7TR1QS(C$!IE*RROS?^6VDKY5T_R[Y9'Z.T[1Y[:S MTJ`'X8(T/&=^1^)F(=F8DDDY5,7NF$J+'=0?47U#2?RV\DW<^F::R*FIW19I M&ABGE!:=Y7-5FWTEE->12 MK#;M5)*L:RD'?B`-Z'*J3;-I;:"SEO=3D"*=+A6"WC6B!I/2W`\!\63IB@[? M5;R\LM,L3&&>^++.@ZB`,?C/@0HK[[8+)%)I)=3O[:TLHH;6T5&N7::VED7F MZPABB[M73B9Y(09%781=C\`)I[D#>GRQ59NQH?M`/TL+]08!Y#_*B__+OSCK=]HVLAO)6MQ._Z M"/"<D^3?(FH^:+I$AA9;<']Y,1L!B!;"4@'VWY1\B MZ=Y7TQ$MXP9S0S3$58^!R^..@XTI&3(P>,I,C4D"G[/V3DV"(MT^"3D-GJ:? M/"`KRO\`.BPN9_(=_J-BHDN?*=W9^81;BI>6'2[A+FYB0#J\ENDBH/YB.V&. MYKO3R0/EC4(M6T=OJKB:VCX2VMT-U>.10PH>^Q&4CN9RYIZ7FGM3:PIR:$&7 MD>RJ-\*$ATFV-K'=LT@D:>?F7J$,Z&!_-(BM^#-1U&62Y#W?I M+'JS*ZM[>[BFM+J".ZMID*7$$JAT=2-U96%"/8Y!+#]9\JPR77^(/+UI8:9Y MKBG2<:D8N'UQ5B]%H+QX>+R(T9XKR+<&".%)0#)1ET/)40WFG6;8&'S!Y0O[ M:"UC:2;5](9-4@(IT6&,)>NWLMLCWJJH$2BI/+;!R7F6.:W MY@_1<]A%I]LNK:UY@81Z+IZO19=JF0N`W&*-?C=Z&@'=BH,\>,SE2]$QT[R= M=:G)!<>>KNUUI;4,+30+5)$TT-(3SDN(Y7;ZRQ%`!(."@55`U6S-QXHQ8L#O M?RH\I><;[S%?V^C6^B6^FR-IWDN&):6%O?6+2I<7YTV)UMI0UR`ACEC(80\J M4>IJRYC"6WQ15O7K#SK+H=A9IYD\J:AHJ6[M:W5[IMN+[3HR@8I)&+5I)UAD M"U4O".-0K\3UOAFB>K&GL&BZG::C:6FH6%S'>6-]$D]G=PL'CEBD`9'1AL0P M(((S*B4$,RMY*@98&*9(:@'[\DA4Q5V%78$*+M08I2RXEH#OD2EBFJZE;V=O M2*?BXK"K@-'0:W/DXC09@)O61X?WE1$\BE%/0 MN>F^8S)357]J/$T[']>*7G7DF9--_*OR]<7,ALY/,>E0:>%C%)4N M[CXYH47J!`0Z'I2E,LR;$E8[L&T/A:_G#I26,9>UT;1XXIY0"/@N+I%C1B-J M@6S_`'Y$&H_%G+=]%_F!IUK?Z;%<3?&MM;RIP._,,O$AE-000=P<.3H6N!>' M>3=1^I?DQYJDXA];\LWEU:S/=.TKW#VZJFEHS$EY)9XY(%_F9V('Q9/AXCMU M3(T64^5?R?\`(^AOI5ZND"[UBRD^N7.HS2SD7-\X9I+F6!I#$6]6625`5(C> M1WC"L[$YL0Q+W_3K?D5VRV(8$LTM(0H&7`,4[B2G;)A"(IA0IR&@)Q*4GNI: M`Y`I>6^>/-1\MZ=#+;6+ZMK&JW2Z=Y?T>,D&ZO)$>14+`'@B1QO)(U/A16(! M(H:K^7;/ROH,9EO/-3&`VXC?U+BQ M=-_P[^7LU@E]/;6GEBW-SJ,MDBB6YEDY/(2S5`WKOVVR.Y"+N2"70+2]T_3! M;H]C>VD$(L;UVYSPD%7(=J_%X'(IMG;:EIVDR7FGO*D<\"GZU%;CUIY.7$%2 M2*`4;)6([,*)>3>:?-4OE[R=806UH=.NKF_EEL[:45].W2?FJ,>I!2@(/C3! M>U-D8V7F_P"@-;\X>6_+%-.DM_J;WL<-X8U1)(W=95H*K4?$?B^C%G8!+/+C M2O,ND>6-5_1DT+:QI.GW4GEV.,^O[69/:_R M_N-*TGR1I&E>4VFO=-B]:"PFF23ZRTHG<7NYK@-#9L`,U+\O[R3S1J-UY[\T01V M5AY/,T.FW#"BL]S4-*[ML1%'0?-JX8=Y68X=AU2_S/IM]JWY37T>CAE\Y>09 MKF_\IZ["50J9FE,4T0-5>*6*0QNC`JPKWH1*$J%=&)%R;\A_GEY8OM$B$VG: MUJ6JV%O!/=6=AH]_J6^H)^Y1&:-_KB::RFDH(''&8%W-Y7I.I61EEBM;A+B.`>G`T M;*X90:EJK4;G*91(YMX(*-DMTFN([B1B%%&H-MP:_CD4HQ3@)"9W`/1[8)[/S;JV@ZQJML+=;CRG:ZB;-78\'O&,C)S'$D`H17- MMBF?"!'4_H>4U&(0RRASHD?:F::)I4EN[Q03Q24)0"ZN%_XC(,/B2:N$(VQT M2RF9(XKC46:O&14OKP?%3VFP&9\OD$T]7\M_ELU^RO)6?)/U'2X1;>8_,>GR1T4^CJEQQ:G5E$A?;)QGY#Y-$MRS MBU\K:I-8">V_,GS=;2.K1K'];LY1ZB@U)]:SDV-0?\ZY8,FW(,"&`6UEYT*R M'_E:OFF/T[DPHS0Z(X*^/[S2F/XY#Q?(?;^MGPLP@L?.4""OYJ>89Z=!+9Z` M0?\`@-)0_CA\3R'V_K8TD_F'5O-.CZ3>WEWYVNKJ&-!''9RZ?I\DEU-*>$-M M$D<,/.29V6-5'5B!C&7$:I::\EVEQY0\JZ3Y;NFV\OV-E!J;\@74B,1O(*=5 M#*0?HR$C6-0U^"R MUB^BKR2VG^&*%N)JL=S&^!6#^>-!TW4='UL1:%9ZAYEGTZXCT6X:*+ZRMQZ9 M]!DG<5C*N%(:HH:'MDX2HCN33'M;\R:==>3]+DN+^32[GSM:I%&/U8'`=*21*.2G8C?WS+)0G5[JEAI%C<:GJEW'8V%J`UQU*.;'OR7C_`$1HNN:)<33MJVEZ M[=G5[=RGU>.2Y$=S&;)4CB"P212))2A(D:0,[N&8[/#(<(IA)]!V=P&`S*!8 M)]#)4#)!"+!K3\,DK9.*%%W`K3I@2@I9@.^1)5(+RZ`!WR,I4EX=^:.B:AK] MA87-J]O>VN@W#ZA?>6+U3]6U(1H?35Y%J5:)OCCJKH6`Y+T9,;(.(J MVQ\O:M<:YK^ESPVQADL1]:2>>*20RN)&D-]2,JJT"M4'+)D2%LH;*OEJQFT[ MS]YBM[Z14U'7;/1-:MHD;D$@G:X0(6[$``D#O7YF,AL/QW)+Z%\_SF/RO/<6 M2CC87D'Z0>G(^BQ(=1\R4&3GN&N'-\FP7,=A?3P6DUW>IJFM6^H^9O*MA%]8 M:6RTQX[Z'4N/-6B^KR6JQ,142AO3XLX0K9@/>RR2-955C&2`2CJU/`YEA@7J&ED`K^&708'DS*V((6F6ABFB M=![9-"KBA"S-UP%(8Y?2T!RLI?/'YL:S)9:E^7$%KJUIH]W/Y@N99;^\H88+ M5-)OXI)9ZBBQ>I/%&SF@!=16K#,7."8D!L%=5+1]>TO4?+'F>:XIKVE^6;LR MS7$4BW5O.DDA)%LZL0PCZ@=@0,U_"0-VRMQ3V'RZFE0Z(=:TN"W!OH#-;3D" M,R+QY*&8BM"=\L@`!88&[W>'^3;$6^FMK$LGUF^\P32:C/>.*.PN#4?>-_IR MALD>B>^>KR]MORWU"'2XVDO]:O4L^*H7;TFIS-`#M3KD^440^I3TR(_HVP6( MB010QHLRDL#0`5!.Y]LK"GFFMO9PS7LZT2._)47I;9UV%.?>M!D@-T6P'S_I M-IJ**EXHBM=+>9KB0L`[VX4'U$4[DDB@]\!V9P-,:TKS'JGF_7M*\NZ(\UKI M&F`6T*V:_%Z$:>DKM(XX@O4DE]NG?"-V1B(BRF7GC6]$_*RY6WAM)KV30;)Y M]9E+<[J[#1M)Z:.W$4'P\105/7)0`8+ M3X2,JRSXR7MO/<6?K"0&*[M9_[N(LQ6JJ2Q4UZ$>&-K MPB[9S^6VA6&@:@=6UHW%WY@:?QM-7M%N+"\G(,L4\!4%%6I94?F>M.F2C&VN1%!(?(D^BV/YD M^I:W':6TO%:D6EA;6K1!R-V6XCF7KUVR=T0"BC5J'YY6")#+<36 M-KZD:XD:-V81)%RA*]Q\(([T&0R#=GB?'P@D2X^KO&R25`:)QQ;Q`H= M]\BY#*+^'1H5$+^7SI>N6BR0R7+?%56W"@U.].NV^53M`?+'YM:%I-EJNDZW M;Z?:FYODE6Y#0(P9HBI#FJ]2'H?EE^"ZIK%Z>,4,2D?$XZLS$A41068 MD*`20"QB9F@PG*GOWDSS+Y)U?19=5T"=;@1TD=+R">QO$$BAXA-:W<<-Q%ZB M$,OJ1CDI#"JD')2B8\VJR641>8K.#3;C7]:U/3?+OE[3X0;O5+^XCMX(J]9) M7+D$ M4_8DE];_`%2:;?CE;8D=S^:WY?P>;KSR%)YCC_Q-IBVQU:T$%RUO9M?4^JQ7 M5ZL1M8))]O3CDE5WJO%3R%;?#E5]&#+;_1X-62&.6ZN+">VN([FQU&U94G@F MCKQ>,NK*?A)5E92K*2K`@D9&)HJ4E\N276O:)'J.JNDVHR27EG<742>FLQM; MJ6W#\*D#GZ?(@;`G;&<0"H*WRQYNLIX[>XLM3M]>TB662TM=3L9DN$CDMI'A MF19$)4A'1D85JK*1U&#<6A`2,\X63HHW%/?WQ.[$&DGG/Z0 MM(/6;ZLUO*?K+$;CTS7;PK3(LN20^8KF+4O\&:?,CBUU_7X4EC#%.0L+>YU. M,,5W*E[):CHPV;X21EL.I\OV,2'HUS.DEM;11C^ZJ&'^1)0$CTNR1HI[B M_5OJSWK/;Q$;MZ;'BV_;KD0&1**EN!=:HL0%3;+G1[**W/UJ[TJY^KPPO>W-U+(_UT)&6"01QN4M>9YB M-VJ%HMD_EI8-:>64N4C:ULM:NIM3TG3ROI_5[2Z(>!/2Z1EEI(R M`;,Q!WJ7?*>H0*]J8:K?ZE`OKW4B11M/8?69+NX+%J+&!<1Q\GH>4;[<0K M-GZ<$18%ZWY=U_2]:M5OM'U2TU:R+M&+NSFCGBYK]I><985'<5VS*A)@0SZU MFY`9<$)HC;9)#G>GL,;5+IYP`=^F1)2D=S>=@=\@94M, M7>9/--P;K_#?E6XM+SS9<5]19&,D6FPJ*MM_)N@Z?Y9BN9;VTTBWA2PDDX^IPAA50K!`JC<5````V`H,P)GVUN(&YT_2;'U',@!D"_6[QY0U./46ZY(R`&P M8#F\X_+JP;RQJ?G2&P,FK>9);![E+B]FJ9YK<2>C"2`J1KRP;)C:V:?ESB+'=Z?YHNHDU+S#!JD,D5Y>7;HD<]QZCM)'/Q*! M#Z$LB1J$12$"#-C`@C9J+U#2_-_EF3S#/Y3B\PZ=)YGLX4N+KRZMU$;U(I!R M60V_+GQIO6G0CQ&6Q*'JUE)4#+@P3R,[`Y,(51WPH2^Y:G+YG(E(8CJ,U*BN M529!\]>?;CS$OG7R7%Y/<-YAU.QU:QEAJM%L9);&26X>OV5CECB7ETJ_'J1F M'J+,=FR-7NP[6O+/DW2--@\S:LUWJ&J2:M+I>M:O8.=+>-XW43312V@CG?B# MM^\Z['PS$$B!S;*O:DX\VZ$OD_7O+PT_SUK^HRZG$6\MVFO.FHZ/":!1(_$6 M]S(:,!\5P1ON-\E(@=/Q^/)$02"K6^I_F!:VVG1ZOY2TW4FC017/Z!O!;E0N MR\+6\"(H``V^L'(5$]:0G=K^8GEV*&_TK7I[GR;#=0R6MU?>8+62QM8#(I3D MM](/JC=>J3')1@>08^:CY"U.#2M-OM3M9(M>\L^5?]Q.D360]8ZE=DAWGC<, M5XKR`VJ-]CMD1Z=RSEO\6](FN+;S9'87E[#=ZUJ\S:YYXNXR%@TZS2$&.`.= MB!\(Y5ZG&K*3N/N>;>:TU;S?KM]K:Q3G0]9G;3O+4:MQ5Q;!6)4;`@J78>)R M)/5G&HBF9?E3]6\H>?\`7_*<\\<8U81SZ9,X^)O2$C+!OT;C(3_LK6`^<-2\O:EYQUJ[U'7;J\US4;I62.S MM.*)`XIP#N0P2-0?F3[Y#BMNL1&S,O-_D;4=/\A>6-!EG@MCHL#7>K73-\-L MWIR-(0!3D6+<1DI"J8QGZB6(ZSY6\G^7O+VDFWCOM;\SZC8)VT.S<4>5V`^+<@_&310 M=^_?)Q%;EJESV9Q87=M;&^\QW&IP+I2)*E^7H!!)`:."QW&X-0:-8O-72=:JT1O;I]0:0/MQ1);DH&_F!';(9#ZMV\&HT M'T+^>6I:1JFB:;HE@UO/?2RMJ`O`PI;PQ#BSD@_MLZCWIAR2'1CB%&WQIJ4M MY/=W%S>W!N+]Y6-Q+R#DL#N>0)K\\K<@,/;S%U==B'+!6^@@[Y'&:DE\XV&CZAJ- MS%:V\!]2:E"WP@`GJ:^&9)D`KWO1()K'3;;2[FX6YETY.'K("%"LQ8+4]:5S M'D;-L4]TZ+T6GN&;EQ?U)&.^Q.P&1*7DNOP#ZYYKU*"JNFI0.41Y?I*!S+W7\K/+3:REOJ5T6]"(>D+L=VY`+6NVV5RYID:>@_F;;VWF7\ MT_\`G'_\H]4MG_P?=Z_?^:?-%#1+S_#>GO<6%O,!LZF\FBF*&H/I;C;+L)J, MC\/FXTEWYC/JWD/\P]?_`#$L8+77;GSO;^4OR^\DZ%=-*D!U+])ZB[7MXR@U MCBBO^5$^)A$R[5!QA4APGI97DP3SW^9OFK\T?+FO>6+/0--L/+$5UY(L]>O9 M)Y/5GF\R^8;6&&/3Z1JDD0M$]8EP"Z31D<>+!K,>/@-]=_L""]-_Z&)\ZZ\O MF*71O*.FWEK?Z7YVOOR]NY;N3UF7R:R:?ZU];%%#QWM^P$?IRJPB*EJL20#C M'4]U_%%/6/('G`?F#^7VA^>(M%GT2R>FS3:YJ<^EQK=,KR2\[5K*ZGE4*M40(M"0YB,((!M*5^2/S\OYVETN MT\M6MQH'EZ=HO,&H1W4C3G4=8OM5O8UM4$0#06]G:"=V?B6252M.#!I9,0_' MP0$D_P"<:];U]/('Y3^7KS3K(V&H>2;C51?6[,]S#J&E75I:Z@+M@S1L;RYO M)GC"\2OI-RY,3PCJ(CB)\V42^M;*]FTN6QDMV+P:@P1X&^R>0K]!S&!I)%IE M)#!>:D\T='C]+C*5T85#48\'1J,+(FD%+K3S%>Z;JUGY:\V116^L7-P(+'5K: M-TTV^Y#DOHL[2>E(`&!AD2[@F/<@,JN;N.VN8[":0R*KM'!(=@Y.]! ME=II?I-IZ%[J&IS'DZ0/'&6V"*PH$`^>&*DI3H*F76[B\ORI,++%'#3X54$L M#OW-<$>:9IZ3'/]4_2]B=*LI(2(RLU_2UB2&E*/RE`4#OEF,7(, M67Q1)&J(B+&B`*B***`-@`.P&9BL*\B3?6]"?447C::OJVJZAIS5J);.YOYW MM9U/\L\)25?9LQ,Q]2AZ!#Z?JB1_[JW7FU.].@^G*PK`_/.I7MEH-]?64%@5''X@149+&!*0!2>3$XX='O_-T/EG2 M"VI^6O*$"W%Y&]PUW"=:OIGN6DF9V=I9HHR)/WA(4RHR@,!3(U$Z%!`#T'R^ MEKY:\XZ3!96QAA\V6UY;:M<`T22]LV-W9OQZ>HT,ER';[3*D8K1`!+2SVI$G MT)93$@9L`6I/HY-ADE62RT&)5C]Y;]4UQO,&H76H)HVK MW.GQ^5Q*\%A;"%N4!F@C*_6&GMY(ICZY=1S'IJ@K77:C+(2ILB%2+R-Y.G?B MWENTM1&I?G8*;)Y``?@D>U,32(W=')4FE0:#*(Y)#JDA,-`MM/T_S7I.F:=I M5KI6FWEC=3OIMG$D$;S0!`'(0`?$3UIU&1!XC937I7ZYKTMA+IVH78YV%E>" MTU!/VO2<\#*?]44ID;LI`MD=R#;1WEK=2*EQIUP\D4R_[MM>/J1$_P#!<3DB M*V8L?@]6>9&0.RWL121E2-=OLUV.U<'!'O;(V!N]RNM1_,*]LO)LMKIF@Z"R0(R?7+FYU( MDS1A6YQ)#9A6`/:1J9(F(KFU=[Q/R7K'FNVE\N?F#K+6%U8>:%LY-;TW3K"Y M66VM]2MZF2,FYG,A@GEC+_!_=K(0*@8"(\1BS))BS/\`-'SEH8\M6VNZ7J/U MC4]/22[\LZAI$MNTZR0QLMQVU31?/Z7UQ!<7]TRQ5.G5@4_53&29/6]1)%_=H MQH7S81LCN8E^@5B#Q'AF0&MD$?3)A"N.APH26^>AD^9R!9,#U>[BMX[BXN)D MM[>!&DGN)6")&B`EF9F("@`$DG*9%E'D\6T;S+HVI^4?S4\TVJO:WUWJ"1:5 M=B)A?/;6EO;PV+!>/J+&UPLLL:D"GJ%J`L4HJ*ZPGTWDNI0*<6G?ELV].N8Q;H`='K/G:*X\VIH6H<[6P MTF.%K>VL2K%^;<">+T`HI7B:;5&U<9FV$=FY;/S,WF^>Y>[0^7XX8Q#;Q[LS MLE0K;``DDG:O3(TC:O-DVK:TWD_2#!96QN_/'FUGM]!LD-6%?AB=Z[(J4M`T[3;=+/0O-'J:7IE_YJTUGLKV:ZU.Y5)Y/K M%N4ED"*78!R0`.F3C*C1Y!!WW0OD_0/.ME?:IJ^DZ['-:Z[UFC1(8Q61VD^*OPG(`@]&4AM2KI'G+S/I46B>7?,FB?I:[TVZ.J MK-Y7FANU^J2MR5I([M;.1-F^S$)&I@H'8%2.KSW\VO,OEY_S!CN-`UE[>]U! M;>817L%QIUQ# MA0$4Y;],-]S`A;K>G3ZA=6VFR3^I)-"\MQ;<0YN$!'Q,#O133&0)4&D1%Y$1VDI!CA]5@BL\:CXC\6P-WF[\SHM)\O#RC^7 MFAO#H_ES2H["RN$3>2.%ITVD-=PJ@2$$?$37!D.],\?>P?\`/_1KJR\WP7]K M$J:?J>EQO"L.W%8#QD5@/#8_3[8)BBRQ'9XK:IIERNG6\_-9Y+EHKD)L6C<` M(P)VJIKMD"V)#K4=M;P_4]'LE@)N`]YRJ&ZA6D;J2>(&5:VDB:+DOJP MR03O'(G(5!JK*X5EE`U?<6HE+=8_*J#S8=2O6-YJ5]=7,T'K$(%I&H6,"/]VE$93T300>E_DIY0@U&VN+75-5B MO=&DOA9^C.BA+34=0_2=Y8T,1K;RW(5B#5J(BA@HI@\8I(>O^5/*^G>2O*,/ MEW1Y9VTW3S.VGQ7$@D,,2>SL[WUUCCAK(5C#6[-&GP*VRE2,EFR- MTE&7/Y&^2;LWKRF\#W]Y;ZE,WB6>J7Z(TLB0+(O)6"NL; M(C*B*4XK0F>0\OQR4`I,T)Y#A)#(&20."&5U8`JRD$$`@@C`)$&PFF(6PN;;4]>\LRZJ M^IVUG!:ZQH]W=S&:ZBB9GBE@>0U9PCQ<@S'E^\`->-9/(5MZU9/TC>7#6E*U2/3KE3*?`(TBK\W&9&GYE!9R-B-_EF32L&\CA( M?+XTWFB-H%]?:2EDH*M;6]I=21V<+JP!J+41$&E&4AUJK`G#S"I%0S9HH2D? M-RL,A^.FY8#IX=,J5*Y69Q524#UZ#<^X7P-<"4#INC6>CP+#IEK':*[,\RHJ MJ"&8L104`K4GYG#NFUOFF!_\/R7^GQ";7]!ECUC1HW8K&;BS_>>BS+N%F3E" MQ'17.6XI\,K8D6]KT?4K>_M+2^M)/5M;V&.>VEZSTRRO=1U"Z2TL;"%[B]NI31(XHU+.['P`%ZMI;*/S!J$&RAMH;:$2H0"AD:*2;B=U$G%O MB!`UV>0E+9L&S)[BY$"1P6D;7,[$_8'@*G?PRE-,=U#7-$\O7MG-JNKV.FR7 M$,MO$O$U8+-':V,[*X MY`J#-,D4!!'\T@P\!Z[)M%ZAYRU.&%)==\L:GI6CV\WU;4M3E,%W=6R,IE3U M;;3Y+KE&0G$LCL5)6J\2S*>&^J&86VLZ?=R6K:.[W.FWTC1VVI`<><9CC=)4 M'7B_,\2?XY$BC2TP+\Q)0OE+S1:*99K?0YH;J5:LL4L>G7<%V`!MLZQTKAA] M5)\U7R_8Z>L,_F&=X=.M[!AH>FN66*(1:-Y>M+RTMO(D6C)%&896BU._=(NJJL+_58J4`1RTU0/BC4F@R/RP, MK*.)EUS^1GEC4/+WFW1I9KJ]O_.%E>6M]KFIL+UD>\?UGD2U8+;)654=E2-5 M8JO+IF3"`')B2]%_+;\L?+_Y;Z3+I'EZ.<0W4#?D>:Y%)`B1X72TGFH16"&Z:.24]%`#O^[5\Q09/*WFO M5+5K7S5>V&HV>NZ8!\-^]O(JP2R'H*-1C3>E,UOTT6\#BL#DQC\L=.N?S,\] M7_F7S-$NH6UJ&GN(Y4!BEG/PQ1<34<47>GL,8CB.[*9X10?6&OV]W;V<-_IJ M1J^E(7-EZ:$3(M/W8+#X=AM0]=#*V.H00*%U@3G3)7:D9U"W M5/2BF(KP9U?8=\K,AS9\!>?Z'<:EK7GOS'YNUM(XGL=)C33[0R!5LVG7]P&= MJ!=P26/"V\CZA/#H<6G.XCG,H" M/;^H^Y%)F5BHK[T&1`V2.==Z>:7Y?\MV5IY&UJ6FBFX6:ZCTB0,][J/*)5AC M)8EN$:&M.PW'7#P@`$H).X8/J\MS^8FH16]OY=MY]+T[7+>36'N84EB>-G*Q MPHCJ0R>G&S,M/GVP`F[94(C=DL'Y<:'%I.L:_P"3[F\\J^)JESJ M,;:5>6<_H2(3--:++$:$`@K;)6@V[Y$F,MTC8H#\NO/D^FSS:AKGDO6M'\LV MFESQ?IJ&SEU&&XN;B199)@NGK-(D;<&/.2-`H^U2N,(]Q3/[5WDS5M.\Q^=[ M[5M$URSU3R;Y9O$O-5OUGC8I.J.R*(D/*I+"I9>M=ZY$0,3922*KJS32(=8U M'S/KOG+4[M=#L]:L)=%TBSE;E=2F[*&V=(]_3!X\@#OXC"#S*#0%)2FM0>?9 MK_2YII;2UN])BF8**S27%E*L3/*P&P"QMN>M=LA=IKA05EKDVG:KKOYIRZ=] M4TW4WTZSL;6Y%'FF*"*X,"_:^",D@]S].2!ZI(L<+,O.;)#J/D[2)4:>'S!Y MFT[A+,"?W=ESU5F8'_)LBI^>3@*-M3SO\_AI\7F-!PJ-6L5N994!+O,G[F.A MZ<0J#8=\ADYMV+DA]:$WYD?EGH%\DKR^9/+-K7?+\ MVNSVUC:0%K3@C2L0=F+4%3]^*\MWTCY2T&+0=/U9[.`2076L7,%W!U200<8F M!]ZQG)RZ>YINR]EM+:62;0=)L+4Q3:HWJ2*BT6.!-W9VZ`4ZX`+8GJ4_O+VW MA6>VMC6VB7DYX!0?A0'84\3AZ()LH=[QX)%LX;0++?1.$N:;^JBL0K M>%0,"::T:XNH=*'Z3/%VJWIOU4L2`"/?%3S3"SB$4,:!B54=?'YX0@L6\XW] M[;S>4;>QUBYT6WU#6Q9ZO?6L5O(1#+9W7H(S7,,R()+H0H#QJ6(7]K+(5O[D M-:+Y2N[6U6V7SGKC&]NKR\,3)IH`$LS3.Q9;!35I705)G_+?0?K$\\FH^96,[F/B'R^0_4JJGDKR\+>:2'],W+*E81=:YJUSRV\)KM_QQ.0_@!-(8^1/+4J M#ZUI%O=24"NMPIF%>K?WA8G(\9[T[(D_ES^7DAHWD/R[+VYOI5HQ/O4Q')>) M+O+&F*ZOY8T'R[YH\K3>6M#L-`.H?7M.U1;&WAM8KBT:U><*RQ*G)UN((>)[ M(9/'#Q&0-E(#U_18_6LX+4<8C%,ZS*.D9-'X_<:Y`;J41,;"">5@M(XEKN0# M2M*GYX-D(/ZZ_P!=NH/2"B-4],?.M?NIC::21Y##^8&FMK%<0R7"KX%E,9]PGMF9I^18EG:]?D,O5A6LQC2_-WEC5K1`K>9I)M"U=`>( M?TK6XO[:TG@HRK/&XWW*RDCELP#`=`=\PDMEJMN=P*5]ATQ5KJ MQ'ATQ5AOF&74-6U;2/+'E_5SIVJ>J-1UF58!D4RH+I32B7%P$0*'1W" MR<#1'*WXN^7+.#0M&TC1+>62:WT>RM[*"64@R,EO&L2LY``J0M3M MF?;`LG%[\/VLE98TEM[J,4,,T\TR0P0(TD\\C!41%%69F-```*DG!:7SIYCF M\S^?[W2=7T<00>5M%OEN=.T/5&>&+63&DHCO9Q''(XCBE,4ULC#I.=$T]?54$4`]6_>Z0[=/W(S&N/-C`[W.IW-M:FB_$);6S>WMI-NQB/RP1F>E!)4]"@\J^ M6]0T74?+&@V&F'S)`]X+VULX8"'A;BPE9%4L:D'?$R/4IX>:8*FG:5YBN)Y9 M[F>QNT7Z[KMP/@:2OV44TKNY)(R/5.Y"*TK4FU:RF=;+ZBEM=*6:Z0F5H(F: MC<#W8`;GH,""*>7>5I?-T7F^\TSRI%;>9?)/D*W@N;N"\I9WLUM,A6TL(;GG MZ$DJB)N/J(@X*GJ2`OZF9`C&7J.R#L*7_FS^8_E[_`OF/7-*GB:WO=/N_K(O M8^"VUP/W:VMU"_%D<5^)'IL1V-<@(>L!,>3R6W7S+/Y4\N6^OL);'3+)#Y6T MG4>4SW=S&:/?X^`1;UG\O?R)M)-4 MD\U^<+"1KB\-M.^B74S2-=7%H6-O<:I%'(]LS0%CZ$2`K&*V]U9WEO'=VEW&\-U:RJ'CEBD4JZ.IV(9200>V8Y;'S+^8,EW MJ7Y=?E7K>H:H+V]%E/9_6#4->0HJ*EX>HK(L:N3WYC-?G%%NP]4E_(G5K^Q_ M,'3M.CNI$L=52X6[MEH48Y=2NM+N;#3-.EO)K MV)H&G61(1$''$MR<]1[`Y;*R*#C1?,=C9:WY;NM&\GRWESIUO!J4L]WK]B@9 MKG4&JJPO*U>/[FH6FYRFR-F\D'=ZE<:?!YFU;S?Y$N(9M/TN[L+AR0`LAK!JB\E>YOM=_,2#2]-D=O+'D'0AH%]J[E4+2Q$O? M7"'E\0I]4-0.^^&?T@)&UE.=,LM+M1JFE0:(^L^6_++ME1OB- MD2-I%KNLKY-M?->HV#1R/J]P&N8YGV,R+Q^$?SE:5\-,0+1+TJ6F/K%GY8&@:NT>F+HM[+L">F/2DFKL/%/S&;2)O+WF_05T^*\)L],TORC(L""73; MO5I([5>$P7U%=))@00PJQKD\4B"LAM;Z#T'\B_)K21:E<6>I13V)3ZEZ>M:I M%P*#X2/2NU*D#?;+(V=S]S7:)L/R9T.RN;VY\N>8/,>@W-XGH&2VU26<(J`@ M+2]%S6E237!$^04FTNNOR4)*A/8]0@37TNKNWM]4?5;>.U\K7#@.UNS(P=!4'CS. MX;WIE(+.MDMN]&'D[1?\(ZEKKWGZ?OI9Y[>R`C$5O("TBR.:E8@0W?`0-V!+93 M6[37FHW0:>Z>BE5$:(O0(!OMOW.&TJNE0Q:EJ-X9+>$V>DN%A>OQBY"O6@KT MH?#`=@J;W(%S:-9R1#ZO-42H1LQ(I^K`ABNCZ==V6II`K^KI4Q*JRBI4K^R? M#;ODSN/-D^T-#\J6.FZ17-.OKO6]4U:_EOKFUADE(N=2N)K96=D)(6%D`WZ"F73D0:![ON84SV[ M\J>5+6ZM+4^4=!(NU9$E6PMJ"A%%/[OWR/'+O0`EC^0_)>G3_4]2T+1I9(V^ M!(;""B\^JEN!+'KB9R[RGFC[KR=Y5D1;>W\G:)!$*%)WT^WJV]``.%=Z8\^#CEWE**U7R?Y+M[NPMT\GZ/)< MW*EQPL+:8KN3RDB MACDMY(W(ILDHC)J2G(EL>,'ZMU/DR)/+.O&;ZQ%Y]U=#']BV>UTMK0GL'1;) M)67Q"S*:=&'7")#N^]#SOSM?>9=*O_+,7FBXT_5_*S:M;76M:CI&FW5HMFUH M3/:O=!KN\X0IS@M)6#":WE6.XO/6'JVTD;$4-&)7D>)R1B!O>Q4;IWJ>O^:+^2 MWU+3OR\O1%>52YAGO[!%`ZT(2:0BA'?$QCWJ#6R+BU#SM+/]8;R79Q2E%CY3 MZP`:+_QCM9.^/#'O^Q%J-]<>8)_,GD--7TC3["W&JW3QR6M_+=2EQIE[0<7L MX`!0FM'^@C+\`%[(+T[F:GM7H,R:6F*^9+@'5O(]E'"9[F?5YIU*BIAA@TZ\ M$DQ_R:R)$3_Q8,KS?059(.0VZL=J#,%*Y!(S!%3D\FP7K7%72HEM&KW$Z(6) M^&O0`]SBK&?(7[[3=0\QMZHD\X7\FJHDH"E;7@EM9<1U4-;012$']MFZ5IFQ MA'AB`QMZ)%.?&F3M-)%K_G*UT1X-/@@EUCS#>QF33O+]H1Z\B`E?5E9B%AA# M"ADD(6OPCDY"EE,1%EB0\I\_:3YDUWREKVI>8M753IMM+J%IY9TTM%IZ_5&% MR%N':DMV>,90\^,35KZ(:A&+XYD:')-/32]02IKX'K7QS%9)C<32>G8,7XQ4 M/K<>IW_ABA*6T]7%]P9@H-!OA(2.2`O+:UU3S$\=TZMI?ER2"2:U#CBP(+HLA\6 M8`MCU2#0]Z6ZIYAAM/-FH7U_.$TB2QN6GBM5YF&&U@,\C4&Q?BK4&$>J2UZ4 MHBOM1\L^0[?RYI]@L6M2J;W6G1_6N)Y[J3C#)<2*S*TQA5.80^FI'".D:H!/ M++>AR1"-[EY[KOY>6OYE>=+V30=3L$7\MIM-TJXOI;=[FTNK^V2X^N1W$"30 M&22U9H6B9B54\@"23PR<6/TT>K&]WTAY1\E6/E]#,9IM7UJX18]0\PWHC-U. M%IQ7]TD<<:"FT<:J@ZTY$DWQB!L&)+U6QT^H4E=LMC%@2RBWM`H&V6@(36.& MG:GCDJ0B50#WPJJ4PH;&*78JQ_4!O)\S^O(22\?\_P!]<:1Y4\UZM9R>E=:7 MI%]=VTIZ+)#;O(A^@KF/-F^BEZG_()`^>,>:Y9 M='V3&OVHPS%S1W(K2K=LR`X[YW\Z^6)+#5-7CU>YNKWRUKEPFN_WH$D=W:NB MO!$HH2'C;J*$!?&F43%-T3W.19$;4R'R=:Z:VK:OJUV$GN]5U?5+B+3/4Y(+!;A+-*I4@A MTM(S4]1*1=7"Q5^%&Y?:8]NI.1Y M%/U#N3K4?(-A=:5H]IYAU2[U6\\Q:FM[-%;,$B:XNBKRD,02$2-C2G85.$QY M>;$3WV334O,DUXLN@>1(DM5TYX5O]9J`BLC5]-#U?A%&Q/AB9=`@"MRA;/2= M&U5[C7Y0FI+=0/>1W=XQ>&I3E'Q5M@.]*9$!))&SP]3'K^L^73'&\VG:SYYT M,>M0*K3:5749(U7N%%HIK[Y+$*L^3+)L*?;FC2R\YHKH!$E=C`AI2BGX1UZD M?JRR#24RCB6V1H$%0"[N!U)D)8_B9`T@-&7ZS_P"ZVP2VB?>/TLHA;%J%A87>E6&G M11?HNU>))]1E/.3ZPYK"B#L=@:^^4-E/-OSB\UQV6ISV8U.XN]1NHU^OP1,! M##R%>(`'7NII3GL":]`/')!4)Y$2">RU&&1^>H.P>X>NXD50`PVZ-2N.14FO=;U4>6 MK.VO;;TM7U29UMGB7B>,4G`O[U[A.[V:-YUN&_ M>B,JT,9VXNM=QD"600]Q%&S37,S@C7A"O%9' M&[/T''VKC::1]NPLA=>H_JW"[&=S0?$/A%/;"CFJ^F6FM@[,\F\O(GXE!-:5 M[BIVQ5+KTUNI7X[*RT`WJ-CM^.!(9-*[-ZEJ'Y0.HDM70T(%-P?`C),4G^K0 M3.T4D:R*P821L.096%#R!Z@@TI@2PGRA&NE^8M<\L-=2O:6(@O\`RU;SLS&* MPE7TF@B9RQ=89HF[_`KHM`O"LY;@%')ZP#0JQZ\@*^V!"6:G\/F-B`%66SCX M'Q/(FI^_`>:1R5&=(`7DZ;DGP\,54KE0Z&/[)E1F4CJVQZ8E0E;K'):Z-!)( M9I`P^PN[JI`(;P[8$IU.Y$<9'53T-L292P_8YJ025I*.\2%9II\\D=Q=7,TOK1 M0EXIH1LLD[!1&B+_`)(J2&_M#ZULB2\7"F1E]-B58<&;DI!H9XI\,K4A MK1-<\^ZCHMIJT6@Z)K&GW<%O+8ZL-1GL)+I)XQ(DC61L[@0U!W43R?/,GQP. M:*66=K^8DOF:ZUR\TORY:1FR2PTEHM4O+M[6%V$MP6A-A;JSRR!:TD`XH@ZU M)KR9(R[UI.DT_P`\R/(9?-^F6D#=4L-&9)P.X]6YOKE*^_I95<>[[52F&TUU M-=UK3/\`'>L^BFFV-Y"5BTM94$TEY'<,'%CT`BCV`!'+KAL`77WK2C%Y'TW4 M^2:E?:SK-@P$CC4-3NGCGKO1H$D2'CXCAD.,VRJDQM_),>E".+RSYAU3RO8I M$(4TBTDCN+5%'Q2XG`8[A8Y$X]"9.N2EJ#T6DWTK0].T5+CZC%)ZU[ M(LVH7]Q*]Q=7,BJ$5IYY2TDA55"CD?A4!10`#*93,N::16K0(^CZB;F)[J"6 MVG22SB7E+*GIGDJ*2`2W0"N`]NTN[U]!T]YKJ-N4L:A;P$/ MY2PNQ`]1H(XX&'4*)33=F&9>GB0&!+V[3K.M"1F9&+` MEE]M;@`;9<`Q3:..@&2`0B0*=L*MXJ[WQ5V!784)+?+4R?,Y`L@\R\VZ%9>8 M]%UOR]J2NVG:]8W&GWXB8HYANHVBDXL.AXL:'*9L@^;=:EN4M=1@O8HGU?1+ MHVNM+Q$4-](!ZT!2*%>2#X/HZ9"'-&1[U92%HXJDDLG)C3;8TI\\R0U/'O./FJYT[\TO*.B M1V<%Y!=6DL;O.H)M_7:LD\9/0QI$2?8G*Y'U-D8^DEXSKOF?3O*GEGS1KWF- M7D\DZU>W@TMK9`O];/IE"8W:,#CWZY",;-=[,_:$U_+/R;=>7M+T MJ36(Y1YCL=.M]*U"9I?53C'%$R?9JO(IQ8T)Z^^"1)D2Q)VIZ)YOTV_UC]'Z M!(OZ'\F?7[:+41*ZK=ZK))*B@1H*LB5WJU":?3DCW=$1-;]4EL93%TLA&H^$2-'\1(-0".F(^ID?I+I+W1+_5?,-M#= M?I34?.KRV)NHGJ;>TMJAH8V&R(#W[GZ,AQH_6?T_H^_UB]\MVS6>DV5I:Z! MH$!C9([B]N:-`T*$`D?'+S=OM`KUPGR15\TUN;6S35=*\K^7K=GMO+FO,TL+ M,S!IOJ3N.98FJ\I/D":=,>1H(\R\;:_@B_-SR#Y`TY@NC>2F\P:F][R#-/=R M1+;/*_'9>!NV5>X'ODQM$_!,AU?7%[=,+^U@M9/BOKF)K5^-5$<:$.PV_;)_ MCB3OLUIW9ZHDZ6C2A;=Y%E%PKGBP,-5.WX_+)"2%+1[^UE@U*96'IP3,LKG: M.@&Q!.W3KC$[%:>._F3Y2\E^=KK1M2U.VOFU#1EEM(-4LM2O=/D2WG9'9";2 M>(2`F,'XPP%,B[5O+/F[7[6Z29)H8FEM+I><:\`["[M M9V.W3?*3,=P_'Q;H@D/G?4]7\Q2ZUIA374UF_P!>NW6Y_2-HA9$C@DE:2MN\ M`J"BCI3?"!$@FN7G_:SJJ2F>X\\:GJ4]E83Z==2!:W,Z)+$L(Z`,Y:4`^PJ< M1P`;VRW9%+I^LQZ+^@M5AMKZ:XB,1=+W]XP8U^`3PQKMV^+(W&[!^Q;+!);K M5_+GFS3WGT^]L;6Y2".!F>T>J1A8Z,(IV%#3O3KD^$2CS'V_J6_)[&=+@U34 M$O[[3]2T=-+A,:&XTC5)8U0,?WCRV]I+$HIW+8P@0.GS"#,!ZQHWF+ROY7MX M$;SEI0ORT@%W/<>A###*JDHHNO2(8E:FB^&)A(]&!D"S<:AH5]^67F.]TR[L MM7U=K&>P:^MY8YW9KP"W6CJS&G*0;UPPB>(6&N9^3TGZTPC,2DJM:;=A3VRHII+[S48[.1&<4E?X8%;]LOLO7K4C`D!T>KRRLMA):5OY8:R MQ"GI[J>Y['"M*MCIUU8PRQ7G&&Z5/58FAXFE54?/IB5)M6N_^E6%#?Z742%C M6JL*@?ABJ)$LL&G+"[J^JQPO*%.Y"HVRD_=BCJE[>C<7UM,CI&H!(&Y7H#]./)BU';B$F1C\3DA2>M.V-4KSW74AL-9 M\H:Q<0.QL=7^JRS(>7I0ZE#+;+5:THUP8!6E1\N59PY$*7IBOZ\4CH#1'XD^ MX[9%"'UA?@TW4>\3>A(?\EAB4Q6R(98U5:<]3NM-T8R6RLD?"X0#H%CA0MS4'^8D#'F4\@U!';G3[NUM;51]2F!EA<\BY^ MUS)/4FN]<>B]6,?EG*EOY'\GZ1/)2>TTB&UN(CUY6/&U8?/DE,LR'U%BS0?N MV,8!)J:D[5).02IB9`%`8_&-J5)^G!:L3O;8IY_T"[!"V]SH&K6MPO\`/(ES MI[PBG>BF4Y9_"??^M67[*`H``V`'],@K8IWHRKV'^?OBJH!2A(KV!\<54B#N M:[_PQ51N8YY;:XAM;LV5P\+I;WPH3`[*>,E&J/A)KOA'-7DWY8ZK^F?RP\BW MS\45_+MO;LJ,67UX8Q;L*O\`$0&4TKDLXJ93'D]4>>?-/ERP\[>7=)U+7+#3UTW2S+907-S M%'//+>R/)UYLV#+L>$M))%K7F&YDU?4[:5BTD#7` M58;=STY00)'$U-JKM7J=KCAP@!J)>W6-N%4"F9`#!D,,=`,L"$6!3"K>*NQ5 MV*NQ5V*I;=+7G\SD2K$M0BZD#*I!D'SCY]LOK'G&QT\1QV]MYCT.:WFN)D*K MUB#K+<(9F(IS0;BOT;Y"6]MD#1#Y/\^V,VO\`Y?\`EO6M=U". MY-E91:=I>B6Q0?78[&Z+7$+2;K&SVX$88BG(@G8;PB=P2V]2`^@?RTU_1->G M\UOI*R'1;+4H&LYY0ZW"(MHMND,J2#DK(\!4AMPU0V^2JC35+D$ZDCN+Z'R@ MES`(/,&N217_`)EF:LLT=I!^\V8U$0+%5"KW:F#N[U[WFWYE:O:>7=3OM-TB M*2X\ZZ](Z:C?0U:2*.Y?G%90`="RNO,@5/3H:`2V;("]SR>:PE_+$%QHEMJ, M-EKE@'U7S'J'J`@/#^[BL(*;,P,AY4ZDGLF19<]WI=GYY\OZ_I6L^8M0CAYZ M7MM M/86>GZA<>;_,#W@(6-;6%(X5C-!R4%05VZ5\,8FRI%?>5.I^=-2U>U M:6.Q@GUZ_P!3C('Q#@BP\3XU^&A[8QYVN2'*GEWY50MYB_./SSKMO#ZUMINA M+=!9>WZ1OIY9`:=R+91D_P"#XK/;9]Q*WUK6--FME$5H;-2).BDG[*J>]*=, M>9:52#ZO;:UJ(AA]54])YV.Y]29N+D5Z"AJ#(=DA\]_F)K\7E:RCC:[07EW!ZL,4@*FG]G?*)2;81M\CSSG7KR>^F MN^*\CZK@?%MU^)B:#*B:<@!@&K+IUOYNT%$#S0QZ=JL\WIDLP`-K&K$BM-I& MRV-\!]X_2Q/,)OIT_P!3TUOT-`8[:204N`G-RSM]H@T+4)KD#N=TK;W1;87$ M&IZSK<\KQ3QB!F]-1S)HJA>/OTQ$N@"LTA_+D>;_`#CY2TX*OIW2F.02$A1& MLB,S,1X)R/T9+&2@F@2^K/SSGT9_*'EZ\T.D:7%]/8B5`%]2&U#1N!3JO,"F M6R`H4TXKMX)Y0U_3]*N?3UN&2ZTZOJ1Q+0\)=J.0>H`'3($-LA?)[)JW^`/, M^A7=Y/I]E+:"0"6?ZE`\S"-@2BET)4M44.'C(ZM/#18%'Y1\OZIJ]O\`H7RM M^@=,=T5)K>>XM9)`#5FK!(E:CZ!A\27>RX0&>R_E9974MO?7'FCS!:W<#\HF MBOFN4B0'X`JWXNAM[C$3[P&%]RIY`UN632)VOY7U?4%UC6+*/5+F.%)7M;&^ MGMHV?ZO'#&2%B`^%%KC.@=AW?J;5-#]%,*@*4"W37U]&5"SWT9-O,PKQCZ!1[TK@5--*M&M8 MX;/3[4?NF),\R]9">M#U]\(02F%Q^XFC,LWUJ]NN3W+]@JT"T\/EA0$/#SN9 MWD8_!'\,8^C!S5B?YBVL+^5==YDJ\]E,$E5N!B=$9XY%;]DHP#`]B,G':05E M^AOZ\+QUH;M(KN!:%:ATJQH=QN>F#ELI5M4;U=-FLU7G)(X`'\OO@*CFI6:R M+#$DE/4"@2'Y#?$*Z\#^C*(V*-(IXGP--NN)4);I;+*L\SD_6681W1\"O6GW MUP!)8+YENY/,FK/Y)M;>=(()K>7S)J99(D%JRO,((JDN[3F,1M10`K/1PXIE M@'".+Y(>BVT27,JZQJ-8HE0KIUM7CZSL:,S=Z;$4R'O4]S;74,^N/).HX647 MJQVZ+4&1OA04]@*XWNM;(BP65KR\U*8,+RYK9VB`5*(2'=_FW&F(4HM0(WD( M7BTBE9/$^QPH8?Y+FC:UU&>-`MS8ZYK3N?YG/EAOW':&?3+Z-0?G/Z63CR/N_2K.66.&W@F*&1I"] M5)I]G84R"H"+4G>\%NL2T1`Q0**5D)'7_8X+6FK_`.L6VH6\,C422/E*2=N9 MZ`??B=BD0>BD4C_9F/%37H0*[_?A0Q7S]J3:5Y9UR.%:W&JV/Z/TR5A4& MYOV6UC55&[,/4J!WR>/Z@@\F'Z;Y0\ZZ/#'HVD:SHMCID5_J=S`UQIUQ=R^A M>WLUW'&.%[;*I19@@-&K2OMC*49&R"D*_GN76_+EUY#BN_/&N36FN27D,NC: M7!I\+W=U%$LD%O:DVS3*SL2-YZ`58E0I.6Q`(V#%C_F/R-YAN;&SN=>@:ZMM M1O;2V/EVPU"]U/442XG2W817NIW(LR[&02DM:*$4%`22)5,)"Z'X_'O5AVC^ M9-/TGS-YL\J:/%/#I=E/8Q1^:)M/AL3I4MTI@>WU<6\4(B>)X7D+M&JT;?V\LZ9;OJ;^6='O8M`T^8G>78Q>:A=6GEGS9#8>=;(E[?5+J-[ M^#6-"5U^I7,\'K6_UAX;>:*)IE=765:.S(>+V4)C=BG7D&WN_P`Q+ZRUO7HO M]`\KW6-SLI20*U3M0&M149CR#,,+_+[5 M)K;ZGH^H.+B]M5;UYE!"EXVXO0'<"O2N:D'=NF.KWN$&XG6*1&FC:-J6]2`_ M,5!8BG2F7C=J3:2QFN=*NK!X(K*.XBDC]&$U^%P1N:#6M2L(]1MXKRZLC93$M$I"NID(.U!QY'Y9CTY4CZ;9/:>:H?(_GK5-<\M< M=1\K>;+X+YXEN62&RM+NXD6."\4D`[7%RJ]3(%8B/?X=F^1`ZE)GM3QW\Q?)FE^7M'\ MG:EI?KF77[>XEN1<.6F<1F,I(5_9J)#L,%4&R$B27HWY5:+IWE7R]K/YDWB2 M2Z:5Y M]OTLKE(:BXMDAC662WYDEN!>=!X?"V`)EW]S)/*7DR`K^:7D^WU']'RQ>BNI MWK`2L+:V+R%5%5'QN:$UV`P@'<(E+D4G_P"<=/+XB\Q_F'^=3[C)D;!A,V7UFEK'2H=C0^)ZG*)SL[-L(6^-O-OF;4?.UY;7UPY:XF=XQ$#\"[UH!V'?*^ M3>!00=AI\5HLI$INE=PC+2@!&[&F^1)ME3$[C4$_Q_>V[2<&@\NP+!&@K_O3 MO+*D,A*QQ@D_Y5:]`!AALMOM[\BORGO-`BN-=\UV MB_7T],Z99W#\[B-MV]28U(4FHHM?GF1"'5HRY+V#!O\`G(7S-'?^8;7RS9HL M=IY=0F8)Q"M8MD\FQ"M M(RT`C4G:IK7(%G(D![_?^6;'RWHP3R_IP:>2YBISK+R)J`SAJU%1I;7D[26\P-*47?X?F1M@6D;J-_+'->35`MK)$^IP_[\Y[%F/A6N MV)0`P?R:MI)Y6TS6H(RT>K&YU!5H>E]<27(H.U?5!R63G20R2RM;R>)YY(?3 MC9SR=@1MT%!]%,@I*:VSF5'M8XQZ,"\GFI56;8CC\AA0A3=WKW,<;2^EZ%"9 M%&YKTH?#`FDQMVNX[6Y$3R&0EWCE/4L:4I7MA05:)'8*C&MPP(FDZD5-2`<5 M3:&-(P%2BC>I[D^).2`8L>OQ]>O8X%4ND$@:8=5IVR/5D.3RW3?*3:5KU_Y= MGUS6[>SLH1?^3K>RU*>TB&EDF)[.-(2G'ZFQ2,4/]V\7?EE\I[<0'O\`QYL0 M.C-SY!T.1(Y(]7\S2E@&E#>8]84@]ZA+Q>F0\0^7R"TLE\GZ/9>DWUO7W20A M&:3S!K$@WV!/.\/C@,SY?()`:C\IZ9-;0PSP75PXF;UGGOKN;G&35=GF;]G' MC*T@;+\L=+L8'C&N>93R-337M2!IT`J+BIH`!OA\0]P^004D\J:;'I;>;=.D MGFN=1@UV47,UQ<27EPT+PPO9'UIG>1N-LRU#'9N=-A@RFZ]S*+U/S$2!8VT: ML]Q8PI("!L02"WMT)R,D11D<$<4EQ6.%:D\%9F/4D@'^.$A0P#RE`UG>^=H/V4\PR2H/#ZQ96EP? MQE)R4^GN5EVG21/H$S)11ZI+L.@!3L&5:'?Z<,D18Y>>8+73_)WF'6]0AEDA\N6-SJ-_'$ M!ZCPVJ-)6(,5!9@A`J1OA@.+99;%B^DZ%YADN;'6?/&IPWUUIWJMY>T*VB58 MK*64GV?W@K0#VZ9 M$;(.Z*GLTN;C1;EH(6ALC,:U;Z MK=>0/-`ALTO=9_-74XDO;!Y5M_3TV>242CU6!XO-$92AH:44T-:97&0!LMLA M>W<\KU+\P==\D^<-(\Y2>7M4\O\`FR_T&YT;5M+UV&0Z=>W$RQRB2TU"`21B M:);;BY(Y.#&`C+5DOA`<)%VP^HLW_*'3=-;5?(<.CP:Y8+I.E7\VM?7+RZEM M4NX(K6W73HH;B0)P"7?K"2.(!@D='HQ!GC!LW2GF^SM-AJ5_7EX82>A6$0"K MF0&MD,*T`R80C,DK>*NQ5V*NQ5V!785491L6>>=%N->\L^8= M$LYUM;G5;"XM(9G!*`RQE*-3>AK0D;TZ93(,@^=O+_F/3I//MQ8PE;'4$AY^ M8=$G-+FRNI4YO&ZFE1R^RZ_`X^-"5(.:F<#`[N1SB^HM,N5_T:YK4L/3VZ;4 MIED2TJWFK4M0M]*BM]+ZN([RX0R3W3N`[SK3DZ%:4!#4(^?CE,A1IR,YVQ[J9`&RS/R=^8.G76MW M?Y>F&;7[)X/TA^7<]RI-R5MX2_Z-NI*!I3;'X0[$EDXLS,W,Y.52W#5PF+T7 M2)+Y=/\`.,GF#5+.]\R^2],D2.T45CM%N*W#$O0\R:2'5K"SUZVBDO;G]'PZ7#:O58XK>XG#2RD*.7(+L0".F1)L(&VRSSII[:OI4 M5A)*VF^1]!AA$\-M\$M]?2(&X[#:.(>/?Y;&7),37O8-:Z%H'E[\S_(MOH]C M+Z%OI<>J7%OZCF1KGC-(C.6)I4<"0`!3MCR(963$VRG0++4-`\P>4[:^6$ZS M^9USJL_F9UV2`Y>;$FP?)7_`.<=]/@LO+&J33R4_P`0 M:_YAF%VH`/H6%_+IT81AN.45JI^5*9811KR82-O=@?T>9;.U0QS7BB/3K$'X MDC4%F=C78DDDDG!R8L0\PZG)Y)\O:U>*LEUK-(XW52X\/#Z#O@DJO/< M3,RV=G_>2=2-J5[L<%)+S:&.[N?.'FJPTUA-JP%E9S7C["&-(!,S;[];B@R\ M[0C?X_%,1N2]3M])TS2H(J306TZE$GOIB"Q+==V).YRBR4OKO\G+>Q\N6#7' MF"ZBL5UPNWEO4R.#21+&&)",.JDG<[&@R[&`-RT9-^3M*\[7?E6^\^^6M=UB M6^:W66^\O:C?51[IX0?3!:E&$B`$4V)&V3NK"F-T0\/BL8-1\K^9_-FK>I=: MK-J$<$+M4!6F#2O+7O4T%,BV7N`NT#R+<76BW/F[6KEM%\MVCB**\I6:XF/V M4@4T_P"".V-;*9;T'T59M^BY;#1XIIKO2Y+-9+34KEP\C.OQ/S;O6M13(VT\ M]V':_8W=UYFM;^XG^J:/I;^HEU,5'-^%0L2BE<68.R1'A45&"D'8O)ORVT3RK+Y#\D2ZEY7TK4+B3R]IC\C86X:28VREV MDA6T3AG2-8>4>QH%'P%<'B2[V5!TWD7RP+$20:7<"9(@ M;B=+V\B%0>1`"3"NU.A;5X0W'TQ%K>JH`?D+L8^++R^010 M3JV_+C0OWCM=>88@30*GF/6U[4J:7PWPC(?+Y!"8IY#T-=TOO,1^?F37#W][ MXX>,^7R"I58>4])CO]0C6^UPL"K+76]4:H%>O*Z-?IR(F?+Y!)"#\T^7M/TV MSLO,2:WJ%C?>6KE;G3I+J:[U*.26='M/JYM3<1M*9Q/P5%<$N4I4[&<97MWH M9!H5UK'HV%YK]LFGZC8!*UP!2C_WDD`E*E4YE5KX# M:OM4X4//?,FCZQ8ZJ?-OEJ*.6^BM?2U;2F"E;^*+D4"_#R6>,._ID,`U>#[% M62<2#L4LG2[@US1;6XMKP3V=]`ES'JKKP+V\A!"E3NI`/0].AR)%;%0G:3_5 MI0@43*69+P)^6%#S>PEO'\V>>M)B(A]:+3=220FAIX/[_`%:^20PBGPVL(45XUZ,>YQ1T>9^; M=?\`+M_I/F_RO<^8[2VUB\TZ6TM[**3U;\S7<4B1&&SA$D[OL77A&Q^$D`TR M>,&[K92QY](U:QT+RCYETI-:DUJ.*Q?6?+FH:O>7?/U8R)(T75)Y5BDADE#[ M<">/%O8RD"2#^/DL6>6GFF]LQ'IEUY&U^*YL+1IHK*W2WG@,(_W8MSZZ12N2 MS?NT8RUJ>%.)+PCO"+275?S%$MU;VUYY8U/2/+.I6XMM*\PWEOAZ?I-N*VTDMJ M8[JZGK/!)-&R,?5@A1>*$$1M*&^&5:L)&$;'.TRW+V33[1YYKJYE0LD("1,P M[,:M2OA3*@%)3Z)Q<007"T>&:-9;66FS*1LP^@Y)BP_45UWS)YJT?RCHNOW& M@PQ65QJ.OZGI\5O+=0@R)#9PCZU%-$HG/KO7@6_4?- M6K^7K.TC@\I>5?*T<5Q9T+@&*"*TM(JN3RHA5`/=B>^"9]1;!'TAX]#::YYG MT_RY#8Q3W$=SJ4M_J^I/5(TD=Q;QQJYI7TXH*@+TY4RIM)`MG?GK2M/\UZEI M'E2\M8KO2K$23ZPD@5DK*0JIN"*GA^&'BKDUQY$O-_R>U0-/HT-Y,DVJ6VH7 M.B:L5:I6_71[&6Y4@'H)+*0`G8TKOL;KYKWS7;>>Y%$>F:?J&H>5M."UY!=-N#%>-,*;-+<*X4=/3C1^KL!KM5*] MG(Q"[?1'E:Z6YL)8PXD:VY+ZG^KN"/HIE,"PES9JU_,B6S6%C^D+^5E4@LJ^ MG$6'J,2QV`ZT[Y;?,_P#.0VDWNH>7(-22T8P:))&TMPI&WUAO3((ZD`\? MOR.0$MN$[OC"6]EFL;/3V4&.SEFEB;]K]^(P1\@4J/F6K,0*9]>TI_K-ZQ+"!+832M/1`3R9RA!]SD2:":N15#K=W MM;B:.&?4?J-E?V4GQ/'_`*++#-=21@"I9G#"IH*`Y&T5NQS2[B+1?,7G[SI& M9;JR\L:>+2PO;HM++-3)2@7X6)`Z?#A'>R.X`9AIMG<:?Y?T/4M9C MD&IZ#!<:A:AO@>`3123R0J22>*(Q^@5P`&Z82.Y9=^2>D0Q?E=Y$%ROI.-)A MO+GM6;48UO9@?$\IR#[Y?(7(M99=JUKJ^I:R;W28V5+;]VMPQ"+455AN=P:^ M&1-DV$BDF\\6*0>6)(I!62_;E>1%N0214(^$4&V0R#TICS?FOJMJ+769525! M;23LCK4[J&H01\LH/*%UC`V&[+N?#(GDE,=0,6EVT;1J&F MF=0\G=N)Y$GV]L`W6WBEI];_`$KYJ\Z:9=I))::W,M_I8V?THHXX2>5>XCVV M[9DRY")[F,>KZZ_YQ\\@>5?S`O\`4?,6I1-?Q6$P>2TN':;'1M&\N+#HV@6TD5OK5S"8[2W98R&930?"!\(X]>V MV3D"30Y-0V%E\#_\Y8#5+[R=<_F=;><=8MM5ATV?3-'T'3I[G28M/GM[@V5O M'>R6_P"7?F;\G_*^J:3Y@A;2+C4;:V%O:PS/<2:C,`(85M40S'DDH=2$H4^. MO'?(\$OIIC#8DO-_)/YR3ZKYN\TZ5JVOG_#MKHWE6Q\FH%YVC7-[+>376H-. MD;%$>*\LHN;,$^*,=7%3+&>`;;V?Q]ZFN)[EK_YA>4+RVT[RW9^8+/7-8M;7\\]+\J7-_/;>3O+GY1VKMIID_T8WL,]E)/=&/H M'2&9$KX$C,B<08$]3)@&2?D%^:UII7Y0:5YA\^>:;.SNM1DGO)W M]+6M06.",4D<1PP6Y8`#C'&I)XJ,&:!,ZB.@^Y`?0C:]H$M_3]-V$@O[F)+4 MFZB_>-<0F>W5?BJQEC!=%&[+N*C*#$]S)Y_YT_.CRWI_D*3SAYAZ?#!'>K$LC:Y?V]G;F1@':-2D_JBJ[JI/3?)QQ$RH^?V(NF86GYG>1X_,$ MOE)?,=@WF&U4,VBF4+(7>V-ZL*2/QB>7T!ZI0/54*LP"L"1X9[+2)%U>VTW5=1^E.,R!BH M:3HON`,51%JTL=I!!=2`^K([[]26.P^C"I4[B189(XG!,DQ(6,;GX17^&)5Y MAJ?Z&\HZ_:ZB3)INC^:[:Y2^LH(99(Y]4,L'HLD$".WK31M(6*K\?"IW7)@& M4?TLI6M03&\,B/$0KQO'*%=36E0P!Z9$@CFJ?JPJ M0G2-BI`\5)!!P(=2A=]]]E&*L+TN)X_/'FR6Z4K->:9I7U&8D&-K2W:[!0"M M0Z32N6VZ.FYZ+,_2/BK-X9"56:,U0DJKCH2IH:?(Y$*H:AJNF:%8S:SJ4K") MYXX(S''),[S32+$B)'$KN[,Q"A5!.$"U8;Y;M[JTMKK7M2L5M/,/FZ6&[.DJ M!QL&:UAA^K^H"W)U6)1(XV8C8!0,,R.04!F7U*&`6-S/'];FX\Y*]`R'?B.@ MZ=<@FTTFH M2>:E7#%6!QRW=E(>J17%Q#HFCZR8A':?7!^DK:GQ&SG5HU>GBI8-\AA`VM%; MTBWC@TK3Y-)C*ZYY<_,.+],^<;/4$;1IY49O*$EHDL]S; MKR]:0R5+2!HV(6%>#$])`:#+,?#U'Q61Z!@OY277E_RYY@AU?6]>MM&L;S3[ M>T\L^6[EHIKB:XN9D@:=&B$6KKRG&7 MN=VF@MN&I2 MLY833^K(WJ*"3Q'`JM/:N5.0$=8^8M0T^TU?38I>>FZXL8U"T:I5FBD$B.-] MF5AU^C`M;O9_(OE'7;'1;KSSH\B:S>VNFS6UQY5M6;UKW3+P%GM]A4S1-SE@ M7^8NM1ZO(6X]P0T9#NF%PW^*#^6^AZ%J"76CQMJFDVUW:4:&[L[>!&,HI]HR M1-0'I7($'DR!JR@=3N9_+/GY_+D]T%C;45GUS4Y`%:6W5%G2&(G[`6(!`!^U MD3&CND;QM._.)\U2^3?)'ER%TBD\VS7=_IZA++JL/E.[M-!T>S/-GO+JV?38YKR4D@$F16XC6MLEO!C*@1:?ZJJ!]&2Y"^K7S*3+KOU8 M6-G).TL(N(9[FX'6GVV2G@"W:7LDGJR1MS*.0W&E32A.0DR#X+\ MQ:1.=>OX44M(9G!0C90=PQ/;KE-N4.3RW\S_`,TX?R@E\MW-[HTFNVNO&[AO M[N&01RPO;^BR!%8%6#>H:@D=.N8V;-X=;;%VG9W9OYP2`E1C7QNUGEK\W?*/ MYG0"P\O7-R-6M8S=7>E7<#1RQQ+-&9V:]9V9FTHN8% M75@_@_8RW\IO*ZG2QJ`'UNY\S3333P2@%?BNIF2FW3B^96>7JKN=;'D_0_\` M+_1]'\JWNAPQVPTJRCTF]_20K'R7H.@\,;[FS@&SP;_G);R7!^?& M@:K?^1_)^DVNJZ\^DVFIWC-:6M]*\&H6OK&6[HDJAH/A4\N@[9=CS5,$\D<- M"F`Z/^1_FSRYY6_/'\NM0EL?,VJ6/D_5O+_E_P`]:E>W$MW!8W2?5$#02Q.% ME@DEBY/"RK(J>HPY@)DCD!D):;-H$WG/SGY1\YZ?Y/%I?:`VDVD7 MY?7,UJ_JQ:=IFJVK7,9$QMN:R:I\"M*OP15-&(&1XP`8WSZ_+]2\)&Z#\G_E M?^:MAYD\W>78M*T23\O-5MO+NG7^AV%PB31+HUA80PBVN+B42)9Q&T>&7D&E M=>+HK&I$CEB0-]]V)%(3R?Y,U'R1^;MKY6U^XL9_JWD,6UA`K0J?B/:.20E"QW_H91)M[SJ/F#SAH*_F:VF?EWJWGKR]>VAE MT_4=/O=+MHM.*6$4,B72:C>6K\%>`S!K=93\;C@#]N.,"5;TQGL\XO?RC\]6 M^K^7_,&D7&F3ZMJ>BZQY:_,J:\EGC2*TUZ6QE::PXQLTC6?U+T((Y.-492[" MAJ1ECN#W@CX)(9#Y5_*KS;Y!U;R]J=OY:;6]*\B^;//6I:5I]GIED$A[P/L84PK0/R.\ZZ'=^3M/L8--O+#R[ MJ?EK7&UF>X*+_[0BGK%C^3GG426E;*+3BOF'S=K&I:G//"YN)/-5C/:V5 MQ;B,LP;3895@D1T7D%!B+#(>(*^`^S]:*8AIWY!>>Y/->EZ]?Z'I\%EY4'DZ MUT'3/KZL);#3]'O=+U2#DBCB`\D$FX%55@M6V,CFC57SO[U?0OY*>4]3\FPZ MK977EN/R_86FF:'HV@2SW*7&HRVFE6TD:07#6\LD#QVOJ>E!(%25U_OEY#FU M668EU[UI['>W*V\1)/[R39-JUJB`=E'^UD*6T9;7L)@F,($C2-5#3 MP)!VP@J0@VE:6Y+&LD\?][$.FXVH/'`J)E6XL[%Y)0&U/4V6WL8=B8@]%W^9 MWPJLU>0:;91+Z@$&GP4O[HJ6`6)"\KD`$F@!VPU>P4,%\C+7&\P7-IZM_ MKNIRZC/<6MK+-9F8R7$T=O,Z/RF*(>$Q0JBK\*LQYV MRC$1J]U#-;O7OS$U[1UE\F^6;?3]/EBN+.Q&K^O9:C!.\C1F]D@DBX>E$QY\ M-V=!S5CR52@1%`H5]+_+&WTFST33H-6U5-!T&^%U;Z+/-'.EU?2%I9+B266) M[DDRRO*?WH!=NE``!+(3>W-:>BS6444UHIDHUC'2+COP)^$_.@RM-JB/#ZB6 MRJ\GP,8Y'8\>*FI44[FN*KXT=BH'P1H/MGH`-P!BJKR]:YM+/DIGNU/H5)KQ M%-S^./-6`_FAH":39G6='NYK+S;?%-.L[2WB2?\`3$GQ-!9S0L4)*'DPE#Q^ MBO)V<1!P;0.AY?<@'=&:5YD\ZW/EFPL]2\CSW/F>PC6VU6VMKJU33IK5*\+B M.:242%6`(53%SJ1R515@U$CFIYJVG^7/-_F6VD77]87RGY2T^,B:RTHB;5&M M3&%-O<7\JNBDU8?Z/&KK1>$Q(Y$QX1YT@HO0KJVT/SEJ^G6,1.G:Q;Q7%H(4 MXI96\*+%!"`=J@?9[=,KXM[9D7%(_P`S[;7M8U#3?2A@T;0M-NH?1N)I";BX MGF`+.4'Q.0%W)Z#OC(LL9`1^N7$U]:V]G:CDC`J9#M0<1\2]Q3*R41%)Z+=W MMK6.:4M!;F,A?$(**#A0\LUR+\I8?,FHRWFGZ!>Z_J,48\PV5O:0W6IW"PRQ M3Q&6"!'N).$D2.!Q)Y!3V&6@SVJZ^Q%!*=$T34-#CN;?\L+;S7Y>T76[^?47 MMEL]#TRRAN;@@RNZ:I82:B!L`H,3\5"HM$55%XS2',C[_P!C&GH&A?\`*Z], MENY=0\R^7M9M_A%GIMW:2-+L=RU]:K9J*C_EU.'\T!T1PO1?+OYAZG=>;(/) MNL^5I;#4IM.DU-=4LKJ*ZT_T(72)JO+]6GY8M)FLTDCM]1MI%N]%O)D]2.&[B!X&1.K1N&:.5006C9U!4FHHG$'8MCP3\I M-2AU/S7J&K_HL:69$F$>EM()##)%O+EQ(/AD6W=NSTY_4TR>]@ECTZ]G0":A'J1"3TY"A[T-1\\5M]F^5M M.L/)GYH2:)9R%+#4=*D_1UL26]&.`*P!+$EB0C&I\3DX[2<>1XHV^:_/6OW' MY9?G/JNH:-$L.CRZU]:@AY,8K?4+B-3<`CHL=WS([<9-M_4`6G?J MIZGI6L^=Y?-7G:W`33K>8WYZ+Y)U3 MS7;V.L>;_-,=IIGE^VL[6$6)*2`O!&X0.]`I>*2.K4)-:4%,D(WN6LR`Y!// MS6LM,C'EW\N](LKC3M&U2:#4/-=[I,$1GTVSL[F.:SF629)(E>:\C1:2JP:- M9MJKEVT-VH>IBUIYG_-/S!YAOO+VA^9+'4/T$9)S=ZYHZW,LB!Z(:Z==6,:O MQ_XK._897Q\73\?:R,*%HCSCY_\`-WDC5;`:UY0T75WD:*:XFL]5EBF(X,"! M:S6951W_`+\TVQ/#>ZQB3R3?2OS(N=2T.-[OR3YFL=-UF7C9:@+2&]0AVW5$ MLIYY6%=JA,1"QS""*+Y?_-76O+&@^8;B`ZNVG-<\/575;6;2W$II4<+V.%OL MD91+#*]A;?CF*W?-7YK_`)>1?F]H-E966N06S:;>&[@U")!<*08VC,94.FQY M`UY=LQ,^#C%'9VW9O:'Y.9E7$"*JZ8+^5'Y.ZK^4=]YG\R:QJMAJ-C/I1CL9 M+?U%E_=OZT@D1U`7^[%*,.(B""#9OW/K7\E[:33_+>@ M:G=7$5O'I>DPBUCD4GU+UH^2`P6&GSS75G.K16ZE+R)O3\QP^?M?O/*,*:B][HTLFK6CI15@NU]%TJ2`Q)3F,M MD-S3&!'#N\(\C>7Y=4OH+VQUJTL=1L+A72SF!+LH.Y4=#X4RLMLC3TY-#DTN M[T.[N[WC=:I+,);)!QK&]?@Y&O3N,#"[1GE;\M_RT\NR^8M=T_0H8-3D"VMS M<3R2SR1I:?W%O$9G?TXDJ>,:45:[#)&9(W8$E0\W^8@/)WY@Z4T"V\MMY\A[UE':V:1I#>W$JP4,:3>H90-B5.P([Y!>2-OW>*"XG$G%'DJ>-#\0I[8$K;"W,NI7#^KZ4 M2N%>4#HW$4Y`;T%H MLJ--'V*@_$,58U81)_RLS5$0\U;1!(KCH5>Z)%,L'T_%!+T`QEJQKW(`'7<[ M9!"I:0FV:YB@)3ZI&Y=5VVH#^O?$*47;V_U>"[U(@`"(N-A5B!M^O#75'D@K M.*2\CM=0F(1GD*P5/^[*$&GRP).R^Y$,$4MS4952:Y\EJA$D$AD0?I"&<@\3'+1D(!I]I&!ROELGFK>?C#:>0[FRMI?1U' MS=#%:"<.0[3:E(EE&D;A7X$"2H-"%^T10'+<8W'S8E%ZA)#']3TS2H_WJ>B8 MRHHBVZ[4'7:FV5ED`S:\8(([:(_NU4$D>X%1]^28!+491*IY$T-=S6@]ONP) M7R^O+<@6T'/U>7)CVH=OOQ58BSI(K/$O".IJ&KN#T^_`JK>SR+%%&&#S35:6 M)-Q'7L3B2H0&N:K:>7(M#U:6.6[NN4PTW2X(Y)+F]NQ!+-%;0I&KL2RQ,3\- M%4%C0`Y9&-D(OFL\L^6;EYYM>U^VCU'SIK4DSWUZ?WBV,$TC-%8P2,H")!&P MC^!5]1@9&7DQR4C9HX(H3<,K<0J@=/\`.DOJV')-"/-Y;H/F M_P#+;0->O;&+S(WF232KE!J'U1'OKBYG3XE8QVJR,%2G%00%'4UKB($'R3(D MI7YE\V^:?,&LPZ_IOE"Z&G_5)8(EUJ>/3XOWCU9U$8N9P2!WB'A@D!U/R6.P MI/=-T/SSJMI]:N_,-CHEJT9CMH=.LO4NHJ[;75V\L3T][48!P]WX_'F@G=.# MY&\ORF*TUNYU#S7):@/+-JMY+)"S=N5K&8[4=.T0R7B'ILQI'^7;*RMWOY-, ML;;3=/#^A%:6L211@QD@L%0*/PR%D[LCLR]2"5'4*/OQ8L7\W_F#Y/\`(-M% M<>:M7CTWZW%-)86[`F2X,!C#+'^S7E*BCD0*L!7?&&.4SL@[/%_,.H^?OS12 MT3RQI+Z!%"\D_ESS#$8PD-U'#(\5U)J4UO*0G,+&8[2%N1/^]/'DHR(<.+P!?45A&S+1@RR(0:%&5N M^;+',2%AK(>FP';+@A,%Z9)BNP*[%78I=A5V*J4@J,"I3=1U!R)2PW4(:,QI ME4@SB^/IO*VK:=YPU?5O+2SZ?I5QYA:QT5D#21H8K>!KS@-PL?UEID"]*JU- MJ#-;J14FZ!%$%]AW0T>WT2&_U?ZJ]KI\/-9I^)C4D4ZOL"3MC0K=J%OBO6OS M#\U^>M:F\OQ:PFBZ)J$LD`LK=2L8MUJU&5!R:L5L+CE(L,<`4LXC*L?MGF6)[[XR(Z(QD]7IWY=_HCS:J>== M047/F'1=/%MXG9_7NH5$,,7Q1R!2Z9/)VG>:=!\I7=AJ MGK?5_P!-Q:'IMK-=+ZL4E+9YTMHV:LC1.$+T6B;TIDA&Z[FNR\&O)?/?G#5O M,UA?1-I-QJFI2:AYIM3Q)T^R@<16D%U)&[HWU:-1\*,5:3FZUY9')*S70-L` M(BWKWY/^6[7REYJUBVD\SV^I7$U@"+6*-U,BLPE61F?N%[#QP8]BQR2LZ+M975Z4F"DG_1K?G(^_;D%(R(%EF#PP>VW7F@6B MQ0:->-I$'-/]'MQ;`%F55*[;A!\L92LM7#WL,_-[R%<>=?RXU)])J;1!3*M><:>FK$DM54!)^C&CS90E1V?$GDO\`*Q-7@U6SNO*\%W+9R`SS MO`CR)\%*H]"RU-3MD93D.1+=*NKS/S9IUY9P>8]*M(]5AM+6UDM(%^M7`B2X MG0P1*(W=E(9W`I3+,4K()KY(D-GW+^6?Y"75]Y226@9A2NW/(PD)&Z'V_K:IS(.STVR_(OSQ%KUSYHE_,+1[N\EN37A=^7X' MBCN+#79[AY8Z@("MQIEJ`10_M'*S&/>?E^UL$WK7YF^\2NIB9B0"HK&.M>NV6RB*YAA`[OCB.R\U6S"6?R= MYDT^2(\@ZZ?-<$$;U#68GZ?/*N#S#D>('O47GGRIJ$.@ZAY@FN]%U33H076_ MT^^ME$G'B27GMT6A.YH<'A2:N(!*-=_-#R59V8^H^:]%N-8O)N=RD5U%P/Q5 M+D,P*G^.1\*7<64:+"_S+\V:#>Z%JDD'F"QO9;_0+JUBMXKJ)F>2XB9/CX,: MA:[#)XH2XAMU4U1>^:%J=B;&>:VU&SEDE+/:1),FY`(WH>YRKA(8E-+$6L_& M"XNA=WK_`!LO*H##>@`\*X*5JPD97GGG=;>*&1T,0V`-=S[XJ6!^8OS!T#0[ MM%BNUYS2<2B_%\5">WR[X&8@2A=+_,WR]/,ZS2E+V1J.[]"#N`#VQM3`O1]/ MEAN[A[U74QL"8Z'"&!3J"7ZW(\2KQ51\3GO7WP\T%*8AZ%K=<`?4CD;<=33I M@24PL52]M*-\4DJ$;>+'^F$;H+#-&Y'SY=!UHT'EY(A\EO9A7\,F/H^*#S>I MBW$202258RM]@=:>.!%HM_J]E.TDWQ/+"R&G\I)H#\L>2$J>[:2V>!!1)!Q8 M]RI\,#*DHN[T65K$]1'%8@I`O\K':H'O@2`PB>2]U*9?7#?5X)6-Z.G!.-5: MGMYX=:8Z=`]GIS%`+!I(W67G&><$?(`1J?4D3CO?+%Q>KH?Q_:HE6 MST>WLKKSYY@0:O;ZUI^B^5AIT^E:'%XHY.:2O$0Z`; M@EHGT@52&9ZSYE\J>7=8_0UU=.NIQI`L\<-I=7'IF;F41FMX9`"W&B@FI^61 M&,E;5[GSEI/U9C::3KU[<0RD31IH]_%6,@<6#W$$2`$[;MAX/Q:$KA\VZQ/= MN\/Y;^8D@)`C>1](C2E.ZR:DK_\`"X\`[Q]OZDIB=>\QVRE'\BZ[+Z:U:07. MCJE9.A8_I'G0=Z*3[8\/G]Z+2C])>>+B_FL8O+.D\K50TQ_34Q/Q#X!\.G,` M3]."H]Y^7[4HZ9OS+BTHPV'E#R[!J%Z2MK=3Z[E:/YVM-=9K^RTB[\P6MNRC6[K6;K5Y8HI'3U1;VXT[38H5=@M5B"\ MCQ%309.G(E3A.PY"U,K>F^*^6M.N?-&FZ386SQ:+IWE!Z1 MK$E!+-*YE>5C4#D:`=.E!F.2WR/#\7K]MZ6IW,=I<)ZRPQ&0(!0Q"J-X5XPQKM7L`/IR18@;I#>((--,;?O+R^6C+U9G(`H*'(LAS M3NWA^K6L<`4`1(%%-JFF^PR3%$0FN]-A@*HPPV\DD4LL$&V)CB3X8T M6.W1545H!NS-5CN,4!$4&!>HVXV&7!"8+MDF*_%+L4.Q2[%78H:.*4!.E0XOH=*U)VMKB":XF:YEBBE M6*6.5&F=V42!"O(@R$4XX>3#9L%L%/!=3UOSSYRU2V\HZ[!>>48=1U"$W%GJ M,36MNUPX%4@N"3;W3`U(6"5ZGY9ARQ3CS;@8C=FGD+R1>:1YC\TQWVE&RATB M)+JQU:\C*$)'S1Y(I6'1P:T!_4,KX2LY6`]+N;^P$>I^7?+T/KS^59>,>G"- M88+G4#PFBFEI\3A"-J]2*[Y(FMF%'F7AFB>4?,NN:CYWTO4XX+2XOK3Z]>17 M4G)X[@RB2&1*5ZFJ$U^R3D0V&0%%])?E=Y=/ERQUB75I+1;FZBMFU%(`$@00 MQMTZJ*D]*Y9C'.VF4M4N+C6/,EC!)^F_*%J+S1P["(/:;&5]0OUCX7%P'C8 M1*`%YNSNU*MLJU.)(K9@-CN\F\DZ=)J6B?4];O#;Z]Y2NYH=+U2V9EE6!619 M(3(/MF-Z\0>VV5C<-DC1VZIYKOF[2?RMU&U*:1:WM]>QSV^JZFD217;%6#QS M`_M!RQ+#8>'3")<+$1,V3^6K73XM!EU"&1I(O,$HU:!QU;]5G%#J: MQRT,8`B1'DH`"/!^GMD8'FSR&Z>(?FAH$%]YL_+VW/!H/,'FK2EOK.-0'G^I M7(U&0E1N08[9B?NPX^9/E^QE?II]Q6D<%H5CAB$-M,`8UI3C44Z98!32J6T; MLS6SREE5^8Y=AW'],0.BL;AU*%=5U&TN8.4W+T4J1R>-23QJ=OB\,C=)0(TO M4-3U6W>X@,-O/*TLJEEY+&A#4H.@J:8B-E5/SQ)&UQ`CL3<(#Q3L$)J"?GC/ MFL4G\L6B7%Y-+.@:"W@;DI&Q+;`'\&VFO'8-HE]OZ,"2.1R`J0M!U.3@+!_ M'5-IS<^9/ROO+LRZBNDHUQ&(^6I67U<`#J3]9B2F#ADJ!EN_^<;F+?I"Z_+/ MF/AX7CZ.":==I#7)CC\T(1-/_P"<8+@W%S';_E5,B`>GZ46B.[$=:!0VVAZH&!A="X>2."4D%66@/ MOE9D3S88P3_RW^M[;^LDE?IR6QZ!%E3@_+!XF@CL_/_F> MR5JE>'Z)DI0$_P"[M-D_'`*[A]JV7G&I>7O,7DC\R=$CTJ?6?S(;S9Y?U!3! M>2:1:2VQTNZMG)1HH+!"&^NFH/(^&U`=Z+8K>R_F=J$D[)^7$X@:E>6JZ?5J'<&DAV/MD3C!ZLA*D; M!<_F,T!+?ELSS2E44_I>Q"HJ;$4#$UQX!WK:275K^9EXVIE_R^4VUFT;1*=7 MM`%:A^UL:]*[8/#'>GBI4T[3OS'@@2>X\AP7#7#E;@_IBW'($[4'IGH#CX8[ MU,D3Y3UJ;49M9T74[!M+UOR;>?HS4+%I5G"!X8KN%DE0`,K0W"$&@\#N,C*' M#2;M@FE'5OS!FMM3TZVD\N>7=$\RW%[I_F`7<2@[O1X?(VEWD@>_UGS+*X78V^NZI9`G_4LKFW3_`(7( MB9'=\D%$)H%AHOZ3&C6TL-W=NK7%U//->7+O%LA>>ZDD=^.]`6\]E#7DQZ`(.(4 M?+)QY(D4'JNHR:98VLY8`VLC@D_R@A@:'`304"V!'S2?+6J7M_SQO--(P/[V=DB:,1"B!8V^-JLQIQ3+0`-_O8VS+R=JGE MJPO;KR)I6GC27T.!8-(AZE888E"@,Q9B0*&I))ZGO@$K)[TF-"WS[JOF7S)^ M9,VF>79[CZK/IT,OZ0D)?T7D4TYNH!`(`[]\J,B6X`0W9%H/EB#R_!<6UMJ< MEX))$-SSH$YD\2R@"NX%.N0)096SZ6*'2K^:6,<[B6,P")16BD@F@'A3#R8< MPBFA19#/<-N0!&C'84W.V%"5V9?4Y8=0?]U;6KR+;QCJ[`\>1KVVVP#=)V3A MOB+4!)J:#"A%Q)\/O3;$H)59?5]*7ZNJ/<<&^KI(2J&2GPAB`Q`)ZD`Y!7G_ M`.7$/GNPU[2?+E[J6F36^EVD]YYRL-.MV^I0RWKR31M'V-:T%,@8VD%Y_P"8O+]KK.FWNE7\9:UO8S'(5V=# M6J21M^RZ,`RL-PP!&XRDAG3S+S/YL\P6WEV;2_.?EF]U2\M+0Q6>O>7EENQ= ME(PC23111))`S&KF,HR#HLCG;,3)A)Y)B:*6>0-1UO0_-NJG6;)KRTU*UBU' M4_-\(!6*!8&:%RQ!2C5X["M5899]%M=+FTB] MB>1%-6AD'[P#6;)="\L:)<%_,^M2+1KFX M8^G#"DLE71>/:#I]GY/_._6/)U^BS^7&UZ\\Q6ME+62%[;5H&N M$N`AJ"(I$DA![>EX4RW*;(/2D0^D][.],\R>8-(TO4+9VGT_R[=3RVGE7SC, MM?2MWD]:*-Z_S1K\#>)WRFZY,C$$^;.O*VM>1[70)8M.OC<+->3W%W=W!I=2 M3%GE%*=P3L,((IC(2M\W?F0=;O=0TW4]=M9(M:UFW,TD+?\`+."!;MQZ(Q4? M$H^??([WNW0KH^H_*]_Z_D3RT)(4CN&5X;JU;;B\=$&PZ#X01DK]+1(;E1UK M6KBQL[70D*7EZ"L%TL55*12"JNS;]ZY&1H4H'5&:A:VVFP6.FVWJ323*L3MS M+M(S5)J!V%.N)%;(&[S%M'AU3\X_RP$:^I>:-!K>L.U:T2&V%BIITIROLLQC M8I)V?1U[<113^I.65^/!81L#0]1]^,N;!$I?2F:,Q6IC#E5ED:GV14D_,FF$ M2W5AWF>*WBG2Z?E]>NY'D9@?A5%)5*>!H`7$1EF67T("O M638$?KWR<94+4AYQK%W-J&IW4TJ_O#(4$:]@OP@#Y4RLFRR"+T>6[A]:)4:. MUF8"YGI0IQZD'QH<0@LRCA`N8U*4F6`2\VWZ;4'WXL7DGF<++^97Y4BI$=M# MK]]\77]U:QVW,^'^]1&3!])^"7HZD37$)B4^BA#I,?$]AD$)ER$4P$YYGC1J M[[MX#"KP/\]M=T_0_+-[+=6UI#"D4DMQ2]?T+6+?RQK=EJ#WNK:1,EO:#A5(;:^$K\>*_99T!^8P2E<1\7 M#UN:$H5$]1^E\@'VZY%UC]/="_-C\BX;B'5;7S#IEIK)L(K"XU%[:6"=X8^) M".[1"H!4=3D'>PU&#F"+>^,>Z]01AX>7?SBT'45=)Y1;3M$3$'(`!_:WZ98,G M>U'$0C]?U*R?SY^3>KVMPLD$MUJVDSN"#_O=ILETGWR62C+X2!B6NGLDI)JH M-%/ACS0H-QBBV'R4=\3LJ`N/6#B.WC/.3=&&P%>I)R*HR;A''=6W(&6YB5W( M&Q(HI&'DJ1WGUT:;>PZ=)#'J/HR)IDEPC20)<<"(FD1&1F4-0L`P)&P(P*^= M[CR)YJ\E^1?-M[KFN^7/K&K6]S>>:?-VH"ZE:2[N4$1G>**.,<44(B1KT554 M99M(@IM-?R\.JWGE'RZGF'23Y?.DQ3VEKI\7J*[V\+M%;32)-#`\;2I&CE60 M$N]!D0@I6[;EFK5C\1]SD4LNL9K*7RNT% MJJ0_499K>Z@5N597/JES7<%@_*GOX9;_``H/-AZH6:?BIBCB:B\B/B%*EMOG M3*J2FFEPO)<1QLM5O$`#':H.ZL,D!N@HVYU2UT&SN!+ZG)YK\^ZKJF@>6[W2],BT*:V/F;5=1BENP)9D]7ZK#;13VQ;@I7F_J M_:+)Q!0G)"(&Y973V7R[Y2MO*T5QK<=ZVJ>87$<.L:]>TDN[SBH4"O2-`3\$ M<85%[#KDB3S[FM*/.FH>7KR[$'FOSC1I'H M@5:L3L!4X*XS3,&A;YIE\T:E'YCUB]\A)!H]OII)MK_7X)[F[NV<^D(8+**: M"0*%;D6DE4CC3@:U`J,>9OW?K;*)#+]/T+6I88+&+S5-I$MZHN+R33+&TMR' MDJQY+>)>M4=-VR'$.[\?8@JJPZIY$FB_2GFRY\PZ!JUU+;K)?VD(N+*X2$3V M_&2RAC]02&.4,&0[F,+QXMSE0F-A187NRZ7SG9R:G*UC6I:2=; M:YG=(P`>3LH"]6HM2'AOD4C9Z/%Z7!3`4,`0%.%"K`]""-C7(H58!MOU8FHK M[XJUJ>IV&B6$^HZA-Z-K;`58*7=W398L` MB/-@2]8\L>5-%\M6C6.A:;%IMM+*9YUB!Y22LH4O([$L[<5`JQ)H`.@&9<8T MP)MGEO"`!MDP%3-!09)"ITVPJW@5V%78JX8J[%78%:(PJHNE02!AW4]"/`Y3*+)YQY8[W]/^6I M[:UL+'66@@MVL;A2+:*.[$94O'<3`#[*"I)IL*]LP@'+Y#=Z)9Z_IOD^:>!V5?,=JL MUO?6=E&PAFN7"<&X[5(-0WOTR+"N+W/7O-^GGS;HUIY/FOH](O%F&L3W,H(" MVUJ#&YXC9ET74KSS7Y>T:XU'R?Y>\J7"^:==D^! M[@Z?`\[\6?["]":$GPR)'()!`)(>(:OK>G_`)>^==8T_P`L MQJ;73[CD(9F,B32Q_:B(-:!>10$;Y`BBV`<0W>T_F!I5IYLTS0M>LT*#6=)# MV+,-X_5$4JCYTH,EDZ%K@:V8GY>NKBT\L:S:QPO#J&G:IP1YB&:0-N5!/4*" M*^V0Z,I#=DDEWIUE!>ZMJ5Q#96L$7JZQJ4CJ$ABC2I9Y&H%55!-308C=@\[\ MT_\`.0%OY7O?*NB^7ORD\X:['YGCNKO2-9-OIT4UU'8PK)ZA;:G*84 MD#.BVW*GV5;,@8]MB/Q]C'WIS^6GF;RY^8?YC2^>?)VNIYFT-?)5K;6=[%') M`R3WVJ7*W-O+#,J20RQMIX5XY%5T(HP!%,,H&`H\[0]VU>*6^9+5YA&L?Q!R M.3+X_+ME1*A!O>7=G#:E[CZR+1WBE1:5,9`HYI784[XW2616M@MU'>7E]P93 M*&MN0Y*D4:BAW[D5.2$;%E"7ZC>QO8V5Q;1%;**\)7]GD!5.0IXUVQ)V2\E\ MW?F;^7WY:27$6H75Y>WNE6T^H>9+BQL+N]CTVT2/UF>^NH8G@M`L7Q_OY$JO MQ=-\1C)I>:6^2OS>\D>=?,]YY8T:^O-.U^W@^M:GY5US3[S2-0^K,Y5;J*WO MX8&GB)H/5AYIN!RJ1C*!COT5[C-]8)Y*@#\"@D)H`O7(H>,WEH^I_GEHELX` MMM'\EZG<.3]DR7=_8H*#Y0G)5K].ORS_/[0?S+ MU]O+UCH5_I=\+22[+SM%)#QB*@CDK!J_&*?#DJ=E@UDA^#VBSH90Z]5X M2*VD^8=)GC`8[&2Y2U8T.WV)R,MQ_+_YBZ+YA>&.VN$$A6K(YH?NRP9+:90(9Y+/((TD044?M#PR MQ@A((Y97DDF+%6&Q.WT8JJ3%APB514$4/?KU.*OGO_G(G4[&\A\D_E]JWF:# MRYH7GB]N8?,'&Z:"[N+:WA+FW`26,^A+5DEWT[1]=O9+J475VS:9?147BO[1_P!R98#?NN/".\?;^I5MYYE\X0ZSH]LWE^TM M+C4X[B+3UU#5?0C$L"JYA+6UM=_O'CYNH`(XHY)%!5$1SM4L\PZ1Y^_,::?R MI,K1A)%I_*M:4-*[Y(&-V+V4;!-]/\M>8-#N MH]!\N^8M+T6VOV,C0:3H,5LL8ZA562YG554$\0%H*GN3@XQ?*_BCF&3ZI#!H M%CJQUO\`,/S%/]7MD]&>*#3H(KR25#QAA>.QY\@>M&J!ODN*(Z*(DOERUMI= M1_,&SUCS%KFH^7ET:%/\.V6L7]U,]Z)4_>7-M]9?T:I5H@J`.AJYV=,!D3'8 M?)LH![3HFA6EG9>93I$(MC;""UM[JG*62X<%C\9Z*NU:>/ME/1)/)F$&D+:I M!=TEWY8M6O_+I M;G>^4(R%>WK4M+IG(A5_RKL91JK)98ESY]Z&5:=YBT.[TN/6X=4MUTJ2 MH^NS-Z(1P>)CD$O%HW5JAD!785=XXJ[`KL*M4KBJDZ@X%2Z>`, M"*9$A+%=1L>0.V0D&0-,`U?2;>\@N+2\MH[JUN4:*XMI5#QR(PHRLIJ""/'* M2$V^%["\UG\N_/-_9PW1DU7R=?B&QNY?B:>SEC62U:1FJ79[>14E;]IP_?,# M+'@DY4/5&GO_`)F\MV'F_P`M-^<&GPRZ3J5NJ7$VD\8FB,EO*%D?9:G>I%=V M`&5D6+8QEPGA++8$L_-NKPZI9W+3ZI/;W,%W;#95A<12[""<:-Y*T=E9>5?A5D`^["#OLO#M9>/6_E MNUD\D7GY@:Z9I]:U'5W2U$Y*H(-V>8(`"[/)R%3MD2-K;.+>@]5U^!=4\S>0 M?R\;7)]$MM(T6U87$0_=SS)&CR1M0BE88FH37?;)D60&L;`E,M1U3R_K.N2V M'E5GU-DF$NI7"GA%;J8_3]4.W$$5`K3(2`)V0`0-T;J_E"'5-#UKR];ZO%:Z MAKMK:RV&JRJ9(5N[2<36WJ1JR%XVD55<*REEJ`P.^3@!$L;?-^C>;/-NJ?\` M.3OY6>6]>\JK<:_Y#\A^>X]0T_2[Z*X(CEO_`"[!'>>K?K8(2_IE*+O0\NY` MR,8]!'F/TK(4;>5^0_,OG+\J/S7_`#7\J:0VCV>K^=O,WF#\P[_31"]X+Z\G M>T%CH%K*K1\1#->S/=7""@:)I.*Q%\LR48@^X?M0`R[4?^O,9I^<=02R1LJKDO#'+S`_6A]#?E!^9>K?FAY. M\PWOF+3[+0[CRWYGGTE;6R+D-;K9V=_$']1F/JJ+L(Y&Q920`#049(B-!7AG M_.0ESYFT'_G'G\U-#U#R75+X MJZF'@KUH_I@-D\0!F#?X"6_S'\W6Y_,OR)YY\]>5;_\`+O\`Y5)Y6\Y^;_+> ME/);W5[YAMK'3%6_L8IK!YX(8X8V65HI'YR,(V1>,;G&$;!`WND*L/YG?GTD M^H>2]3U;1I-0T5/(=YYS\W:1I9:?0X/,[:G?-/_.,?EW5?,>I:1Y7D'E2+2I+-KMY&GO#Z4\.:W5$\=CN>_]F--&&CECG1!D=C[A MT2_\O/.]Q^6_FO3_`#/9VZ3QI6VU*U('[VUE(]15/[+;`J?$;[5&3TN24I42 MXGM'H=-H\(SXL8C+B`VVV(/3ET[GZ,^9O/GE_4_R]\X:OY4\SV=Y>6WES4+Z MT>QND:XA9;=N$A5&YQE'9:U`*M3OF>\QDS1.,F)Z%\*^5?\`G([\Q?*NEW6F MHUEKC7EQ+=2:IJXN;BZYRA5-)!<**#CL..&G4X];D@*Y^]YCH'G76-"\YVOG MK]UJNMV]Y)?2M>!BDTTH;F7$;(=^9.Q&--$,IC/CYEZIY4_/C\PKC5+#1-9U M9=8TC5]9M99X;M`SPLU['/6*448K+R=^67E/4;!S*!>^<+JP,EHY8558Y9(W@5!OR9JFM`.-#6MSL^ M;+Q<,!\:>U_EKA=2MYI\;1'@5!(F.R%U8D515%*;5Q M[#+\9MIR1HO4)(@H(IL:$^^6EK M2X[W2``;+\7WX@)?+?E_T?/'G_\`,SS1JOE..PM;'4(O+NFPZI%%/=22:3ZB M3W*D@F**42)QCKU5GZN:RR>D``I#TM+.RM2GU>SA@5-P(HU3Y=`,H)2G%RYF M6)T!6V`'%>X/4U/TXE`8!%:0VWGF[EMH4MSJ&DK+JGIJ%]>6*;TX9'H*LRIR M4$[TV["DN<4LX>WB6*&XN1ZT?(_N>Y'XTR*HVV&COSN3]8L991Z;3568"/PI M2,_CA%+NP3SUITDFEO?:25N;SRU,FLZ;*Z49Q9BL\2BOPM/;M+!7_+R4.==Z MLWMM0TO3](06=Q#?KK2QWD][":)+`R`QJA[B@'SZ]\!](I'-(]#BG:__`$O/ MR/%J(YJ*[G8#P`.0'-E+E2SS?90:O+Y>@O8V_1VDW1YA;3'BW'Q8V]+NFA@CMI M":-+((V3Q#`DCZ.'&:1R3GRY^5_EC3U-SJ.DV6OZ_=R_6M7\Q7UK%)<3W)4*SIS#> MDH`"JB&BJ`-SN=G&(B*#"WKVFZ9;VR"*WMT@CK7A&H5:_(9;&+$EE$$%`-LL M"$RC2G;)(5P,*MX%=A5V*NP*["KL4.Q2[%78$.PI:(KBJBZUP*E-U!R!VZ9$ MA+$=0LJU(7*Y19`OBS\W/)WFZZ_,DZMIGE&]U/19](TZV?5+,02*)8+B[:02 M1>JLI(65>B&HZ9AYL4I/+/G'0?+VC7FE:EI^KV%F)F,//1-4X,A4 M*=Q:E0*;=^5\$HGDS)!BH_F9J\,>J^6[_RUYRB=O-)NM(\RQ:5+;W<^U^#E#+$SU-`P'$`[!0O6@ MS&;"SG3]'O!>ZY.84@M]/TB>W^NNG)IOK#(W%C4590E!3)`SO,R>B1Z2K)7T>(;HK;X>B":-LJU'RAY9>?3?-MVESJ6KVY1; M?C(56L2E0"BD"@%>OCDR!5L1(\D1?:CY(\E)]9MM,M?T[K4"5T>U4O+,C[%: M*&VKMAN,5`,F51KH]M+;ZK)I[1/]7X4D3]Y'QHRQ<>B@=MZ5R6PW8OB?S-J< M5W^;=S^9^E^7I/KFCO+ISZFB'G^CY'@%S;M(OPTF:W1B-Z$`C*S/Y.0("J+T M#\O/(&D>?_)MGYS\PV$5M;^:-3\RWELBNZ2/IFLZM//]3G,;()8'B2(%'JI" MCX:9;,D'Y-/)ELOY,_EO]<\M3)H,4CZ=J>FZCH:F69OJ]WH\,D%I=!533[B:]MJ M^FR[PSS2NIZKS<`T9@3QFUZ(W5_R=_*W6="\SVVJ^2+.33[ZUU"R>W5YT=]- MU>25KN!&60-%#+)-)((T*HKGFJAP")^++G:&1Q:'Y:\EG](Z%I$-B/,TPOM0 MMH@0DLR00VXF*UX\C%%&E0`2%%:TRN71(W2WS;I6@?F!Y=U+RIYDTBW\P:#K M4,(N-)N8^<3R0S).H(VWC=%=2-U(!!J,$9$&PM(.R\C>28-(JX50Y8*,1D6GF_F)/R8T*ZCNK7 M20-8L_JR)K$%W=_7R;1)HH&-X)O69HH[F6-&9R521T4A'93&67;>'1]`'EBU\NZ:TDJ)&=&?\`2\#%5DH[K=R>H6>I8EN1 M(=ZSEF(B/._U*8$/LOR]I6BZ!9II_E^RBT_3));B\6T@J(Q/>3O<7#JI)"^I M+(SD+0(1AR'B1N*X%0%^D<@$!%1*P#$C9:_P"UC(6$ MOG/S_P#D#'J>IMYE\GW45EK[CT]6M+DR?4[Z(*0H<(3Z MF_9Y'O()(FD:_*&MC6?+<#ZMY3T407UQJ=U8[+RA_P`Y M?:`-;NV\P>;?/%U8Z*9[BXN#HGE?6/+NG'3[R"/XA"MSZRHG$JJ22\]^-#EB M`N)\OF;2]U_*_P`[>4?RN_+?\O=%U.6+3]+L_P`L(?//FG7[F[]6:)%CM%EE MD@;U)Y3-),WQ"M"H0`E@!BSB9R)\Z2RC\J_,][YV_,/\Y=12\U5?+^GW/EW2 MM)T/4XKBT-E.NDI?W5+2Y5&A=S?()/A^+@O44.1R1J(^*6,ZA8R?G-^??FC0 M=7N+L_EG_P`X_P`.GV5OH<%Q);P:KYJU:U%_+0/S53RG/]0_-:YU73]91/,4>DRW]E>W-XWE[1-GVVOZ%+-#JVE7#- M`T;065OJ,QK*JHZI:W44K,I(`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``&V6`(3*-*=*NQ5V*NQ5K%6\5=BKL4.P)=BAV%+L56D`BF*H M:2.N`JE-Q;!J[9$A*0W&G`U/'(&*0:2R333N0M<@8IL(%[!T-153V(VR)%)> M9>:?RQT/7]5@\R)`FF>;;-1';Z_%&K/+$&#?5[R/87$)W!5B&4$F-XV/+(2@ M)"BD2I#^4-:_02&TF(IZAH:PR4E%"P5D M',X5==U+6;XV]GJDS/'-]ME>1@$X+U^$]0.V0JHF^J1N M7G?D3S5^E-6OQ;63V5B@AM[3FA19C)6K@4[\>1]LKB:+.<:#.IEU#RWY2OM8 MN)N=U--ZT5LK!U6.1MRO*O;)48QMAL2PZ,6&B6/E[\P]8\SSWMG<<1;QPVL( M-&+$Q2&A8%/BJ*[$'$"J+/GL`F7YG^:EM8]&N-%CN-2.M02O%):*TR.$2L/) M5KU9AM[''(;Y(A'O>=ZE:ZSHGY7ZUJNOV!34KN&[UHV\O%&@1`C?8:@!]*+H M>E>E<`CN!WI)%[/2_*^A:EI_Y>?EIY5M86;]">5M,CO*;#U8[:-7=F-!4D$Y M;D)D6L,E7U+%-%CE$?K6[23!P:CX6!`J.M:Y7R5.],L"LSW4AK9+7RMIKWLU(%TM7K'7I=P=B>N7L*&HKM@G`%(D0_/S\S/R+T/1K MR\D?R]:FUNXVC2ZBB6-T#C=D9`.#_"/B6AV&^PI6,LX]6^/#+H^=_.'D/S+Y MQ\N7?EC7=1M-3TVX:-9#$S6=U((91+'*9A%-&K54`J(:$5^(8DXSWA&3$ M$\F"?E-^5LWY<:EK.MZ?Y=OIIYXVTQUN[^$O(B3ES+;H(8E]-N"&KL&\!3J9 M0@.4FK3Z88B2'N+:YJL\BVMKY7O%O>7&X:[>*&UB%*AO70R\P:](U8^(&1X( MCF7*XCW+V_QHPF=!HD)J1!;$W,H`I0,TH$==]R!&/"O?'T>?V(]20^:[C75\ ML^9]-U'3_P!(B^TFYBT^^TJWEDY3RQ2((I+8--(N]*,"R[_$5ID\0CQ`@UOU M_6B5T626'F73+R6TLXY9X[RXC/I0SVT\',HM7"F6-`2!O0&N5G&1NR$@G9AY MQF(CX6Z#PRMD]L_);4TT_P`Q16X/'ZPIC6GB*'^&2B=VK*-GKNAZ3^<5AH.E M_EG;^7]'TO2M-T^#2&_-B>5A$BPF>VTQ(%E2]>,I0G0]..D:9ZD4JA M?3,*0W44I)5]:_,/5 MM=O;2^?SYKJ:Z@MFC?F?=V>N3/:2VRSZ?JEI80:9<))'=30!HIX;6!XV1F(? MU0X5>!,C(2B!U"'ENI^4?S!\Q?F'YKU6XL=-:?S%Y"F\N&PNY^$FC6FKWURU MOS,*31SE4MW-P$8U?TU1F0&03$HB(]Z4%9_\X^^:'\[ZIYBOM;T^'3W\Q:K) MIKV[2F[.BWWEI](MW=C%0W4$\O0GBT:@\ZT7'QA5>7Z52S7_`,B?S*O_`,O9 M=%L+C0(/,,?Y8V_Y>VT37MR]FIL'BE6Y0FR4@73(4D4CX55#5S4`C+'BOI=K M2O-_SC;YDTG7-)E\OW\=QI$%]YH&FZ';3I;N^E>8+32+>9)C/:S^F8#II0F% MED,+EDD##TW?&L5^-K4,,UO_`)QW\U:9Y[GUS5]7TNP@\S7?F30D&F/,L,>G MZGH/U?2G$3I\,T$YN(PM:,AC!?D`,EXPX:[J/VH#[*\@Z5K7EWRGY4\L>8+> MQM]5TC3++3A#IUQ)=0LMI;1Q^H'D@MR.7$GCQV%-SF-,@RV2S/D%CWZUZ9%4 MI@D]:_N1Q9T"\.78$BA4?.N1YE/1&F&**U2U7X`04C\:D&F^%#01;I52Y"F0 M1B.[@:A#%-@:8\U8-9VVG^2]=DT]-.ATWRMYAFMGT5[:+C;6FJ$>A);LB`)` MDX6)HJ`*TID!(=T#VGU"^H1R>DA213JQ(H?\_'()8+^CQ^9&LV5G:S:FGD[2 M#>KKNK6-YW040):P3VTL,DR(7D+LA],.O'EZBD+EX,7608DOHG3-/BM MX8+>WB6"WMT6*"%!Q5$0!550-@`!0#,Z,6LEEEO`%`VRT!";1QTR00KTIA5O M%78%=BAV%78I=BKL"'84NQ5V!#L5=BEV*M85:(K\\"J#Q@_/%4,]N#VP4E#- M:@]L%*A)+%2.FV`A4JN-.&]!2F0,4VQ36O+NGZO8W&FZM8Q:A872\9[6=`Z, M.HV/<'<$;@[C(&*07C?F7R_YLTF/3;*.[N?,OD33Y+AYM/X&?5K9)U*\"QJU M["E:?\M`'>=CMBY<'$-F<94B?*/^&X[_`$_S-INM-KFGWMJP:])J%O%;T5C1 M``%6JE=Q4$4.^8=<)W9DV&?1:G)YFTV;RK?6UJGF*_TZ28V18M%:(I*Q!R-R MRLPK3)WQ"F-5OT8C^6R:9K/EOS3Y*\S6T%Y^@=6GB%H!5HHIVY&0'J`)3)N, M8U5%G/8@A(_RNU._T'S7/^7FM6S26E]'.-(O*4:(1*TOP/W5D!(/8X,?.DS` M(L,#\^>9-;\X>0->\JZBWU&\TRZL_+\VI"A-['J-]!8\/9^,M6*]1OMAQFY# MR1*('+J^M]3N!$NF6-NSQBZ5HUBC`^$#[()(.RX9%J8O>P0Q>7-,NG)-VKE( MO8#18WN5LR_`3,E%5>5#2M>M,QLD^$&3L=#I_&R1QW5E^?S?\Y=:B8HXH_(U MLBQ"B?Z>Y_YD#,'\X>YZD>S4?]4/R_:^6]+T'3;V"&>:X-S=&;U&:9JG9'4;4IEI#AX=;+%'A`#[)_(/\`-[7_ M`,QH=?U?4]/L]*;1KBV@M/J9D^,R*[OR]1FZ46E,#LM)J#F!L5CUJ*?>,G"5;,LD.KWYC%)(#QY>D.#^[!`!3Z,N:47&&]6,. M`-JE1M2N%4P%2>M%\9?*2Z=9Q7UPL>I3B":8P+18XHR>8CDZ>KTIEN,#@E M?E^EKD383/Z]YO/3R[I@]SJLH_58G!PP[S\OVI]7SU[3Y[;RYHS M2),A5)-8N$!W[E=-;]6"H=Y^7[42NN3]`+#5/S8FM8&;R?Y24%`0W^)+]C_W M0QF7'AKG^/FXA>07LGFORC^9QF\QZ'IBVGYN7*K!)HMZ\XM+O2=/5"]PMU!; MO)ZT407E&`%XHO`DLY9@&-]R07JBFA7;KWS'9.;CT[]\55;>X-L\DD:"1S&R MHI\2-M_GC:U;!H4E@_,'S0LA0S'ROY>E=!N%+7>M;?ADR/2/>?T*$_M99KC3 MA.M#=%7`KM5@Q`(&5]$GFBKZX2U*1[@2.$3:I',T%<25"I=W$L%SY=N8J$VT MD@9NY^`U!_R2#0X;JD#JD'GD\8:7AOP7;E7;[M\!2%\42QHS(E&/BNRG MX>?=3V8?(C`4A&A8VEY<@TT"^DQ%/G0X4('6=*M-=TC4]%ODY6&JVLUI=4(# M\)5*$J=Z$5J#V.2!HVA@FG2>;_.;:AY3(LGL[&6"R\Q^>K!Y(H)%%1?6UO;M M5DN2%],A976+GR,GJ((FR<6$$\71!+Z1TC2[:RMK:RL[=+:TM(DAM;>)0J1Q MQ@*B*HV``%`,S0+8%F5K;A0-LN`8IS%&!VZ9,!"*`IA0W@2["KL5=BKL"NQ0 M[%78I=A5V*NQ5V!785=BKL5=BK6QZXJM*XJT8P>N!5-HL50LD`-=L%*E<]F& M!VR)"4BN+&E2!ME9BRMY/Y@_+U'U0^9?+%PF@^87N(;G4U*%['53!QX)?0*5 MJW%`HF2DB@`591PRG)B$N:06.?E_?75]3ACNITL9I`ZWD4SJ M5>RGXK]816!)-%9=N:(6`S#\$QE?1L,APJVGFRTG\Z?/=M8Q\+:ZT-YKUE8D M+.YAG=CR[LS'8>.0Y2+([P"GYN(T>V\E>;1%"\CL>RJJDGVQHEK8C M;^>O(&MZ9%::;YQT2[D/%E3Z["LFY)-(V8.*U\,)A(#DK/-$,=P+N%&+P3QQ MF&8?9;C457VVQCW*@=/\P6'UC4[*:_M;>7390DL+S(&K4@[$U[8`"J5BRTK4 M?TC%+J$:/Z[M93)*A)5@.(.^P&#AM-ORQ_YS4L!HWESSGP=6,D=JC,IK4R74 M*'\#F!J16.0_'-WO8?JU6/X_<7Y%YJ'T1*[L`3&G<`G-II#Z'RGVMQQCKB1U MB"??^`]#T_\`+CSC=:-IVL1Z(5TO4T+V%[--!"DH!->)ED6M,Q<\)F9+UW8. M;2QT6.$B"0-]KYDGN\WV[_SC3Y8O_+WDW67U.V6VNM0U9W@X21RJT44,:JP: M)F4_&7'7MF3I8D1-NM[;GBEF`Q@`5O0K>SY#R?46B:E)IFH6]Y`Q2>(JP/A3 M?,ETQ%OOGR7YCMM>TBTNZCU53E2H=HQR:@V(JU>_M@(5^9?_.?/ECS/I_D#]*^3;;4 M9KK6-3@L[Z+2XY9)C!)%,90ZP@G@P4!J[>/7,>8HL=1.7AT.;Y1_YQ8\H3^7 MO)NK:IJFDSZ9K6K:FZ2?6HY(93:VZ((E*24H`[2&M-Z_+(LM!CX8$D;DOI[C M\3'QZX'/<"/B]NN*K=@02:#?%6)WQ,GG?RR`/[O2-7 MH/%/^4=)T&R\MZX-+N]9-U'J<,0B:AJ,P- M5D,0`"]#V%H\>>QMKN;XI3 M!##!+^\D-6&(?LJ`:>$_GW<:?IVG^3]>EO()-6\L:P^J:)Y8G@EN#JSI;2PRPVZ1!F6=(YB\+\ M2`X"GBK%A9$6"%#([>7UH()C$\!F17,,@I(G(`E6`)`(KOOF,S;(`()Z4W_# M`JT0/'/`LL<8^R.)%*?JP]5')/9E2VA0\5 M+RKQ^+&28\WGOG[U!Y/UV2, MG*N&'U!*?7MR)K"&2W:J7G`QS#LDE/BH?GD))"?SB..".:(!(8XXXHU\```* MGQ/7)%BA-/\`]*CN7D;XH5(XC^9>N^`;I.R52RF[>XL0I)4IR!-!Q/[7WC`E M-_36VA2>X>.%I22Y'I>6]%LM#TO3=%TV(Q6&E6\=K:(26;A&H4%F.[, M:58G9`X(7'N_,&BWVDPWMOJMW&$:\MW@$GI26#`A>=:> MI@&"B#:&92^7;.ZTV#2]1LH=0LXXEC:UN(UEB/%0/L.".WAEU+;&O^5:^4+2 M)X]+\NVF@LW MWY7_`)2P:<^H-^6?E.4+(BQQ#1+`EZGO6',;Q)5=E:>(_FS^0/D#4H+F:P\B M^7K!Y0'BAATJTA`(4$*R)$.N4992EL38;\&0P-QV/>'R/RU#R+ MH;.5#H\FF6M2&Z4K'F,81/0.>-9F_GR^92Z;\M/R[=@7\A^733H?T7:;_/\` M=80`.31EK++BGZCWG<_:^9O^QMD6*.,"., MJ$C4!0`*],HSX99*IV'9_:V'LRS.)-T!PUT^(>R_D';-:_E'Y1C8A6N(KBYY M#^6>ZED%?]B0#D\,#"-%IUFMCK,IS1!`-;'GRI[&WP`LF\B=O'+'%?0GY+>9 M3;7[:7/+1;H46O8T_IDHFBU98V'V!9*K&+D_(`50`[`TI7,@.*B'D5[B0G[, M94(I\0-S])P]5;1F]1A)L#T&$)2;5;*VO898)H%F4,/@85!'<9"0M0:>;:O^ M37EO4%$T$7U?ZR%8<#0`L*TH:Y`X^YF,I8Q=_D/IB0T2YD#MLO3K]V1.,AEX MR17?_./\J*?JEU78&C#^F/AED,S"=0_)+S';R2)"JRK4%2IWW^8&1X2&0RAY M/Y@_+GS-H?G/RY>W^G2QZ??6ESHUK>K1T^O74T$L4+!267U%@:C$<:T6M2H, MP#P$?%>,6R.3\A)?,]S#-K7E#3]4FB7THKC4+2"=T2I/$&56(%23092<8ES% MM\-7/&*C,CW$A](_DI^1?E_\K+:]&DZ=#IPU&[DOI[6$MZ2S2A0Y16)"`A!\ M*T44V`RW#A$>0:=5J\FH(,S9`KX/HNGW9EVXCY_U&?\`Q/\`FMJ=TC/)I/Y> MZHR.0[5WI#*_'M0]0H13YXJ6#>I<67YDVD\G]]Y@\NSK)*NRJ-'NXS$A]R-37Y9XIH[VXO80*"/2[&\U"H'2GU2&8G M$P)4;,8\PZ_8>:?+WF3R]I=AYBBN->TN\TZ.>X\OZM;I&US$\:NS75M`**6K MUZ9*,3$@[?,+S9CH6HKYH\KZ-?063Z8;F#T[VREH9()H7,4T-14$HZ,M1UI7 M(3C1I065SQFXLWLRW&-RC`^'%@=OHVP*N50@/ICB*]%[^YQ5#K;HDTUP%`FG MIR;QH<:5(O-NKG1-#O\`5/J9U2\M^$6E:8KB/ZQ>W,BP6L'J-\*"6:14Y'9: MU.PR48\1I6.QZU5+_`,N4U6:=9M2DT^2`S)IUVD<,;VMU/61F MDY(*#[).QXALC3Q`ESZ,9/HO3P*J/?,T,"S6T`XC+PQ3J(#;)A"(Q0["EV!# M6%+>*NQ5V!#L5=A2[%78H=B5=BEK%6\5=BKL5=@5V%6L5;P*[%785:(K_7%5 M-D!&!4,\(/;!2H*2U![8*2@WL@?V<%*A6T\']G!PIM1.FCPP<*VL_1J]*?3@ MX%MWZ,'AAX5M!7&FBGV=\B8+;$M9T6UO[.\T^_M8[RQOH9+>]M)5#QRQ2J4> M-U.Q5E)!!ZY613(//_+>IR^1FA\I^:[N6^TF6=%\G>:[IN2EJA8K#4'/V9@2 M!%,32;[+<9:>IBY,5;A+TNXL8==6^N?4+W$D)"Q]@\8J%^?;,?ZD\GD.M>3M M*\RZ=<17$8CU&S4_590/BX[DCWH- M.WRRLBF^,P7SW^8GY7>7/S(L[2Q\RQW2'3?6:PEMY3&T4DRJ"]*$-3B*`BF! MAFP1S"I/-Y?-LWY&^1O+VCZQY9U/68]'M8K*;7K+T/J+2FM`&:7U%KVY1C*< MN;@Z.S[,[+.>(@)Q!'3>_N_2QO0O^/*M.0^>51U=D"G:YO9\XLGW5GJVA23@^E] MS*PR]O-TG1?)GF\@`';0[P?\209'PCY+:'N//EM9/8KJ7ECS+I,% M_>6VGPWU[I_\FZC" MG*&VUQ;?49*;B"^MI[5%^FYD@/T9./4>2&-MJ-QYKU+SC^7^N6L5O9W=IJ=A M]9LY&]:.#TK52&,B%&9X-0BE##92QC*GAS>1CP@2"LC\G:I/=P:EIE]#;P:M MY:O/T;J36JF.*9A!%/'/'$Q+()(YE/$DT-0&:E3&0Z]Z65O2HI6@&Y&05@IOJ^I$=_^7K'C/X"%"3\NO*3\N5E>-R%/BU*_;?MUN#CXA6E, M_EKY+9@3I+L1N0UY=MN?]:8X?$DM)5J?Y7:46T]_+DX\NR0WD,FJ?#+=+>6L M90CB6-'23NZTROS-IUWJFC7<&G.D&KV[17>BSRCE' M'?6CK/;,XI]GU$7D.ZU&1A/AD"EZAY2URU\PZ)H^OV221VFLV<%[;Q3+QE1) MT#A)%WXNM:,.Q!&;0-1>DV3@J/NR\%BGL35`R80BL4.Q2UA5O%78%=BAV%+L M5=@5V*'84NQ*'8%=A2[%78%=A5V!#L*78%=A5V*NP(=BEV*&B!A2L*#`JF8J MXTJPPCVQI;6^@/#&EMWU<>&"E6F$`=,:5#2VX(.W7!26/7]D"&H,A**07GVN MZ+9ZC9WFG:E9Q7]A>QO#>6KR&/U6@YN2S>G5F+5.8F2(!2F-S;++JV MI26:A4]0K`1\*@[!Z9CEDG>IPV&H*\=U$DEM'($J0*$=Q@D`4`O)?-/Y.:+J M*OGW\=S=75TJQ>F(P6!*.P;[0';,#%AEQ`D/7=H]IZ>6"<8S M!)%;/UC_`"Z\@:CJM[:S3P-':J5,LK"@H-Z#YTS9@6\+.8#[GH MIQ:FP)'@-P4"EN1!H0*FO?KB$+HI:7BPTX1O&QJ?YNV$:?,'F#7].- M/M6>I:K=7%HW^S@=&^G)3YJ]4\:9%6JT&^%7AQ$^O/";.XMO5MTZ22VYG$JH=V"L$^/B#+F".] M0:8KI_GKRCJ6D1Z[:>8+4Z7+;W-UZTK&&00V3M'6O,_GDZ2VJAO*GE*2-+R^T:.:NJW,R36]Q:I,Z1CZIZ7I-R]*9F):E M5XUS+QX!'FQ)9/J<:`"E,?"CW+91K?D[^6CEGF_+WR]M3GHVG:\1+=SZ?IK0ULQJ2ZQ8G3BG/Z^+B/T2O\WJN8U%+'HM4\P^ M;+D6WE>QGTK0BLK'SY>00RVD_I\4$=C;FZCGGO>2 M+;N[WS!Y.`D\T21ZWY=5*R^:K2W>*:T8$FM]:Q^H/2IN9XR%7?FB(.>.33UO M%;94K*X61""K`%7&X((J"/',5DK`[@]QT.*J3H"/#VQ5+?)=V/+OF'4O*DX] M*PUB2?6O+,E6*EY7]34K?D=@PFD,ZBOQ+(_$4C:FPT\^*-=S"0>[V,W05S+@ M6!9/!)4#?+0A,5-?IR3%=@5V%+L"NPJ[%78%=BAV*NPI=BKL2AV*78J[%78J MUBK>*NP*["KL5=@0[%+L*NQ5K%6\5=BKL"&J>V%+J8%;VPJI/&"*C[L"I9<0 M\@2MR8%F%.H^+8Y MA=&2G/;7VH"2)8?J\$4B.2:#X>))K[[X%8$OYP>1)K=5T]] M8;*ZT4S2,WPQQ#4H;?U&-:`+7(2PF^27I;^4M!GNKL-I\+!&4QU4>%3^.0\, M6O$4TLM-L8HE^K6ZPB(E3&H`H1AC$(M%^A`I9I!^[8CD3ON.@R5*U'(AY&.( M(H)4%NM?E@M4+F$`WLK`/*_F>S\B?E?^7R_F%>C1M;&AV%D^F2*9+Z MYNXK9`T$-I`'EFGVJT<2L:UH*9*N(FE1,7YG31GZ_K7DC7/+WEEZ!=?NU@=H ME/\`NVZM()99[>+Q=U^`;R!%WR1PD!4\E_,S\MX_JOJ_F#Y:B^O!38\]6LU] M<-]DQ5E^.M=J5R'"3T*ADGZ8TCZS:V?Z5M/K=XI>RM?7C]290*DQIRJP]P,A M24S/2$KUS2[/7M&U?0M2]0:=K5E/87WI2-$_HW,;1R<76A4\6-".F/%2T M^0-!_+WREKWG3\O-6\C:!JA\HZ`FH7>O^;]7,R-J?IM!^C+>U]4AC`L\9F"1 MI'#111:.:Y>.)ZK;["M;7F1MEH#$ED$&GBFXRP01:.%@`/LY+A0L>P'\N#A5 M"OI_@,'`FV(/^77DUKHWQ\GZ*;TOZAO/T?;&4O6O+U/3Y5KWK@X%M.Y-/Z_# M@,2FTKN+$%65T#HP(=&%00>H(/7(4EX==6^L_E[:7D!TR^\Q^3M*A$^GZE%- M`]U86<:TD@N$E>*298%6J2+S=DV>KKS?%R:>S89"3,H9H[B*.:"1989562&9 M"&5U854JPV((-01F&R56'X8JD^M:3'J]I$B7#V.HZ?,+O1-6B'[VTNU5D65` M=C\+LK*=G1F1JJQ&3A,P-A:9SY%\SS:Y93Q:C;K8Z_HT_P!2UZQ3EZ:S!5=9 M8&;[4,R,KH:FE2C?&C@;/',2%AJ(>L6DU0#F0&*=Q-44K\LF$(CKBKL5=A5V M*NP(=A2[`KL*NP*["AV)5V!+L*NQ5V!#L*78$.PI=BKL"NQ5K"KL5;P*["K6 M*MXJ[%78J[`AV*7850\B5K^.!4GNK?D#MD2$L2O]/#AU9`R,"&4BH(/6HRF4 M60+Q:7R_J_Y?V/I^6K:7S#Y/M6FD;R2:"XL5FD,K-I<:$_[RR5^'^Z=. M(B?&R8>+ES3;'?.GG73//.CZ#Y1\EZX;O4O/&H1P:U^C9'6XLM!@H^H2S%>+ M0<@OU?X^+B7IMGHMOI]G:V%C;1VEE8PQV]G:Q*%2**-0J(H M&P"J``,R:2"MO-)M[RVN+*]M8[NSO(FAN[69%DBEB=2KHZ,"&5@:$$;XTFV. M>5=3O/)?F+3O)NKW4MYYYN8ZJ4D:@,I?[;L_7QWQI4()02HK1?LJQ M[X%0-W/3G&C%V0U"+W^GWQ5$V]N(IVF9SQ']VW8@[XA43#\=P\A.R[4PCFJ+ M/>G@/QPJM)90*^/;!:7R9J'_`#D1*OG31KNV:/3_`,O(9KS3M3T^XCBEUF^O M(8+MD,5O%,\L)DEBACMXY$224M)R4!5S(&(\/FAG6I^7/S)_,KR[=Z9YJUK3 M_)NB>8X>%_Y9TRQ-SJ-M;N0WHMJ<]PT+2TV9EM>(.PK]K+8X@$6SOR[^7>AZ M!=S:M%'/JOF*\01W_FC5)6O-2G0=$:XDW5!VC0*@[*,L`KDMLV%@>H&2I%H/ M]`V*&5UL($>>OKL(D!>O7D0-Z^^"EMYWYO\`RIT+7/+NJZ1I&FZ;Y>O[^2WN M$U.VLHD)EM;B.X02&(1N5T:\J8XP4?)*7Z7JWYU MZWDRV.D>44T">>"?S9?V37T>M\9G6VDL[&"^B,$;0JKR&24MR;@JT!;#^ M7%[K;!?*OF*;3O-I\H^5K'4)M:\O:W#I/GWR5:M->:)9V-TLA:VVJW,-O$@Z!%B5?3`V"<1VS6YA4RV#DS,^!IL=\J2MV M4[CY8JE?E>[AT3SSK-CJB.)$F12?B+S$?9: MN=II`QIA)[U83=-_?,Z)8%DL#U`RP,4P4U&20NP)=BAV*NPI=BKL5=BKL5=B MAV*NP)=BKL5=BAV%+L5=@0["EV*NP*_$[_G-3_G.;\\ORZ_/;S%^5OY6ZM:> M2]&\@+I\>H7TFG6M_[TG8O8<-=BEDG(BC0KW#];Z&\R_\Y')XL!+E8MT>H MP>#EEC)OA)"=:-_SE1^8?Y?:1I&G>?\`RCYG_-3SAYJM?-&O:3;KY:C\@RV6 MD^5+:QGO3<6FL7K,X9;HM'(A/-AP"]\L::>FZ%_SF'H7F6>XU?0_RV\T:A^6 MNB6^ER><_P`R$-CZ&CS:KHD&OHLUC]8^MR1P6MU%ZTD<;!7:@#`$XHX6"R_\ MY\Z#96.A/JOY.^;K#6_.VG^6->_+KRTL^ESW6MZ+YLNWLM/NXWCNC#`XF""2 M&=T9>:FI'(JKPLW\A?\`.8N@>>/S4M?RK_Y5_KNCWTFIWWEO4=9>>QNX+'S! MI5F;G4;&YCM9Y)4BAECEMEN>/I22I1"4='96GA7F?_G)K\]K7_G(C\Q/(?DQ MH_--GY._,'RQY:TS\L[?R;JMY]U6ZEE'U@@<4!* ME<*T]/T3_G-J;S/I?EB_\N_D+YNU"Z\\6VMZGY.T^6_T6W:_TKRT0FL7X:2] MI&D,LD44:R!7E9ZJO!2V*TB=._YSE\K:S=QZCI'Y;^9;W\N8+KR/:ZW^8IFT MZ*"P/G^TL;C23)9/*TQ"R_Y^,>0=0TJZUJQ_+/S;?Z M?='3)?)[6AL9WU>VU+5X='CIQN.%M/ZMQ%(()V5VC:HW5PH7A0%Y_P`YE^?] M(\]^8-&_,/\`+V3\K_+OE+S_`.7_`"]J)5['6;M;74?*EUY@NK6\>VOG3G2` MR)-;A@$XQE66KSREJ?FB'\I?-A2U.BW-D$>SN+(Z9KAF]* M^O=0M99X+(6_H?Z0DIY1H;1POL3\NO.EA^9GD/RMY\TRV%I8^:;".^M M[47=G?B/G4%!=:?/11(DMP8P0AE=0&?B"0.1-,CP)M,1I@[K7'@1:$G MTZ@-%P&*;>;>?O*]QY@\M:GIMC(+;55$=YH5Y6GHZC92I-O=X.05!F*6ZCD,@]-30(BG>A[XJBEAC2LLL8J`JD^(7VQ55 MEYW!B5$*PA@6;Q`';#S5%\504``Z?PP[!75IX^YQ2\E\X^:]7U378_R_\AW: M0^8%XS>;/,7II/%H5FP!6J.&1KN?I#$P(`K*XX`![<6/BW/)#(?*OD/2/+8N MI+9;C4-4U21)M9UW49GN[Z\DCKP:::0DT2IX(M$0;(JC;,L1[D$O1;:PZ57+ M1%C:;162@?9&3I")%H/#\,-*M:S7^7!2H:2P'AUP<*H5M/\`;!PILK!IV_3' MA6T1#IZHQ8(`6-6:FY/3?Z,("$YA@XTVR0"IBB`=NF20K`4Q0T<4M4^G"K7' MY8JIO&/#K@5+YXJ@[9$A+&;Z#KME<@D/GK3%;2/-'G/RY.X!6_\`TWI?,TFF MM-2`EDCZK$`9+2\B-8IE!V:AV9#\+H61@49@9PF8&U+T7R+YC/F/0K' M4IH5L]27E;:WIJL'^JW]NQCN8.0)J%D4\3^TM&&Q&;6$KW#47J5K)4#+PQ3B M,[9)"MBAV%+L5=BK6*MXJ[%78J[%#L5:Q2WBKL"'84NQ5K%6\5=BKL"'84OE M'\]O^<4O^<C8IK-KJDNDS:A#$28[2H:Y^0WY1^8_RQT[\F]6\E6LGY9Z2 M+0:;Y5MYKFTBA-C()K=DEMI8I@R2`/RYU+;L223$+/';1J:';C5:$DEI;*ZU_Y MQ;_(6RU_1O,MO^7EJNIZ!!IT&FQ-=WSV7^XFR73K"::P>X-K/-;VJB))IHGE M"@?'MA6RA-!_YQ._YQ]\M"']$?EY%$;6\TF^L7GU'4KI[5]"F>XTR*V:YNI3 M!!;2R,R6\96&I^Q@199?IWY%_E7I'Y@W7YHZ;Y6^I>=+VZGU"XOHKV^%H;VZ MM_JMQ>#3OK'U);B6'X'F6$2,*U8U.*VR_0/(_E7ROK7G#S#H.D)I^L^?K^'5 M/-]ZLDKF]N[>UBLHI65W94*P0HE$"C:M*U.%;>9ZO_SC-^2&M^5?*?DN^\D! M/+_D87R^4X+/4=2LKFRCU,L;Z*.\M;J*Y,5QR/JQM(4<4#*0!16V$Z-_SAU^ M3^G?F/Y@_,&^TC])K=WOEB\\H^5EENK33-%_PGIMMIVG(+2"Y6WNA%]666/U MXF]-OL>.*;93I_\`SBI^06EK<1V7D!$@GO+*^BLY-2U.6WM9=.OUU.V6RADN MVCM(DNU$QB@5(V8#DIP+93K6_P#G';\F?,?G2]_,'6_)$.I>:]2O['5-0OI; MN]]&>\TZRDTVUGDLQ.+9G2UF>&ICW4T:M!BBTAL?^<4?R&TW29M%L/)ES:V; MW%CN:T+NS;3!*+)+"\^O?6+.*`3R!(K>2.,!B.-#BFR]@\F^2_+'Y>^ M5M%\E^3=(BT+RQY=MQ:Z/I,+.Z0Q`EB.*(E+`428%FVE++BYH7N&;V".K>J&7K^ MS[YBA6T0(*GJ!7"!2H5VDN00J\8S^T>^1YJC4'%57KQ[Y,*QSS7YJT3R=I3: MMK=RT<1D6"RM(4,MS=W,FT5M;0K5I99#LJJ/:C2/.GYB#U?-M MQ-Y.\JS?W/D?3)RM[I>6_*>B^7;* M/3=`TBTT:P0\A:V<*0Q\CU8A`*D]R=\O$;8DLXMK("FV6"-,4WCMP`-LG2HM M8O;#2%81?+%5IB&*K##7M7&E4S`/#!2M?5QX8TMJ@A'AAI594`Q54IA5V*MX M%=A5V!6CN,4(:5*_3B4I)=PU!VWR!2\?_,'RQ=ZO96VI:-#"?,_EV;Z[H32_ M")2`5GLWD_96YB+1\C4(Q63BQ0#,?)#B%,@6*:3JUKK.G6NI6@D6*X#!H9D, M&*I?Y5G72OS$NM,MV( MMO-VD7&KW%K2B1W>DS6EK),M/VIX[R-7_P",2^)S.TLB01W,)!]"V;;+FP#6 MGT1R80BATQ0[%784NP*["KL"'84NQ5V*'8I=BKL5=BKL5=BKL"M85;Q5V!78 MJ_FY_P"?EOE/\S[O_G)S7]3\RZ+JVK>3=1T_3(?RON?0ENK%;(64"W=M;\5= M$E-\)V>/[9Y*U.)7-?K(Y3(<-UY=[CYQ,D6/SS7_GWC^7&A>:]-\U M:CKEM?Z;)^9GEO3VG_Q-<>0UUMY+JPC4,+@SG22B&-3ZG"L=.51F=C$N$<7- MR(WM?-#6?FC0_(FFZU>_\XO^6O/7Y/\`Y,:]YZ\OV'GC\P8O+=[6M4L99H!];CM;:ZG:T:,L_(*2I<39>]+)/-/\`SE[^;'DCSUIM]YK\ MR^3[:Q_([6=>L[;3_*MM:ZCYDU1]4\QV&G*&GM3-9SWNGVUE,T,`65&=3&(B MVZNR3^3?SL_YRF@\X?EIY;M=?U!/(]IH_E58OT[Y=U'ZYKFG26#'7;MQ;^5[ MEEN+.9'C4R7=LJF)/4CF];F0I`?0W_.(OYG_`)G_`)H:3^;>H?F)YQ\QZNI> M9?(ODOS'Y5&A:II^E1>M#%=7US;Z986LMQ>L.?H0/*(4X`N6+43R5\0?E/\` MDU_SD%^3?_..NB?\Y`?E]I^E_ESYRTWR-;:5#Y:T/3]2OM<\PWFJ:Y81FZ\Q MZ9>Q+!ZEG;B8H$C=@'8\U`%"4OJOS+^9?_.3WDO\W5\BGS7KWFJ_TGS#Y2T[ MRMH/^$K4:9YMT#4%Y:_K-[JMK8B.R>SK(`L<\:IZ2ADD,M<"-GSYY*_YRE_Y MRX\S?EA8>;/).N:O^9VM:MY#?5O/)N_)Z:?9>5KY=?L;..YTV6UTL_7RVFR7 M,YC5;K^[]58RH]$JT'NWY8^=/^64FDOK+29M%72XII=;\OZ1%',[W5W&)([*..1$Y(I8ZY=ZY;:Q&!=Z3Y>\K7IOM?5O,L MUI',!J?EBSB=OJ`020B333Q_TI&X2*H44'[`X6+5,5=3%#5,4N*@X%0TD?MB M52:[MPP.W7($)8%YAT.PUC3]1TC5;2.^TS5+>6TU"RE%4E@F0I(C#P921E,A M3(//_+&KZMH'F.#\OM=OFUOZQH]QJ7E;S!+M=2VNGS06]Q!?4'%Y8OK4)65: M>H"W)59:OA9BJL+4CB&]"O2F$%6.>=/-MGY* M\OW6MW=O+?RJ\=MINE6Y7ZQ>WEPXBM[:$,0"TCL!X`58_""*+FQB(\D/:+ M.RK2HRR,;8DLDM[4+3;+0$)I'%0;#)4A%*@&%53%#6%+>*NIBAJF*7=\5=BK ML5;Q5V!78J["KL"NPJL85P*ET\=0=L!5CUY;=2!E<@EX1YD\LZYY=N/,'F7R MRL.J6=V_Z3U/RE)&XN)9DC"W#6-P)."O*D:D1-'Q:6I+KZC$8>7");M@-(FV MN[:_M+74+*X2[LKV%+BSN8B&22*50\;J1U#*00G4X%2339#'^:W ME&E&$WEWS#`1W'*YTB3E\AZ=/F1F9I.98R?2-G4`9L@U,@A[9,(10Z85;Q5V M!#L*78JUBK>*NP*["AV)5V!+L*NQ0[`KL*78J[`KL*NQ5V!#1`/45IN,*6\5 M=@0UA2[%6\5=BK1`8$,*@[$'PQ5)_+_EW0/*6C:?Y<\K:)8>7/+^DQ^CIFB: M9;QVMI;QU+<(H8E5$%230#%4YQ5V!6L*MXJ[%78J[%6L5:85Q0@9HZ@C(D)8 M[?6W(';?*Y"TO#?S'5/+MSY;_,/X(T\H7;6VO2FI)T35C';WP`Z`1R+!E$H".1Z#]D80$O*O/4<>I^?/RIT6< MU2UGU?S&(^S/IUHMDE?]5M2Y#W&9.`;E#U6RM]QMF5$6Q++;:``#;+@&*;QQ MC;;)A")"@85;Q5O`AH84MXJ[`AV%+6*MXJ[`AV%+L"'84NQ5V*NP(:PI49$K M_'`J63PUKMD2$L?NK6A)4=,KE%;>#ZWY1U;R=;7>I>4G-_H-F&N+GR5,A9HH M5Y22KI.50Z..]""#FO(IFA/)SL_YHZC;ZA9R&2V\NJWEV_6*L0BENE_2*M(">+.R MVO%2`2$8C:N9^C`H][";Z.M%V&9X:T]A'3)A")'08H;PI=@5V*NPJZF*NQ5V M*NQ0[%78%=BKL*NQ2[%78%=A5V*NQ5V!#L*78J[`AV*785=@0[%784NQ5V*N MQ5V!78H=BEV%78J[%78H4G6HP)2RXAY`Y$A+$M6TFVO[6ZLKRW2ZL[V)X+NV MD'))(Y%*NC#N""0<@8VD%X_"/-_Y>Z;:Z?)IK>=_*>C,(;&_M9)6UVUL0.," M26?I.MZ8-E9UE65TW]-Y`>>%DP=0RMZ!Y?\`,6C>9K!=0T34[?5($=H;E[=P MQBF3[<4J_:C=:[HP##N,QJ(.Z6$?F'(NA:OY)\]S(#IGEZZNM.\R71Z6NFZM M&JORV,8HIZUZ',Z(IK9+`M`-LL"$P44&%"[% M+L5=BAK"EO`KL*NP*["KL"NQ5V%78J[%78$.PI=BKL"M$5Q0AY$![8I2V>`- M7;(D)22>UH:@9$A7S./KWY=VRZ'YATV\ET^R>6'RYK=A;R7<-W;^H?JEL4A5 MY([D(RQA&6DC#]VS$\5UN;3R$K'5M$GI_P"7?EG5;:;5_-&OVQL-7\PBWAM] M),@D^I:?:^HUO#(5JGK,\TDDI0D594#,(PQS,&+@BPD;>R6\5`-LR`Q35!05 MR2%7"K>*NQ5V*NQ5K%6\"NQ0["EV*'8%=A2[%78$.Q2[%#L4NPJ[`KL*NQ5V M*NP*["KL5=BAV!+L5=A5V!#L*78%=BAV*NPI=@0["EV*M4Q5#R1UWP*ETT`: MNV1I*4S60WVR)"L+U;R#Y:UB_P#TK?:3'^EO16W;6+9I+6\:%266)KFW:.5D M5B2%+4!-:9$P!3;"-5_*34]50:`//.JC\O[]C_B#RS=L]W>7$)5^5M%JTTIN M8X969?45B[%5X(Z(S*:_!%VFWNUE:I`D<<:"..-0J(HH%4"@`'8#+P&*=Q+2 M@R80B1A5O`KL*NP*[%785:Q5O`KL4.PI:Q5O`KL*NP(=A2[%78J[`AV%6B,4 MJ#Q@_(X%0$EN#VR-)0AM16M,%*KQ6].V&E1\<=!D@$(L"F%#>!+L*NQ5V*NP M(:PI;Q5V*NQ0[%78$NQ0UA2WBKL"'84NQ5V*NQ5V*N[XJ[%78J[%78J[%#L4 MNQ0UBEO`AV%+L5=BKL5=BKL5=BKL"M85<1[?1BJBT8/SP*AVAKVP4J'-L/#! M26Q;`4VQI;1,<5*8:0BE%/X9)"_%+L"NPJ[%78J[`KL*NP*["KL5=@5V%6L5 M;Q5V!785=BKL"'8J["EJF*K"@.!5/TABJX1C%50"G3"A=BEV*NQ5V!785=BK ML5=BKL5=BKL4.Q2[%78J[%6L5;P*["KN^*M8JWBKL"NPJ[%6L5=BK>*NP*[% M#L4M#"K>*NP(=A2UBK>*NQ5V*NP(=A2[%6L5:IBK7$;UQ5W$8JW08JV,5;Q5 MJF*MXJ[%78J[%78J[%78%=A5V*NQ5K%6\5=@5K"K>!#L4M?AA5O%78JT<5;Q M0UBK>*M8I;Q5K%6\"'8I=BKL*M8JW@5V%78E#L"N.%+L"'8I=A5V!785=BAV M*6L5;Q5V!#L4NPJ[`AV*NQ5V*N[X4NQ5V!#L*78$.PI=BKL5=BKL5:Q5O`KL M5=BKL*NQ5V*NQ5V*NP*["KN^*NP(=BKL*78H=@2[%6L*MXJ[%78%=BAV*NQ5 HV*78H=A2[`AV*N'3"EV!#L5=BKL4NPJ[%#L4NP(=A2[`KL5=A0__V3\_ ` end ~~-----END PRIVACY-ENHANCED MESSAGE-----~~


(1)	Our CCA properties, which produce mainly from porous dolomites drilled on 40 to 80 acre spacing intervals, have longer reserve lives than our other properties because the low permeability level encountered within those producing intervals require a longer time to produce the reserves in place. This results in a lower production decline rate.

(2)	Permian Basin includes the Central Permian, Indian Basin and Crockett properties.

(3)	Rockies includes the Paradox Basin, Lodgepole and Bell Creek properties.

(4)	Mid Continent includes the Elm Grove and Verden properties. The Elm Grove properties were acquired on July 31, 2003, and the R/ P index shown in the table is calculated by annualizing our production since the acquisition.


	•	Maintain an Active Low-Risk Development Drilling Program. Our technological expertise, combined with our proficient field operations and reservoir engineering, have allowed us to increase production and reserves on our properties through development drilling, workovers, waterflood enhancements, tertiary projects, and recompletions. Our plan is to maintain an inventory of low-risk


		exploitation and development projects that provide us ongoing drilling activity. Each year, we budget a portion of internally generated cash flow to secondary and tertiary recovery projects whose results will not be seen until future years. Our conventional development budget for 2004, exclusive of spending on high pressure air injection, is $93 million.

	•	Maximize Existing Reserves and Production Through High-Pressure Air Injections. In addition to conventional development drilling, we utilize high-pressure air injection techniques on certain properties to enhance our growth. High-pressure air injection involves utilizing compressors to inject air into previously produced oil and natural gas formations in order to displace remaining resident hydrocarbons and force them under pressure to a common lifting point for production. We believe that the HPAI programs on our CCA properties will generate a higher rate of return than other tertiary processes and can be applied throughout our CCA properties. The zone of our initial focus for HPAI, the Red River U4 zone, is the same zone where HPAI has been successfully implemented by other operators in adjacent areas and on our Pennel unit of the CCA. Response from HPAI investments is not expected until ten to eighteen months from the time of first injection. Our high-pressure air injection budget for 2004 is $34 million.

	•	Expand Our Reserves, Production, and Drilling Inventory Through a Disciplined Acquisition Program. We will continue to pursue acquisitions of properties with similar upside potential to our current producing properties portfolio. Using the experience of our management team, we have developed and refined an acquisition program designed to increase our reserves and to complement our core properties, while providing upside potential. We have a staff of engineering and geoscience professionals who manage our core properties and use their experience and expertise to target attractive acquisition opportunities. Following an acquisition, our technical professionals seek to enhance the value of the new assets through a proven development and exploitation program. For the year ended 2003, we evaluated over $1 billion of potential acquisitions. We will continue to aggressively evaluate acquisition opportunities in 2004 with the same disciplined commitment to acquire assets that fit our portfolio and continue to create value for our shareholders.

	•	Focus on Cost Control Through Efficient and Safe Operations. As of December 31, 2003, we operated properties representing approximately 84% of our proved reserves, which allows us to control capital allocation and expenses. Not only do we strive to efficiently operate our properties but we strive to safely operate our properties. The total recordable incident rate (“TRIR”) averaged 2.5 per 200,000 man hours for the industry in 2003. We are very proud to have a perfect TRIR of zero for our employees in 2003.


(1)	Volumetric reserves attributed to the net profits interests in our CCA properties were 20,623 MBOE, 16,262 MBOE, and 11,062 MBOE, respectively, at December 31, 2003, 2002, and 2001. See “— Properties — Net Profits Interests” on page 13. The volumes attributed to the net profits interests, which reduce our reserves on a BOE for BOE basis, will fluctuate from period to period primarily based on commodity prices and the level of planned development expenditures.

(2)	The pretax present value of estimated future revenues to be generated from the production of proved reserves net of estimated future production and future development costs; using prices and costs as of the date of estimation without future escalation; without giving effect to hedging activities, non-property related expenses such as general and administrative expenses, debt service, and depletion, depreciation, and amortization; and discounted using an annual discount rate of 10%. Giving effect to hedging transactions based on prices current at such dates, our PV-10 value would have been $997.2 million at December 31, 2003, $860.6 million at December 31, 2002, and $364.4 million at December 31, 2001.


(3)	Estimated future cash inflows to be generated from the production and sale of proved oil and natural gas reserves, net of estimated future production and development costs, and future income tax expenses discounted at 10% per annum to reflect the timing of future cash flows. Standardized Measure differs from PV-10 because Standardized Measure includes the effect of future income taxes.


(1)	Our total wells include 906 operated wells and 1,824 non-operated wells.


	•	additional acquisition of interests;

	•	detailed attention to the existing wellbores;

	•	the addition of strategically positioned new horizontal and vertical wellbores;

	•	the highly successful application of horizontal re-entry drilling in existing wellbores;

	•	waterflood enhancements;

	•	and implementation of our high-pressure air injection program.


	•	royalties, overriding royalties, net profit interests, and other burdens under oil and natural gas leases;

	•	contractual obligations, including, in some cases, development obligations arising under operating agreements, farmout agreements, production sales contracts, and other agreements that may affect the properties or their titles;

	•	liens that arise in the normal course of operations, such as those for unpaid taxes, statutory liens securing unpaid suppliers and contractors, and contractual liens under operating agreements;

	•	pooling, unitization and communitization agreements, declarations, and orders; and

	•	easements, restrictions, rights-of-way, and other matters that commonly affect property.


(1)	For the years ended December 31, 2003, 2002, 2001, 2000, and 1999 we reduced revenue for the payments of the net profits interests by $5.8 million, $2.0 million, $2.8 million, $11.5 million, and $4.4 million, respectively.

(2)	Net income for the year ended December 31, 2003 includes a $0.9 million cumulative effect of accounting change, which affects its comparability with other periods presented. See pro forma amounts presented in “Note 2. Summary of Significant Account Policies — New Accounting Standards” to the accompanying consolidated financial statements.

(3)	Net income for the year ended December 31, 2001 includes $9.6 million of non-cash compensation expense, $4.3 million of bad debt expense, $1.6 million of impairment of oil and natural gas properties, and a $(0.9) million cumulative effect of accounting change, which affects its comparability with other periods presented.

(4)	Net income for the year ended December 31, 2000 includes $26.0 million of non-cash compensation expense, which affects its comparability with other periods presented.


	•	Oil and natural gas reserves increased 10% to 140,890 MBOE. During 2003, we added 20.7 MMBOE at a FD&A cost of $7.42 per BOE, replacing 255% of the 8.1 MMBOE produced in 2003. Including revisions, the development program added 14.4 MMBOE (178% of our production) at a cost of $6.86 per BOE. Included in our reserve additions are 12.5 MMBOE of high-pressure air volumes. The 12.5 MMBOE represents the first reserves related to our high-pressure air injection program in the Cedar Creek Anticline of Montana and North Dakota. Our three year FD&A costs, including revisions, are $5.60 per BOE with a reserve replacement ratio of 329%. Oil reserves accounted for 84% of total proved reserves, and 78% of proved reserves are proved developed. Our reserve-to-production ratio is 17 years for total proved reserves and 14 years for proved developed reserves.

	•	Production volumes for the year increased 10% to 8.1 MMBOE (22,218 BOE per day), compared with 2002 production of 7.4 MMBOE (20,273 BOE per day). Oil represented 81% and 82% of our total BOE production in 2003 and 2002, respectively. The increase in production is due to our continued successful development and exploitation program as well as the Elm Grove acquisition.

	•	Net income for the full year of 2003 increased 69% to $63.6 million, or $2.10 per diluted share, on revenues of $220.1 million. Net income for the year ended December 31, 2003 includes a $0.9 million ($0.03 per diluted share) cumulative effect of accounting change resulting from the adoption of Statement of Financial Accounting Standards No. 143 “Accounting for Asset Retirement Obligations” on January 1, 2003. This compares to full year 2002 net income of $37.7 million, or $1.25 per diluted share, on revenues of $160.7 million. For 2003, cash flow from operations increased 35% to $123.8 million from $91.5 million for 2002. The increase in net income and cash flow from operations from 2002 was primarily a result of higher production and higher commodity prices throughout the year.

	•	We improved our financial flexibility and liquidity by negotiating an increased borrowing base under the existing credit facility from $220 million to $270 million. At December 31, 2003, we had $29 million outstanding on the borrowing base and $241 million available for funding of future capital requirements.

	•	We improved our ability to access capital markets with the filing of a $400 million universal shelf registration statement on Form S-3. We currently have $216 million availability remaining under the registration statement.

	•	We expanded the liquidity and public ownership of our common stock by facilitating the sale of common stock by J.P. Morgan and Warburg Pincus. On November 13, 2003, we priced a public offering of 8.0 million shares of our common stock at a price to the public of $20.25 per share. The underwriters also exercised their over-allotment option for an additional 1.06 million shares of common stock, at a price of $20.25 per share, on December 2, 2003, for a total of 9.06 million shares. We used all of the net proceeds to repurchase 6,866,643 shares of our common stock from J.P. Morgan and 2,193,357 shares from Warburg Pincus at a price of $19.3775 per share. The 9.06 million shares we purchased were retired upon repurchase. Our total shares outstanding did not change as a result of this offering. Net proceeds from the original offering and the over-allotment option totaled approximately $175.6 million, after deducting underwriting discounts and commissions and the estimated expenses of the offering. After giving effect to the repurchase, J.P. Morgan


		no longer beneficially owns any of our common stock and Warburg Pincus beneficially owns 24.5% of our common stock.

	•	High-pressure air injection was implemented in a second area on the CCA properties in the Little Beaver area. We were able to negotiate the purchase of high-pressure air compression services from an offset operator. This allowed us to implement a project in Little Beaver unit, on the south end of the Cedar Creek Anticline, in less than one year. First injection began in Little Beaver phase one during December 2003 and phase one and phase two should be completed during 2004. Our independent reserve engineers, Miller and Lents, Ltd., booked 12.2 million barrels of oil reserves associated with high pressure air at year end 2003 at Little Beaver. High pressure air injection contributed to our FD&A cost during 2003.


	1. The project involves the application of one or more qualified tertiary recovery methods that is reasonably expected to result in more than an insignificant increase in the amount of crude oil that ultimately will be recovered;

	2. The project is located within the United States;

	3. The first injection of liquids, gases, or other matter for the project occurs after December 31, 1990; and

	4. The project is certified by a petroleum engineer.


	1. Tangible Property. Any amount paid for tangible property that is an integral part of a qualified enhanced oil recovery project, and with respect to which depreciation is allowable.

	2. Intangible Drilling and Development Costs. Intangible drilling cost with respect to which the taxpayer may make an intangible drilling costs deduction election under Code Sec. 263(c).

	3. Qualified Tertiary Injectant Expenses. Any qualified tertiary injectant expenses for which a deduction is allowable under any Code section.


	•	Development and exploitation of our existing oil and natural gas properties

	•	High-pressure air injection programs on our CCA properties

	•	Acquisitions of oil and natural gas properties

	•	Leasehold and acreage costs

	•	Other general property and equipment

	•	Funding of necessary working capital

	•	Payment of contractual obligations


(1)	Amounts included in the table above include both principal and projected interest payments. See information presented in “Note 6. Indebtedness” to the accompanying consolidated financial statements for additional information regarding our long-term debt.

(2)	Amounts included in the table above include both principal and projected interest payments. See “Note 6. Indebtedness” to the accompanying consolidated financial statements for additional information regarding our long-term debt. Giving effect to the Cortez acquisition, the pro-forma amount outstanding under our revolving credit facility as of December 31, 2003 would be approximately $152.0 million.

(3)	Derivative obligations represent liabilities for derivatives that were valued as of December 31, 2003. The ultimate settlement amounts of the remaining portions of our derivative obligations are unknown because they are subject to continuing market risk. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” and “Note 11. Financial Investments” to the accompanying consolidated financial statements for additional information regarding our derivative obligations.

(4)	Development commitments represent authorized purchases not placed to vendors, thus not accrued at year-end. These purchases are authorized and expected to be made during 2004 unless circumstances change. Above amounts also include minimum transmission payments for electricity.

(5)	Operating leases represent office space and equipment obligations that have remaining non-cancelable lease terms in excess of one year. See “Note 4. Commitments and Contingencies” to the accompanying consolidated financial statements for additional information regarding our operating leases.


	•	expected capital expenditures and the focus of our capital program;

	•	areas of future growth;

	•	our drilling program;

	•	future horizontal development, secondary development and tertiary recovery potential;

	•	the implementation of our High-Pressure Air Program, the ability to expand the program to other parts of the CCA and the effects thereof;

	•	the completion of current HPAI projects and the effects thereof;

	•	anticipated prices for oil and natural gas;

	•	projected revenues; FD&A costs; lifting costs; lease operations expenses; production, ad valorem and severance taxes; general and administrative expenses; taxes; and DD&A;

	•	timing and amount of future production of oil and natural gas;

	•	expected hedging positions and payments related to hedging contracts;

	•	expectations regarding working capital, cash flow and anticipated liquidity;


	•	the closing of the Cortez transaction and the benefits to be derived therefrom;

	•	projected borrowings under our credit facility; and

	•	marketing of oil and natural gas.


	•	the supply of domestic and foreign oil and natural gas;

	•	the ability of members of the Organization of Petroleum Exporting Countries to agree upon and maintain oil prices and production levels;

	•	political instability or armed conflict in oil or natural gas producing regions;

	•	the level of consumer demand;

	•	weather conditions;

	•	the price and availability of alternative fuels;

	•	domestic and foreign governmental regulations and taxes;

	•	domestic political developments; and

	•	worldwide economic conditions.


	•	recoverable reserves;

	•	future oil and natural gas prices;

	•	operating costs; and

	•	potential environmental and other liabilities.


	•	diversion of management attention from existing operations;

	•	unexpected losses of key employees, customers and suppliers of the acquired business;

	•	conforming the financial, technological and management standards, processes, procedures and controls of the acquired business with those of our existing operations; and

	•	increasing the scope, geographic diversity and complexity of our operations.


	•	a counterparty to our derivative instruments is unable to satisfy its obligations;

	•	production is less than expected; or

	•	there is an adverse change in the expected differential between the underlying price in the derivative instrument and actual prices received for our production.


	•	acquiring desirable producing properties or new leases for future exploration;

	•	marketing our oil and natural gas production;

	•	integrating new technologies; and

	•	acquiring the equipment and expertise necessary to develop and operate our properties.


	1.	On November 4, 2003, we filed a Form 8-K to furnish certain earnings-related information under Items 7 and 12.

	2.	On November 7, 2003, we filed a Form 8-K to furnish information under Items 7 and 9 regarding the appointment of Roy W. Jageman as our Chief Financial Officer.

	3.	On November 10, 2003, we filed a Form 8-K to furnish information under Items 7 and 9 regarding a public offering of up to 9.2 million shares of our common stock and the use of proceeds therefrom.

	4.	On November 14, 2003, we filed an Item 5 and Item 7 Form 8-K to disclose the execution of an underwriting agreement with respect to the public offering of up to 9.2 million shares of our common stock and the execution of a stock purchase agreement with respect to the repurchase of up to 9.2 million shares of our common stock from J.P. Morgan Partners (SBIC), LLC and Warburg, Pincus Equity Partners L.P.

	5.	On November 20, 2003, we filed a Form 8-K to furnish information under Items 7 and 9 regarding the closing of a public offering of 8.0 million shares of our common stock and the use of proceeds therefrom.

	6.	On December 3, 2003, we filed a Form 8-K to furnish information under Items 7 and 9 regarding the sale of 1,060,000 shares of our common stock pursuant the exercise of the underwriters’ over-allotment option and the use of proceeds therefrom.


*	Filed herewith

+	Management contract or compensatory plan, contract or arrangement.


Name of Subsidiary		State or other Jurisdiction of Incorporation or Organization

EAP Energy, Inc.		Delaware
EAP Properties, Inc.		Delaware
EAP Operating, Inc.		Delaware
EAP Energy Services, L.P.		Texas
Encore Operating, L.P.		Texas
Encore Operating Louisiana LLC		Delaware


						Very truly yours,

						MILLER AND LENTS, LTD.


						By: /s/ CARL D. RICHARD


						Carl D. Richard
						Vice President


Date: March 11, 2004	By: /s/ I. Jon Brumley

		I. Jon Brumley
		Chairman and Chief Executive Officer


Date: March 11, 2004	By: /s/ Roy W. Jageman

		Roy W. Jageman
		Chief Financial Officer, Treasurer, Executive Vice President and Corporate Secretary