exhibit99-2.htm

Exhibit 99.2

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

ENCORE ENERGY PARTNERS LP

CONSOLIDATED BALANCE SHEETS

(in thousands, except unit amounts)

	September 30, 2010			December 31, 2009
ASSETS
Current assets:
Cash and cash equivalents	$	10,283		$	1,754
Accounts receivable:
Trade		16,753			24,543
Affiliate		2,628			8,213
Derivatives		15,078			12,881
Other		697			857
Total current assets		45,439			48,248
Properties and equipment, at cost— successful efforts method:
Proved properties, including wells and related equipment		856,182			851,833
Unproved properties		19			55
Accumulated depletion, depreciation, and amortization		(247,750	)		(210,417	)
		608,451			641,471
Other property and equipment		991			863
Accumulated depreciation		(575	)		(419	)
		416			444
Goodwill		9,290			9,290
Other intangibles, net		3,088			3,316
Derivatives		10,023			13,423
Other		2,207			3,459
Total assets	$	678,914		$	719,651
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities:
Accounts payable:
Trade	$	418		$	577
Affiliate		2,356			2,780
Accrued liabilities:
Lease operating		6,363			4,157
Development capital		1,576			1,484
Interest		312			429
Production, ad valorem, and severance taxes		10,988			10,218
Derivatives		5,643			9,815
Oil and natural gas revenues payable		1,611			1,598
Other		1,691			1,632
Total current liabilities		30,958			32,690
Derivatives		9,929			13,401
Future abandonment cost, net of current portion		12,950			12,556
Long-term debt		39			—
Other		240,000			255,000
Total liabilities		293,876			313,647
Commitments and contingencies (see Note4)
Partners’ equity:
Limited partners— 45,285,347 and 33,077,610 common units issued and outstanding, respectively		386,752			409,777
General partner— 504,851 general partner units issued and outstanding		317			(353
Accumulated other comprehensive loss		(2,031	)		(3,420	)
Total partners’ equity		385,038			406,004
Total liabilities and partners’ equity	$	678,914		$	719,651

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

ENCORE ENERGY PARTNERS LP

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per unit amounts)

(unaudited)


	Three months ended September 30,						Nine months ended September 30,
Revenues:	2010			2009			2010			2009
Oil	$	36,286		$	35,494		$	114,733		$	88,952
Natural gas		6,497			5,436			21,407			14,624
Marketing		60			102			207			381
Total revenues		42,843			41,032			136,347			103,957
Expenses:
Production:
Lease operating		9,607			9,717			31,701			32,614
Production taxes and marketing		4,413			4,523			14,157			11,865
Depletion, depreciation, and amortization		12,782			14,640			38,472			44,226
Exploration		53			3,034			129			3,074
General and administrative		2,817			3,557			10,088			9,800
Derivative fair value loss (gain)		7,609			(4,822	)		(14,347	)		21,711
Total expenses		37,281			30,649			80,200			123,290
Operating income (loss)		5,562			10,383			56,147			(19,333	)
Other income (expenses):
Interest		(3,277	)		(2,984	)		(9,912	)		(7,551	)
Other		9			23			47			34
Total other expenses		(3,268	)		(2,961	)		(9,865	)		(7,517	)
Income (loss) before income taxes		2,294			7,422			46,282			(26,850	)
Income tax benefit (provision)		147			38			36			(163	)
Net income (loss)	$	2,441		$	7,460		$	46,318			(27,013	)
Net income (loss) allocation (see Note 8):
Limited partners’ interest in net income (loss)	$	2,419		$	5,904		$	45,813		$	(26,745	)
General partner’s interest in net income (loss)	$	22		$	63		$	505		$	(444	)
Net income (loss) per common unit:
Basic	$	0.05		$	0.13		$	1.01		$	(0.72	)
Diluted	$	0.05		$	0.13		$	1.01		$	(0.72	)
Weighted average common units outstanding:
Basic		45,342			44,653			45,328			37,373
Diluted		45,342			44,675			45,336			37,373
Cash distributions declared per common unit	$	0.5000		$	0.5125		$	1.5375		$	1.5125

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

ENCORE ENERGY PARTNERS LP

CONSOLIDATED STATEMENTS OF PARTNERS’ EQUITY AND

COMPREHENSIVE INCOME

(in thousands, except per unit amounts)

(unaudited)

											Accumulated Other			Total
	Limited Partner					General Partner					Comprehensive			Partners’
	Units		Amount			Units		Amount			Loss			Equity
Balance at December 31, 2009		45,285	$	409,777			505	$	(353	)	$	(3,420	)	$	406,004
Owner contributions		—		(4	)		—		935			—			931
Non-cash equity-based compensation		—		1,035			—		8			—			1,043
Vesting of phantom units		57		—			—		—			—			—
Other		—		(186	)		—		(2	)		—			(188	)
Cash distributions to unitholders ($1.5375 per unit)		—		(69,683	)		—		(776	)		—			(70,459	)
Components of comprehensive income:
Net income attributable to unitholders		—		45,813			—		505			—			46,318
Change in deferred hedge loss on interest rate swaps, net of tax of $6		—		—			—		—			1,389			1,389
Total comprehensive income															47,707
Balance at September 30, 2010		45,342	$	386,752			505	$	317		$	(2,031	)	$	385,038

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

ENCORE ENERGY PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Note 1. Description of Business

ENP is engaged in the acquisition, exploitation, and development of oil and natural gas reserves from onshore fields in the United States. Encore Energy Partners GP LLC (the “General Partner”), a Delaware limited liability company and indirect wholly owned subsidiary of Denbury, serves as ENP’s general partner and Encore Energy Partners Operating LLC (“OLLC”), a Delaware limited liability company and wholly owned subsidiary of ENP, owns and operates ENP’s properties. ENP’s properties and oil and natural gas reserves are located in four core areas:

·	the Big Horn Basin in Wyoming and Montana;

·	the Permian Basin in West Texas and New Mexico;

·	the Williston Basin in North Dakota and Montana; and

·	the Arkoma Basin in Arkansas and Oklahoma.

EAC’s Merger with Denbury

On March 9, 2010, Encore Acquisition Company (“EAC”), the former parent of the General Partner, was merged with and into Denbury (the “Merger”), with Denbury surviving the Merger. As part of the Merger, Denbury became the owner of the General Partner and approximately 46 percent of ENP’s outstanding common units. The Merger did not impact the accompanying Consolidated Financial Statements.

Strategic Alternatives and Asset Transaction Processes

On April 30, 2010, ENP and Denbury, the ultimate parent of the General Partner, announced the intent to explore a broad range of strategic alternatives (the “strategic process”) to enhance the value of ENP’s common units, including, but not limited to, those alternatives involving a possible merger, sale, or other transaction involving ENP, Denbury’s interest in the General Partner, or all or part of the ENP common units that Denbury owns. Additionally, ENP and Denbury also announced their intent to explore a sale or other transaction involving one or more of ENP’s assets (the “asset process”), initiated in light of the substantial projected capital requirements required to recognize the full potential value of certain fields owned by ENP which are possible CO 2 tertiary projects, such as the Elk Basin field. On September 2, 2010, ENP and Denbury announced (1) that they had terminated the asset process regarding the Elk Basin field, as no agreement could be reached on the value of the potential tertiary reserves; and (2) Denbury’s ongoing focus upon its intent to sell its interest in the General Partner and all or part of the ENP common units that Denbury owns. Although Denbury intends to sell its interest in the General Partner and all or part of ENP’s common units that Denbury owns, there is no assurance of completion of any transaction.

In May 2010, the Conflicts Committee of the board of directors of the General Partner engaged an investment bank to assist in its responsibilities with regard to the asset process. This agreement was terminated during the third quarter of 2010. In conjunction with entering into this agreement, ENP accrued a $1 million non-refundable retainer fee in the second quarter of 2010, which was paid in the third quarter of 2010, and which is included in “General and administrative expenses” in the accompanying Consolidated Statement of Operations for the nine months ended September 30, 2010. In addition, the Conflicts Committee engaged other advisors such as engineers and legal counsel to help them evaluate any potential transaction and in their capacity as Board members approved paying a fee of $50,000 to each of the members of the Conflicts Committee for considering any potential transaction. These third party expenses and directors’ fees expensed during the three months ended September 30, 2010 totaled approximately $0.5 million, which is included in “General and administrative expenses” in the accompanying Consolidated Statement of Operations.

Note 2. Basis of Presentation

ENP’s consolidated financial statements include the accounts of its wholly 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, ENP’s financial position as of September 30, 2010, results of operations for the three and nine months ended September 30, 2010 and 2009, and cash flows for the nine months ended September 30, 2010 and 2009. 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 ENP’s 2009 Annual Report on Form 10-K.

Reclassifications

Certain amounts in prior periods have been reclassified to conform to the current period presentation. On the accompanying Consolidated Statements of Operations, NGL revenues were reclassed from “Natural gas revenues” to “Oil revenues,” marketing expenses were reclassed to “Production taxes and marketing,” ad valorem taxes were reclassed to “Lease operating expenses,” and transportation expenses were reclassed to “Production taxes and marketing.”

Note 3. 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:

	September 30, 2010		December 31, 2009
Proved leasehold costs	$	609,910	$	609,692
Wells and related equipment — Completed		246,162		241,953
Wells and related equipment — In process		110		188
Total proved properties	$	856,182	$	851,833

Note 4. Fair Value Measurements

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

	September 30, 2010				December 31, 2009
	Book Value		Fair Value		Book Value		Fair Value
	(in thousands)
Assets:
Cash and cash equivalents	$	10,283	$	10,283	$	1,754	$	1,754
Accounts receivable — trade		16,753		16,753		24,543		24,543
Accounts receivable — affiliate		2,628		2,628		8,213		8,213
Commodity derivative contracts		25,101		25,101		26,304		26,304
Liabilities:
Accounts payable — trade		418		418		577		577
Accounts payable — affiliate		2,356		2,356		2,780		2,780
Revolving credit facility		240,000		237,636		255,000		252,047
Commodity derivative contracts		13,164		13,164		19,547		19,547
Interest rate swaps		2,408		2,408		3,669		3,669

The book values of cash and cash equivalents, accounts receivable, and accounts payable approximate fair value due to the short-term nature of these instruments. The book value of the revolving credit facility approximates fair value as the interest rate is variable; however, ENP adjusted the estimated fair value for estimated nonperformance risk of approximately $2.4 million and $3.0 million at September 30, 2010 and December 31, 2009, respectively. The nonperformance risk was determined using industry credit default swaps. Commodity derivative contracts and interest rate swaps are marked-to-market each period and are thus stated at fair value in the accompanying Consolidated Balance Sheets.

Derivative Policy

ENP 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 ENP’s exposure to commodity price decreases, but they can also limit the benefit ENP might otherwise receive from commodity price increases. ENP’s risk management activity is generally accomplished through over-the-counter derivative contracts with large financial institutions, all of which are lenders underwriting ENP’s revolving credit facility. ENP also uses derivative instruments in the form of interest rate swaps, which hedge risk related to interest rate fluctuation.

ENP applies the provisions of the “Derivatives” topic of the FASC, 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, the effective portion of changes in fair value can be recognized in accumulated other comprehensive income or loss within partners’ equity 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.

ENP has elected to designate its outstanding 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 and included in “Derivative fair value loss (gain)” in the accompanying Consolidated Statements of Operations.

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

Commodity Derivative Contracts

ENP 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 for 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, ENP enters into floor spreads. In a floor spread, ENP purchases puts at a specified price (a “purchased put”) and also sells a put at a lower price (a “short put”). This strategy enables ENP to achieve some 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 ENP 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, ENP purchased oil put options for 2,000 Bbls/D in 2010 at $65 per Bbl. As NYMEX prices increased in 2008, ENP wished to protect downside price exposure at the higher price. In order to do this, ENP purchased oil put options for 2,000 Bbls/D in 2010 at $75 per Bbl and simultaneously sold oil put options for 2,000 Bbls/D in 2010 at $65 per Bbl. Thus, after these transactions were completed, ENP 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 result was ENP effectively owning one oil put option for 2,000 Bbls/D in 2010 at $75 per Bbl. The following tables include information on both ENP’s purchased floor component of its floor spreads net and ENP’s other floor contracts.

The following tables summarize ENP’s open commodity derivative contracts as of September 30, 2010:

Oil Derivative Contracts

	Average Daily Floor Volume		Weighted Average Floor Price		Average Daily Cap Volume		Weighted Average Cap Price		Average Daily Swap Volume		Weighted Average Swap Price		Asset (Liability) Fair Market Value
	(Bbls)		(per Bbl)		(Bbls)		(per Bbl)		(Bbls)		(per Bbl)		(in thousands)
Oct. — Dec. 2010														(853	)
		880		80.00		440		93.80		760		75.43
		2,000		75.00		1,000		77.23		250		65.95
		760		67.00		—		—		—		—
2011														1,084
		1,880		80.00		1,440		95.41		760		78.46
		1,000		70.00		—		—		—		—
		760		65.00		—		—		250		69.65
2012														(5,566	)
		750		70.00		500		82.05		210		81.62
		1,510		65.00		250		79.25		1,300		76.54
														(5,335	)

Natural Gas Derivative Contracts

	Average Daily Floor Volume		Weighted Average Floor Price		Average Daily Cap Volume		Weighted Average Cap Price		Average Daily Swap Volume		Weighted Average Swap Price		Asset Fair Market Value
	(Mcf)		(per Mcf)		(Mcf)		(per Mcf)		(Mcf)		(per Mcf)		(in thousands)
Oct. — Dec. 2010													$	4,301
		3,800	$	8.20		3,800	$	9.58		5,452	$	6.20
		4,698		7.26		—		—		550		5.86
2011														9,083
		3,398		6.31		—		—		7,952		6.36
		—		—		—		—		550		5.86
2012														3,888
		898		6.76		—		—		5,452		6.26
		—		—		—		—		550		5.86
													$	17,272

Counterparty Risk. At September 30, 2010, ENP had committed 10 percent or greater (in terms of fair market value) of either its oil or natural gas derivative contracts in asset positions to the following counterparties:

	Fair Market Value		Fair Market Value of Natural Gas
Counterparty	of Oil Derivative Contracts Committed		Derivative Contracts Committed
	(in thousands)
BNP Paribas	$	3,610	$	4,084
Calyon		2,082		8,462
RBC		2,157		4,372

In order to mitigate the credit risk of financial instruments, ENP enters into master netting agreements with certain counterparties. The master netting agreement is a standardized, bilateral contract between a given counterparty and ENP. Instead of treating each financial transaction between the counterparty and ENP separately, the master netting agreement enables the counterparty and ENP to aggregate all financial trades and treat them as a single agreement. This arrangement is intended to benefit ENP in three ways: (1) the netting of the value of all trades reduces the likelihood of counterparties requiring daily collateral posting by ENP; (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 ENP’s credit exposure to a given counterparty in the event of close-out. ENP’s accounting policy is to not offset fair value amounts 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 September 30, 2010, all of which were entered into with Bank of America, N.A.:

	Notional Amount		Fixed Rate			Floating Rate
	(in thousands)
Oct. 2010 - Jan. 2011		50,000		3.1610	%	1-month LIBOR
Oct. 2010 - Jan. 2011		25,000		2.9650	%	1-month LIBOR
Oct. 2010 - Jan. 2011		25,000		2.9613	%	1-month LIBOR
Oct. 2010 - Mar. 2012		50,000		2.4200	%	1-month LIBOR

Current Period Impact

ENP recognizes 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) receipts and settlements on derivative contracts not designated as hedges; and (4) premium amortization. The following table summarizes the components of “Derivative fair value loss (gain)” for the periods indicated:

	Three months ended September 30,						Nine months ended September 30,
	2010			2009			2010			2009
	(in thousands)
Ineffectiveness on interest rate swaps		29			18			133			(16	)
Mark-to-market loss (gain)		8,922			4,957			(12,521	)		62,638
Premium amortization		2,474			5,918			7,342			17,326
Receipts, net of settlements		(3,816	)		(15,715	)		(9,301	)		(58,237	)
Total derivative fair value loss (gain)		7,609			(4,822			(14,347	)		21,711

Accumulated Other Comprehensive Loss

At September 30, 2010 and December 31, 2009, “Accumulated other comprehensive loss” on the accompanying Consolidated Balance Sheets consisted entirely of deferred losses, net of tax, on ENP’s interest rate swaps of $2.0 million and $3.4 million, respectively. During the twelve months ending September 30, 2011, ENP expects to reclassify $1.9 million of deferred losses associated with its interest rate swaps from accumulated other comprehensive loss to interest expense. The actual gains or losses ENP will realize from its interest rate swaps may vary significantly from the deferred losses recorded in “Accumulated other comprehensive loss” in the accompanying Consolidated Balance Sheet due to fluctuations in interest rates.

Tabular Disclosures of Fair Value Measurements

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

	Asset Derivatives					Liability Derivatives
		Fair Value					Fair Value
	Balance Sheet Location	September 30, 2010		December 31, 2009		Balance Sheet Location	September 30, 2010		December 31, 2009
Derivatives not designated as hedges
Commodity derivative contracts	Derivatives - current	$	15,078	$	12,881	Derivatives - current	$	3,719	$	6,393
Commodity derivative contracts	Derivatives - noncurrent		10,023		13,423	Derivatives - noncurrent		9,445		13,154
Total derivatives not designated as hedges		$	25,101	$	26,304		$	13,164	$	19,547
Derivatives designated as hedges
Interest rate swaps	Derivatives - current	$	—	$	—	Derivatives - current	$	1,924	$	3,422
Interest rate swaps	Derivatives - noncurrent		—		—	Derivatives - noncurrent		484		247
Total derivatives designated as hedges		$	—	$	—		$	2,408	$	3,669
Total derivatives		$	25,101	$	26,304		$	15,572	$	23,216

The following table summarizes the effect of derivative instruments not designated as hedges on the Consolidated Statements of Operations for the periods indicated (in thousands):

		Amount of Loss (Gain) Recognized in Income					Amount of Loss (Gain) Recognized in Income
		Three Months Ended September 30,					Nine Months Ended September 30,
	Location of Loss (Gain)
Derivatives Not Designated as Hedges	Recognized in Income	2010		2009			2010			2009
Commodity derivative contracts	Derivative fair value loss (gain)	$	7,580	$	(4,840	)	$	(14,480	)		21,727

The following tables summarize the effect of derivative instruments designated as hedges on the Consolidated Statements of Operations for the periods indicated (in thousands):

	Amount of Loss Recognized in Accumulated OCI (Effective Portion)				Amount of Loss Recognized in Accumulated OCI (Effective Portion)
	Three Months Ended September 30,				Nine Months Ended September 30,
Derivatives Designated as Hedges	2010		2009		2010		2009
Income expense	$	401	$	1,289	$	1,536	$	2,444

	Amount of Loss Reclassified from Accumulated OCI into Income (Effective Portion)				Amount of Loss Reclassified from Accumulated OCI into Income (Effective Portion)
	Three Months Ended September 30,				Nine Months Ended September 30,
Location of Loss Reclassified from Accumulated OCI into Income (Effective Portion)	2010		2009		2010		2009
Income expense	$	974	$	983	$	2,925	$	2,786

	Amount of Loss Recognized in Income as Ineffective				Amount of Loss (Gain) Recognized in Income as Ineffective
	Three Months Ended September 30,				Nine Months Ended September 30,
Location of Loss Recognized in Income as Ineffective	2010		2009		2010		2009
Derivative fair value loss (gain)	$	29	$	18	$	133	$	(16	)

Fair Value Hierarchy

The FASC established a fair value hierarchy that prioritizes the inputs used to measure fair value. The three levels of the fair value hierarchy are as follows:

·	Level 1 — Unadjusted quoted prices are available in active markets for identical assets or liabilities.

·	Level 2 — Pricing inputs, other than quoted prices within Level 1, that are either directly or indirectly observable.

·	Level 3 — Pricing inputs that are unobservable requiring the use of valuation methodologies that result in management’s best estimate of fair value.

ENP’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the financial assets and liabilities and their placement within the fair value hierarchy levels. The following methods and assumptions were used to estimate the fair values of ENP’s assets and liabilities that are accounted for at fair value on a recurring basis:

Level 2 — Fair values of oil and natural gas swaps were estimated using a combined income-based and market-based valuation methodology based upon forward commodity price curves obtained from independent pricing services reflecting broker market quotes. Fair values of interest rate swaps were estimated using a combined income-based and market-based valuation methodology based upon credit ratings and forward interest rate yield curves obtained from independent pricing services reflecting broker market quotes.

Level 3 — ENP’s oil and natural gas calls, puts, and short puts are average value options, which are not exchange—traded contracts. Settlement is determined by the average underlying price over a predetermined period of time. ENP uses both observable and unobservable inputs in a Black-Scholes valuation model to determine fair value. Accordingly, these derivative instruments are classified within the Level 3 valuation hierarchy. The observable inputs of ENP’s valuation model include: (1) current market and contractual prices for the underlying instruments; (2) quoted forward prices for oil and natural gas; and (3) interest rates, such as a LIBOR curve for a term similar to the commodity derivative contract. The unobservable inputs of ENP’s valuation model include volatility. The implied volatilities for ENP’s calls, puts, and short puts with comparable strike prices are based on the settlement values from certain exchange-traded contracts. The implied volatilities for calls, puts, and short puts where there are no exchange-traded contracts with the same strike price are extrapolated from exchange-traded implied volatilities by an independent party.

ENP adjusts the valuations from the valuation model for nonperformance risk, using management’s estimate of the counterparty’s credit quality for asset positions and ENP’s credit quality for liability positions. ENP uses multiple sources of third-party credit data in determining counterparty nonperformance risk, including credit default swaps.

The following table sets forth ENP’s assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2010:

				Fair Value Measurements at Reporting Date Using
Description	Asset (Liability)			Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
	(in thousands)
Oil derivative contracts — swaps	$	(9,254	)	$	—	$	(9,254	)	$	—
Oil derivative contracts — floors and caps		3,919			—		—			3,919
Natural gas derivative contracts — swaps		11,056			—		11,056
Natural gas derivative contracts — floors and caps		6,216			—		—			6,216
Interest rate swaps		(2,408	)		—		(2,408	)		—
Total	$	9,529		$	—	$	(606	)	$	10,135

The following table summarizes the changes in the fair value of ENP’s Level 3 assets and liabilities for the nine months ended September 30, 2010:

	Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
	Oil Derivative Natural Gas Contracts – Floors and Caps			Natural Gas Derivative Contracts - Floors and Caps			Total
	(in thousands)
Balance at January 1, 2010	$	8,585		$	8,528		$	17,113
Total gains (losses):
Included in earnings		(4,996	)		(9,566	)		(14,562	)
Settlements		330			7,254			7,584
Balance at September 30, 2010	$	3,919		$	6,216		$	10,135

The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets still held at the reporting date	$	(4,996	)	$	(9,566	)	$	(14,562	)

Since ENP does not use hedge accounting for its commodity derivative contracts, all gains and losses on its Level 3 assets and liabilities are included in “Derivative fair value loss (gain)” in the accompanying Consolidated Statements of Operations.

All fair values have been adjusted for nonperformance risk resulting in a decrease of the net commodity derivative asset of approximately $0.1 million as of September 30, 2010. For commodity derivative contracts which are in an asset position, ENP uses the counterparty’s credit default swap rating. For commodity derivative contracts which are in a liability position, ENP uses the average credit default swap rating of its peer companies as ENP does not have its own credit default swap rating.

Note 5. Asset Retirement Obligations

Asset retirement obligations relate to future plugging and abandonment expenses on oil and natural gas properties and related facilities disposal. The following table summarizes the changes in ENP’s asset retirement obligations for the nine months ended September 30, 2010 (in thousands):

Future abandonment liability at January 1, 2010	$	13,130
Accretion of discount		548
Revision of previous estimates		66
Plugging and abandonment costs incurred		(96	)
Future abandonment liability at September 30, 2010	$	13,648

As of September 30, 2010, $12.9 million of ENP’s asset retirement obligations were long-term and recorded in “Future abandonment cost, net of current portion” and $0.7 million were current and included in “Other current liabilities” in the accompanying Consolidated Balance Sheet. Approximately $5.0 million of the long-term future abandonment liability represents the estimated cost for decommissioning the Elk Basin natural gas processing plant.

Note 6. Long-Term Debt

OLLC is a party to a five-year credit agreement dated March 7, 2007 (as amended, the “OLLC Credit Agreement”). The OLLC Credit Agreement matures on March 7, 2012. In November 2009, OLLC amended the OLLC Credit Agreement, which amendment was effective upon the closing of the Merger, to, among other things, permit the consummation of the Merger not being treated as a “Change of Control” under the OLLC Credit Agreement. Denbury paid a fee of approximately $0.9 million for this bank waiver and did not seek reimbursement from ENP for this payment. As such, the $0.9 million paid by Denbury is reflected as a capital contribution to ENP by Denbury in its capacity as the parent of the General Partner and is included in “General and administrative expense” in the accompanying Consolidated Statement of Operations for the nine months ended September 30, 2010 as a non-cash expense.

The OLLC Credit Agreement provides for revolving credit loans to be made to OLLC from time to time and letters of credit to be issued from time to time for the account of OLLC or any of its restricted subsidiaries. The aggregate amount of the commitments of the lenders under the OLLC Credit Agreement is $475 million. Availability under the OLLC Credit Agreement is subject to a borrowing base, which is redetermined semi-annually and upon requested special redeterminations. On June 14, 2010, the borrowing base under the OLLC Credit Agreement was reaffirmed at $375 million. As of September 30, 2010, there were $240 million of outstanding borrowings and $135 million of borrowing capacity under the OLLC Credit Agreement.

OLLC incurs a quarterly commitment fee at a rate of 0.5 percent per year on the unused portion of the OLLC Credit Agreement.

Obligations under the OLLC Credit Agreement are secured by a first-priority security interest in substantially all of OLLC’s proved oil and natural gas reserves and in the equity interests of OLLC and its restricted subsidiaries. In addition, obligations under the OLLC Credit Agreement are guaranteed by ENP and OLLC’s restricted subsidiaries. Obligations under the OLLC Credit Agreement are non-recourse to Denbury and its restricted subsidiaries.

Loans under the OLLC Credit Agreement are subject to varying rates of interest based on (1) amount outstanding in relation to the borrowing base and (2) whether the loan is a Eurodollar loan or a base rate loan. Eurodollar loans under the OLLC Credit Agreement bear interest at the Eurodollar rate plus the applicable margin indicated in the following table, and base rate loans under the OLLC Credit Agreement bear interest at the base rate plus the applicable margin indicated in the following table:

Ratio of Outstanding Borrowings to Borrowing Base	Applicable Margin for Eurodollar Loans			Applicable Margin for Base Rate Loans
Less than .50 to 1		2.250	%		1.250	%
Greater than or equal to .50 to 1 but less than .75 to 1		2.500	%		1.500	%
Greater than or equal to .75 to 1 but less than .90 to 1		2.750	%		1.750	%
Greater than or equal to .90 to 1		3.000	%		2.000	%

The “Eurodollar rate” for any interest period (either one, two, three, or six months, as selected by ENP) is the rate equal to the British Bankers Association LIBOR for deposits in dollars for a similar interest period. The “Base Rate” is calculated as the highest of: (1) the annual rate of interest announced by Bank of America, N.A. as its “prime rate”; (2) the federal funds effective rate plus 0.5 percent; or (3) except during a “LIBOR Unavailability Period,” the Eurodollar rate (for dollar deposits for a one-month term) for such day plus 1.0 percent.

Any outstanding letters of credit reduce the availability under the OLLC Credit Agreement. Borrowings under the OLLC Credit Agreement may be repaid from time to time without penalty.

The OLLC Credit Agreement contains several restrictive covenants including, among others, the following:

·	a prohibition against incurring debt, subject to permitted exceptions;

·	a prohibition against purchasing or redeeming capital stock, or prepaying indebtedness, subject to permitted exceptions;

·	a restriction on creating liens on the assets of ENP, OLLC, and OLLC’s restricted subsidiaries, subject to permitted exceptions;

·	restrictions on merging and selling assets outside the ordinary course of business;

·	restrictions on use of proceeds, investments, transactions with affiliates, or change of principal business;

·	a provision limiting oil and natural gas hedging transactions (other than puts) to a volume not exceeding 75 percent of anticipated production from proved producing reserves;

·	a requirement that ENP and OLLC maintain a ratio of consolidated current assets to consolidated current liabilities of not less than 1.0 to 1.0;

·	a requirement that ENP and OLLC maintain a ratio of consolidated EBITDA, as defined in the OLLC Credit Agreement, to the sum of consolidated net interest expense plus letter of credit fees of not less than 2.5 to 1.0; and

·	a requirement that ENP and OLLC maintain a ratio of consolidated funded debt to consolidated adjusted EBITDA of not more than 3.5 to 1.0.

As of September 30, 2010, ENP and OLLC were in compliance with all covenants of the OLLC Credit Agreement.

The OLLC Credit Agreement contains customary events of default including, among others, the following:

·	failure to pay principal on any loan when due;

·	failure to pay accrued interest on any loan or fees when due and such failure continues for more than three days;

·	failure to observe or perform covenants and agreements contained in the OLLC Credit Agreement, subject in some cases to a 30-day grace period after discovery or notice of such failure;

·	failure to make a payment when due on any other debt in a principal amount equal to or greater than $3 million or any other event or condition occurs which results in the acceleration of such debt or entitles the holder of such debt to accelerate the maturity of such debt;

·	the commencement of liquidation, reorganization, or similar proceedings with respect to OLLC or any guarantor under bankruptcy or insolvency law, or the failure of OLLC or any guarantor generally to pay its debts as they become due;

·	the entry of one or more judgments in excess of $3 million (to the extent not covered by insurance) and such judgment(s) remain unsatisfied and unstayed for 30 days;

·	the occurrence of certain ERISA events involving an amount in excess of $3 million;

·	there cease to exist liens covering at least 80 percent of the borrowing base properties; or

·	the occurrence of a change in control, as defined in the OLLC Credit Agreement.

If an event of default occurs and is continuing, lenders with a majority of the aggregate commitments may require Bank of America, N.A. to declare all amounts outstanding under the OLLC Credit Agreement to be immediately due and payable.

Note 7. Partners’ Equity and Distributions

Distributions

ENP’s partnership agreement requires that, within 45 days after the end of each quarter, it distribute all of its available cash (as defined in ENP’s partnership agreement) to its unitholders. ENP’s available cash is its cash on hand at the end of a quarter after the payment of its expenses and the establishment of reserves for future capital expenditures and operational needs. Distributions are not cumulative. ENP distributes available cash to its unitholders in accordance with their ownership percentages.

The following table illustrates information regarding ENP’s distributions of available cash for the periods indicated:

	Date Declared	Cash Distribution Declared per Common Unit		Date Paid		Total Distribution
						(in thousands)
2010
Quarter ended September 30	10/28/2010	$	0.5000	11/12/2010	(a)	$	22,923	(a)
Quarter ended June 30	7/29/2010	$	0.5000	8/13/2010			22,923
Quarter ended March 31	4/30/2010	$	0.5000	5/14/2010			22,923

2009
Quarter ended December 31	1/25/2010	$	0.5375	2/12/2010			24,642
Quarter ended September 30	10/26/2009	$	0.5375	11/13/2009			24,642
Quarter ended June 30	7/27/2009	$	0.5125	8/14/2009			23,481
Quarter ended March 31	4/27/2009	$	0.5000	5/15/2009			16,813

2008
Quarter ended December 31	1/26/2009	$	0.5000	2/13/2009			16,813

(a) Represents the date the distribution is expected to be paid and the total amount of the distribution that is expected to be paid.

Note 8. Earnings Per Unit

ENP applies the provisions of the “Earnings Per Share” topic of the FASC, which requires earnings per unit to be calculated using the two-class method. Under the two-class method of calculating earnings per unit, earnings are allocated to participating securities as if all earnings for the period had been distributed. A participating security is any security that may participate in distributions with common units. For purposes of calculating earnings per unit, general partner units and unvested phantom units are considered participating securities. Earnings per unit is calculated by dividing the limited partners’ interest in net income (loss), after deducting the interests of participating securities, by the weighted average common units outstanding.

The following table reflects the allocation of net income (loss) to ENP’s limited partners and earnings per unit computations for the periods indicated:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2010			2009			2010			2009
	(in thousands, except per unit amount)
Net income (loss)	$	2,441		$	7,460		$	46,318		$	(27,013	)
Less: net income for pre-partnership operations of assets acquired from affiliates		—			(1,493	)		—			(176	)
Net income (loss) attributable to unitholders	$	2,441		$	5,967		$	46,318		$	(27,189	)

Numerator:
Numerator for basic earnings per unit:
Net income (loss) attributable to unitholders	$	2,441		$	5,967		$	46,318		$	(27,189	)
Less: distributions earned by participating securities		(253	)		(271	)		(757	)		(783	)
Plus: cash distributions in excess of (less than) income allocated to the general partner		231			208			252			1,227
Net income (loss) allocated to limited partners	$	2,419		$	5,904		$	45,813		$	(26,745	)

Denominator:
Denominator for basic earnings per unit:
Weighted average common units outstanding		45,342			44,653			45,328			37,373
Effect of dilutive phantom units (a)		—			22			8			—
Denominator for diluted earnings per unit		45,342			44,675			45,336			37,373

Net income (loss) per common unit:
Basic	$	0.05		$	0.13		$	1.01		$	(0.72	)
Diluted	$	0.05		$	0.13		$	1.01		$	(0.72	)

(a)	For the nine months ended months ended September 30, 2009, 43,750 phantom units were outstanding but were excluded from the diluted EPU calculations because their effect would have been antidilutive. Please read “Note 9. Unit-Based Compensation Plans” for additional discussion of phantom units.

Note 9. Unit-Based Compensation Plans

Long-Term Incentive Plan

In September 2007, the board of directors of the General Partner adopted the Encore Energy Partners GP LLC Long-Term Incentive Plan (the “LTIP”), which provides for the granting of options, restricted units, phantom units, unit appreciation rights, distribution equivalent rights, other unit-based awards, and unit awards. All employees, consultants, and directors of the General Partner and its affiliates who perform services for or on behalf of ENP and its subsidiaries are eligible to be granted awards under the LTIP. The LTIP is administered by the board of directors of the General Partner or a committee thereof, referred to as the plan administrator. To satisfy common unit awards under the LTIP, ENP may acquire common units in the open market, use common units owned by the General Partner, or use common units acquired by the General Partner from ENP or from any other person.

The total number of common units reserved for issuance pursuant to the LTIP is 1,150,000. As of September 30, 2010, there were 1,075,000 common units available for issuance under the LTIP with none outstanding.

Phantom Units. As a result of the change of control of the General Partner in conjunction with the Merger of EAC with and into Denbury, all 56,250 of ENP’s outstanding phantom units vested and were settled in an equal number of ENP’s common units. The acceleration of the phantom unit vesting resulted in the recognition of the remaining unrecognized unit-based compensation expense during March 2010. The fair value of these phantom units was approximately $1.2 million on the date of the Merger. During the nine months ended September 30, 2010 and 2009, ENP recognized non-cash unit-based compensation expense related to phantom units of approximately $0.7 million (upon closing of the Merger on March 9, 2010) and $0.3 million, respectively, which is included in “General and administrative expense” in the accompanying Consolidated Statements of Operations. As of September 30, 2010, there were no outstanding phantom units.

Note 10. Comprehensive Income (Loss)

The components of comprehensive income (loss), net of tax, were as follows for the periods indicated:

	Three Months Ended September 30,					Nine Months Ended September 30,
	2010		2009			2010		2009
	(in thousands)
Net income (loss)	$	2,441	$	7,460		$	46,318	$	(27,013	)
Change in deferred hedge loss on interest rate swaps		573		(306	)		1,389		342
Comprehensive income (loss)	$	3,014	$	7,154		$	47,707	$	(26,671	)

Note 11. Commitments and Contingencies

ENP is a party to ongoing legal proceedings in the ordinary course of business. The General Partner’s management does not believe the result of these proceedings will have a material adverse effect on ENP’s business, financial condition, results of operations, liquidity, or ability to pay distributions.

Additionally, ENP has contractual obligations related to future plugging and abandonment expenses on oil and natural gas properties and related facilities disposal, long-term debt, derivative contracts, operating leases, and development commitments. Please read “Capital Commitments, Capital Resources, and Liquidity — Capital commitments — Contractual obligations” included in “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Report for ENP’s contractual obligations as of September 30, 2010.

Note 12. Related Party Transactions

Administrative Services Agreement

ENP does not have any employees. The employees supporting the operations of ENP are employees of Denbury. Encore Operating, L.P. (“Encore Operating”), a Texas limited partnership and indirect wholly-owned subsidiary of Denbury, performs administrative services for ENP, such as accounting, corporate development, finance, land, legal, and engineering, pursuant to an administrative services agreement. In addition, Encore Operating provides all personnel, facilities, goods, and equipment necessary to perform these services which are not otherwise provided for by ENP. Encore Operating is not liable to ENP for its performance of, or failure to perform, services under the administrative services agreement unless its acts or omissions constitute gross negligence or willful misconduct.

From April 1, 2008 to March 31, 2009, the administrative fee charged by Encore Operating to ENP under the administrative services agreement was $1.88 per BOE of ENP’s production. From April 1, 2009 to March 31, 2010, the administrative fee was $2.02 per BOE of ENP’s production. Effective April 1, 2010, the administrative fee increased to $2.06 per BOE of ENP’s production. ENP also reimburses Encore Operating for actual third-party expenses incurred on ENP’s behalf under the administrative services agreement. In addition, Encore Operating is entitled to retain any COPAS overhead charges associated with drilling and operating wells that would otherwise be paid by non-operating interest owners to the operator.

The administrative fee will increase in the following circumstances:

·	beginning on the first day of April in each year by an amount equal to the product of the then-current administrative fee multiplied by the COPAS Wage Index Adjustment for that year;

if ENP acquires additional assets, Encore Operating may propose an increase in its administrative fee that covers the provision of services for such additional assets; however, such proposal must be approved by the board of directors of the General Partner upon the recommendation of its Conflicts Committee; and

·	otherwise as agreed upon by Encore Operating and the General Partner, with the approval of the Conflicts Committee of the board of directors of the General Partner.

ENP reimburses Denbury for any state, income, franchise, or similar tax incurred by Denbury resulting from the inclusion of ENP in consolidated tax returns of Denbury as required by applicable law. The amount of any such reimbursement is limited to the tax that ENP would have incurred had it not been included in a combined group with Denbury.

Administrative fees (including COPAS recovery) paid to Encore Operating pursuant to the administrative services agreement are included in “General and administrative expenses” in the accompanying Consolidated Statement of Operations. The reimbursements of actual third-party expenses incurred by Encore Operating on ENP’s behalf are included in “Lease operating expense” or “General and administrative expenses” in the accompanying Consolidated Statement of Operations based on the nature of the expense. The following table illustrates amounts paid by ENP to Encore Operating pursuant to the administrative service agreement for the periods indicated:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2010		2009		2010		2009
	(in thousands)
Administrative fees (including COPAS recovery)	$	2,276	$	1,325	$	7,717	$	4,150
Third-party expenses		1,212		1,059		4,527		4,031

As of September 30, 2010, ENP had a payable to Denbury of $2.4 million which is reflected as “Accounts payable — affiliate” in the accompanying Consolidated Balance Sheets, and a receivable from Denbury of $2.6 million which is reflected as “Accounts receivable — affiliate” in the accompanying Consolidated Balance Sheets. As of December 31, 2009, ENP had a payable to EAC of $2.8 million which is reflected as “Accounts payable — affiliate” in the accompanying Consolidated Balance Sheets, and a receivable from EAC of $8.2 million which is reflected as “Accounts receivable — affiliate” in the accompanying Consolidated Balance Sheets.

Acquisitions

In January 2009, ENP acquired certain oil and natural gas properties and related assets in the Arkoma Basin in Arkansas and royalty interest properties primarily in Oklahoma, as well as 10,300 unleased mineral acres (the “Arkoma Basin Assets”) from Encore Operating, at the time a subsidiary of EAC, for approximately $46.4 million. In June 2009, ENP acquired certain oil and natural gas properties and related assets in the Williston Basin in North Dakota and Montana (the “Williston Basin Assets”) from Encore Operating for approximately $25.2 million. In August 2009, ENP acquired certain oil and natural gas properties and related assets in the Big Horn Basin in Wyoming, the Permian Basin in West Texas and New Mexico, and the Williston Basin in Montana and North Dakota (the “Rockies and Permian Basin Assets”) from Encore Operating for approximately $179.6 million in cash. Prior to the acquisition by ENP, the properties were owned by EAC and were not separate legal entities.

In addition to payroll-related expenses, EAC incurred general and administrative expenses related to leasing office space and other corporate overhead expenses during the period these properties were owned by EAC. A portion of EAC’s consolidated general and administrative expenses was allocated to ENP and included in the accompanying Consolidated Statements of Operations based on the respective percentage of BOE produced by the properties in relation to the total BOE produced by EAC on a consolidated basis for the three and nine months ended September 30, 2009. A portion of EAC’s consolidated indirect lease operating overhead expenses was allocated to ENP included in the accompanying Consolidated Statements of Operations based on its share of EAC’s direct lease operating expense for the three and nine months ended September 30, 2009.

Distributions

Each quarter, ENP pays cash distributions with respect to operations in the previous quarter on all of its outstanding units, including those common units held by the General Partner and its affiliates, and pays cash distributions to the General Partner based upon its general partner interest. On each of August 13, 2010 and May 14, 2010, ENP paid cash distributions of approximately $22.9 million, of which $10.7 million was paid to the General Partner and its affiliates. On February 12, 2010, ENP paid cash distributions of approximately $24.6 million, of which $11.5 million was paid to the General Partner and its affiliates. On August 14, 2009, ENP paid cash distributions of approximately $23.5 million, of which $11.0 million was paid to the General Partner and its affiliates. On each of May 15, 2009 and February 13, 2009, ENP paid cash distributions of approximately $16.8 million, of which $10.7 million was paid to the General Partner and its affiliates.

Note 13. Subsequent Events

On October 28, 2010, the board of directors of the General Partner declared an ENP cash distribution for the third quarter of 2010 to unitholders of record as of the close of business on November 8, 2010 of $0.50 per unit or approximately $22.9 million of which $10.7 million is expected to be paid to the General Partner and its affiliates. The distribution is expected to be paid to unitholders on or about November 12, 2010.