Concho Resources Inc. Reports Second Quarter 2012 Financial and Operating Results

MIDLAND, Texas--(BUSINESS WIRE)--August 6, 2012--Concho Resources Inc. (NYSE: CXO) (“Concho” or the “Company”) today reported financial and operating results for the three and six months ended June 30, 2012. Highlights for the three and six months ended June 30, 2012 include:

¹Adjusted net income (non-GAAP) is comparable to securities analyst estimates. For an explanation of how we calculate adjusted net income (non-GAAP) and a reconciliation of net income (GAAP) to adjusted net income (non-GAAP), please see "Supplemental Non-GAAP Financial Measures" below.

²For an explanation of how we calculate and use EBITDAX (non-GAAP) and a reconciliation of net income (GAAP) to EBITDAX (non-GAAP), please see "Supplemental Non-GAAP Financial Measures" below.

The Company closed its previously announced acquisition of the oil and natural gas assets of Three Rivers Operating Company (“Three Rivers”) on July 2, 2012, paying a total of approximately $1.0 billion in cash funded by the Company’s revolving credit facility. Accordingly, results from the Three Rivers acquisition did not contribute to the Company’s second quarter results.

Production for the second quarter of 2012 totaled 6.8 MMBoe (4.2 million barrels of oil (“MMBbls”) and 15.6 billion cubic feet of natural gas (“Bcf”)), an increase of 22% as compared to 5.6 MMBoe (3.5 MMBbls and 12.3 Bcf) produced in the second quarter of 2011. During the second quarter of 2012, the Company estimates that production was negatively impacted by 3,000 barrels of oil equivalent per day (“Boepd”) due to scheduled and unscheduled maintenance and expansion work at two gas processing plants and a compression station in southeast New Mexico.

Tim Leach, Concho's Chairman, CEO and President commented, “The Permian Basin continues to be one of the most attractive and profitable oil basins in the country. The recent acquisition of assets from Three Rivers was our most strategic acquisition since Marbob and reinforced Concho’s significant presence in the Permian Basin. The unprecedented level of activity across the Permian Basin during the first half of 2012 has certainly introduced new challenges; however, I am confident that given our scale and continued success in our core areas, like the Delaware Basin, our capital budget and production guidance for the year remains on track.”

For the second quarter of 2012, the Company reported net income of $319.3 million, or $3.07 per diluted share, as compared to net income of $232.2 million, or $2.24 per diluted share, for the second quarter of 2011. The Company’s second quarter 2012 results were impacted by several non-cash items including: (1) a $394.8 million unrealized mark-to-market gain on commodity derivatives and (2) $8.4 million of leasehold abandonments. Excluding these items and their tax effects, the second quarter 2012 adjusted net income (non-GAAP) was $80.5 million, or $0.78 per diluted share. Excluding similar non-cash items and their tax impact, adjusted net income (non-GAAP) for the second quarter of 2011 was $113.2 million, or $1.09 per diluted share. For a description and a reconciliation of net income (GAAP) to adjusted net income (non-GAAP), please see “Supplemental Non-GAAP Financial Measures” below.

EBITDAX was $327.4 million in the second quarter of 2012, an increase of 5% from $310.7 million reported in the second quarter of 2011. For a description and a reconciliation of net income (GAAP) to EBITDAX (non-GAAP), please see “Supplemental Non-GAAP Financial Measures” below.

Oil and natural gas sales from continuing operations for the second quarter of 2012 decreased 3% when compared to the second quarter of 2011. This decrease was attributable to a 12% decrease in the Company’s unhedged realized oil price and a 46% decrease in the Company’s unhedged realized natural gas price, which was substantially offset by a 22% increase in production in the second quarter of 2012 compared to the second quarter of 2011. In addition, oil sales were adversely impacted by a temporary widening of the Midland-to-Cushing basis differential, which averaged approximately $5.00 per barrel during the second quarter of 2012. Today, the Midland-to-Cushing basis differential has returned to historical levels of less than $1.00 per barrel. Finally, natural gas price realizations were adversely impacted by the decline in natural gas liquids and residue gas prices.

Oil and natural gas production expense from continuing operations for the second quarter of 2012, including oil and natural gas taxes, totaled $87.7 million, or $12.85 per barrel of oil equivalent (“Boe”), a 3% increase per Boe from the second quarter of 2011. This increase was due primarily to higher lease operating expenses and workover costs, which averaged $7.52 per Boe in the second quarter of 2012 as compared to $5.97 per Boe in the second quarter of 2011, which was partially offset by lower oil and natural gas taxes, which averaged $5.33 per Boe in the second quarter of 2012 as compared to $6.51 per Boe in the second quarter of 2011. The increase in lease operating expenses per Boe over the second quarter 2011 is primarily due to an increase in workover costs and cost of services, including labor related expenses.

Depreciation, depletion and amortization expense (“DD&A”) from continuing operations for the second quarter of 2012 totaled $141.5 million, or $20.73 per Boe, a 17% increase per Boe from the second quarter of 2011.

General and administrative expense (“G&A”) from continuing operations for the second quarter of 2012 totaled $32.0 million, or $4.69 per Boe, as compared to $22.6 million, or $4.06 per Boe, in the second quarter of 2011. Cash G&A for the second quarter of 2012 totaled $24.6 million and stock-based compensation (non-cash) totaled $7.4 million. The increase in per Boe expense for the second quarter of 2012 over the second quarter of 2011 was primarily due to a 41% increase in absolute G&A expenses reflecting increased staffing across the Company, and was partially offset by a 22% increase in production.

The Company’s cash flow from operating activities (GAAP) was $611.0 million for the first six months of 2012, as compared to $485.8 million for the first six months of 2011, an increase of 26%. Adjusted cash flows (non-GAAP), which are cash flows from operating activities (GAAP) adjusted for settlements paid on derivatives not designated as hedges, were $587.3 million for the first six months of 2012, as compared to $409.8 million for the first six months of 2011, an increase of 43%. For a description of the use of adjusted cash flows (non-GAAP) and for a reconciliation of cash flows from operating activities (GAAP) to adjusted cash flows (non-GAAP), please see “Supplemental Non-GAAP Financial Measures” below.

In the second quarter of 2012, the Company collected net cash receipts on derivatives not designated as hedges of $8.3 million and the non-cash unrealized mark-to-market gain on derivatives not designated as hedges was $394.8 million. In comparison, the Company made net cash payments of $47.8 million on derivatives not designated as hedges and reported a $192.6 million non-cash unrealized mark-to-market gain on derivatives not designated as hedges in the second quarter of 2011. To better understand the impact of the Company’s derivative positions and their impact on the statements of operations, please see the “Summary Production and Operating Data” and “Derivatives Information” tables at the end of this press release.

For the quarter ended June 30, 2012, the Company commenced the drilling of or participated in a total of 221 gross wells (186 operated), 84 of which had been completed as producers and 137 of which were in progress at June 30, 2012. In addition, during the second quarter of 2012, the Company completed 139 wells that were drilled prior to the second quarter of 2012.

Currently, the Company is operating 37 drilling rigs; 7 of these rigs are drilling Yeso wells on the New Mexico Shelf, 19 are drilling in the Texas Permian, 10 are drilling in the Delaware Basin and 1 rig is drilling Lower Abo wells in the New Mexico Shelf. Included in the 37 operated rigs, the Company is currently running 15 horizontal drilling rigs, including 10 in the Delaware Basin, 1 in the Texas Permian and 4 on the New Mexico Shelf.

For the remainder of 2012, the Company expects to operate an average of approximately 33 rigs, including 13 horizontal drilling rigs. Of the total 33 rigs, 7 will drill Yeso wells in the New Mexico Shelf, 17 will drill in the Texas Permian and 9 will drill in the Delaware Basin. The Company expects this level of activity is sufficient to invest the remainder of its $1.5 billion annual capital budget and produce 28.7 to 29.8 MMBoe in 2012 as previously guided.

During the second quarter of 2012, the Company drilled or participated in 93 wells (78 operated) on its New Mexico Shelf assets, which included both Yeso and Lower Abo wells, with a 100% success rate on the 47 wells that had been completed by June 30, 2012. In addition, during the second quarter of 2012, the Company completed 60 wells that were drilled prior to the second quarter of 2012.

At June 30, 2012, on its New Mexico Shelf assets, the Company had identified 2,470 drilling locations, including locations associated with the Three Rivers acquisition, with proved undeveloped reserves attributable to 680 of such locations. Of these 2,470 drilling locations, 1,559 target the Yeso formation vertically, 369 target the Yeso formation horizontally, 111 target the Lower Abo formation and the remaining drilling locations target other objectives.

During the second quarter of 2012, the Company drilled or participated in 89 wells (88 operated) on its Texas Permian assets with a 100% success rate on the 31 wells that had been completed by June 30, 2012. In addition, during the second quarter of 2012, the Company completed 57 wells that were drilled prior to the second quarter of 2012.

At June 30, 2012, on its Texas Permian assets, the Company had identified 5,772 drilling locations, including locations associated with the Three Rivers acquisition, with proved undeveloped reserves attributable to 1,786 of such locations. Of these 5,772 drilling locations, 2,064 target the Wolfberry play through 40-acre spacing, 2,629 target the Wolfberry play on 20-acre spacing, 927 target the Wolfcamp vertically in Irion and Schleicher Counties and the remaining drilling locations target other objectives. The Company recently began testing a horizontal Cline shale exploration concept in the northern Midland Basin and as of June 30, 2012, had not included any potential drilling locations across its approximately 74,000 gross (51,000 net) acres in Terry and Hockley Counties.

During the second quarter of 2012, the Company drilled or participated in 39 wells (20 operated) with a 100% success rate on the 6 wells that had been completed by June 30, 2012. Of the 39 wells drilled, all were horizontal, which included 30 Bone Spring sand wells, 1 Avalon shale well, 5 Wolfcamp shale wells and 3 Delaware sands wells. In addition, during the second quarter of 2012, the Company completed 22 wells that were drilled prior to the second quarter of 2012. The Company’s net production in the second quarter of 2012 from horizontal Delaware Basin wells averaged approximately 13,850 Boepd, an increase of 12% over the first quarter of 2012 and a 147% increase over the second quarter of 2011.

At June 30, 2012, on its Delaware Basin assets, the Company had identified 2,375 drilling locations, including the locations associated with the Three Rivers acquisition, with proved undeveloped reserves attributable to 195 of such locations. Substantially all of the 2,375 drilling locations target horizontal objectives in the northern Delaware Basin. The Company has excluded all 364 vertical Wolfbone play drilling locations in the southern Delaware Basin, which were previously identified as of December 31, 2011. The Company recently began testing a horizontal Wolfcamp shale exploration concept in the southern Delaware Basin and as of June 30, 2012, had not included any potential drilling locations across its approximately 140,000 gross (125,000 net) acres in the southern Delaware Basin. Currently, the Company has completed 3 horizontal Wolfcamp shale wells on its acreage in Reeves County and expects to drill another 7 horizontal wells on its acreage in both Reeves and Pecos Counties during 2012.

At June 30, 2012, the Company had $427 million of indebtedness outstanding under its $2.5 billion credit facility. Pro forma for the closing of the Three Rivers acquisition on July 2, 2012, the Company’s outstanding borrowings under the credit facility would have been $1.4 billion on June 30, 2012, leaving approximately $1.1 billion available to be borrowed.

The Company maintains an active hedging program and added to its derivative positions in July 2012. Please see the “Derivatives Information” tables at the end of this press release for more detailed information about the Company’s current derivative positions.

The Company will host a conference call on Tuesday, August 7, 2012 at 9:00 a.m. Central Time to discuss the second quarter 2012 financial and operating results. Interested parties may listen to the conference call via the Company’s website at www.concho.com or by dialing (800) 638-5439 (passcode: 79957631). A replay of the conference call will be available on the Company’s website or by dialing (888) 286-8010 (passcode: 75490323).

Concho Resources Inc. is an independent oil and natural gas company engaged in the acquisition, development and exploration of oil and natural gas properties. The Company's operations are focused in the Permian Basin of Southeast New Mexico and West Texas. For more information, visit Concho’s website at www.concho.com.

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 statements, estimates and projections regarding the Company's future financial position, operations, performance, production growth, returns, capital expenditure budget, oil and natural gas reserves, number of identified drilling locations, drilling program, derivative activities, costs and other guidance. These statements are based on certain assumptions made by the Company based on management's experience, expectations and perception of historical trends, current conditions, anticipated future developments and other factors believed to be appropriate. Forward-looking statements are not guarantees of performance. Although the Company believes the expectations reflected in its forward-looking statements are reasonable and are based on reasonable assumptions, no assurance can be given that these assumptions are accurate or that any of these expectations will be achieved (in full or at all) or will prove to have been correct. Moreover, 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 the factors discussed or referenced in the "Risk Factors" section of the Company's most recent Form 10-K and 10-Q filings and risks relating to declines in the prices we receive for our oil and natural gas; uncertainties about the estimated quantities of reserves; risks related to the integration of acquired assets; the effects of government regulation, permitting and other legal requirements, including new legislation or regulation of hydraulic fracturing; drilling and operating risks; the adequacy of our capital resources and liquidity; risks related to the concentration of our operations in the Permian Basin; the results of our hedging program; weather; litigation; shortages of oilfield equipment, services and qualified personnel and increases in costs for such equipment, services and personnel; uncertainties about our ability to replace reserves and economically develop our current reserves; competition in the oil and natural gas industry; and other important factors that could cause actual results to differ materially from those projected.

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.


Concho Resources Inc. Consolidated Balance Sheets Unaudited


	June 30,			December 31,
(in thousands, except share and per share amounts)	2012			2011
Assets
Current assets:
Cash and cash equivalents	$	710		$	342
Accounts receivable, net of allowance for doubtful accounts:
Oil and natural gas		167,138			213,921
Joint operations and other		208,353			153,746
Derivative instruments		126,723			1,698
Deferred income taxes		-			28,793
Prepaid costs and other		12,144			12,523
Total current assets		515,068			411,023
Property and equipment:
Oil and natural gas properties, successful efforts method		8,279,969			7,347,460
Accumulated depletion and depreciation		(1,388,180	)		(1,116,545	)
Total oil and natural gas properties, net		6,891,789			6,230,915
Other property and equipment, net		99,590			59,203
Total property and equipment, net		6,991,379			6,290,118
Funds held in escrow		50,000			17,394
Deferred loan costs, net		72,281			65,641
Intangible asset - operating rights, net		32,651			33,425
Inventory		25,749			19,419
Noncurrent derivative instruments		63,029			7,944
Other assets		8,152			4,612
Total assets	$	7,758,309		$	6,849,576
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable:
Trade	$	29,361		$	23,341
Related parties		540			11
Bank overdrafts		33,528			39,241
Revenue payable		133,808			146,061
Accrued and prepaid drilling costs		319,601			293,919
Derivative instruments		-			56,218
Deferred income taxes		45,076			-
Other current liabilities		137,171			142,686
Total current liabilities		699,085			701,477
Long-term debt		2,523,366			2,080,141
Deferred income taxes		1,120,593			1,002,295
Noncurrent derivative instruments		-			32,254
Asset retirement obligations and other long-term liabilities		59,700			52,670
Commitments and contingencies
Stockholders’ equity:
Common stock, $0.001 par value; 300,000,000 authorized; 104,386,021 and 103,756,222 shares issued at June 30, 2012 and December 31, 2011, respectively		104			104
Additional paid-in capital		1,952,735			1,925,757
Retained earnings		1,409,288			1,058,874
Treasury stock, at cost; 79,643 and 55,990 shares at June 30, 2012 and December 31, 2011, respectively		(6,562	)		(3,996	)
Total stockholders’ equity		3,355,565			2,980,739
Total liabilities and stockholders’ equity	$	7,758,309		$	6,849,576


Concho Resources Inc. Consolidated Statements of Operations Unaudited


	Three Months Ended						Six Months Ended
	June 30,						June 30,
(in thousands, except per share amounts)	2012			2011			2012			2011

Operating revenues:
Oil sales	$	361,313		$	342,747		$	774,960		$	625,174
Natural gas sales		71,483			103,485			165,641			181,898
Total operating revenues		432,796			446,232			940,601			807,072
Operating costs and expenses:
Oil and natural gas production		87,689			69,577			179,839			133,235
Exploration and abandonments		14,398			400			20,377			1,126
Depreciation, depletion and amortization		141,450			98,881			277,319			189,169
Accretion of discount on asset retirement obligations		1,047			715			2,035			1,419
Impairments of long-lived assets		-			76			-			76
General and administrative (including non-cash stock-based compensation of $7,347 and $4,725 for the three months ended June 30, 2012 and 2011, respectively, and $13,475 and $9,193 for the six months ended June 30, 2012 and 2011, respectively)		31,968			22,618			59,355			44,010
(Gain) loss on derivatives not designated as hedges		(403,050	)		(144,882	)		(244,957	)		88,260
Total operating costs and expenses		(126,498	)		47,385			293,968			457,295
Income from operations		559,294			398,847			646,633			349,777
Other income (expense):
Interest expense		(41,899	)		(21,660	)		(77,736	)		(51,320	)
Other, net		(535	)		(1,735	)		(1,803	)		(2,087	)
Total other expense		(42,434	)		(23,395	)		(79,539	)		(53,407	)
Income from continuing operations before income taxes		516,860			375,452			567,094			296,370
Income tax expense		(197,563	)		(143,270	)		(216,680	)		(112,801	)
Income from continuing operations		319,297			232,182			350,414			183,569
Income from discontinued operations, net of tax		-			-			-			91,188
Net income	$	319,297		$	232,182		$	350,414		$	274,757
Basic earnings per share:
Income from continuing operations	$	3.10		$	2.26		$	3.40		$	1.79
Income from discontinued operations, net of tax		-			-			-			0.89
Net income per share	$	3.10		$	2.26		$	3.40		$	2.68
Weighted average shares used in basic earnings per share		103,114			102,569			102,984			102,407
Diluted earnings per share:
Income from continuing operations	$	3.07		$	2.24		$	3.38		$	1.77
Income from discontinued operations, net of tax		-			-			-			0.88
Net income per share	$	3.07		$	2.24		$	3.38		$	2.65
Weighted average shares used in diluted earnings per share		103,880			103,638			103,825			103,570


Concho Resources Inc. Consolidated Statements of Cash Flows Unaudited


	Six Months Ended
	June 30,
(in thousands)	2012			2011
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	350,414		$	274,757
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		277,319			189,169
Impairments of long-lived assets		-			76
Accretion of discount on asset retirement obligations		2,035			1,419
Exploration and abandonments, including dry holes		11,539			168
Non-cash compensation expense		13,475			9,193
Deferred income taxes		202,559			101,967
Loss on sale of assets, net		68			1,455
(Gain) loss on derivatives not designated as hedges		(244,957	)		88,260
Discontinued operations		-			(82,118	)
Other non-cash items		5,837			(2,321	)
Changes in operating assets and liabilities, net of acquisitions:
Accounts receivable		7,425			(105,761	)
Prepaid costs and other		(3,160	)		(3,734	)
Inventory		(6,385	)		(10,868	)
Accounts payable		6,549			(29,488	)
Revenue payable		(12,253	)		66,164
Other current liabilities		500			(12,491	)
Net cash provided by operating activities		610,965			485,847
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures on oil and natural gas properties		(949,059	)		(677,172	)
Additions to other property and equipment		(45,701	)		(24,981	)
Proceeds from the sale of assets		4,419			196,252
Funds held in escrow		(32,606	)		-
Settlements paid on derivatives not designated as hedges		(23,624	)		(76,047	)
Net cash used in investing activities		(1,046,571	)		(581,948	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of debt		1,776,500			1,645,000
Payments of debt		(1,333,500	)		(1,569,000	)
Exercise of stock options		3,110			7,140
Excess tax benefit from stock-based compensation		10,393			21,117
Payments for loan costs		(12,250	)		(24,466	)
Purchase of treasury stock		(2,566	)		(1,720	)
Bank overdrafts		(5,713	)		18,043
Net cash provided by financing activities		435,974			96,114
Net increase in cash and cash equivalents		368			13
Cash and cash equivalents at beginning of period		342			384
Cash and cash equivalents at end of period	$	710		$	397
SUPPLEMENTAL CASH FLOWS:
Cash paid for interest and fees, net of $73 capitalized interest in 2011	$	67,528		$	32,069
Cash paid for income taxes	$	12,982		$	14,322


Concho Resources Inc. Summary Production and Price Data Unaudited

The following table sets forth summary information from our continuing and discontinued operations concerning our production and operating data for the periods indicated:


			Three Months Ended					Six Months Ended
			June 30,					June 30,
			2012		2011			2012			2011

Production and operating data:
Net production volumes:
Oil (MBbl)				4,220		3,522			8,434			6,749
Natural gas (MMcf)				15,619		12,307			31,848			24,314
Total (MBoe)				6,823		5,573			13,742			10,801

Average daily production volumes:
Oil (Bbl)				46,374		38,703			46,341			37,287
Natural gas (Mcf)				171,637		135,242			174,989			134,331
Total (Boe)				74,980		61,244			75,506			59,675

Average prices:
Oil, without derivatives (Bbl)			$	85.62	$	97.32		$	91.89		$	94.03
Oil, with derivatives (Bbl) ^(a)			$	87.51	$	83.57		$	89.01		$	82.09
Natural gas, without derivatives (Mcf)			$	4.58	$	8.41		$	5.20		$	7.48
Natural gas, with derivatives (Mcf) ^(a)			$	4.60	$	8.90		$	5.22		$	7.94
Total, without derivatives (Boe)			$	63.43	$	80.07		$	68.45		$	75.60
Total, with derivatives (Boe) ^(a)			$	64.65	$	72.48		$	66.73		$	69.18

Operating costs and expenses per Boe:
Lease operating expenses and workover costs			$	7.52	$	5.97		$	7.40		$	6.28
Oil and natural gas taxes			$	5.33	$	6.51		$	5.69		$	6.21
Depreciation, depletion and amortization			$	20.73	$	17.74		$	20.18		$	17.71
General and administrative			$	4.69	$	4.06		$	4.32		$	4.07

	(a)	Includes the effect of cash settlements received from (paid on) commodity derivatives not designated as hedges and reported in operating costs and expenses. The following table reflects the amounts of cash settlements received from (paid on) commodity derivatives not designated as hedges that were included in computing average prices with derivatives and reconciles to the amount in gain (loss) on derivatives not designated as hedges as reported in the statements of operations:



			Three Months Ended					Six Months Ended
			June 30,					June 30,
		(in thousands)	2012		2011			2012			2011

		Gain (loss) on derivatives not designated as hedges:
		Cash receipts from (payments on) oil derivatives	$	7,963	$	(48,398	)	$	(24,233	)	$	(80,628	)
		Cash receipts from natural gas derivatives		324		6,076			609			11,205
		Cash payments on interest rate derivatives		-		(5,429	)		-			(6,624	)
		Unrealized mark-to-market gain (loss) on commodity and interest rate derivatives		394,763		192,633			268,581			(12,213	)
		Gain (loss) on derivatives not designated as hedges	$	403,050	$	144,882		$	244,957		$	(88,260	)


		The presentation of average prices with derivatives is a non-GAAP measure as a result of including the cash receipts from (payments on) commodity derivatives that are presented in gain (loss) on derivatives not designated as hedges in the statements of operations. This presentation of average prices with derivatives is a means by which to reflect the actual cash performance of our commodity derivatives for the respective periods and presents oil and natural gas prices with derivatives in a manner consistent with the presentation generally used by the investment community.


The following table sets forth summary information from our continuing operations concerning production and operating data for the periods indicated:


			Three Months Ended					Six Months Ended
			June 30,					June 30,
			2012		2011			2012			2011

Production and operating data:
Net production volumes:
Oil (MBbl)				4,220		3,522			8,434			6,632
Natural gas (MMcf)				15,619		12,307			31,848			24,277
Total (MBoe)				6,823		5,573			13,742			10,678

Average daily production volumes:
Oil (Bbl)				46,374		38,703			46,341			36,641
Natural gas (Mcf)				171,637		135,242			174,989			134,127
Total (Boe)				74,980		61,244			75,506			58,995

Average prices:
Oil, without derivatives (Bbl)			$	85.62	$	97.32		$	91.89		$	94.27
Oil, with derivatives (Bbl) ^(a)			$	87.51	$	83.57		$	89.01		$	82.11
Natural gas, without derivatives (Mcf)			$	4.58	$	8.41		$	5.20		$	7.49
Natural gas, with derivatives (Mcf) ^(a)			$	4.60	$	8.90		$	5.22		$	7.95
Total, without derivatives (Boe)			$	63.43	$	80.07		$	68.45		$	75.58
Total, with derivatives (Boe) ^(a)			$	64.65	$	72.48		$	66.73		$	69.08

Operating costs and expenses per Boe:
Lease operating expenses and workover costs			$	7.52	$	5.97		$	7.40		$	6.31
Oil and natural gas taxes			$	5.33	$	6.51		$	5.69		$	6.17
Depreciation, depletion and amortization			$	20.73	$	17.74		$	20.18		$	17.72
General and administrative			$	4.69	$	4.06		$	4.32		$	4.12

	(a)	Includes the effect of cash settlements received from (paid on) commodity derivatives not designated as hedges and reported in operating costs and expenses. The following table reflects the amounts of cash settlements received from (paid on) commodity derivatives not designated as hedges that were included in computing average prices with derivatives and reconciles to the amount in gain (loss) on derivatives not designated as hedges as reported in the statements of operations:




			Three Months Ended					Six Months Ended
			June 30,					June 30,
		(in thousands)	2012		2011			2012			2011

		Gain (loss) on derivatives not designated as hedges:
		Cash receipts from (payments on) oil derivatives	$	7,963	$	(48,398	)	$	(24,233	)	$	(80,628	)
		Cash receipts from natural gas derivatives		324		6,076			609			11,205
		Cash payments on interest rate derivatives		-		(5,429	)		-			(6,624	)
		Unrealized mark-to-market gain (loss) on commodity and interest rate derivatives		394,763		192,633			268,581			(12,213	)
		Gain (loss) on derivatives not designated as hedges	$	403,050	$	144,882		$	244,957		$	(88,260	)


		The presentation of average prices with derivatives is a non-GAAP measure as a result of including the cash receipts from (payments on) commodity derivatives that are presented in gain (loss) on derivatives not designated as hedges in the statements of operations. This presentation of average prices with derivatives is a means by which to reflect the actual cash performance of our commodity derivatives for the respective periods and presents oil and natural gas prices with derivatives in a manner consistent with the presentation generally used by the investment community.


	Concho Resources Inc. Supplemental Non-GAAP Financial Measures Unaudited

The following tables provide information that the Company believes may be useful to investors who follow the practice of some industry analysts who adjust reported company net income and cash flows from operating activities to exclude certain non-cash items. Adjusted Net Income The following table provides a reconciliation of net income (GAAP) to adjusted net income (non-GAAP) for the three and six months ended June 30, 2012 and 2011.


		Three Months Ended						Six Months Ended
		June 30,						June 30,
	(in thousands, except per share amounts)	2012			2011			2012			2011

	Net income - as reported	$	319,297		$	232,182		$	350,414		$	274,757

	Adjustments for certain non-cash items:
	Unrealized (gain) loss on commodity and interest rate derivatives		(394,763	)		(192,633	)		(268,581	)		12,213
	Impairments of long-lived assets		-			76			-			76
	Leasehold abandonments		8,437			30			8,557			156
	Discontinued operations:
	Gain on sale of assets		-			-			-			(141,950	)
	Tax impact ^(a)		147,577			73,545			99,329			49,341
	Adjusted net income	$	80,548		$	113,200		$	189,719		$	194,593

	Adjusted basic earnings per share:
	Adjusted net income per share	$	0.78		$	1.10		$	1.84		$	1.90
	Weighted average shares used in adjusted basic earnings per share		103,114			102,569			102,984			102,407

	Adjusted diluted earnings per share:
	Adjusted net income per share	$	0.78		$	1.09		$	1.83		$	1.88
	Weighted average shares used in adjusted diluted earnings per share		103,880			103,638			103,825			103,570


(a)	The tax impact is computed utilizing the Company's statutory effective federal and state income tax rates. The income tax rates for the three months ended June 30, 2012 and 2011 were both approximately 38.2%, and 38.2% and 38.1% for the six months ended June 30, 2012 and 2011, respectively.

The following table provides a reconciliation of cash flows from operating activities (GAAP) to adjusted cash flows (non-GAAP) for the six months ended June 30, 2012 and 2011.

EBITDAX (as defined below) is presented herein, and reconciled from the generally accepted accounting principles ("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 and amortization expense, (3) accretion expense, (4) impairments of long-lived assets, (5) non-cash stock-based compensation expense, (6) bad debt expense, (7) unrealized (gain) loss on derivatives not designated as hedges, (8) (gain) loss on sale of assets, net, (9) interest expense, (10) federal and state income taxes on continuing operations and (11) similar items listed above that are presented in discontinued operations. EBITDAX is not a measure of net income or cash flows as determined by GAAP.

Our EBITDAX measure (which includes continuing and discontinued operations) 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 for the three and six months ended June 30, 2012 and 2011:



	Three Months Ended						Six Months Ended
	June 30,						June 30,
(in thousands)	2012			2011			2012			2011

Net income	$	319,297		$	232,182		$	350,414		$	274,757
Exploration and abandonments		14,398			400			20,377			1,126
Depreciation, depletion and amortization		141,450			98,881			277,319			189,169
Accretion of discount on asset retirement obligations		1,047			715			2,035			1,419
Impairments of long-lived assets		-			76			-			76
Non-cash stock-based compensation		7,347			4,725			13,475			9,193
Unrealized (gain) loss on derivatives not designated as hedges		(394,763	)		(192,633	)		(268,581	)		12,213
(Gain) loss on sale of assets, net		(827	)		1,431			68			1,455
Interest expense		41,899			21,660			77,736			51,320
Income tax expense on continuing operations		197,563			143,270			216,680			112,801
Discontinued operations		-			-			-			(83,306	)
EBITDAX	$	327,411		$	310,707		$	689,523		$	570,223


Concho Resources Inc. Costs Incurred Unaudited

The table below provides the costs incurred for the three and six months ended June 30, 2012 and 2011.

Costs incurred for oil and natural gas producing activities ^(a)


		Three Months Ended				Six Months Ended
		June 30,				June 30,
(in thousands)		2012		2011		2012		2011

Property acquisition costs:
Proved		$	5,568	$	3,230	$	165,615	$	69,148
Unproved			21,851		18,132		61,207		75,340
Exploration			159,013		181,353		343,496		271,919
Development			192,051		140,768		386,782		334,485
Total costs incurred for oil and natural gas properties		$	378,483	$	343,483	$	957,100	$	750,892



(a)	The costs incurred for oil and natural gas producing activities includes the following amounts of asset retirement obligations:


		Three Months Ended				Six Months Ended
		June 30,				June 30,
	(in thousands)	2012		2011		2012		2011

	Proved property acquisition costs	$	77	$	-	$	2,127	$	148
	Exploration costs		469		320		1,267		640
	Development costs		3,239		757		3,283		752
	Total	$	3,785	$	1,077	$	6,677	$	1,540


Concho Resources Inc. Derivatives Information Unaudited

The table below provides data associated with the Company’s derivatives at August 6, 2012.


		2012
		Third Quarter		Fourth Quarter		Total		2013		2014		2015		2016		2017

Oil Swaps:
	Volume (Bbl)		4,044,500		3,676,500		7,721,000		12,215,000		6,043,000		1,076,000		429,000		168,000
	NYMEX price (Bbl) ^(a)	$	96.15	$	96.01	$	96.08	$	96.01	$	91.99	$	86.69	$	88.31	$	87.00

Natural Gas Swaps:
	Volume (MMBtu)		75,000		75,000		150,000		-		-		-		-		-
	NYMEX price (MMBtu)^(b)	$	6.54	$	6.54	$	6.54		-		-		-		-		-


(a)	The index prices for the oil contracts are based on the NYMEX – West Texas Intermediate monthly average futures price.
(b)	The index prices for the natural gas contracts are based on the NYMEX – Henry Hub last trading day of the month futures price.

CONTACT:
Concho Resources Inc.
Price Moncrief, 432-683-7443
Vice President of Capital Markets and Strategy

001-33615		76-0818600
(Commission File Number)		(I.R.S. Employer Identification No.)

550 West Texas Avenue, Suite 100 Midland, Texas		79701
(Address of Principal Executive Offices)		(Zip Code)

Exhibit No.		Description of Exhibit

99.1		Press release dated August 6, 2012, announcing financial and operating results for the quarter and six months ended June 30, 2012.

	CONCHO RESOURCES INC.

Date: August 6, 2012	By:	/s/ C. WILLIAM GIRAUD
	Name:		C. William Giraud
	Title:		Senior Vice President and General Counsel

Exhibit No.		Description of Exhibit

99.1		Press release dated August 6, 2012, announcing financial and operating results for the quarter and six months ended June 30, 2012.