Exhibit 99.1

Concho Resources Inc. Reports Third Quarter 2007 Financial and
Operating Results and Provides 2008 Capital Budget Detail and Guidance

MIDLAND, Texas, November 13, 2007 (Business Wire) – Concho Resources Inc. (NYSE: CXO) (“Concho” or the “Company”) today reported third quarter 2007 financial and operating results. Highlights of results for the quarter and the nine months ended September 30, 2007 include:

	•		Third quarter net income of $8.0 million, up 22% from the same period in 2006
	•		Third quarter EBITDAX1 of $52.7 million, up 16% from the same period in 2006
	•		Implementation of a five rig drilling program and the initiation of a Paddock re-stimulation program on its core New Mexico Shelf assets
	•		Production of 21.7 Bcfe for the nine months ended September 30, 2007, an increase of 36% over the same period in 2006

For the three months ended September 30, 2007, Concho reported net income of $8.0 million, or $0.11 per diluted share, on revenues of $69.1 million, as compared to net income of $6.5 million, or $0.11 per diluted share, on revenues of $58.3 million for the three months ended September 30, 2006. EBITDAX increased to $52.7 million in the third quarter of 2007, as compared to $45.4 million in the same period of 2006.

Production for the third quarter of 2007 totaled 7.2 Bcfe (705 MBbls and 3.0 Bcf), an increase of 8% as compared to 6.7 Bcfe (661 MBbls and 2.7 Bcfe) produced in the third quarter of 2006. For the first nine months of 2007, production totaled 21.7 Bcfe, representing a 36% increase over the 16.0 Bcfe produced in the first nine months of 2006. On a pro forma basis, as if the combination with the Chase Group that occurred on February 27, 2006 had occurred on January 1, 2006, production for the first nine months of 2007 increased 18% when compared to pro forma production for the first nine months of 2006 of 18.4 Bcfe.

As described in the Company’s second quarter press release, dated August 29, 2007, a natural gas processing plant through which it processes and sells production from the Company’s New Mexico Shelf assets was shut-down for repair twice, first as a result of severe weather and a second time due to equipment failure. As a result, the Company estimated at that time that its production would be reduced in the third quarter by an estimated 260,000 Mcfe, or 2.8 MMcfepd. However, the plant downtime and associated production and transportation interruptions caused the Company’s quarterly production to be reduced in the aggregate by approximately 500,000 Mcfe, or approximately 5.4 MMcfepd.

¹For an explanation of how we calculate and use EBITDAX and a reconciliation of net income to EBITDAX, please see “Supplemental non-GAAP financial measures” below.

Tim Leach, Concho’s Chairman and CEO, commented, “Despite production interruptions during the third quarter, we are still on track to achieve our 2007 plan, and results from our core New Mexico Shelf area give me confidence in the 2008 budget that our board approved last week. We will continue to focus our capital spending on our core New Mexico Shelf assets, but we will also continue to devote manpower and capital to new initiatives and growth opportunities.”

Operations

For the nine months ended September 30, 2007, the Company drilled or participated in a total of 79 wells (63 operated), 59 of which had been completed as producers, 19 of which were in progress and 1 of which was a dry hole at September 30, 2007. In addition, the Company operated or participated in 89 recompletions (75 operated), 79 of which had been completed as producers, 9 of which were in progress and 1 of which was a dry hole at September 30, 2007.

New Mexico Shelf

For the quarter ended September 30, 2007, the Company drilled or participated in 29 wells (28 operated) and 23 recompletions (22 operated) on its New Mexico Shelf assets, with a 100% success rate on the 16 wells and 19 recompletions that had been completed by September 30, 2007. Of the 29 drill wells, 28 were drilled to, and will be completed in, both the Blinebry and Paddock intervals of the Yeso formation (“combination wells”).

For the first nine months of 2007, the Company drilled or participated in 61 wells (57 operated) on its New Mexico Shelf assets, 47 of which had been completed as producers and 14 of which were in progress at September 30, 2007. In addition, the Company completed 51 recompletions (49 operated) on its New Mexico Shelf assets during the first nine months of 2007. Of the 61 drill wells, 57 were combination wells, and since the closing of the combination with the Chase Group in February 2006, Concho has drilled 109 wells to the Blinebry interval, 108 of which will be completed as combination wells.

During the third quarter, the Company commenced its program to re-enter existing wells that produced only from the Paddock interval and re-stimulate them with current techniques. During the third quarter of 2007 the Company completed re-stimulations on three wells and has subsequently completed re-stimulations on three additional wells. Early results of this program are encouraging, and the Company has identified over 300 potential re-stimulation candidates on its New Mexico Shelf assets.

In addition to the re-stimulation program, the Company began engineering design during the three months ended September 30, 2007 on a plan to deepen certain existing Paddock wells to the Blinebry interval. Approximately 80 of such deepening opportunities have already been identified and the Company plans to deepen 2 wells during the fourth quarter of 2007. The economics of this operation are significantly enhanced as compared to drilling a new well solely to access the Blinebry interval.

Horizontal Wolfcamp Oil Play

The Company’s first well in this play, the Reindeer Federal #1, continues to produce at a rate of approximately 185 boepd and to date the well has produced approximately 65 Mboe since February of 2007. During August and September 2007, the Company drilled its second well in the play, the Moose 23 Federal #1, and its third well, the Dasher 16 State #1. Initial evaluation indicated higher water saturation levels than anticipated in the Moose well, so the Company decided to drill only a vertical hole on the Dasher well and await further evaluation on the first two wells before drilling a lateral section in such well. The drilling rig, which was on a well by well contract, was released after drilling the Dasher well and will not continue drilling in this area until further evaluation of these wells is complete.

Subsequently, the Company placed the Moose well on pump, and it is currently making approximately 60-80 barrels of oil and 400 barrels of water per day.

Exploration and Abandonments

Exploration and abandonment expense totaled $11.8 million for the three months ended September 30, 2007. Included in this total was exploratory dry hole expense of approximately $8.6 million related to the Company’s activity in the Western Delaware Basin of West Texas. This charge includes expensing all drilling and completion costs related to the Sawyer 14 #1 well ($6.8 million) and a portion of the drilling and completion costs related to the Raymond 19-1 well ($1.8 million). The Company is still evaluating the Woodford formation in the Raymond 19-1 well, on which it has approximately $3.3 million in remaining capitalized drilling and completion costs. In addition to the dry hole expense associated with the Company’s activity in the Western Delaware Basin, the Company incurred approximately $1.4 million of dry hole expense in the third quarter related to two non-operated wells in the Southeastern New Mexico Basin of Eddy County. The remaining dry hole expense during the three months ended September 30, 2007 was primarily attributable to one unsuccessful operated well in Lea County, New Mexico. The Company also recorded approximately $0.9 million in abandonments in the third quarter of 2007 related to a prospect in Edwards County, Texas.

Production Expense

For the quarter ended September 30, 2007 oil and gas production expense totaled $8.1 million, or $1.12 per Mcfe. Approximately $0.9 million, or $0.12 per Mcfe, of the $8.1 million of oil and gas production expense was related to repair activity associated with a single well in Gaines County, Texas. Other increases in production expenses were primarily related to increases in contract labor, subsurface pump maintenance, treating chemicals, electrical work, and well service and repair.

Derivative Financial Instruments

In late September, the Company entered into crude oil price swaps to hedge an additional 2,000 barrels of oil per day for calendar years 2008 and 2009. The average fixed price for the 2008 swaps is $75.78 and for 2009 the average fixed price is $72.84. The Company has not designated these derivative instruments as cash flow hedges. In addition, during the three months ended September 30, 2007, the Company determined that all of its natural gas commodity contracts no longer qualified as hedges under the requirements of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended (“SFAS No. 133”), as a result of the historical relationship between the hedging instrument and the forecasted transaction no longer being highly correlated. This lack of correlation is due to the substantial component of natural gas liquids in natural gas produced from the Company’s New Mexico Shelf assets. Prices received for natural gas liquids are not highly correlated to the price of natural gas, but are more correlated to the price of oil. During the third quarter of 2007, the price of oil and natural gas liquids rose substantially and at a significantly higher rate than the corresponding change in the index on which the Company’s natural gas derivatives are based. This resulted in a decrease in the correlation between the prices received and the derivative index below the level required for cash flow hedge accounting. A summary of the Company’s derivative financial instruments is included in a table at the end of this press release.

2008 Budget

The Company’s Board of Directors recently approved a 2008 exploration and development budget of $250 million, which consists of $230 million committed to the Company’s core operating areas and $20 million to exploration, leasehold and G&G. Of the $230 million dedicated to the Company’s core areas, 94% will be spent on properties operated by the Company, 90% will be dedicated to the New Mexico Shelf assets, and approximately 60% will be dedicated to projects on which the Company has not yet assigned reserves to the proved category.

On its New Mexico Shelf assets, the Company plans to drill 120 wells, perform 48 re-stimulations on existing Paddock wells, and deepen 19 existing Paddock wells to the Blinebry.

Financial and Operating Guidance

2007
The Company’s 2007 guidance remains unchanged.

2008
Production:

Natural Gas Equivalent (Bcfe)		35 – 37
Oil (MMbbl)		3.5 – 3.7
Natural Gas (Bcf)		14.0 – 14.8

Price Differentials to NYMEX:
(excluding the effects of hedging)
Oil (per Bbl)		8 – 9	%
Natural Gas (per Mcf)		2 – 3	%
Operating costs and expenses:
Production expense (per Mcfe)		$1.00 - $1.05
Production tax (percent of oil & gas revenue)		9	%
Depreciation, depletion, and
Accretion (per Mcfe)		$2.45 – $2.55
General and administrative (per Mcfe)		$0.60 - $0.65
Non-cash stock-based compensation (per Mcfe)		$0.10 - $0.15
Exploration, abandonments and G&G (per Mcfe)		$0.40 - $0.60
Interest Expense (as a % of outstanding debt)		7.5 – 8.5	%
Income tax rate		42	%
Percent deferred		Approximately 80	%

Conference Call Information

     The Company will host a conference call on Wednesday, November 14, 2007 at 10:00 a.m. Central Time to discuss third quarter 2007 financial and operating results. Interested parties may listen to the conference call via the Company’s website at http://www.conchoresources.com or by dialing (866) 356-4441 (passcode: 69952837). A replay of the conference call will be available on the Company’s website or by dialing (888) 286-8010 (passcode: 9860288).

Forward-Looking Statements and Cautionary Statements

The foregoing contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical facts, included in this press release that address activities, events or developments that the Company expects, believes or anticipates will or may occur in the future are forward-looking statements. Without limiting the generality of the foregoing, forward-looking statements contained in this press release specifically include the expectations of plans, strategies, objectives and anticipated financial and operating results of the Company, including as to the Company’s drilling program, production, hedging activities, capital expenditure levels and other guidance included in this press release. These statements are based on certain assumptions made by the Company based on management’s experience and perception of historical trends, current conditions, anticipated future developments and other factors believed to be appropriate. Such statements are subject to a number of assumptions, risks

and uncertainties, many of which are beyond the control of the Company, which may cause actual results to differ materially from those implied or expressed by the forward-looking statements. These include risks relating to financial performance and results, prices and demand for oil and natural gas, availability of drilling equipment and personnel, availability of sufficient capital to execute our business plan, our ability to replace reserves and efficiently develop and exploit our current reserves and other important factors that could cause actual results to differ materially from those projected as described in the Company’s reports filed with the Securities and Exchange Commission.

Any forward-looking statement speaks only as of the date on which such statement is made and the Company undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law.

About Concho Resources Inc.

Concho Resources Inc. is an independent oil and natural gas company engaged in the acquisition, development, exploitation and exploration of oil and natural gas properties. The Company’s conventional operations are primarily focused in the Permian Basin of Southeast New Mexico and West Texas. In addition, the Company is involved in a number of unconventional emerging resource plays.

Consolidated balance sheets
Unaudited

		September 30,				December 31,
(in thousands, except share and per share data)		2007				2006
Assets
Current assets:
Cash and cash equivalents		$	19,868			$	1,122
Accounts receivable:
Oil and gas			24,793				27,304
Joint operations and other			16,027				22,638
Related parties			—				1,449
Derivative instruments			1,658				6,013
Deferred income taxes			3,625				82
Inventory			1,404				1,309
Prepaid insurance and other			3,618				3,848
Total current assets			70,993				63,765
Property and equipment, at cost:
Oil and gas properties, successful efforts method:
Proved properties			1,266,890				1,159,756
Unproved properties			237,223				239,462
Accumulated depletion and depreciation			(142,981	)			(84,098	)
Total oil and gas properties, net			1,361,132				1,315,120
Other property and equipment, net			6,894				5,535
Total property and equipment, net			1,368,026				1,320,655
Deferred loan costs, net			3,737				4,417
Other assets			751				1,235
Total assets		$	1,443,507			$	1,390,072
Liabilities and stockholders’ equity
Current liabilities:
Accounts payable:
Trade		$	7,583			$	16,157
Related parties			2,941				3,593
Other current liabilities:
Revenue payable			4,576				9,901
Accrued drilling costs			27,633				17,051
Accrued interest			1,755				8,004
Other accrued liabilities			7,712				6,220
Derivative instruments			10,303				6,224
Dividends payable			—				87
Income taxes payable			225				—
Chase Group unaccredited investors asset purchase obligation			—				906
Current portion of long-term debt			2,000				400
Current asset retirement obligations			1,005				1,958
Total current liabilities			65,733				70,501
Long-term debt			343,880				495,100
Noncurrent derivative instruments			1,514				—
Deferred income taxes			251,800				241,752
Asset retirement obligations and other long-term liabilities			7,196				7,563
Commitments and contingencies
Stockholders’ equity:
6% Series A preferred stock, $0.01 par value; 30,000,000 shares authorized; and zero shares issued and outstanding at September 30, 2007 and December 31, 2006			—				—
Preferred stock, $0.001 par value; 10,000,000 shares authorized; and zero shares issued and outstanding at September 30 ,2007 and December 31, 2006			—				—
Common stock, $0.001 par value; 300,000,000 authorized; 75,750,517 and 59,092,830 shares issued and outstanding at September 30, 2007 and December 31, 2006, respectively			76				59
Additional paid-in capital			751,680				575,389
Notes receivable from officers and employees			(2,488	)			(12,858	)
Retained earnings			30,609				12,152
Accumulated other comprehensive income (loss)			(6,493	)			414
Total stockholders’ equity			773,384				575,156
Total liabilities and stockholders’ equity		$	1,443,507			$	1,390,072

Consolidated statements of operations
Unaudited

		Three months ended								Nine months ended
		September 30,								September 30,
(in thousands, except per share amounts)		2007				2006				2007				2006
Operating revenues:
Oil sales		$	45,685			$	40,239			$	128,152			$	90,737
Natural gas sales			23,413				18,036				67,395				44,908
Total operating revenues			69,098				58,275				195,547				135,645
Operating costs and expenses:
Oil and gas production			8,100				5,524				22,309				14,511
Oil and gas production taxes			5,673				4,621				15,616				10,831
Exploration and abandonments			11,805				3,316				18,110				4,717
Depreciation and depletion			18,003				19,674				55,036				42,170
Accretion of discount on asset retirement obligations			106				87				334				196
Impairments of proved oil and gas properties			1,379				2,679				4,577				5,762
Contract drilling fees — stacked rigs			—				—				4,269				—
General and administrative (including non-cash stock-based compensation of $703 and $1,090 for the three months ended September 30, 2007 and 2006, respectively, and $2,656 and $8,041 for the nine months ended September 30, 2007 and 2006, respectively)			4,646				3,832				16,567				16,044
Ineffective portion of cash flow hedges			(22	)			(1,190	)			1,134				(64	)
(Gain) loss on derivatives not designated as hedges			(3,088	)			—				(3,088	)			—
Total operating costs and expenses			46,602				38,543				134,864				94,167
Income from operations			22,496				19,732				60,683				41,478
Other income (expense):
Interest expense			(9,054	)			(9,184	)			(29,803	)			(20,998	)
Other, net			484				333				957				907
Total other expense			(8,570	)			(8,851	)			(28,846	)			(20,091	)
Income before income taxes			13,926				10,881				31,837				21,387
Income tax expense			(5,972	)			(4,351	)			(13,335	)			(8,664	)
Net income			7,954				6,530				18,502				12,723
Preferred stock dividends			—				(32	)			(45	)			(1,210	)
Effect of induced conversion of preferred stock			—				—				—				11,601
Net income applicable to common shareholders		$	7,954			$	6,498			$	18,457			$	23,114
Basic earnings per share:
Net income per share		$	0.12			$	0.12			$	0.30			$	0.52
Shares used in basic earnings per share			69,067				54,936				60,648				44,710
Diluted earnings per share:
Net income per share		$	0.11			$	0.11			$	0.29			$	0.48
Shares used in diluted earnings per share			69,913				58,625				62,858				47,937

Consolidated statements of cash flows
Unaudited

		Nine months ended
		September 30,
(in thousands)		2007				2006
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income		$	18,502			$	12,723
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and depletion			55,036				42,170
Impairments of proved oil and gas properties			4,577				5,762
Accretion of discount on asset retirement obligations			334				196
Exploration expense, including dry holes			17,117				3,204
Non-cash compensation expense			2,656				8,041
Gas imbalances			33				(7	)
Ineffective portion of cash flow hedges			1,134				(64	)
Deferred rent liability			33				49
Deferred income taxes			11,460				7,603
Interest accrued on officer and employee notes			(274	)			(510	)
Amortization of deferred loan costs			3,251				1,157
Amortization of discount on long-term debt			480				—
(Gain) loss on derivatives not designated as hedges			(3,088	)			—
Dedesignated cash flow hedges reclassed from AOCI			(722	)			—
Changes in operating assets and liabilities, net of acquisitions:
Accounts receivable			11,355				(25,943	)
Prepaid insurance and other			135				(1,752	)
Accounts payable			(9,230	)			2,373
Revenue payable			(5,325	)			(289	)
Accrued liabilities			1,492				204
Accrued interest			(6,249	)			4,024
Income taxes payable			225				—
Net cash provided by operating activities			102,932				58,941
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures on oil and gas properties			(113,936	)			(122,839	)
Acquisition of oil and gas properties and other assets			(256	)			(413,842	)
Additions to other property and equipment			(2,218	)			(1,249	)
Proceeds from the sale of oil and gas properties			96				—
Post-dedesignation settlements on dedesignated cash flow hedges			1,286				—
Net cash used in investing activities			(115,028	)			(537,930	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt			283,600				563,005
Payments of long-term debt			(433,700	)			(150,000	)
Proceeds from issuance of subscribed units and common stock			173,002				61,178
Payments of preferred stock dividends			(132	)			(2,542	)
Proceeds from repayment of officer and employee notes			10,644				—
Payments for loan origination costs			(2,572	)			(5,500	)
Negative cash balances			—				3,666
Net cash provided by financing activities			30,842				469,807
Net increase (decrease) in cash and cash equivalents			18,746				(9,182	)
BEGINNING CASH AND CASH EQUIVALENTS			1,122				9,182
ENDING CASH AND CASH EQUIVALENTS		$	19,868			$	—
		-
SUPPLEMENTAL CASH FLOWS:
Cash paid for interest and fees, net of $2,160 and $1,415 capitalized		$	28,233			$	11,294
Cash paid for income taxes		$	2,050			$	100
NON-CASH INVESTING AND FINANCING ACTIVITIES:
Issuance of common stock in acquisition of oil and gas properties and other assets		$	650			$	384,336
Deferred tax effect of acquired oil and gas properties		$	—			$	227,537
Issuance of notes receivable in connection with capital options		$	—			$	3,158
Discount on long-term debt		$	(1,000	)		$	—

Summary production and price data

The following table presents selected financial and operating information of Concho Resources Inc. for the three and nine months ended September 30, 2007 and 2006:

		Three months ended								Nine months ended
		September 30,								September 30,
		2007				2006				2007				2006
(in thousands, except price data)		(unaudited)								(unaudited)
Oil sales		$	45,685			$	40,239			$	128,152			$	90,737
Natural gas sales			23,413				18,036				67,395				44,908
Total operating revenues			69,098				58,275				195,547				135,645
Operating costs and expenses			46,602				38,543				134,864				94,167
Interest, net and other revenue			8,570				8,851				28,846				20,091
Income before income taxes			13,926				10,881				31,837				21,387
Income tax expense			(5,972	)			(4,351	)			(13,335	)			(8,664	)
Net income		$	7,954			$	6,530			$	18,502			$	12,723
Production volumes:
Oil (MBbl)			705				661				2,143				1,554
Natural gas (MMcf)			2,982				2,718				8,887				6,634
Natural gas equivalent (MMcfe)			7,211				6,683				21,747				15,956
Average prices:
Oil, without hedges ($/Bbl)		$	69.91			$	65.52			$	61.36			$	63.20
Oil, with hedges ($/Bbl)		$	64.82			$	60.89			$	59.79			$	58.40
Natural gas, without hedges ($/Mcf)		$	7.61			$	6.58			$	7.48			$	6.75
Natural gas, with hedges ($/Mcf)		$	7.85			$	6.63			$	7.58			$	6.77
Natural gas equivalent, without hedges ($/Mcfe)		$	9.98			$	9.16			$	9.10			$	8.96
Natural gas equivalent, with hedges ($/Mcfe)		$	9.58			$	8.72			$	8.99			$	8.50

Supplemental non-GAAP financial measures

EBITDAX (as defined below) is presented herein, and reconciled to the generally accepted accounting principle (“GAAP”) measure of net income because of its wide acceptance by the investment community as a financial indicator of a company’s ability to internally fund exploration and development activities.

We define EBITDAX as net income, plus (1) exploration and abandonments expense, (2) depreciation & depletion expense, (3) accretion expense, (4) impairments of proved oil and gas properties, (5) non-cash stock-based compensation expense, (6) ineffective portion of cash flow hedges and unrealized (gain) loss on derivatives not designated as hedges, (7) interest expense, the amortization of related debt issuance costs and other

financing costs, net of capitalized interest, and (8) federal and state income taxes, less other ancillary income including interest income, gathering income and rental income. EBITDAX is not a measure of net income or cash flow as determined by GAAP.

Our EBITDAX measure provides additional information which may be used to better understand our operations. EBITDAX is one of several metrics that we use as a supplemental financial measurement in the evaluation of our business and should not be considered as an alternative to, or more meaningful than, net income, as an indicator of our operating performance. Certain items excluded from EBITDAX are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic cost of depreciable assets, none of which are components of EBITDAX. EBITDAX as used by us may not be comparable to similarly titled measures reported by other companies. We believe that EBITDAX is a widely followed measure of operating performance and is one of many metrics used by our management team and by other users of our consolidated financial statements. For example, EBITDAX can be used to assess our operating performance and return on capital in comparison to other independent exploration and production companies without regard to financial or capital structure, and to assess the financial performance of our assets and our company without regard to capital structure or historical cost basis.

The following table provides a reconciliation of net income to EBITDAX:

		Three months ended								Nine months ended
		September 30,								September 30,
(in thousands)		2007				2006				2007				2006
		(unaudited)								(unaudited)
Net income		$	7,954			$	6,530			$	18,502			$	12,723
Exploration and abandonments			11,805				3,316				18,110				4,717
Depreciation and depletion			18,003				19,674				55,036				42,170
Accretion of discount on asset retirement obligations			106				87				334				196
Impairments of proved oil and gas properties			1,379				2,679				4,577				5,762
Non-cash stock-based compensation			703				1,090				2,656				8,041
Ineffective portion of cash flow hedges			(22	)			(1,190	)			1,134				(64	)
Unrealized (gain) loss on derivatives not designated as hedges			(1,802	)			—				(1,802	)			—
Interest expense			9,054				9,184				29,803				20,998
Other, net			(484	)			(333	)			(957	)			(907	)
Income tax expense			5,972				4,351				13,335				8,664
EBITDAX		$	52,668			$	45,388			$	140,728			$	102,300

Derivatives information as of September 30, 2007

     The table below provides the volumes and related data associated with our oil and natural gas derivatives as of September 30, 2007 (unaudited). Our counterparties in our derivative instruments are Bank of America, N.A., BNP Paribas, Citibank, N.A., JPMorgan Chase Bank, N.A. and Wachovia Bank, N.A.

		Fair Market Value				Aggregate
		Asset / (Liability)				remaining				Daily				Index				Contract
		(in thousands)				volume				volume				price				period
Cash flow hedges:
Crude oil (volumes in Bbls):
Price collar		$	(2,278	)			59,800				650			$	37.95 - $41.75	(a)			10/1/07 - 12/31/07
Price swap			(2,570	)			211,600				2,300			$	67.85	(a)			10/1/07 - 12/31/07
Price swap			(7,668	)			951,600				2,600			$	67.50	(a)			1/1/08 - 12/31/08
Cash flow hedges dedesignated:
Natural gas (volumes in MMBtus):
Price collar			735				1,472,000				16,000			$	5.98 - $9.75	(b) (c)			10/1/07 - 12/31/07
Price collar			1,740				4,941,000				13,500			$	6.50-$9.35	(b)			1/1/08 - 12/31/08
Price swap			257				193,200				2,100			$	7.40	(b)			10/1/07 - 12/31/07
Derivatives not designated as cash flow hedges:
Crude oil (volumes in Bbls):
Price swap			(33	)			732,000				2,000			$	75.78	(a) (c)			1/1/08 - 12/31/08
Price swap			71				730,000				2,000			$	72.84	(a) (c)			1/1/09 - 12/31/09
Net liability		$	(9,746	)

Contact:
Jack Harper (432) 683-7443
Vice President – Business Development and Capital Markets