UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended June 30, 2009

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

For the transition period from                      to                     

ENCORE ACQUISITION COMPANY

(Exact name of registrant as specified in its charter)

Delaware		75-2759650
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

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

(Registrant’s telephone number, including area code)

(Former name, former address and former fiscal year, if changed since last report)

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 whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o    No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o    No þ

Number of shares of common stock, $0.01 par value, outstanding as of July 31, 2009		52,793,909

 

 

ENCORE ACQUISITION COMPANY

INDEX

				Page
		PART I. FINANCIAL INFORMATION
Item 1.		Financial Statements
		Consolidated Balance Sheets as of June 30, 2009 and December 31, 2008			1
		Consolidated Statements of Operations for the three and six months ended June 30, 2009 and 2008			2
		Consolidated Statement of Equity and Comprehensive Loss for the six months ended June 30, 2009			3
		Consolidated Statements of Cash Flows for the six months ended June 30, 2009 and 2008			4
		Notes to Consolidated Financial Statements			5
Item 2.		Management’s Discussion and Analysis of Financial Condition and Results of Operations			41
Item 3.		Quantitative and Qualitative Disclosures About Market Risk			60
Item 4.		Controls and Procedures			61
		PART II. OTHER INFORMATION
Item 1.		Legal Proceedings			62
Item 1A.		Risk Factors			62
Item 2.		Unregistered Sales of Equity Securities and Use of Proceeds			62
Item 4.		Submission of Matters to a Vote of Security Holders			62
Item 6.		Exhibits			63
EX-31.1
EX-31.2
EX-32.1
EX-32.2
EX-99.1

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

     Certain information included in this Quarterly Report on Form 10-Q (the “Report”) and our other materials filed with the United States Securities and Exchange Commission (“SEC”), or in other written or oral statements made or to be made by us, other than statements of historical fact, are forward-looking statements as defined by the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. These forward-looking statements give our current expectations or forecasts of future events. Forward-looking statements can be identified by the fact that they do not relate strictly to historical or current facts. These statements may include words such as “may,” “will,” “could,” “anticipate,” “estimate,” “expect,” “project,” “intend,” “plan,” “believe,” “should,” “predict,” “potential,” “pursue,” “target,” “continue,” and other words and terms of similar meaning. You are cautioned not to place undue reliance on such forward-looking statements, which speak only as of the date of this Report. 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 “Item 1A. Risk Factors” and elsewhere in our 2008 Annual Report on Form 10-K and in our other filings with the SEC. If one or more of these risks or uncertainties materialize (or the consequences of such a development changes), or should underlying assumptions prove incorrect, actual outcomes may vary materially from those forecasted or expected. We undertake no responsibility to update forward-looking statements for changes related to these or any other factors that may occur subsequent to this filing for any reason.

ENCORE ACQUISITION COMPANY

GLOSSARY

     The following are abbreviations and definitions of certain terms used in this Report. The definitions of proved developed reserves, proved reserves, and proved undeveloped reserves have been summarized from the applicable definitions contained in Rule 4-10(a)(2-4) of Regulation S-X.

	•		Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbons.
	•		Bbl/D. One Bbl per day.
	•		BOE. One barrel of oil equivalent, calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Bbl of oil.
	•		BOE/D. One BOE per day.
	•		Completion. The installation of permanent equipment for the production of hydrocarbons.
	•		Council of Petroleum Accountants Societies (“COPAS”). A professional organization of petroleum accountants that maintains consistency in accounting procedures and interpretations, including the procedures that are part of most joint operating agreements. These procedures establish a drilling rate and an overhead rate to reimburse the operator of a well for overhead costs, such as accounting and engineering.
	•		Delay Rentals. Fees paid to the lessor of an oil and natural gas lease during the primary term of the lease prior to the commencement of production from a well.
	•		Development Well. A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.
	•		Dry Hole or Unsuccessful Well. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production would exceed production costs.
	•		EAC. Encore Acquisition Company, a publicly traded Delaware corporation, together with its subsidiaries.
	•		ENP. Encore Energy Partners LP, a publicly traded Delaware limited partnership, together with its subsidiaries.
	•		Exploratory Well. A well drilled to find and produce hydrocarbons in an unproved area, to find a new reservoir in a field previously producing hydrocarbons in another reservoir, or to extend a known reservoir.
	•		FASB. Financial Accounting Standards Board.
	•		Field. An area consisting of a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.
	•		GAAP. Accounting principles generally accepted in the United States.
	•		Gross Acres or Gross Wells. The total acres or wells, as the case may be, in which an entity owns a working interest.
	•		Lease Operating Expense (“LOE”). All direct and allocated indirect costs of producing hydrocarbons after the completion of drilling and before the commencement of production. Such costs include labor, superintendence, supplies, repairs, maintenance, and direct overhead charges.
	•		LIBOR. London Interbank Offered Rate.
	•		MBbl. One thousand Bbls.
	•		MBOE. One thousand BOE.
	•		Mcf. One thousand cubic feet, used in reference to natural gas.
	•		Mcf/D. One Mcf per day.
	•		MMcf. One million cubic feet, used in reference to natural gas.
	•		Natural Gas Liquids (“NGLs”). The combination of ethane, propane, butane, and natural gasolines that when removed from natural gas become liquid under various levels of higher pressure and lower temperature.
	•		Net Acres or Net Wells. Gross acres or wells, as the case may be, multiplied by the working interest percentage owned by an entity.
	•		Net Production. Production owned by an entity less royalties, net profits interests, and production due others.
	•		Net Profits Interest. An interest that entitles the owner to a specified share of net profits from the production of hydrocarbons.
	•		NYMEX. New York Mercantile Exchange.
	•		Oil. Crude oil, condensate, and NGLs.
	•		Operator. The entity responsible for the exploration, development, and production of a well or lease.
	•		Production Margin. Wellhead revenues less production costs.
	•		Productive Well or Successful Well. A well capable of producing hydrocarbons in commercial quantities, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities.
	•		Proved Developed Reserves. Proved reserves that can be expected to be recovered from existing wells with existing equipment and operating methods.

ENCORE ACQUISITION COMPANY

	•		Proved Reserves. The estimated quantities of hydrocarbons that geological and engineering data demonstrate with reasonable certainty are recoverable in future periods from known reservoirs under existing economic and operating conditions.
	•		Proved Undeveloped Reserves. Proved reserves that are expected to be recovered from new wells on undrilled acreage 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 for recompletion. Includes unrealized production response from enhanced recovery techniques that have been proved effective by actual tests in the area and in the same reservoir.
	•		Recompletion. The completion for production from an existing wellbore in another formation from that in which the well has been previously completed.
	•		Reservoir. A porous and permeable underground formation containing a natural accumulation of producible hydrocarbons that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
	•		Royalty. An interest in an oil and natural gas lease that gives the owner the right to receive a portion of the production from the leased acreage (or of the proceeds from the sale thereof), but does not require the owner to pay any portion of the production or development costs 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.
	•		Secondary Recovery. Enhanced recovery of oil or natural gas from a reservoir beyond the oil or natural gas that can be recovered by normal flowing and pumping operations. Involves maintaining or enhancing reservoir pressure by injecting water, gas, or other substances into the formation in order to displace hydrocarbons toward the wellbore. The most common secondary recovery techniques are gas injection and waterflooding.
	•		SFAS. Statement of Financial Accounting Standards.
	•		Tertiary Recovery. An enhanced recovery operation that normally occurs after waterflooding in which chemicals or natural gases are used as the injectant.
	•		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 or natural gas lease that gives the owner the right to drill for and produce hydrocarbons on the leased acreage and requires the owner to pay a share of the production and development costs.
	•		Workover. Operations on a producing well to restore or increase production.

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

ENCORE ACQUISITION COMPANY
CONSOLIDATED BALANCE SHEETS
(in thousands, except share and par value amounts)

		June 30,				December 31,
		2009				2008
		(unaudited)
ASSETS
Current assets:
Cash and cash equivalents		$	35,840			$	2,039
Accounts receivable, net of allowance for doubtful accounts of $434 and $381, respectively			96,591				117,995
Current portion of long-term receivables			13,260				11,070
Inventory			27,266				24,798
Derivatives			53,204				349,344
Income taxes receivable			5,452				29,445
Other			5,286				6,239
Total current assets			236,899				540,930
Properties and equipment, at cost — successful efforts method:
Proved properties, including wells and related equipment			3,743,817				3,538,459
Unproved properties			114,168				124,339
Accumulated depletion, depreciation, and amortization			(914,021	)			(771,564	)
			2,943,964				2,891,234
Other property and equipment			25,794				25,192
Accumulated depreciation			(14,854	)			(12,753	)
			10,940				12,439
Acquisition deposit			37,500				—
Goodwill			60,606				60,606
Derivatives			48,151				38,497
Long-term receivables, net of allowance for doubtful accounts of $11,981 and $7,643, respectively			51,419				60,915
Other			31,490				28,574
Total assets		$	3,420,969			$	3,633,195
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable		$	15,808			$	10,017
Accrued liabilities:
Lease operating expense			24,796				19,108
Development capital			56,144				79,435
Interest			16,059				11,808
Production, ad valorem, and severance taxes			28,392				25,133
Compensation			19,865				16,216
Derivatives			23,214				63,476
Oil and natural gas revenues payable			11,373				10,821
Deferred taxes			76,862				105,768
Other			17,411				10,470
Total current liabilities			289,924				352,252
Derivatives			47,861				8,922
Future abandonment cost, net of current portion			47,985				48,058
Deferred taxes			408,514				416,915
Long-term debt			1,172,912				1,319,811
Other			3,647				3,989
Total liabilities			1,970,843				2,149,947
Commitments and contingencies (see Note 14)
Equity:
Preferred stock, $.01 par value, 5,000,000 shares authorized, none issued and outstanding			—				—
Common stock, $.01 par value, 144,000,000 shares authorized, 51,870,080 and 51,551,937 issued and outstanding, respectively			519				516
Additional paid-in capital			542,278				525,763
Treasury stock, at cost, 466 and 4,753 shares, respectively			(16	)			(101	)
Retained earnings			733,309				789,698
Accumulated other comprehensive loss			(1,434	)			(1,748	)
Total EAC stockholders’ equity			1,274,656				1,314,128
Noncontrolling interest			175,470				169,120
Total equity			1,450,126				1,483,248
Total liabilities and equity		$	3,420,969			$	3,633,195

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

ENCORE ACQUISITION COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per share amounts)
(unaudited)

		Three months ended								Six months ended
		June 30,								June 30,
		2009				2008				2009				2008
Revenues:
Oil		$	133,677			$	286,924			$	221,966			$	507,458
Natural gas			29,486				67,889				54,740				116,201
Marketing			315				2,521				1,121				6,577
Total revenues			163,478				357,334				277,827				630,236
Expenses:
Production:
Lease operating			40,451				40,697				84,676				81,047
Production, ad valorem, and severance taxes			17,033				35,043				28,852				62,495
Depletion, depreciation, and amortization			74,434				51,026				144,734				100,569
Exploration			15,934				11,593				27,133				17,081
General and administrative			13,779				11,559				27,473				21,246
Marketing			515				3,725				1,254				7,507
Derivative fair value loss			61,106				256,390				12,515				321,528
Other operating			14,835				3,226				21,178				5,732
Total expenses			238,087				413,259				347,815				617,205
Operating income (loss)			(74,609	)			(55,925	)			(69,988	)			13,031
Other income (expenses):
Interest			(19,126	)			(16,785	)			(35,089	)			(36,545	)
Other			657				686				1,211				1,537
Total other expenses			(18,469	)			(16,099	)			(33,878	)			(35,008	)
Loss before income taxes			(93,078	)			(72,024	)			(103,866	)			(21,977	)
Income tax benefit			31,558				21,322				36,443				2,589
Consolidated net loss			(61,520	)			(50,702	)			(67,423	)			(19,388	)
Less: net loss attributable to noncontrolling interest			14,545				14,982				12,892				14,888
Net loss attributable to EAC		$	(46,975	)		$	(35,720	)		$	(54,531	)		$	(4,500	)
Net loss per common share:
Basic		$	(0.91	)		$	(0.68	)		$	(1.05	)		$	(0.09	)
Diluted		$	(0.91	)		$	(0.68	)		$	(1.05	)		$	(0.09	)
Weighted average common shares outstanding:
Basic			51,849				52,344				51,769				52,571
Diluted			51,849				52,344				51,769				52,571

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

ENCORE ACQUISITION COMPANY
CONSOLIDATED STATEMENT OF EQUITY AND COMPREHENSIVE LOSS
(in thousands)
(unaudited)

		EAC Stockholders
		Issued																								Accumulated
		Shares of								Additional				Shares of												Other
		Common				Common				Paid-in				Treasury				Treasury				Retained				Comprehensive				Noncontrolling				Total
		Stock				Stock				Capital				Stock				Stock				Earnings				Loss				Interest				Equity
Balance at December 31, 2008			51,557			$	516			$	525,763				(5	)		$	(101	)		$	789,698			$	(1,748	)		$	169,120			$	1,483,248
Exercise of stock options and vesting of restricted stock			429				3				415				—				—				—				—				—				418
Purchase of treasury stock			—				—				—				(111	)			(2,961	)			—				—				—				(2,961	)
Cancellation of treasury stock			(116	)			—				(1,188	)			116				3,046				(1,858	)			—				—				—
Non-cash equity-based compensation			—				—				7,859				—				—				—				—				69				7,928
ENP cash distributions to noncontrolling interest			—				—				—				—				—				—				—				(12,153	)			(12,153	)
ENP issuance of common units			—				—				—				—				—				—				—				40,520				40,520
Adjustment to reflect gain on ENP issuance of common units			—				—				9,312				—				—				—				—				(9,312	)			—
Other			—				—				117				—				—				—				—				—				117
Components of comprehensive loss:
Consolidated net loss			—				—				—				—				—				(54,531	)			—				(12,892	)			(67,423	)
Change in deferred hedge loss on interest rate swaps, net of tax of $219			—				—				—				—				—				—				314				118				432
Total comprehensive loss																																			(66,991	)
Balance at June 30, 2009			51,870			$	519			$	542,278				—			$	(16	)		$	733,309			$	(1,434	)		$	175,470			$	1,450,126

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

ENCORE ACQUISITION COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
(unaudited)

		Six months ended
		June 30,
		2009				2008
Cash flows from operating activities:
Consolidated net loss		$	(67,423	)		$	(19,388	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depletion, depreciation, and amortization			144,734				100,569
Non-cash exploration expense			26,264				15,545
Deferred taxes			(37,514	)			(26,756	)
Non-cash equity-based compensation expense			6,863				6,205
Non-cash derivative loss			98,325				300,370
Gain on disposition of assets			(43	)			(79	)
Other			14,039				6,619
Changes in operating assets and liabilities:
Accounts receivable			39,030				(47,301	)
Current derivatives			257,137				(670	)
Other current assets			16,142				(9,680	)
Long-term derivatives			—				(1,196	)
Other assets			5,835				(1,033	)
Accounts payable			10,719				4,208
Other current liabilities			30,702				25,825
Other noncurrent liabilities			(663	)			(923	)
Net cash provided by operating activities			544,147				352,315
Cash flows from investing activities:
Proceeds from disposition of assets			514				631
Purchases of other property and equipment			(772	)			(1,622	)
Acquisition of oil and natural gas properties			(39,990	)			(49,280	)
Divestiture of oil and natural gas properties			(220	)			—
Deposit on acquisition of oil and natural gas properties			(37,500	)			—
Development of oil and natural gas properties			(235,101	)			(233,225	)
Net collections from (advances to) working interest partners			3,709				(22,907	)
Net cash used in investing activities			(309,360	)			(306,403	)
Cash flows from financing activities:
Repurchase and retirement of common stock			—				(39,118	)
Exercise of stock options and vesting of restricted stock, net of treasury stock purchases			(2,543	)			374
Proceeds from long-term debt, net of issuance costs			320,450				618,339
Payments on long-term debt			(473,000	)			(598,500	)
ENP cash distributions to noncontrolling interest			(12,153	)			(11,168	)
Proceeds from ENP issuance of common units, net of offering costs			40,724				—
Payments of deferred commodity derivative contract premiums			(69,536	)			(20,583	)
Change in cash overdrafts			(4,928	)			4,634
Net cash used in financing activities			(200,986	)			(46,022	)
Increase (decrease) in cash and cash equivalents			33,801				(110	)
Cash and cash equivalents, beginning of period			2,039				1,704
Cash and cash equivalents, end of period		$	35,840			$	1,594

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

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)

Note 1. Description of Business

     EAC is engaged in the acquisition and development of oil and natural gas reserves from onshore fields in the United States. Since 1998, EAC has acquired producing properties with proven reserves and leasehold acreage and grown the production and proven reserves by drilling, exploring, and reengineering or expanding existing waterflood projects. EAC’s properties and oil and natural gas reserves are located in four core areas:

	•		the Cedar Creek Anticline (“CCA”) in the Williston Basin in Montana and North Dakota;
	•		the Permian Basin in West Texas and southeastern New Mexico;
	•		the Rockies, which includes non-CCA assets in the Williston, Big Horn, and Powder River Basins in Wyoming, Montana, and North Dakota, and the Paradox Basin in southeastern Utah; and
	•		the Mid-Continent area, which includes the Arkoma and Anadarko Basins in Arkansas and Oklahoma, the North Louisiana Salt Basin, and the East Texas Basin.

Note 2. Basis of Presentation

     EAC’s consolidated financial statements include the accounts of its wholly owned and majority-owned subsidiaries. All material intercompany balances and transactions have been eliminated in consolidation.

     In the opinion of management, the accompanying unaudited consolidated financial statements include all adjustments necessary to present fairly, in all material respects, EAC’s financial position as of June 30, 2009, results of operations for the three and six months ended June 30, 2009 and 2008, and cash flows for the six months ended June 30, 2009 and 2008. All adjustments are of a normal recurring nature. These interim results are not necessarily indicative of results for an entire year.

     Certain amounts and disclosures have been condensed or omitted from these consolidated financial statements pursuant to the rules and regulations of the SEC. Therefore, these consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in EAC’s 2008 Annual Report on Form 10-K.

Noncontrolling Interest

     As of June 30, 2009 and December 31, 2008, EAC owned approximately 58 percent and 63 percent, respectively, of ENP’s common units, as well as all of the interests of Encore Energy Partners GP LLC (“GP LLC”), a Delaware limited liability company and indirect wholly owned non-guarantor subsidiary of EAC. GP LLC is ENP’s general partner. Considering the presumption of control of GP LLC in accordance with Emerging Issues Task Force (“EITF”) Issue No. 04-5, “Determining Whether a General Partner, or the General Partners as a Group, Controls a Limited Partnership or Similar Entity When the Limited Partners Have Certain Rights,” the financial position, results of operations, and cash flows of ENP are consolidated with those of EAC.

     As presented in the accompanying Consolidated Balance Sheets, “Noncontrolling interest” as of June 30, 2009 and December 31, 2008 of $175.5 million and $169.1 million, respectively, represents third-party ownership interests in ENP. As presented in the accompanying Consolidated Statements of Operations, “Net loss attributable to noncontrolling interest” for the three and six months ended June 30, 2009 of $14.5 million and $12.9 million, respectively, and for the three and six months ended June 30, 2008 of $15.0 million and $14.9 million, respectively, represents the net loss of ENP attributable to third-party owners.

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

     The following table summarizes the effects of changes in EAC’s ownership interest in ENP on EAC’s equity for the periods indicated:

		Three months ended								Six months ended
		June 30,								June 30,
		2009				2008				2009				2008
		(in thousands)
Net loss attributable to EAC		$	(46,975	)		$	(35,720	)		$	(54,531	)		$	(4,500	)
Transfer from (to) noncontrolling interest:
Increase in EAC’s paid-in capital for ENP’s issuance of 283,700 common units in connection with acquisition of net profits interest in certain Crockett County properties			—				3,458				—				3,458
Increase in EAC’s paid-in capital for ENP’s issuance of 2,760,000 common units in public offering			9,312				—				9,312				—
Net transfer from (to) noncontrolling interest			9,312				3,458				9,312				3,458
Change from net loss attributable to EAC and transfers from (to) noncontrolling interest		$	(37,663	)		$	(32,262	)		$	(45,219	)		$	(1,042	)

Supplemental Disclosures of Cash Flow Information

     The following table sets forth supplemental disclosures of cash flow information for the periods indicated:

		Six months ended June 30,
		2009				2008
		(in thousands)
Non-cash investing and financing activities:
Deferred premiums on commodity derivative contracts		$	40,087			$	25,685
ENP’s issuance of common units in connection with acquisition of net profits interest in certain Crockett County properties			—				5,748

Allowance for Doubtful Accounts

     During the three months ended June 30, 2009, EAC recorded bad debt expense of approximately $4.7 million, primarily related to balances due from ExxonMobil Corporation (“ExxonMobil”) in connection with EAC’s joint development agreement, which is included in “Other operating expense” in the accompanying Consolidated Statements of Operations. The following table summarizes the changes in allowance for doubtful accounts for the six months ended June 30, 2009 (in thousands):

Allowance for doubtful accounts at January 1, 2009		$	8,024
Bad debt expense			4,678
Write off			(287	)
Allowance for doubtful accounts at June 30, 2009		$	12,415

     Of the $12.4 million allowance for doubtful accounts at June 30, 2009, $0.4 million is short-term and $12.0 million is long-term.

Reclassifications

     Certain amounts in prior periods have been reclassified to conform to the current period presentation. In particular, certain amounts in the Consolidated Financial Statements have been either combined or classified in more detail.

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

New Accounting Pronouncements

FASB Staff Position (“FSP”) No. FAS 157-2, “Effective Date of FASB Statement No. 157” (“FSP FAS 157-2”)

     In February 2008, the FASB issued FSP FAS 157-2, which delayed the effective date of SFAS No. 157, “Fair Value Measurements” (“SFAS 157”) for one year for nonfinancial assets and liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). EAC elected a partial deferral of SFAS 157 for all instruments within the scope of FSP FAS 157-2, including, but not limited to, its asset retirement obligations and indefinite lived assets. FSP FAS 157-2 was prospectively effective for financial statements issued for fiscal years beginning after November 15, 2008, and interim periods within those fiscal years. The adoption of FSP FAS 157-2 on January 1, 2009 did not have a material impact on EAC’s results of operations or financial condition. Please read “Note 5. Fair Value Measurements” for additional discussion.

SFAS No. 141 (revised 2007), “Business Combinations” (“SFAS 141R”)

     In December 2007, the FASB issued SFAS 141R, which replaces SFAS No. 141, “Business Combinations.” SFAS 141R establishes principles and requirements for the reporting entity in a business combination, including: (1) recognition and measurement in the financial statements of the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree; (2) recognition and measurement of goodwill acquired in the business combination or a gain from a bargain purchase; and (3) determination of the information to be disclosed to enable financial statement users to evaluate the nature and financial effects of the business combination. In April 2009, the FASB issued FSP No. FAS 141(R)-1, “Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arises from Contingencies” (“FSP FAS 141R-1”), which amends and clarifies SFAS 141R to address application issues, including: (1) initial recognition and measurement; (2) subsequent measurement and accounting; and (3) disclosure of assets and liabilities arising from contingencies in a business combination. SFAS 141R and FSP FAS 141R-1 were prospectively effective for business combinations consummated in fiscal years beginning on or after December 15, 2008. The adoption of SFAS 141R and FSP FAS 141R-1 on January 1, 2009 did not have a material impact on EAC’s results of operations or financial condition. However, the application of SFAS 141R and FSP FAS 141R-1 to future acquisitions could impact EAC’s results of operations and financial condition and the reporting of acquisitions in the consolidated financial statements.

SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements — an amendment to ARB No. 51” (“SFAS 160”)

     In December 2007, the FASB issued SFAS 160, which amends Accounting Research Bulletin No. 51, “Consolidated Financial Statements” to establish accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. SFAS 160 was prospectively effective for fiscal years beginning on or after December 15, 2008, except for the presentation and disclosure requirements which were retrospectively effective. SFAS 160 clarifies that a noncontrolling interest in a subsidiary, which was often referred to as minority interest, is an ownership interest in the consolidated entity that should be reported as a component of equity in the consolidated financial statements. Among other requirements, SFAS 160 requires consolidated net income to be reported for the amounts attributable to both the parent and the noncontrolling interest on the face of the consolidated statement of operations and gains on a subsidiaries’ issuance of equity to be accounted for as capital transactions. The adoption of SFAS 160 on January 1, 2009 did not have a material impact on EAC’s results of operations or financial condition.

SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities — an amendment of FASB Statement No. 133” (“SFAS 161”)

     In March 2008, the FASB issued SFAS 161, which amends SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS 133”), to require enhanced disclosures, including: (1) how and why an entity uses derivative instruments; (2) how derivative instruments and related hedged items are accounted for under SFAS 133 and its related interpretations; and (3) how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. SFAS 161 was prospectively effective for financial statements issued for fiscal years beginning on or after November 15, 2008, and interim periods within those fiscal years. The adoption of SFAS 161 on January 1, 2009 required additional disclosures regarding EAC’s derivative instruments; however, it did not impact EAC’s results of operations or financial condition. Please read “Note 5. Fair Value Measurements” for additional discussion.

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

FSP No. EITF 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities” (“FSP EITF 03-6-1”)

     In June 2008, the FASB issued FSP EITF 03-6-1, which addresses whether instruments granted in equity-based payment transactions are participating securities prior to vesting and, therefore, need to be included in the earnings allocation for computing basic earnings per share (“EPS”) under the two-class method prescribed by SFAS No. 128, “Earnings per Share” (“SFAS 128”). FSP EITF 03-6-1 was retroactively effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years. The adoption of FSP EITF 03-6-1 on January 1, 2009 did not have a material impact on EAC’s results of operations or financial condition. All periods presented in the accompanying Consolidated Financial Statements have been restated to reflect the adoption of FSP EITF 03-6-1. Please read “Note 10. Earnings Per Share” for additional discussion.

SEC Release No. 33-8995, “Modernization of Oil and Gas Reporting” (“Release 33-8995”)

     In December 2008, the SEC issued Release 33-8995, which amends oil and natural gas reporting requirements under Regulations S-K and S-X. Release 33-8995 also adds a section to Regulation S-K (Subpart 1200) to codify the revised disclosure requirements in Securities Act Industry Guide 2, which is being phased out. Release 33-8995 permits the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes. Release 33-8995 will also allow companies to disclose their probable and possible reserves to investors at the company’s option. In addition, the new disclosure requirements require companies to: (1) report the independence and qualifications of its reserves preparer or auditor; (2) file reports when a third party is relied upon to prepare reserves estimates or conduct a reserves audit; and (3) report oil and gas reserves using an average price based upon the prior 12-month period rather than a year-end price, unless prices are defined by contractual arrangements, excluding escalations based on future conditions. Release 33-8995 is prospectively effective for financial statements issued for fiscal years ending on or after December 31, 2009. EAC is evaluating the impact Release 33-8995 will have on its financial condition, results of operations, and disclosures.

FSP No. FAS 107-1 and APB 28-1, “Disclosure of Fair Value of Financial Instruments in Interim Statements” (“FSP FAS 107-1 and APB 28-1”)

     In April 2009, the FASB issued FSP FAS 107-1 and APB 28-1, which requires that disclosures concerning the fair value of financial instruments be presented in interim as well as annual financial statements. FSP FAS 107-1 and APB 28-1 is prospectively effective for financial statements issued for interim periods ending after June 15, 2009. The adoption of FSP FAS 107-1 and APB 28-1 required additional disclosures regarding EAC’s financial instruments; however, it did not impact EAC’s results of operations or financial condition. Please read “Note 5. Fair Value Measurements” for additional discussion.

SFAS No. 165, “Subsequent Events” (“SFAS 165”)

     In June 2009, the FASB issued SFAS 165 to establish general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or available to be issued. In particular, SFAS 165 sets forth: (1) the period after the balance sheet date during which management of a reporting entity should evaluate events or transactions that may occur for potential recognition or disclosure in the financial statements; (2) the circumstances under which an entity should recognize events or transactions occurring after the balance sheet date in its financial statements; and (3) the disclosures that an entity should make about events or transactions that occurred after the balance sheet date. SFAS 165 is prospectively effective for financial statements issued for interim or annual periods ending after June 15, 2009. The adoption of SFAS 165 on June 30, 2009 did not impact EAC’s results of operations or financial condition.

SFAS No. 168, “The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles” (“SFAS 168”)

     In June 2009, the FASB issued SFAS 168, which replaces SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles.” SFAS 168 establishes the FASB Accounting Standards Codification as the sole source of authoritative accounting principles recognized by the FASB to be applied by all nongovernmental entities in the preparation of financial statements in conformity with GAAP. SFAS 168 is prospectively effective for financial statements for fiscal years ending on or after September 15, 2009, and interim periods within those fiscal years. The adoption of SFAS 168 on July 1, 2009 did not impact EAC’s results of operations or financial condition.

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

Note 3. Inventory

     Inventory includes materials and supplies and oil in pipelines, which are stated at the lower of cost (determined on an average basis) or market. Oil produced at the lease which resides unsold in pipelines is carried at an amount equal to its operating costs to produce. Oil in pipelines purchased from third parties is carried at average purchase price. Inventory consisted of the following as of the dates indicated:

		June 30,				December 31,
		2009				2008
		(in thousands)
Materials and supplies		$	19,766			$	15,933
Oil in pipelines			7,500				8,865
Total inventory		$	27,266			$	24,798

     During the three months ended June 30, 2009, EAC recorded a lower of cost or market adjustment of approximately $5.7 million to the carrying value of pipe and other tubular inventory whose market value had declined below cost, which is included in “Other operating expense” in the accompanying Consolidated Statements of Operations.

Note 4. Proved Properties

     Amounts shown in the accompanying Consolidated Balance Sheets as “Proved properties, including wells and related equipment” consisted of the following as of the dates indicated:

		June 30,				December 31,
		2009				2008
		(in thousands)
Proved leasehold costs		$	1,448,959			$	1,421,859
Wells and related equipment — Completed			2,252,196				1,943,275
Wells and related equipment — In process			42,662				173,325
Total proved properties		$	3,743,817			$	3,538,459

Note 5. Fair Value Measurements

     The following table sets forth EAC’s book value and estimated fair value of financial instruments as of the dates indicated:

		June 30, 2009								December 31, 2008
		Book				Fair				Book				Fair
		Value				Value				Value				Value
		(in thousands)
Assets:
Cash and cash equivalents		$	35,840			$	35,840			$	2,039			$	2,039
Accounts receivable, net			96,591				96,591				117,995				117,995
Plugging bond			849				1,003				824				1,202
Bell Creek escrow			9,257				9,258				9,229				9,241
Commodity derivative contracts			101,355				101,355				387,841				387,841
Long-term receivables, net			64,679				64,679				71,986				71,986
Liabilities:
Accounts payable			15,808				15,808				10,017				10,017
6.25% Senior Subordinated Notes			150,000				126,000				150,000				101,250
6.0% Senior Subordinated Notes			296,292				249,000				296,040				194,250
9.5% Senior Subordinated Notes			207,799				222,188				—				—
7.25% Senior Subordinated Notes			148,821				127,500				148,771				94,500
Revolving credit facilities			370,000				370,000				725,000				725,000
Commodity derivative contracts			28,323				28,323				229				229
Deferred premiums on commodity derivative contracts			38,927				38,927				67,610				67,610
Interest rate swaps			3,825				3,825				4,559				4,559

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

     The book values of cash and cash equivalents, accounts receivable, net, and accounts payable approximate fair value due to the short-term nature of these instruments. The book value of long-term receivables, net, approximates fair value as it is net of amounts deemed to be uncollectible and bears interest at market rates. The plugging bond and Bell Creek escrow are included in “Other assets” on the accompanying Consolidated Balance Sheets and are classified as “held to maturity” and therefore, are recorded at amortized cost, which was less than fair value. The fair values of the plugging bond and Bell Creek escrow were determined using open market quotes. The fair values of the senior subordinated notes were determined using open market quotes. The difference between book value and fair value represents the premium or discount on that date. The book value of the revolving credit facilities approximates fair value as the interest rate is variable. Commodity derivative contracts and interest rate swaps are marked-to-market each quarter. Deferred premiums on commodity derivative contracts were recorded at their net present value at the time the contracts were entered into and EAC accretes that value to the eventual settlement price by recording interest expense each period.

Derivative Policy

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

     EAC applies the provisions of SFAS 133, which requires each derivative instrument to be recorded in the balance sheet at fair value. If a derivative has not been designated as a hedge or does not otherwise qualify for hedge accounting, it must be adjusted to fair value through earnings. However, if a derivative qualifies for hedge accounting, depending on the nature of the hedge, changes in fair value can be recognized in accumulated other comprehensive loss until such time as the hedged item is recognized in earnings.

     In order 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 effective portion of cash flow hedges are marked to market through accumulated other comprehensive loss each period.

     EAC has elected to designate its current interest rate swaps as cash flow hedges. The effective portion of the mark-to-market gain or loss on these derivative instruments is recorded in “Accumulated other comprehensive loss” on the accompanying Consolidated Balance Sheets and reclassified into earnings in the same period in which the hedged transaction affects earnings. Any ineffective portion of the mark-to-market gain or loss is recognized in earnings as “Derivative fair value loss” in the accompanying Consolidated Statements of Operations.

     EAC has not elected to designate its current portfolio of commodity derivative contracts as hedges. Therefore, changes in fair value of these derivative instruments are recognized in earnings as “Derivative fair value loss” in the accompanying Consolidated Statements of Operations.

Commodity Derivative Contracts

     EAC manages commodity price risk with swap contracts, put contracts, collars, and floor spreads. 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. Collars 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.

     From time to time, EAC enters into floor spreads. In a floor spread, EAC purchases puts at a specified price (a “purchased put”) and also sells a put at a lower price (a “short put”). This strategy enables EAC to achieve downside protection for a portion of its production, while funding the cost of such protection by selling a put at a lower price. If the price of the commodity falls below the strike price of the purchased put, then EAC has protection against commodity price decreases for the covered production down to the strike price of the short put. At commodity prices below the strike price of the short put, the benefit from the purchased put is generally offset by the expense associated with the short put. For example, in 2007, EAC purchased oil put options for 2,000 Bbls/D in 2010 at $65 per Bbl. As NYMEX prices increased in 2008, EAC wished to protect downside price exposure at the higher price. In order to do this, EAC purchased oil put options for 2,000 Bbls/D in 2010 at $75 per Bbl and simultaneously sold oil put options for

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

2,000 Bbls/D in 2010 at $65 per Bbl. Thus, after these transactions were completed, EAC had purchased two oil put options for 2,000 Bbls/D in 2010 (one at $65 per Bbl and one at $75 per Bbl) and sold one oil put option for 2,000 Bbls/D in 2010 at $65 per Bbl. However, the net effect resulted in EAC owning one oil put option for 2,000 Bbls/D at $75 per Bbl. In the following tables, the purchased floor component of these floor spreads are shown net and included with EAC’s other floor contracts.

     The following tables summarize EAC’s open commodity derivative contracts as of June 30, 2009:

Oil Derivative Contracts

		Average				Weighted					Average				Weighted					Average				Weighted					Asset
		Daily				Average					Daily				Average					Daily				Average					(Liability)
		Floor				Floor					Cap				Cap					Swap				Swap					Fair Market
Period		Volume				Price					Volume				Price					Volume				Price					Value
		(Bbls)				(per Bbl)					(Bbls)				(per Bbl)					(Bbls)				(per Bbl)					(in thousands)
July — Dec. 2009 (a)																													$	21,227
			3,130			$	110.00					440			$	97.75					—			$	—
			—				—					—				—					1,000				68.70
2010																														(172	)
			880				80.00					440				93.80					—				—
			2,000				75.00					3,000				74.13					1,385				75.78
			8,385				62.83					500				65.60					1,750				64.08
			1,000				56.00					—				—					1,000				59.70
2011																														23,343
			1,880				80.00					1,440				95.41					325				80.00
			2,500				70.00					—				—					1,060				78.42
			4,385				65.00					—				—					250				69.65
2012																														2,918
			750				70.00					500				82.05					835				81.19
			2,135				65.00					250				79.25					1,300				76.54
																													$	47,316

Natural Gas Derivative Contracts

		Average				Weighted					Average				Weighted					Average				Weighted					Asset
		Daily				Average					Daily				Average					Daily				Average					(Liability)
		Floor				Floor					Cap				Cap					Swap				Swap					Fair Market
Period		Volume				Price					Volume				Price					Volume				Price					Value
		(Mcf)				(per Mcf)					(Mcf)				(per Mcf)					(Mcf)				(per Mcf)					(in thousands)
July — Dec. 2009																													$	12,715
			3,800			$	8.20					3,800			$	9.83					—			$	—
			3,800				7.20					5,000				7.45					—				—
			6,800				6.57					15,000				6.63					—				—
			15,000				5.64					—				—					—				—
2010																														14,169
			3,800				8.20					3,800				9.58					25,452				6.46
			4,698				7.26					—				—					550				5.86
2011																														993
			3,398				6.31					—				—					27,952				6.48
			—				—					—				—					550				5.86
2012																														(2,161	)
			898				6.76					—				—					25,452				6.47
			—				—					—				—					550				5.86
																													$	25,716

     As of June 30, 2009, EAC had $38.9 million of deferred premiums payable, of which $29.0 million was long-term and included in “Derivatives” in the non-current liabilities section of the accompanying Consolidated Balance Sheet and $9.9 million was current and included in “Derivatives” in the current liabilities section of the accompanying Consolidated Balance Sheet. The premiums relate to various oil and natural gas floor contracts and are payable on a monthly basis from July 2009 to January 2013.

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

     Counterparty Risk. At June 30, 2009, EAC had committed greater than 10 percent (in terms of fair market value) of either its oil or natural gas derivative contracts to the following counterparties:

		Percentage of				Percentage of
		Oil Derivative				Natural Gas Derivative
		Contracts				Contracts
Counterparty		Committed				Committed
BNP Paribas			42	%			24	%
Calyon			19	%			39	%
JP Morgan			11	%			14	%
Wachovia Bank			12	%			22	%

     In order to mitigate the credit risk of financial instruments, EAC enters into master netting agreements with significant counterparties. The master netting agreement is a standardized, bilateral contract between a given counterparty and EAC. Instead of treating each derivative financial transaction between the counterparty and EAC separately, the master netting agreement enables the counterparty and EAC to aggregate all financial trades and treat them as a single agreement. This arrangement benefits EAC in three ways: (1) the netting of the value of all trades reduces the likelihood of counterparties requiring daily collateral posting by EAC; (2) default by a counterparty under one financial trade can trigger rights to terminate all financial trades with such counterparty; and (3) netting of settlement amounts reduces EAC’s credit exposure to a given counterparty in the event of close-out. EAC’s accounting policy is to not offset fair value amounts recorded in the accompanying Consolidated Balance Sheets for derivative instruments.

Interest Rate Swaps

     ENP uses derivative instruments in the form of interest rate swaps, which hedge risk related to interest rate fluctuation, whereby it converts the interest due on certain floating rate debt under its revolving credit facility to a weighted average fixed rate. The following table summarizes ENP’s open interest rate swaps as of June 30, 2009, all of which were entered into with Bank of America, N.A.:

		Notional				Fixed				Floating
Term		Amount				Rate				Rate
		(in thousands)
July 2009 - Jan. 2011		$	50,000				3.1610	%		1-month LIBOR
July 2009 - Jan. 2011			25,000				2.9650	%		1-month LIBOR
July 2009 - Jan. 2011			25,000				2.9613	%		1-month LIBOR
July 2009 - Mar. 2012			50,000				2.4200	%		1-month LIBOR

     The actual gains or losses ENP will realize from its interest rate swaps may vary significantly from the deferred loss recorded in accumulated other comprehensive loss due to the fluctuation of interest rates.

Current Period Impact

     EAC recognized derivative fair value gains and losses related to: (1) ineffectiveness on derivative contracts designated as hedges; (2) changes in the fair market value of derivative contracts not designated as hedges; (3) settlements on derivative contracts not designated as hedges; and (4) premium amortization. The following table summarizes the components of “Derivative fair value loss” for the periods indicated:

		Three months ended								Six months ended
		June 30,								June 30,
		2009				2008				2009				2008
		(in thousands)
Ineffectiveness		$	6			$	39			$	(34	)		$	(343	)
Mark-to-market loss			78,082				219,433				280,993				265,048
Premium amortization			6,764				17,293				84,719				32,806
Settlements			(23,746	)			19,625				(353,163	)			24,017
Total derivative fair value loss		$	61,106			$	256,390			$	12,515			$	321,528

ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

     In March 2009, EAC elected to monetize certain of its 2009 oil derivative contracts and received proceeds of approximately $190.4 million from these settlements, which were used to reduce outstanding borrowings under EAC’s revolving credit facility.

Accumulated Other Comprehensive Loss

     At June 30, 2009 and December 31, 2008, accumulated other comprehensive loss consisted entirely of deferred losses, net of tax, on ENP’s interest rate swaps of $1.4 million and $1.7 million, respectively. During the twelve months ending June 30, 2010, EAC expects to reclassify $3.3 million of deferred losses associated with ENP’s interest rate swaps from accumulated other comprehensive loss to interest expense.

Tabular Disclosures of Fair Value Measurements

     The following table summarizes the fair value of EAC’s derivative contracts as of the dates indicated (in thousands):

		Asset Derivatives																	Liability Derivatives
		June 30, 2009								December 31, 2008									June 30, 2009								December 31, 2008
		Balance Sheet				Fair				Balance Sheet				Fair					Balance Sheet								Balance Sheet
		Location				Value				Location				Value					Location				Fair Value				Location				Fair Value
Derivatives not designated as hedging instruments under SFAS 133
Commodity derivative contracts		Derivatives - current				$	53,204			Derivatives - current				$	349,344				Derivatives - current				$	10,037			Derivatives - current				$	—
Commodity derivative contracts		Derivatives - noncurrent					48,151			Derivatives - noncurrent					38,497				Derivatives - noncurrent					18,286			Derivatives - noncurrent					229
Total derivatives not designated as hedging instruments under SFAS 133						$	101,355							$	387,841								$	28,323							$	229
							`
Derivatives designated as hedging instruments under SFAS 133
Interest rate swaps		Derivatives - current				$	—			Derivatives - current				$	—				Derivatives - current				$	3,272			Derivatives - current				$	1,297
Interest rate swaps		Derivatives - noncurrent					—			Derivatives - noncurrent					—				Derivatives - noncurrent					553			Derivatives - noncurrent					3,262
Total derivatives designated as hedging instruments under SFAS 133						$	—							$	—								$	3,825							$	4,559
Total derivatives						$	101,355							$	387,841								$	32,148							$	4,788