10-K

 

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

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

For the fiscal year ended December 31, 2015

or

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

For the transition period from to

Commission file number: 1-33615

Concho Resources Inc.

(Exact name of registrant as specified in its charter)

Delaware	76-0818600
State or other jurisdiction	(I.R.S. Employer
of incorporation or organization	Identification No.)
One Concho Center
600 West Illinois Avenue
Midland, Texas	79701
(Address of principal executive offices)	(Zip code)

(432) 683-7443

Registrant’s telephone number, including area code

Securities Registered Pursuant to Section 12(b) of the Act:

	Name of each exchange
Title of each class	on which registered
Common Stock, $0.001 par value	New York Stock Exchange

Securities Registered Pursuant to Section 12(g) of the Act:  None 

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.      Yes ☑  No o 

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.  Yes o  No ☑  

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes ☑  No o  

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  ☑ 

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

Large accelerated filer ☑	Accelerated filer o
Non-accelerated filer   o  (Do not check if a smaller reporting company)	Smaller reporting company o

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

Aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter:	$	14,274,370,137
Number of shares of the registrant’s common stock outstanding as of February 22, 2016:		129,357,977

Documents Incorporated by Reference:

Portions of the registrant’s definitive proxy statement for its 2016 Annual Meeting of Stockholders, which will be filed with the United States Securities and Exchange Commission within 120 days of December 31, 2015, are incorporated by reference into Part III of this Form 10-K for the year ended December 31, 2015.

TABLE OF CONTENTS
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS			1
PART I			2
	Item 1. Business		2
		General	2
		Business and Properties	2
		Summary of Core Operating Areas and Other Plays	3
		Drilling Activities	5
		Our Production, Prices and Expenses	6
		Productive Wells	7
		Marketing Arrangements	8
		Our Principal Customers	8
		Competition	8
		Applicable Laws and Regulations	10
		Our Employees	16
		Available Information	16
		Non-GAAP Financial Measures and Reconciliations	17
	Item 1A. Risk Factors		19
		Risks Related to Our Business	19
		Risks Related to Our Common Stock	36
	Item 1B. Unresolved Staff Comments		37
	Item 2. Properties		37
		Our Oil and Natural Gas Reserves	37
		Developed and Undeveloped Acreage	41
		Title to Our Properties	42
	Item 3. Legal Proceedings		42
	Item 4. Mine Safety Disclosures		42
PART II			43
	Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		43
		Market Information	43
		Dividend Policy	43
		Repurchases of Equity Securities	43
	Item 6. Selected Financial Data		44
		Selected Historical Financial Information	44
	Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations		46
		Overview	46
		Financial and Operating Performance	47
		Commodity Prices	48
		Recent Events	50
		Derivative Financial Instruments	51
		Results of Operations	52
		Year Ended December 31, 2015 Compared to Year Ended December 31, 2014	54
		Year Ended December 31, 2014 Compared to Year Ended December 31, 2013	60
		Capital Commitments, Capital Resources and Liquidity	66
		Critical Accounting Policies and Practices	71
		Recent Accounting Pronouncements	74
	Item 7A. Quantitative and Qualitative Disclosures About Market Risk		76
		Credit risk	76
		Commodity price risk	76
		Interest rate risk	77
	Item 8. Financial Statements and Supplementary Data		79
	Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		79
	Item 9A. Controls and Procedures		79
		Evaluation of Disclosure Controls and Procedures	79
		Changes in Internal Control over Financial Reporting	79
		Management's Report on Internal Control over Financial Reporting	80
		Report of Independent Registered Public Accounting Firm	81
	Item 9B. Other Information		82
PART III			83
	Item 10. Directors, Executive Officers and Corporate Governance		83
	Item 11. Executive Compensation		83
	Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		83
		Equity Compensation Plans	83
	Item 13. Certain Relationships and Related Transactions, and Director Independence		84
	Item 14. Principal Accounting Fees and Services		84
PART IV			85
	Item 15. Exhibits, Financial Statement Schedules		85
GLOSSARY OF TERMS			90
SIGNATURES			94
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS			F-1

ii

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

Various statements and information contained in or incorporated by reference into this report that express a belief, expectation, or intention, or that are not statements of historical fact, are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 (the “Securities Act”) and Section 21E of the Securities Exchange Act of 1934 (the “Exchange Act”). These forward-looking statements include statements, projections and estimates concerning our future financial position, operations, performance, business strategy, oil and natural gas reserves, drilling program, capital expenditures, liquidity and capital resources, the timing and success of specific projects, outcomes and effects of litigation, claims and disputes, derivative activities and potential financing. Forward-looking statements are generally accompanied by words such as “estimate,” “project,” “predict,” “believe,” “expect,” “anticipate,” “potential,” “could,” “may,” “foresee,” “plan,” “goal” or other words that convey the uncertainty of future events or outcomes. Forward-looking statements are not guarantees of performance. We have based these forward-looking statements on our current expectations and assumptions about future events and their potential effect on us. These statements are based on certain assumptions and analyses made by us in light of our experience and our perception of historical trends, current conditions and expected future developments as well as other factors we believe are appropriate under the circumstances. Actual results may differ materially from those implied or expressed by any forward-looking statements. These forward-looking statements speak only as of the date of this report, or if earlier, as of the date they were made. We disclaim any obligation to update or revise these statements unless required by law, and we caution you not to rely on them unduly. While our management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties relating to, among other matters, the risks discussed in “Item 1A. Risk Factors” in this report, as well as those factors summarized below:

·declines in the prices we receive, or sustained depressed prices we receive, for our oil and natural gas;

·uncertainties about the estimated quantities of oil and natural gas reserves;

·drilling and operating risks;

·the adequacy of our capital resources and liquidity including, but not limited to, access to additional borrowing capacity under our credit facility;

·the effects of government regulation, permitting and other legal requirements, including new legislation or regulation of hydraulic fracturing and the export of oil and natural gas;

·the impact of potential changes in our credit ratings;

·environmental hazards, such as uncontrollable flows of oil, natural gas, brine, well fluids, toxic gas or other pollution into the environment, including groundwater contamination;

·difficult and adverse conditions in the domestic and global capital and credit markets;

·risks related to the concentration of our operations in the Permian Basin of Southeast New Mexico and West Texas;

·disruptions to, capacity constraints in or other limitations on the pipeline systems that deliver our oil, natural gas liquids and natural gas and other processing and transportation considerations;

·the costs and availability of equipment, resources, services and personnel required to perform our drilling and operating activities;

·potential financial losses or earnings reductions from our commodity price risk-management program;

·risks and liabilities associated with acquired properties or businesses;

·uncertainties about our ability to successfully execute our business and financial plans and strategies;

·uncertainties about our ability to replace reserves and economically develop our current reserves;

·general economic and business conditions, either internationally or domestically;

·competition in the oil and natural gas industry; and

·uncertainty concerning our assumed or possible future results of operations.

Reserve engineering is a process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by our reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ from the quantities of oil and natural gas that are ultimately recovered.   

1

PART I

Item 1. Business

General

Concho Resources Inc., a Delaware corporation (“Concho,” the “Company,” “we,” “us” and “our”) formed in February 2006, is an independent oil and natural gas company engaged in the acquisition, development, exploration and production of oil and natural gas properties. Our core operations are focused in the Permian Basin of Southeast New Mexico and West Texas, a large onshore oil and natural gas basin in the United States. The Permian Basin is one of the most prolific oil and natural gas producing regions in the United States and is characterized by an extensive production history, long reserve life, multiple producing horizons and enhanced recovery potential. Currently, the majority of the rigs running in the Permian Basin are drilling horizontal wells. Concho’s legacy in the Permian Basin provides us a deep understanding of operating and geological trends. We are also at the forefront of applying new technologies, such as horizontal drilling and enhanced completion techniques, throughout our three core operating areas: the New Mexico Shelf, the Delaware Basin and the Midland Basin. On the New Mexico Shelf, we primarily target the Yeso formation with horizontal drilling; in the Delaware Basin, we use horizontal drilling to target the Bone Spring formation (including the Avalon shale and the Bone Spring sands) and the Wolfcamp shale formation; and in the Midland Basin, we target the Wolfcamp and Spraberry formations primarily with horizontal drilling. Our strategy remains focused on drilling and exploration activities on our multi-year project inventory and pursuing acquisitions that meet our strategic and financial objectives.

Business and Properties

Our core operations are focused in the Permian Basin, which underlies an area of Southeast New Mexico and West Texas approximately 250 miles wide and 300 miles long. Commercial accumulations of hydrocarbons occur in multiple stratigraphic horizons, at depths ranging from approximately 1,000 feet to over 25,000 feet. At December 31, 2015, substantially all of our 623.5 MMBoe total estimated proved reserves were located in our core operating areas and consisted of approximately 59 percent oil and 41 percent natural gas. We have assembled a multi-year inventory of horizontal drilling and exploration projects, including projects to further evaluate the regional extent and multi-pay potential of our New Mexico Shelf, Delaware Basin and Midland Basin assets.

During 2015, average NYMEX oil and natural gas prices declined 47% and 38%, respectively, compared to 2014. This decline in oil and natural gas prices has reduced our revenues and could reduce the amount of oil and natural gas that we can produce economically. Although we commonly engage in commodity price risk-management initiatives, a key priority, during periods of low prices, is maintaining our strong financial position and preserving operational flexibility for future growth in an up-cycle. As a result of the extended decline in commodity prices, we currently expect our 2016 capital spending and activity level to be less than 2015.

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The following table sets forth information with respect to drilling of wells commenced during the periods indicated:

		Years Ended December 31,
			2015	2014	2013
Gross wells			361	595	633
Net wells			228	370	371
Percent of gross wells drilled horizontally			85.9%	69.1%	43.8%
Percent of gross wells:
	Producers		73.7%	69.9%	83.1%
	Unsuccessful		0.8%	0.2%	0.3%
	Awaiting completion at year-end		25.5%	29.9%	16.6%
			100.0%	100.0%	100.0%

In 2015, we drilled 85.9 percent of our wells horizontally. We will continue to evaluate converting our identified vertical locations to horizontal opportunities, where possible. We believe horizontal drilling is more capital efficient than vertical drilling in many situations. In 2016, we intend to spend substantially all of our capital plan for drilling and completion activities on horizontal opportunities.

We produced approximately 52.3 MMBoe, 40.9 MMBoe and 33.6 MMBoe of oil and natural gas during 2015, 2014 and 2013, respectively. During 2015, approximately 67 percent of our total production was attributable to horizontal wells. During 2015, our total estimated proved reserves decreased by approximately 13.7 MMBoe, despite having 157.1 MMBoe of extensions and discoveries and 11.7 MMBoe of acquisitions, which were offset by (i) negative price revisions of 112.2 MMBoe, (ii) current year production of 52.3 MMBoe, (iii) 10.9 MMBoe of negative revisions due to proved undeveloped reserves reclassified to unproved reserves as they are no longer expected to be drilled within five years, (iv) 5.7 MMBoe of other net negative revisions resulting from technical and performance evaluations and (v) 1.4 MMBoe from various divestitures throughout the year.

Summary of Core Operating Areas and Other Plays

The following is a summary of information regarding our core operating areas and other plays:

		December 31, 2015
		Estimated									2015 Average
		Proved			PV-10				Total	Total	Daily
			Reserves		($ in			% Proved	Gross	Net	Production
Areas			(MBoe)		millions)		% Oil	Developed	Acreage	Acreage	(Boe per Day)
Core Operating Areas:
	New Mexico Shelf		197,334	$	1,309.8		57.7%	68.0%	150,548	102,698	31,432
	Delaware Basin		315,837		2,235.2		58.4%	50.3%	593,274	420,020	85,412
	Midland Basin		110,030		716.3		63.2%	59.2%	263,906	151,802	26,390
Other			260		2.0		3.1%	100.0%	4,033	2,872	22
	Total		623,461	$	4,263.3	(a)	59.0%	57.5%	1,011,761	677,392	143,256

(a)Our Standardized Measure at December 31, 2015 was $3.7 billion. The present value of estimated future net revenues discounted at an annual rate of 10 percent (“PV-10”) is not a GAAP financial measure and is derived from the Standardized Measure, which is the most directly comparable GAAP financial measure. PV-10 is a computation of the Standardized Measure on a pre-tax basis. PV-10 is equal to the Standardized Measure at the applicable date, before deducting future income taxes, discounted at 10 percent. We believe that the presentation of PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to our estimated proved reserves prior to taking into account future corporate income taxes, and it is a useful measure for evaluating the relative monetary significance of our oil and natural gas assets. Further, investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies. We use this measure when assessing the potential return on investment related to our oil and natural gas assets. PV-10, however, is not a substitute for the Standardized Measure. Our PV-10 measure and the Standardized Measure do not purport to present the fair value of our oil and natural gas reserves. See “Item 1. Business —Non-GAAP Financial Measures and Reconciliations.”

____________________________________________________________________________________________________________________________

3

Core operating areas

New Mexico Shelf.  At December 31, 2015, we had estimated proved reserves in this area of 197.3 MMBoe, representing 31.7 percent of our total proved reserves and 30.7 percent of our PV-10.

Within this area our primary objectives are the Yeso, San Andres and Grayburg formations, with producing depths ranging from approximately 900 feet to 7,500 feet. During 2015, we continued our horizontal drilling of the Yeso formation.

During the year ended December 31, 2015, we commenced drilling or participated in the drilling of 99 (65 net) wells in this area. Throughout 2015, we completed 115 (73 net) wells that are producing. Additionally in 2015, we abandoned 1 (0.4 net) well that was deemed unsuccessful. During 2015, approximately 76 percent of the wells we commenced or participated in drilling were drilled horizontally.

In 2016, we intend to spend approximately 11 percent of our 2016 drilling and completions capital plan on the New Mexico Shelf assets.

Delaware Basin.At December 31, 2015, we had estimated proved reserves in this area of 315.8 MMBoe, representing  50.7percent of our total proved reserves and 52.5percent of our PV-10.

Within this area, we utilize horizontal drilling and completion technologies to target (i) the oil-prone Bone Spring formation that includes (a) three Bone Spring sandstone members and (b) the Avalon shale and (ii) the Wolfcamp shale. These formations produce from 4,700 feet to 13,500 feet for our currently targeted activity.

During the year ended December 31, 2015, we commenced drilling or participated in the drilling of 204 (140 net) wells in this area. Throughout 2015, we completed 228 (149 net) wells that are producing. Additionally in 2015, we abandoned 3 (3 net) wells that were deemed unsuccessful. During 2015, we continued (i) development and step-out activity targeting the Avalon shale, Bone Spring sands and Wolfcamp shale and (ii) evaluation of our enhanced stimulation procedures of certain horizontal wells. During 2015, substantially all of the wells we commenced or participated in drilling were drilled horizontally.

In 2016, we intend to spend approximately 62 percent of our 2016 drilling and completions capital plan on our Delaware Basin assets.

Midland Basin. At December 31, 2015, we had estimated proved reserves in this area of 110.0 MMBoe, representing 17.6 percent of our total proved reserves and 16.8 percent of our PV-10.

Our primary objectives in the Midland Basin area are the Spraberry and Wolfcamp zones, which are typically encountered at depths of 7,500 feet to 10,500 feet. These formations are comprised of a sequence of basinal, interbedded sands, shales and carbonates. On our Midland Basin assets we are continuing to (i) develop the Wolfcamp and Spraberry zones with horizontal drilling, (ii) delineate other potential zones on our acreage and (iii) optimize horizontal lateral length, completion techniques and well spacing.

During the year ended December 31, 2015, we commenced drilling or participated in the drilling of 58 (23 net) wells in this area. Throughout 2015, we completed 97 (47 net) wells that are producing. During 2015, approximately 55 percent of the wells we commenced or participated in drilling were drilled horizontally.

In 2016, we intend to spend approximately 27 percent of our 2016 drilling and completions capital plan on the Midland Basin assets.

4

Drilling Activities

The following table sets forth information with respect to (i) wells drilled and completed during the periods indicated and (ii) wells drilled in a prior period but completed in the periods indicated. The information should not be considered indicative of future performance, nor should a correlation be assumed between the number of productive wells drilled, quantities of reserves found or economic value.

				Years Ended December 31,
				2015		2014		2013
				Gross	Net	Gross	Net	Gross	Net
Development wells:
	Productive			180	116	201	128	354	204
	Dry			1	1	1	1	-	-
Exploratory wells:
	Productive			260	154	312	190	321	184
	Dry			3	2	11	10	4	4
		Total wells:
			Productive	440	270	513	318	675	388
			Dry	4	3	12	11	4	4
			Total	444	273	525	329	679	392

The following table sets forth information about wells for which drilling was in-progress or are pending completion at December 31, 2015, which are not included in the above table:

		Drilling In-Progress		Pending Completion
		Gross	Net	Gross	Net
Development wells		3	3	37	23
Exploratory wells		9	6	52	31
	Total	12	9	89	54

5

Our Production, Prices and Expenses

The following table sets forth summary information concerning our production and operating data for the years ended December 31, 2015, 2014 and 2013. Because of normal production declines, increased or decreased drilling activities and the effects of acquisitions or divestitures, the historical information presented below should not be interpreted as being indicative of future results.

					Years Ended December 31,
					2015		2014		2013
Production and operating data:
	Net production volumes:
		Oil (MBbl)				34,457		26,319		21,126
		Natural gas (MMcf)				106,987		87,336		75,054
		Total (MBoe)				52,288		40,875		33,635
	Average daily production volumes:
		Oil (Bbl)				94,403		72,107		57,879
		Natural gas (Mcf)				293,115		239,277		205,627
		Total (Boe)				143,256		111,987		92,150
	Average prices:
		Oil, without derivatives (Bbl)			$	44.69	$	83.17	$	91.76
		Oil, with derivatives (Bbl) (a)			$	62.03	$	86.07	$	89.79
		Natural gas, without derivatives (Mcf)			$	2.46	$	5.39	$	5.08
		Natural gas, with derivatives (Mcf) (a)			$	2.80	$	5.34	$	5.21
		Total, without derivatives (Boe)			$	34.49	$	65.08	$	68.97
		Total, with derivatives (Boe) (a)			$	46.60	$	66.84	$	68.01
	Operating costs and expenses per Boe:
		Lease operating expenses and workover costs			$	7.46	$	8.05	$	7.85
		Oil and natural gas taxes			$	2.90	$	5.12	$	5.69
		Depreciation, depletion and amortization			$	23.40	$	23.97	$	22.97
		General and administrative			$	4.42	$	4.99	$	5.04
	(a)	Includes the effect of cash receipts from (payments on) derivatives:
					Years Ended December 31,
		(in thousands)			2015		2014		2013
		Cash receipts from (payments on) derivatives:
			Oil derivatives		$	597,297	$	76,335	$	(41,616)
			Natural gas derivatives			35,619		(4,352)		9,275
				Total	$	632,916	$	71,983	$	(32,341)
		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 our statements of cash flows. 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.

6

Productive Wells

The following table sets forth the number of productive oil and natural gas wells on our properties at December 31, 2015, 2014 and 2013. This table does not include wells in which we own a royalty interest only.

				Gross Productive Wells			Net Productive Wells
					Natural			Natural
				Oil	Gas	Total	Oil	Gas	Total
December 31, 2015
	Core Operating Areas:
		New Mexico Shelf		3,143	102	3,245	2,531	40	2,571
		Delaware Basin		1,348	498	1,846	784	238	1,022
		Midland Basin		2,491	51	2,542	1,178	18	1,196
	Other			-	3	3	-	0	0
			Total	6,982	654	7,636	4,493	296	4,789
December 31, 2014
	Core Operating Areas:
		New Mexico Shelf		2,994	109	3,103	2,427	45	2,472
		Delaware Basin		1,142	480	1,622	621	216	837
		Midland Basin		2,436	44	2,480	1,147	19	1,166
	Other			-	3	3	-	0	0
			Total	6,572	636	7,208	4,195	280	4,475
December 31, 2013
	Core Operating Areas:
		New Mexico Shelf		2,962	102	3,064	2,416	44	2,460
		Delaware Basin		785	405	1,190	424	177	601
		Midland Basin		2,226	47	2,273	1,047	17	1,064
			Total	5,973	554	6,527	3,887	238	4,125

7

Marketing Arrangements

General. We market our oil and natural gas in accordance with standard energy industry practices. The marketing effort is coordinated with our operations group as it relates to the planning and preparation of future drilling programs so that available markets can be assessed and secured. This planning also involves the coordination of access to the physical facilities necessary to connect new producing wells as efficiently as possible upon their completion.

Oil. Wegenerally do not transport our oil, and we do not refine or process the oil we produce. A significant portion of our oil in Southeast New Mexico, primarily on the New Mexico Shelf, is connected directly to oil gathering pipelines. Most of our gathered oil from the New Mexico Shelf is utilized in a two-refinery complex in Southeast New Mexico. The New Mexico portion of our Delaware Basin production is sold to approximately twelve different oil purchasers; however, that number will decrease when our Alpha Crude Connector pipeline joint venture becomes fully operational in 2016. A significant portion of our West Texas production is on pipeline. Most of this production is sweet crude and is transported by third parties to the Cushing, Oklahoma hub or to the Gulf Coast market. The balance of our oil in these areas that is not directly connected to pipeline is trucked to unloading stations on those same pipelines. We sell the majority of the oil we produce under contracts using market-based pricing. This price is then adjusted for differentials based upon delivery location and oil quality.

Natural Gas. We consider all natural gas gathering and delivery infrastructure in the areas of our production and evaluate market options to obtain the best price reasonably available under the circumstances. We sell the majority of our natural gas under individually negotiated natural gas purchase contracts using market-based pricing. The majority of our natural gas is subject to long-term agreements that generally extend five to ten years from the effective date of the subject contract.

The majority of the natural gas we sell is casinghead gas sold at the lease location under percentage of proceeds processing contracts; however, we are currently transitioning to a mixture of percentage of proceeds and fee based contracts. The purchaser gathers our casinghead natural gas in the field where it is produced and transports it via pipeline to a natural gas processing plant where natural gas liquid products are extracted and sold by the processor. The remaining natural gas product is residue gas, or dry gas, which is placed on residue pipeline systems available in the area. Under our percentage of proceeds contracts, we receive a percentage of the value for the extracted liquids and the residue gas. In a limited number of cases (typically dry gas production), the natural gas gathering and transportation is performed by a third-party gathering company which transports the production from the production location to the purchaser’s mainline.

Our Principal Customers

We sell our oil and natural gas production principally to marketers and other purchasers that have access to pipeline facilities. In areas where there is no practical access to pipelines, oil is transported to storage facilities by trucks and rail owned or otherwise arranged by the marketers or purchasers. Our marketing of oil and natural gas can be affected by factors beyond our control, the effects of which cannot be accurately predicted.

For 2015, revenues from oil and natural gas sales to Holly Frontier Refining and Marketing, LLC, Enterprise Crude Oil, LLC and Plains Marketing and Transportation, Inc. accounted for approximately 25 percent, 12 percent and 11 percent, respectively, of our total operating revenues. While the loss of any of these purchasers may result in a temporary interruption in sales of, or a lower price for, our production, we believe that the loss of any of these purchasers would not have a material adverse effect on our operations, as there are alternative purchasers in our producing regions.

Competition

The oil and natural gas industry in the regions in which we operate is highly competitive. We encounter strong competition from numerous parties, ranging generally from small independent producers to major integrated companies. We primarily encounter significant competition in acquiring properties. At higher commodity prices, we also face competition in contracting for drilling, pressure pumping and workover equipment and securing trained personnel. Many of these competitors have financial, technical and personnel resources substantially larger than ours. As a result, our competitors may be able to pay more for desirable properties, or to evaluate, bid for and purchase a greater number of properties or prospects than our financial or personnel resources will permit.

In addition to competition for drilling, pressure pumping and workover equipment, we are also affected by the availability of related equipment and materials. The oil and natural gas industry periodically experiences shortages of drilling

8

and workover rigs, equipment, pipe, materials and personnel, which can delay drilling, workover and exploration activities and cause significant price increases. We are unable to predict the timing or duration of any such shortages.

Material arrangements.Competition is also strong for attractive oil and natural gas producing properties, undeveloped leases and drilling rights.In January 2016, we entered into an asset purchase agreement to acquire 80 percent of the seller’s interest in certain oil and natural gas properties and related assets in the southern Delaware Basin. As consideration for the acquisition, we agreed to issue to the seller approximately 2.2 million shares of our common stock, $150.0 million in cash and $40.0 million to carry a portion of the seller’s future development costs in these properties. The acquisition is expected to close during the first quarter of 2016, subject to customary closing conditions.

Working Capital

Based on current market conditions, we have maintained a stable liquidity position. Our principal sources of liquidity are cash on hand and available borrowing capacity under our credit facility. At December 31, 2015, we had no debt outstanding under our credit facility and more than $2.7 billion of liquidity available, including $228.6 million in cash and cash equivalents and $2.5 billion of unused commitments under our credit facility. Further, assuming closing of our recently announced acquisition and disposition in the first quarter of 2016, we expect to increase our cash position by approximately $140.0 million. Our primary needs for cash are development, exploration and acquisition of oil and natural gas assets, payment of contractual obligations and working capital obligations. However, additional borrowings under our credit facility or the issuance of additional debt securities will require a greater portion of our cash flow from operations to be used for the payment of interest and principal on our debt, thereby reducing our ability to use cash flow to fund working capital, capital expenditures and acquisitions.

In recent years, the global economic downturn, particularly with respect to the U.S. economy, and the global financial and credit market disruptions have reduced the availability of liquidity and credit to fund the continuation and expansion of certain industrial business operations worldwide resulting in a slowdown in economic activity. This has reduced worldwide demand for energy and resulted in lower commodity prices. Lower commodity prices will reduce our cash flows and borrowing ability, which may make us unable to obtain needed capital or financing on satisfactory terms.

In November 2015, we announced our 2016 base capital budget, excluding acquisitions, of approximately $1.4 billion. During 2016, our current intent is to adjust our capital spending to be within our cash flows. Based on current commodity prices and costs, our capital plan is in the range of $1.1 billion to $1.3 billion. However, if we were to outspend our cash flows, we could use our cash on hand, credit facility and other financing sources. We believe that we have adequate availability under our credit facility to fund any cash flow deficits. Our liquidity position, along with internally generated cash flows from operations and settlements from our derivative contracts, is expected to provide continued financial flexibility as we actively manage the pace of exploration and development activities and acquisitions of leasehold acreage. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations––Capital Commitments, Capital Resources and Liquidity” for additional information regarding our liquidity and ability to fund working capital.

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Applicable Laws and Regulations

Regulation of the Oil and Natural Gas Industry

Regulation of transportation and sale of oil.  Prices at which sales of oil, condensate and natural gas liquids are made are not currently regulated, and sales of these products are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future.

Our sales of oil are affected by the availability, terms and cost of transportation. The transportation of oil in common carrier pipelines is also subject to rate regulation. The Federal Energy Regulatory Commission (the “FERC”) regulates interstate oil pipeline transportation rates under the Interstate Commerce Act. In general, interstate oil pipeline rates must be cost-based, although settlement rates agreed to by all shippers are permitted and market-based rates may be permitted in certain circumstances. Effective January 1, 1995, the FERC implemented regulations establishing an indexing system that permits an oil pipeline, subject to limited challenges, to annually increase or decrease its transportation rates due to inflationary changes in costs using a FERC approved index, without making a cost of service filing. Every five years, the FERC reviews the appropriateness of the index in relation to industry costs. On December 17, 2015, the FERC established a new Producer Price Index for Finished Goods (the “PPI-FG”) of PPI-FG plus 1.23 percent for the five-year period beginning July 1, 2016. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any way that is of material difference from those of our competitors.

Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis at posted tariff rates. When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our competitors.

Effective November 4, 2009, pursuant to the Energy Independence and Security Act of 2007, the Federal Trade Commission (the “FTC”) issued a rule prohibiting market manipulation in the petroleum industry. The FTC rule prohibits any person, directly or indirectly, in connection with the purchase or sale of oil, gasoline or petroleum distillates at wholesale, from knowingly engaging in any act, practice or course of business, including the making of any untrue statement of material fact, that operates or would operate as a fraud or deceit upon any person, or intentionally failing to state a material fact that under the circumstances renders a statement made by such person misleading, provided that such omission distorts or is likely to distort market conditions for any such product. A violation of this rule may result in civil penalties of up to $1 million per day per violation, in addition to any applicable penalty under the Federal Trade Commission Act.

Regulation of transportation and sale of natural gas.Historically, the transportation and sale for resale of natural gas in interstate commerce have been regulated pursuant to the Natural Gas Act of 1938 (the “Natural Gas Act”), the Natural Gas Policy Act of 1978 (the “Natural Gas Policy Act”) and regulations issued under those acts by the FERC. In the past, the federal government has regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at uncontrolled market prices, Congress could reenact price controls in the future, and market participants are prohibited from engaging in market manipulation. Deregulation of wellhead natural gas sales began with the enactment of the Natural Gas Policy Act. In 1989, Congress enacted the Natural Gas Wellhead Decontrol Act, which removed all Natural Gas Act and Natural Gas Policy Act price and non-price controls affecting wellhead sales of natural gas effective January 1, 1993.

The FERC regulates interstate natural gas transportation rates and service conditions, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas. Since 1985, the FERC has endeavored to make natural gas transportation more accessible to natural gas buyers and sellers on an open and non-discriminatory basis. The FERC has stated that open access policies are necessary to improve the competitive structure of the interstate natural gas pipeline industry and to create a regulatory framework that will put natural gas sellers into more direct contractual relations with natural gas buyers by, among other things, unbundling the sale of natural gas from the sale of transportation and storage services. Beginning in 1992, the FERC issued Order No. 636 and a series of related orders to implement its open access policies. As a result of the Order No. 636 program, the marketing and pricing of natural gas have been significantly altered. The interstate pipelines’ traditional role as wholesalers of natural gas has been eliminated and replaced by a structure under which pipelines provide transportation and storage services on an open access basis to others who buy and sell natural gas. Although these orders do not directly regulate natural gas producers, they are intended to foster increased competition within all phases of the natural gas industry.

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In 2000, the FERC issued Order No. 637 and subsequent orders, which imposed a number of additional reforms designed to enhance competition in natural gas markets. Among other things, Order No. 637 effected changes in FERC regulations relating to scheduling procedures, capacity segmentation, penalties, rights of first refusal and information reporting.

In August 2005, Congress enacted the Energy Policy Act of 2005 (“EPAct 2005”). Among other matters, EPAct 2005 amends the Natural Gas Act to make it unlawful for “any entity,” including otherwise non-jurisdictional producers such as us, to use any deceptive or manipulative device or contrivance in connection with the purchase or sale of natural gas or the purchase or sale of transportation services subject to regulation by the FERC, in contravention of rules prescribed by the FERC. The FERC’s rules implementing this provision make it unlawful, in connection with the purchase or sale of natural gas subject to the jurisdiction of the FERC, or the purchase or sale of transportation services subject to the jurisdiction of the FERC, for any entity, directly or indirectly, to use or employ any device, scheme or artifice to defraud; to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or to engage in any act or practice that operates as a fraud or deceit upon any person. EPAct 2005 also gives the FERC authority to impose civil penalties for violations of the Natural Gas Act or Natural Gas Policy Act up to $1 million per day per violation. The new anti-manipulation rule does not apply to activities that relate only to intrastate or other non-jurisdictional sales, gathering or production, but does apply to activities of otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” natural gas sales, purchases or transportation subject to FERC jurisdiction, which now includes the annual reporting requirements under Order No. 704, as described below. EPAct 2005 therefore reflects a significant expansion of the FERC’s enforcement authority. We do not anticipate we will be affected any differently than other producers of natural gas. 

In December 2007, the FERC issued a rule (“Order No. 704”), as clarified in orders on rehearing, requiring that any market participant, including a producer such as us, that engages in wholesale sales or purchases of natural gas that equal or exceed 2.2 million MMBtus during a calendar year to annually report, starting May 1, 2009, such sales and purchases to the FERC. These rules are intended to increase the transparency of the wholesale natural gas markets and to assist the FERC in monitoring such markets and in detecting market manipulation. We do not anticipate that we will be affected by these rules any differently than other producers of natural gas.

We cannot accurately predict whether the FERC’s actions will achieve the goal of increasing competition in markets in which our natural gas is sold. Additional proposals and proceedings that might affect the natural gas industry are pending before the FERC and the courts. The natural gas industry historically has been very heavily regulated. Therefore, we cannot provide any assurance that the less stringent regulatory approach recently established by the FERC will continue. However, we do not believe that any action taken will affect us in a way that materially differs from the way it affects other natural gas producers.

Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states onshore and in state waters. Although its policy is still in flux, the FERC has reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which has the tendency to increase our costs of getting natural gas to point of sale locations.

Intrastate natural gas transportation is also subject to regulation by state regulatory agencies. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. During the 2007 legislative session, the Texas State Legislature passed H.B. 3273 (the “Competition Bill”) and H.B. 1920 (the “LUG Bill”). The Competition Bill gives the Railroad Commission of Texas (the “RRC”) the ability to use either a cost-of-service method or a market-based method for setting rates for natural gas gathering and intrastate transportation pipelines in formal rate proceedings. It also gives the RRC specific authority to enforce its statutory duty to prevent discrimination in natural gas gathering and transportation, to enforce the requirement that parties participate in an informal complaint process and to penalize purchasers, transporters, and gatherers for taking discriminatory actions against shippers and sellers. The Competition Bill also provides producers with the unilateral option to determine whether or not confidentiality provisions are included in a contract to which a producer is a party for the sale, transportation or gathering of natural gas. The LUG Bill modifies the informal complaint process at the RRC with procedures unique to lost and unaccounted for natural gas issues. It extends the types of information that can be requested, provides producers with an annual audit right, and provides the RRC with the authority to make determinations and issue orders in specific situations. Both the Competition Bill and the LUG Bill became effective on September 1, 2007, and the RRC rules implementing the RRC’s authority pursuant to the bills became effective on April 28, 2008.

Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship natural gas on an intrastate basis will not affect our operations in any way that is of material

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difference from those of our competitors. Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.

Regulation of production.  The production of oil and natural gas is subject to regulation under a wide range of local, state and federal statutes, rules, orders and regulations. Federal, state and local statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations. All of the states in which we own and operate properties have regulations governing conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum allowable rates of production from oil and natural gas wells, the regulation of well spacing, and the plugging and abandonment of wells. The effect of these regulations is to limit the amount of oil and natural gas that we can produce from our wells and to limit the number of wells or the locations at which we can drill, although we can apply for exceptions to such regulations or to have reductions in well spacing. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction. The failure to comply with these rules and regulations can result in substantial penalties. Our competitors in the oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect our operations.

Environmental, Health and Safety Matters

General. Our operations are subject to stringent and complex federal, state and local laws and regulations governing environmental protection as well as the discharge of materials into the environment. These laws, rules and regulations may, among other things:

·require the acquisition of various permits before drilling commences;

·restrict the types, quantities and concentration of various substances that can be released into the environment in connection with oil and natural gas drilling and production and saltwater disposal activities;

·limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas; and

·require remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned wells.

The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, environmental laws and regulations are revised frequently, and any changes that result in more stringent and costly waste handling, disposal and cleanup requirements for the oil and natural gas industry could have a significant impact on our operating costs.

The following is a summary of some of the existing laws, rules and regulations to which our business is subject.

Waste handling. The Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. Pursuant to regulatory guidance issued by the federal Environmental Protection Agency (the “EPA”), the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters, and most of the other wastes associated with the exploration, development, and production of oil or natural gas are currently regulated under RCRA’s non-hazardous waste provisions. However, it is possible that certain oil and natural gas exploration and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. For example, from time to time various environmental groups have challenged the EPA’s exemption of certain oil and gas wastes from RCRA. Any such change could result in an increase in our costs to manage and dispose of wastes, which could have a material adverse effect on our results of operations and financial position. Also, in the course of our operations, we generate some amounts of ordinary industrial wastes, such as paint wastes, waste solvents and waste oils that may be regulated as hazardous wastes if such wastes have hazardous characteristics.

Comprehensive Environmental Response, Compensation and Liability Act. The Comprehensive Environmental Response Compensation and Liability Act (“CERCLA”), also known as the Superfund law, imposes joint and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons include the owner or operator of the site where the release occurred, and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that

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have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.

We currently own, lease, or operate numerous properties that have been used for oil and natural gas exploration and production for many years. Although we believe that we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes or hydrocarbons may have been released on or under the properties owned or leased by us, or on or under other locations, including off-site locations, where such substances have been taken for disposal. In addition, some of our properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes or hydrocarbons were not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to remove previously disposed substances and wastes, remediate contaminated property, or perform remedial operations to prevent future contamination.

Water discharges. The federal Water Pollution Control Act (the “Clean Water Act”) and analogous state laws, impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States. The discharge of pollutants into regulated waters, including dredge and fill activities in regulated wetlands, is prohibited, except in accordance with the terms of a permit issued by the EPA, or, in some circumstances, the U.S. Army Corps of Engineers (the “Corps”), or an analogous state agency. In September 2015, new EPA and U.S. Army Corps of Engineers rules defining the scope of the EPA’s and the Corps’ jurisdiction became effective. To the extent the rule expands the scope of jurisdiction of the Clean Water Act, we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas. The rule has been challenged in court on the grounds that it unlawfully expands the reach of Clean Water Act programs, and implementation of the rule has been stayed pending resolution of the court challenge. In addition, spill prevention, control and countermeasure requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations.

Safe Drinking Water Act. Our oil and natural gas exploration and production operations generate produced water, drilling muds, and other waste streams, some of which may be disposed via injection in underground wells situated in non-producing subsurface formations. The drilling and operation of these injection wells are regulated by the Safe Drinking Water Act (the “SDWA”). The Underground Injection Well Program under the SDWA requires that we obtain permits from the EPA or delegated state agencies for our disposal wells, establishes minimum standards for injection well operations, restricts the types and quantities of fluids that may be injected and prohibits the migration of fluid containing any contaminants into underground sources of drinking water. Any leakage from the subsurface portions of the injection wells may cause degradation of freshwater, potentially resulting in cancellation of operations of a well, imposition of fines and penalties from governmental agencies, incurrence of expenditures for remediation of affected resources, and imposition of liability by landowners or other parties claiming damages for alternative water supplies, property damages, and personal injuries. While we believe that we have obtained the necessary permits from the applicable regulatory agencies for our underground injection wells and that we are in substantial compliance with permit conditions and federal and state rules, any changes in the laws or regulations or the inability to obtain permits for new injection wells in the future may affect our ability to dispose of produced waters and would ultimately increase the cost of our operations, which costs could be significant. For example, the RRC recently adopted new permit rules for injection wells to address these seismic activity concerns within the state. Among other things, the rules require companies seeking permits for disposal wells to provide seismic activity data in permit applications, provide for more frequent monitoring and reporting for certain wells, and allow the RRC to modify, suspend, or terminate permits on grounds that a disposal well is likely to be, or determined to be, causing seismic activity. Furthermore, in response to recent seismic events near underground injection wells used for the disposal of oil and gas-related wastewaters, federal and some state agencies have begun investigating whether such wells have caused increased seismic activity, and some states have shut down or imposed moratoria on the use of such injection wells. For example, in July 2015 and January 2016, the Oklahoma Corporation Commission issued various orders and regulations applicable to disposal operations in specific counties in Oklahoma. These rules require that disposal well operators, among other things, conduct additional mechanical integrity testing, make sure that their wells are not injecting wastes into targeted formations, and/or reduce the volumes of wastes disposed in such wells. If new regulatory initiatives are implemented that restrict or prohibit the use of underground injection wells in areas where we rely upon the use of such wells in our operations, our costs to operate may significantly increase, and our ability to continue production may be delayed or limited, which could have a material adverse effect on our results of operations and financial position.

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Air emissions. The federal Clean Air Act (the “CAA”), and comparable state laws regulate emissions of various air pollutants through air emissions permitting programs and the imposition of other requirements. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the CAA and associated state laws and regulations. In addition, the EPA has developed, and continues to develop, stringent regulations governing emissions of toxic air pollutants at specified sources.

For example, in October 2015, the EPA lowered the National Ambient Air Quality Standard (“NAAQS”) for ozone from 75 to 70 parts per billion. State implementation of the revised NAAQS could result in stricter permitting requirements, delay or prohibit our ability to obtain such permits, and result in increased expenditures for pollution control equipment, the costs of which could be significant. In addition, the EPA has adopted new rules under the CAA that require the reduction of volatile organic compound emissions from certain fractured and refractured natural gas wells for which well completion operations are conducted and further require that most wells use reduced emission completion (“REC”) techniques, also known as “green completions.” These regulations also establish specific new requirements regarding emissions from production related wet seal and reciprocating compressors, and from pneumatic controllers and storage vessels. More recently, in August 2015, the EPA announced proposed rules that would establish new air emission controls for emissions of methane from certain equipment and processes in the oil and natural gas source category, including production, processing, transmission and storage activities. The EPA’s proposed rule package includes first-time standards to address emissions of methane from equipment and processes across the source category, including hydraulically fractured oil and natural gas well completions. In addition, the rule package would extend existing volatile organic compound, or VOC, standards under the EPA’s Subpart OOOO of the New Source Performance Standards to include previously unregulated equipment within the oil and natural gas source category.

Climate change.   In response to findings that emissions of carbon dioxide, methane and other “greenhouse gases”, or GHGs, present an endangerment to public health and the environment, the EPA has issued regulations to restrict emissions of greenhouse gases under existing provisions of the CAA. These regulations include limits on tailpipe emissions from motor vehicles and preconstruction and operating permit requirements for certain large stationary sources. The EPA has also adopted rules requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States, as well as certain onshore oil and natural gas production facilities, on an annual basis. Recently, in December 2015, the EPA finalized rules that added new sources to the scope of the greenhouse gases monitoring and reporting rule. These new sources include gathering and boosting facilities as well as completions and workovers from hydraulically fractured oil wells. The revisions also include the addition of well identification reporting requirements for certain facilities. In addition, as part of the Obama Administration’s overall strategy to reduce methane emissions from the oil and natural gas sector by up to 45 percent from 2012 levels by 2025, the EPA and other federal agencies have or are in the process of proposing new rules related to the control of methane emissions. For example, in August 2015, the EPA announced proposed rules that would establish new air emission controls for emissions of methane from certain equipment and processes in the oil and natural gas source category, including production, processing, transmission and storage activities. The EPA’s proposed rule package includes first-time standards to address emissions of methane from equipment and processes across the source category, including hydraulically fractured oil and natural gas well completions. More recently, in January 2016, the Bureau of Land Management (“BLM”) issued proposed rules limiting the venting and flaring of natural gas from oil and natural gas activities on federal lands. Increased regulation of methane and other GHGs have the potential to result in increased compliance costs and, consequently, adversely affect our operations.

While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce emissions of GHGs in recent years. In the absence of Congressional action, many states have taken legal measures to reduce emissions of GHGs primarily through regional GHG cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and natural gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall GHG emission reduction goal.

The adoption of legislation or regulatory programs to reduce emissions of GHGs could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances, or to comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produce. Consequently, legislation and regulatory programs to reduce emissions of GHGs could have an adverse effect on our business, financial condition and results of operations. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our financial condition and results of operations.

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Hydraulic fracturing. Hydraulic fracturing is an important and common practice that is used to stimulate production of oil and/or natural gas from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand, and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. We routinely use hydraulic fracturing as part of our operations. The process is typically regulated by state oil and natural gas commissions, but the EPA has asserted federal regulatory authority pursuant to the SDWA over certain hydraulic fracturing activities involving the use of diesel and issued guidance in February 2014 governing such activities. The EPA has also issued final regulations under the CAA establishing performance standards, including standards for the capture of air emissions released during hydraulic fracturing, and advanced notice of proposed rulemaking under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing, and also proposed in April 2015 to prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants. In addition, the BLM finalized rules in March 2015 that impose new or more stringent standards for performing hydraulic fracturing on federal and American Indian lands. The U.S. District Court of Wyoming has temporarily stayed implementation of this rule. A final decision has not yet been issued.

At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure, and well construction requirements on hydraulic fracturing activities. For example, New Mexico adopted hydraulic fracturing fluid disclosure requirements in February 2012, and the RRC adopted rules governing well casing, cementing and other standards for ensuring that hydraulic fracturing operations do not contaminate nearby water resources in May 2013. In addition, local governments have also taken steps to regulate hydraulic fracturing, including imposing restrictions or moratoria on oil and gas activities occurring within their boundaries. For example, in 2013, Mora County, New Mexico banned hydraulic fracturing. However, the ban was challenged in U.S. District Court and was subsequently overturned. We believe that we follow applicable standard industry practices and legal requirements for groundwater protection in our hydraulic fracturing activities. Nonetheless, if new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells.

In addition, certain governmental reviews are either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices. Additionally, in June 2015, the EPA released its draft report on the potential impacts of hydraulic fracturing on drinking water resources. The EPA report concluded that hydraulic fracturing activities have not led to widespread, systemic impacts on drinking water resources in the United States, although there are above and below ground mechanisms by which hydraulic fracturing activities have the potential to impact drinking water resources. The draft report is expected to be finalized after a public comment period and a formal review by the EPA’s Science Advisory Board. Other governmental agencies, including the United States Department of Energy and the United States Department of the Interior, are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies could spur initiatives to further regulate hydraulic fracturing under the federal SDWA or other regulatory mechanisms.

We do not have insurance policies in effect that are intended to provide coverage for losses solely related to hydraulic fracturing operations; however, we believe our general liability and excess liability insurance policies may cover third-party claims related to hydraulic fracturing operations and associated legal expenses in accordance with, and subject to, the terms of such policies. If new laws or regulations significantly restrict hydraulic fracturing activities or impose burdens on new permitting or operating requirements, our ability to utilize hydraulic fracturing may be curtailed, and this may in turn reduce the amount of oil and natural gas that we are ultimately able to produce from our reserves.

Operations on Federal Lands. We currently operate on federal lands under the jurisdiction of the BLM. Permitting for oil and gas activities on federal lands can take significantly longer than the state permitting process. Delays in obtaining permits necessary can disrupt our operations and have an adverse effect on our business. In addition, in January 2016, the BLM issued a proposed rule which seeks to reduce methane emissions from oil and gas activities on federal lands by limiting venting and flaring of natural gas from wells and other equipment. The proposal also clarifies when operators owe royalties on flared gas, and would provide the agency greater flexibility to set royalty rates at or above 12.5 percent of the value of production. These rules could result in increased compliance costs for our operations, which in turn could have an adverse effect on our business and results of operations.

Endangered species. The federal Endangered Species Act (the “ESA”) and analogous state laws regulate activities that could have an adverse effect on threatened or endangered species. Some of our drilling operations are conducted in areas where protected species are known to exist. In these areas, we may be obligated to develop and implement plans to avoid potential adverse impacts to protected species, and we may be prohibited from conducting drilling operations in certain locations or during certain seasons, such as breeding and nesting seasons, when our operations could have an adverse effect

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on the species. It is also possible that a federal or state agency could order a complete halt to drilling activities in certain locations if it is determined that such activities may have a serious adverse effect on a protected species. The presence of a protected species in areas where we perform drilling activities could impair our ability to timely complete drilling and developmental operations and could adversely affect our future production from those areas. Moreover, as a result of a settlement approved by the U.S. District Court for the District of Columbia in September 2011, the U.S. Fish and Wildlife Service is required to make a determination on listing of numerous species as endangered or threatened under the ESA before the completion of the agency’s 2017 fiscal year. The designation of previously unprotected species as threatened or endangered in areas where we or our oil and natural gas exploration and production customers operate could cause us or our customers to incur increased costs arising from species protection measures and could result in delays or limitations in our customers’ performance of operations, which could reduce demand for our midstream services.

National Environmental Policy Act. Oil and natural gas exploration and production activities on federal lands are subject to the National Environmental Policy Act (“NEPA”). NEPA requires federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an environmental assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed environmental impact statement that may be made available for public review and comment. All of our current exploration and production activities, as well as proposed exploration and development plans, on federal lands require governmental permits that are subject to the requirements of NEPA. This process has the potential to delay or even halt development of some of our oil and natural gas projects.

OSHA and other laws and regulations. We are subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) and comparable state statutes. The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of CERCLA and similar state statutes require that we organize and/or disclose information about hazardous materials used or produced in our operations. Also, pursuant to OSHA, the Occupational Safety and Health Administration has established a variety of standards relating to workplace exposure to hazardous substances and employee health and safety. We believe that we are in substantial compliance with the applicable requirements of OSHA and comparable laws.

We do not believe that compliance with existing environmental laws and regulations applicable to our current operations will have a material adverse impact on our financial condition and results of operations. For instance, we did not incur any material capital expenditures for remediation or pollution control activities during 2015. Additionally, as of the date of this report, we are not aware of any environmental issues or claims that will require material capital expenditures during 2016. However, we cannot assure you that the passage or application of more stringent laws or regulations in the future will not have a negative impact on our financial position or results of operations.

Our Employees

Our corporate headquarters are located at One Concho Center, 600 West Illinois Avenue, Midland, Texas 79701. We also maintain various field offices in Texas and New Mexico. At December 31, 2015, we had 1,121 employees, 387 of whom were employed in field operations. Our future success will depend partially on our ability to attract, retain and motivate qualified personnel. We are not a party to any collective bargaining agreements and have not experienced any strikes or work stoppages. We consider our relations with our employees to be good. We also utilize the services of contractors to perform various field and other services.

Available Information

We file or furnish annual, quarterly and current reports, proxy statements and other documents with the United States Securities and Exchange Commission (the “SEC”) under the Exchange Act. The public may read and copy any materials that we file or furnish with the SEC at the SEC's Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Also, the SEC maintains a website that contains reports, proxy and information statements, and other information regarding issuers, including us, that file or furnish electronically with the SEC. The public can obtain any documents that we file with the SEC at www.sec.gov. 

We also make available free of charge through our website, www.concho.com, our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and, if applicable, amendments to those reports filed or furnished pursuant to Section 13(a) of the Exchange Act as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC.

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Non-GAAP Financial Measures and Reconciliations

PV-10

PV-10 is derived from the standardized measure of discounted future net cash flows, which is the most directly comparable GAAP financial measure. PV-10 is a computation of the standardized measure of discounted future net cash flows on a pre-tax basis. PV-10 is equal to the standardized measure of discounted future net cash flows at the applicable date, before deducting future income taxes, discounted at 10 percent. We believe that the presentation of PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to our estimated proved reserves prior to taking into account future corporate income taxes, and it is a useful measure for evaluating the relative monetary significance of our oil and natural gas assets. Further, investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies. We use this measure when assessing the potential return on investment related to our oil and natural gas assets. PV-10, however, is not a substitute for the standardized measure of discounted future net cash flows. Our PV-10 measure and the standardized measure of discounted future net cash flows do not purport to present the fair value of our oil and natural gas reserves.

During 2015, average NYMEX oil and natural gas prices declined 47% and 38%, respectively, compared to 2014.  Our PV-10 declined significantly in 2015 compared to 2014 primarily due to the sharp decline in commodity price. The following table provides a reconciliation of PV-10 to the standardized measure of discounted future net cash flows at December 31, 2015, 2014 and 2013:

			December 31,
(in millions)			2015		2014		2013
PV-10		$	4,263.3	$	11,384.8	$	9,029.5
Present value of future income taxes discounted at 10%			(523.8)		(3,362.0)		(2,785.1)
	Standardized measure of discounted future net cash flows	$	3,739.5	$	8,022.8	$	6,244.4

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EBITDAX

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) (gain) loss on derivatives, (7) cash receipts from (payments on) derivatives, (8) loss on disposition of assets and other, (9) interest expense, (10) loss on extinguishment of debt, (11) federal and state income taxes from continuing operations and (12) similar items listed above that are presented in discontinued operations. 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, and it is also a material component of one of the financial covenants under our credit facility. 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 and depletable assets. 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, including by lenders pursuant to a covenant in our credit facility. 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. Further, under our credit facility, an event of default could arise if we were not able to satisfy and remain in compliance with our specified financial ratio, defined as the maintenance of a quarterly ratio of total debt to consolidated last twelve months EBITDAX of no greater than 4.25 to 1.0. Non-compliance with this ratio could trigger an event of default under our credit facility, which then could trigger an event of default under our indentures.

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

		Years Ended December 31,
(in thousands)			2015		2014		2013		2012		2011
Net income			$	65,900	$	538,175	$	251,003	$	431,689	$	548,137
	Exploration and abandonments			58,847		284,821		109,549		39,840		11,394
	Depreciation, depletion and amortization			1,223,253		979,740		772,608		575,128		400,022
	Accretion of discount on asset retirement obligations			7,600		7,072		6,047		4,187		2,444
	Impairments of long-lived assets			60,529		447,151		65,375		-		439
	Non-cash stock-based compensation			63,073		47,130		35,078		29,872		19,271
	(Gain) loss on derivatives			(699,752)		(890,917)		123,652		(127,443)		23,350
	Cash receipts from (payments on) derivatives			632,916		71,983		(32,341)		23,536		(84,854)
	Loss on disposition of assets and other			53,789		9,308		1,268		372		1,139
	Interest expense			215,384		216,661		218,581		182,705		118,360
	Loss on extinguishment of debt			-		4,316		28,616		-		-
	Income tax expense from continuing operations			31,371		317,785		118,237		251,041		261,800
	Discontinued operations			-		-		(12,081)		64,701		(26,343)
EBITDAX			$	1,712,910	$	2,033,225	$	1,685,592	$	1,475,628	$	1,275,159

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Item 1A.  Risk Factors

You should consider carefully the following risk factors together with all of the other information included in this report and other reports filed with the SEC before investing in our securities. If any of the following risks were actually to occur, our business, financial condition or results of operations could be materially adversely affected. In that case, the trading price of our securities could decline and you could lose all or part of your investment.

Risks Related to Our Business

Oil, natural gas and natural gas liquid prices are volatile and have continued to decline significantly over the past year. An extended continuation of, or a further decline in, oil, natural gas and natural gas liquid prices could adversely affect our financial position, financial results, cash flow, access to capital and ability to grow.

Our future financial condition, revenues, results of operations, rate of growth and the carrying value of our oil and natural gas properties depend primarily upon the prices we receive for our oil and natural gas production and the prices prevailing from time to time for oil, natural gas and natural gas liquids. Oil, natural gas, and natural gas liquid prices historically have been volatile, and are likely to continue to be volatile in the future, especially given current geopolitical conditions. This price volatility also affects the amount of cash flow we have available for capital expenditures and our ability to borrow money or raise additional capital. The prices and levels of production for oil, natural gas and natural gas liquids are subject to a variety of factors beyond our control, including:

·the level of consumer demand for oil, natural gas and natural gas liquids;

·the domestic and foreign supply of oil, natural gas, and natural gas liquids;

·inventory levels of Cushing, Oklahoma, the benchmark for WTI oil prices;

·liquefied natural gas deliveries to and from the United States;

·commodity processing, gathering and transportation availability and the availability of refining capacity;

·the price and level of imports of foreign oil and natural gas;

·the ability of the members of the Organization of Petroleum Exporting Countries and other oil exporting nations to agree to and maintain oil price and production controls;

·domestic and foreign governmental regulations and taxes;

·the price and availability of alternative fuel sources;

·weather conditions;

·political conditions or hostilities in oil and natural gas producing regions, including the Middle East, Africa and South America;

·technological advances affecting energy consumption and energy supply;

·effect of energy conservation efforts;

·variations between product prices at sales points and applicable index prices; and

·worldwide economic conditions.

Furthermore, oil and natural gas prices continued to be volatile in 2015. For example, the NYMEX oil prices in 2015 ranged from a high of $61.43 to a low of $34.73 per Bbl and the NYMEX natural gas prices in 2015 ranged from a high of $3.23 to a low of $1.76 per MMBtu. Further, the NYMEX oil prices and NYMEX natural gas prices reached lows of $26.21 per Bbl and $1.80 per MMBtu, respectively, during the period from January 1, 2016 to February 22, 2016.

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A significant portion of our total natural gas revenues are derived from the value of the natural gas liquids contained in our natural gas, with the remaining portion coming from the value of the dry natural gas residue. In the past, our liquids-rich natural gas stream and the related value of the natural gas liquids included in our natural gas revenues resulted in our realized natural gas price (excluding the effects of derivatives) being greater than the related NYMEX natural gas price. However, during the year ended December 31, 2015, our realized natural gas price (excluding the effects of derivatives) fell below the related NYMEX natural gas price primarily due to the average Mont Belvieu price for a blended barrel of natural gas liquids decreasing to $17.80 per Bbl, as compared to $34.58 per Bbl during the year ended December 31, 2014.

Declines in oil, natural gas and natural gas liquid prices would not only reduce our revenue, but could also reduce the amount of oil and natural gas that we can produce economically. This in turn would lower the amount of oil and natural gas reserves we could recognize and, as a result, could have a material adverse effect on our financial condition and results of operations. If the oil and natural gas industry continues to experience significant price declines, we may, among other things, be unable to maintain or increase our borrowing capacity, repay current or future indebtedness or obtain additional capital on attractive terms, all of which can adversely affect the value of our securities.

Future price declines could result in a reduction in the carrying value of our proved oil and natural gas properties, which could adversely affect our results of operations.

Declines in commodity prices may result in us having to make substantial downward adjustments to the value of our estimated proved reserves. If this occurs, or if our estimates of production or economic factors change, accounting rules may require us to write-down, as a non-cash charge to earnings, the carrying value of our proved oil and natural gas properties for impairments. We are required to perform impairment tests on proved assets whenever events or changes in circumstances warrant a review of our proved oil and natural gas properties. To the extent such tests indicate a reduction of the estimated useful life or estimated future cash flows of our oil and natural gas properties, the carrying value may not be recoverable and therefore require a write-down. The primary factors that may affect management’s estimates of future cash flows are (i) commodity futures prices, (ii) increases or decreases in production and capital costs, (iii) future reserve adjustments, both positive and negative, to proved reserves and appropriate risk-adjusted probable and possible reserves, (iv) cash flows from integrated assets and (v) results of future drilling activities. We may incur impairment charges in the future, which could materially adversely affect our results of operations in the period incurred.

Additionally, based on the factors above, as of December 31, 2015, we determined that undiscounted future cash flows attributable to certain depletion groups with a net book value of approximately $5.2 billion indicated that the carrying amount was expected to be recovered; however, it may be at risk for impairment if management’s estimates of future cash flows decline, including as a result of further declines in projected commodity prices (and the resulting impact of future cash flows) subsequent to December 31, 2015. We estimate that, if these depletion groups were to become impaired in a future period, we could recognize non-cash impairment in that period of approximately $2.5 billion.

Approximately 42.5 percent of our total estimated proved reserves at December 31, 2015 were undeveloped, and those reserves may not ultimately be developed.

At December 31, 2015, approximately 42.5 percent of our total estimated proved reserves were undeveloped. Recovery of undeveloped reserves requires significant capital expenditures and successful drilling. Our reserve data assumes that we can and will make these expenditures and conduct these operations successfully. These assumptions, however, may not prove correct. Our reserve report at December 31, 2015 includes estimates of total future development costs over the next five years associated with our proved undeveloped reserves of approximately $3.0 billion. If we choose not to spend the capital to develop these reserves, or if we are not otherwise able to successfully develop these reserves, we will be required to write-off these reserves. In addition, under the SEC’s reserve rules, because proved undeveloped reserves may be booked only if they relate to wells planned to be drilled within five years of the date of booking, we may be required to write-off any proved undeveloped reserves that are not developed within this five-year timeframe. For example, as of December 31, 2015, we wrote-off approximately 10.9 MMBoe of proved undeveloped reserves because we have deferred development outside the five-year window primarily as a result of our transition from a vertical to horizontal drilling program. Any such write-offs of our reserves could reduce our ability to borrow money and could reduce the value of our securities.

Drilling for and producing oil and natural gas are high-risk activities with many uncertainties that could cause our costs to increase or production volumes to decrease, which would reduce our cash flows.

Our future financial condition and results of operations will depend on the success of our exploration and production activities. Our oil and natural gas exploration and production activities are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable oil or natural gas production. Our decisions to purchase,

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explore, develop or otherwise exploit prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. Our cost of drilling, completing, equipping and operating wells is often uncertain before drilling commences. Overruns in budgeted expenditures are common risks that can make a particular project uneconomical or less economical than forecasted. Further, many factors may curtail, delay or cancel drilling, including the following:

·delays imposed by or resulting from compliance with regulatory and contractual requirements;

·reductions in oil, natural gas and natural gas liquid prices;

·pressure or irregularities in geological formations;

·shortages of or delays in obtaining equipment and qualified personnel or in obtaining water for hydraulic fracturing activities;

·equipment failures or accidents;

·adverse weather conditions;

·environmental hazards, such as natural gas leaks, oil spills, pipeline and tank ruptures, encountering naturally occurring radioactive materials, and unauthorized discharges of brine, well stimulation and completion fluids, toxic gases or other pollutants into the surface and subsurface environment;

·limited availability of financing at acceptable terms;

·surface access restrictions;

·loss of title or other title related issues;

·oil, natural gas liquids or natural gas gathering, transportation and processing availability restrictions or limitations; and

·limitations in the market for oil, natural gas and natural gas liquids.

Prolonged decreases in our drilling program may require us to pay certain non-use fees or impact our ability to comply with certain contractual requirements. 

Oil prices declined substantially during the second half of 2014 and continued to decline through 2015. In the event that oil and natural gas prices remain depressed for a sustained period, or continue to further decline, we may experience significant decreases in drilling activity. Due to the nature of our drilling programs and the oil and natural gas industry generally, we are a party to certain agreements that require us to meet various contractual obligations or require us to utilize a certain amount of goods or services, including, but not limited to, water commitments, throughput volume commitments and power commitments. In the event that oil and natural gas prices remain depressed, and as a result continue to reduce the demand for drilling and production, this could lead to a decrease in our drilling activity and production levels, which could, in turn, require us to pay for unutilized goods or services or impact our ability to meet these contractual obligations.

We may incur losses as a result of title defects in our oil and natural gas properties.

It is our practice to initially conduct only a cursory title review of the oil and natural gas properties on which we do not have proved reserves. To the extent title opinions or other investigations prior to our commencement of drilling operations reflect defects affecting such properties, we are typically responsible for curing any such defects at our expense. Additionally, the discovery of any such defects could delay or prohibit the commencement of drilling operations on the affected properties. These impacts and other potential losses resulting from title defects in our oil and natural gas properties could have a material adverse effect on our business, financial condition and results of operations.

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Federal, state and local legislation and regulatory initiatives relating to hydraulic fracturing, as well as governmental reviews of such activities, could result in increased costs and additional operating restrictions or delays and adversely affect our production.

Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from tight formations. We routinely utilize hydraulic fracturing techniques in many of our drilling and completion programs. The process involves the injection of water, sand and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and natural gas commissions. However, the EPA recently asserted federal regulatory authority over hydraulic fracturing involving diesel additives under the SDWA’s Underground Injection Control Program and issued guidance in February 2014, governing such activities. The EPA has also issued final regulations under the CAA establishing performance standards, including standards for the capture of air emissions released during hydraulic fracturing, and advanced notice of proposed rulemaking under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing, and also proposed in April 2015 to prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants. In addition, the Bureau of Land Management (“BLM”) finalized rules in March 2015 that impose new or more stringent standards for performing hydraulic fracturing on federal and American Indian lands. The United States District Court of Wyoming has temporarily stayed implementation of this rule. A final decision has not yet been issued.

At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure, and well construction requirements on hydraulic fracturing activities. For example, New Mexico adopted hydraulic fracturing fluid disclosure requirements in February 2012 and in May 2013, and the RRC adopted rules governing well casing, cementing and other standards for ensuring that hydraulic fracturing operations do not contaminate nearby water resources in May 2013. In addition, local governments have also taken steps to regulate hydraulic fracturing, including imposing restrictions or moratoria on oil and gas activities occurring within their boundaries. For example, in 2013, Mora County, New Mexico banned hydraulic fracturing. However, the ban was challenged in U.S. District Court and was subsequently overturned. We believe that we follow applicable standard industry practices and legal requirements for groundwater protection in our hydraulic fracturing activities. Nonetheless, if new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells.

In addition, certain governmental reviews are either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices. Additionally, in June 2015, the EPA released its draft report on the potentialimpacts of hydraulic fracturing on drinking water resources. The EPA report concluded that hydraulic fracturing activities have not led to widespread, systemic impacts on drinking water resources in the United States, although there are above and below ground mechanisms by which hydraulic fracturing activities have the potential to impact drinking water resources. The draft report is expected to be finalized after a public comment period and a formal review by the EPA’s Science Advisory Board. Other governmental agencies, including the United States Department of Energy and the United States Department of the Interior, are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies could spur initiatives to further regulate hydraulic fracturing under the federal SDWA or other regulatory mechanisms.

If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations. In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA, our fracturing activities could become subject to additional permitting requirements and could also result in permitting delays and potential cost increases. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we are ultimately able to produce from our reserves.

Our operations are substantially dependent on the availability of water. Restrictions on our ability to obtain water may have an adverse effect on our financial condition, results of operations and cash flows.

Water is an essential component of both the drilling and hydraulic fracturing processes. Historically, we have been able to purchase water from local land owners and other sources for use in our operations. Over the past few years, extreme drought conditions persisted in West Texas and Southeast New Mexico. Although conditions have improved, we cannot guarantee what conditions may occur in the future. Severe drought conditions can result in local water districts taking steps to restrict the use of water subject to their jurisdiction for drilling and hydraulic fracturing in order to protect the local water supply. If we are unable to obtain water to use in our operations from local sources, we may be unable to economically

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produce oil and natural gas, which could have an adverse effect on our financial condition, results of operations and cash flows.

Estimates of proved reserves and future net cash flows are not precise. The actual quantities of our proved reserves and our future net cash flows may prove to be lower than estimated.

Numerous uncertainties exist in estimating quantities of proved reserves and future net cash flows therefrom. Our estimates of proved reserves and related future net cash flows are based on various assumptions, which may ultimately prove to be inaccurate.

Petroleum engineering is a subjective process of estimating accumulations of oil and natural gas that cannot be measured in an exact manner. Estimates of economically recoverable oil and natural gas reserves and of future net cash flows depend upon a number of variable factors and assumptions, including the following:

·historical production from the area compared with production from other producing areas;

·the assumed effects of regulations by governmental agencies;

·the quality, quantity and interpretation of available relevant data;

·assumptions concerning future commodity prices; and

·assumptions concerning future operating costs; severance, ad valorem and excise taxes; development costs; and workover and remedial costs.

Because all reserve estimates are to some degree subjective, each of the following items, or other items not identified below, may differ materially from those assumed in estimating reserves:

·the quantities of oil and natural gas that are ultimately recovered;

·the production and operating costs incurred;

·the amount and timing of future development expenditures; and

·future commodity prices.

Furthermore, different reserve engineers may make different estimates of reserves and cash flows based on the same data. Our actual production, revenues and expenditures with respect to reserves will likely be different from estimates and the differences may be material.

As required by the SEC, the estimated discounted future net cash flows from proved reserves are based on the average previous twelve months first-of-month prices preceding the date of the estimate and costs as of the date of the estimate, while actual future prices and costs may be materially higher or lower. Actual future net cash flows also will be affected by factors such as:

·the amount and timing of actual production;

·levels of future capital spending;

·increases or decreases in the supply of or demand for oil, natural gas liquids and natural gas; and

·changes in governmental regulations or taxation.

Accordingly, estimates included herein of future net cash flows may be materially different from the future net cash flows that are ultimately received. Therefore, the estimates of discounted future net cash flows in this report should not be construed as accurate estimates of the current market value of our proved reserves.

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Our business requires substantial capital expenditures. We may be unable to obtain needed capital or financing on satisfactory terms or at all, which could lead to a decline in our oil and natural gas reserves.

The oil and natural gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures for the acquisition, exploration and development of oil and natural gas reserves. At December 31, 2015, we had no outstanding debt under our credit facility (and total debt at December 31, 2015 was $3.3 billion), and we had approximately $2.5 billion of unused commitments under our credit facility. Expenditures for acquisition, exploration and development of oil and natural gas properties are the primary use of our capital resources. We incurred approximately $2.1 billion in acquisition, exploration and development activities (excluding asset retirement obligations) during the year ended December 31, 2015. In November 2015, we announced our 2016 base capital budget, excluding acquisitions, of approximately $1.4 billion. During 2016, our current intent is to adjust our capital spending to be within our cash flows. Based on current commodity prices and costs, our capital plan is in the range of $1.1 billion to $1.3 billion. We plan to spend approximately $3.0 billion over the next five years on future development costs associated with proved undeveloped reserves.

We intend to finance our future capital expenditures, other than significant acquisitions, through cash flow from operations and through borrowings under our credit facility; however, our financing needs may require us to alter or increase our capitalization substantially through the issuance of debt or equity securities. The issuance of additional equity securities could have a dilutive effect on the value of our common stock. Additional borrowings under our credit facility or the issuance of additional debt securities will require that a greater portion of our cash flow from operations be used for the payment of interest and principal on our debt, thereby reducing our ability to use cash flow to fund working capital, capital expenditures and acquisitions. In addition, our credit facility imposes certain limitations on our ability to incur additional indebtedness other than indebtedness under our credit facility. If we desire to issue additional debt securities other than as expressly permitted under our credit facility, we will be required to seek the consent of the lenders in accordance with the requirements of the credit facility, which consent may be withheld by the lenders at their discretion. If we incur certain additional indebtedness, our borrowing base under our credit facility may be reduced. Additional financing also may not be available on acceptable terms or at all. In the event additional capital resources are unavailable, we may curtail drilling, development and other activities or be forced to sell some of our assets on an untimely or unfavorable basis.

Our cash flow from operations and access to capital are subject to a number of variables, including:

·our proved reserves;

·the level of oil and natural gas we are able to produce from existing wells;

·the prices at which our commodities are sold;

·the costs of producing oil and natural gas;

·global credit and securities markets;

·the ability and willingness of lenders and investors to provide capital and the cost of the capital;

·our ability to acquire, locate and produce new reserves; and

·the impact of potential changes in our credit ratings.

If our revenues or the borrowing base under our credit facility decrease as a result of lower commodity prices or sustained depressed commodity prices, operating difficulties, declines in reserves, lending requirements or regulations, or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current or anticipated levels. As a result, we may require additional capital to fund our operations, and we may not be able to obtain debt or equity financing on terms acceptable to us, if at all, to satisfy our capital requirements. If cash generated from operations or borrowings available under our credit facility is not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to the development of our prospects, which in turn could lead to a decline in our oil and natural gas reserves, and could adversely affect our production, revenues and results of operations.

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Declining general economic, business or industry conditions could have a material adverse effect on our results of operations.

In recent years, the global economic downturn, particularly with respect to the U.S. economy, and the global financial and credit market disruptions have reduced the availability of liquidity and credit to fund the continuation and expansion of industrial business operations worldwide resulting in a slowdown in economic activity. This has reduced worldwide demand for energy and resulted in lower commodity prices.

Lower commodity prices will reduce our cash flows and borrowing ability. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a decline in our reserves as existing reserves are depleted. Lower commodity prices may also reduce the amount of oil and natural gas that we can produce economically, which could ultimately decrease our net revenue and profitability.

We have substantial indebtedness and may incur substantially more debt. Higher levels of indebtedness make us more vulnerable to economic downturns and adverse developments in our business.

We had approximately $3.3 billion of outstanding debt at December 31, 2015. At December 31, 2015, the borrowing base under our credit facility was $3.25  billion and commitments from our bank group totaled $2.5 billion, of which $2.5 billion was unused commitments.

As a result of our indebtedness, we will need to use a portion of our cash flow to pay interest, which will reduce the amount we will have available to fund our operations and other business activities and could limit our flexibility in planning for or reacting to changes in our business and the industry in which we operate. Our indebtedness under our credit facility is at a variable interest rate, and so a rise in interest rates will generate greater interest expense to the extent we do not have applicable interest rate fluctuation hedges. The amount of our debt may also cause us to be more vulnerable to economic downturns and adverse developments in our business.

We may incur substantially more debt in the future. The indentures governing our senior notes contain restrictions on our incurrence of additional indebtedness. These restrictions, however, are subject to a number of qualifications and exceptions, and under certain circumstances, we could incur substantial additional indebtedness in compliance with these restrictions. Moreover, these restrictions do not prevent us from incurring obligations that do not constitute indebtedness under the indentures.

Our ability to meet our debt obligations and other expenses will depend on our future performance, which will be affected by financial, business, economic, regulatory and other factors, many of which we are unable to control. If our cash flow is not sufficient to service our debt, we may be required to refinance debt, sell assets or sell additional equity on terms that we may not find attractive if it may be done at all. Further, our failure to comply with the financial and other restrictive covenants relating to our indebtedness could result in a default under that indebtedness, which could adversely affect our business, financial condition and results of operations.

Our lenders can limit our borrowing capabilities, which may materially impact our operations.

At December 31, 2015, we had no debt outstanding under our credit facility, and our borrowing base was $3.25 billion and commitments from our bank group totaled $2.5 billion. The borrowing base under our credit facility is redetermined annually based upon a number of factors, including commodity prices and reserve levels. In addition, between redeterminations we and, if requested by 66 2/3 percent of our lenders, our lenders, may each request one special redetermination. Upon a redetermination, our borrowing base could be substantially reduced, and in the event the amount outstanding under our credit facility at any time exceeds the borrowing base at such time, we may be required to repay a portion of our outstanding borrowings. We expect to utilize cash on hand, cash flow from operations, bank borrowings, debt and equity financings and asset sales to fund our acquisition, exploration and development activities. A reduction in our borrowing base could limit our activities. In addition, we may significantly alter our capitalization in order to make future acquisitions or develop our properties. These changes in capitalization may significantly increase our level of indebtedness. If we incur additional debt for these or other purposes, the related risks that we now face could intensify. A higher level of indebtedness also increases the risk that we may default on our debt obligations. Our ability to meet our debt obligations and to reduce our level of indebtedness depends on our future performance which is affected by general economic conditions and financial, business and other factors, many of which are beyond our control.

A downgrade in our credit rating could negatively impact our cost of and ability to access capital.

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We receive debt credit ratings from Standard & Poor’s Ratings Group, Inc. (“S&P”) and Moody’s Investors Service, Inc. (“Moody’s”), which are subject to regular reviews. S&P and Moody’s consider many factors in determining our ratings including: production growth opportunities, liquidity, debt levels and asset and reserve mix.

On December 16, 2015, Moody’s announced that it placed the ratings of 29 U.S. exploration and production companies, including us, on review for downgrade. At December 31, 2015, our long-term debt was rated “Ba1” with an outlook under review. Since that action, Moody’s lowered its oil price estimates and placed additional exploration and production companies on review for downgrade. With Moody’s reduced expectations for the likely range of prices and deteriorating industry conditions, there is an increased possibility for multi-notch downgrades as an outcome of the review process. The ultimate outcome of the ratings review for any particular exploration and production company will depend on such company’s particular credit attributes. On February 11, 2016, Moody’s affirmed our rating as “Ba1” and assigned a stable outlook.

At December 31, 2015, our long-term debt was rated BB+ with a stable outlook by S&P. On February 9, 2016, S&P affirmed our rating as part of a broader review of 45 exploration and production companies. Of the 45 companies under review by S&P, 20 companies’ ratings were affirmed while 25 companies’ ratings were downgraded.

A downgrade in our credit ratings could negatively impact our costs of capital and our ability to effectively execute aspects of our strategy. Further, a downgrade in our credit ratings could affect our ability to raise debt in the public debt markets, and the cost of any new debt could be much higher than our outstanding debt. These and other impacts of a downgrade in our credit ratings could have a material adverse effect on our business, financial condition and results of operations.

As of the filing of this report, no additional changes in our credit ratings have occurred; however, we cannot be assured that our credit ratings will not be downgraded in the future.

Our operations expose us to significant costs and liabilities with respect to environmental and operational safety matters.

We may incur significant delays, costs and liabilities as a result of environmental, health and safety requirements applicable to our oil and natural gas exploration, development and production, and related saltwater disposal activities. These delays, costs and liabilities could arise under a wide range of federal, state and local laws and regulations relating to protection of the environment, health and safety, including regulations and enforcement policies that have tended to become increasingly strict over time. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of cleanup and site restoration costs and liens, and, in some instances, issuance of orders or injunctions limiting or requiring discontinuation of certain operations. In addition, claims for damages to persons or property, including natural resources, may result from the environmental, health and safety impacts of our operations.

Strict as well as joint and several liability for a variety of environmental costs may be imposed on us under certain environmental laws, which could cause us to become liable for the conduct of others or for consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. New laws, regulations or enforcement policies could be more stringent and impose unforeseen liabilities or significantly increase compliance costs. No assurance can be given that continued compliance with existing or future environmental laws and regulations will not result in a curtailment of production or processing activities or result in a material increase in the costs of production, development, exploration or processing operations. If we are not able to recover the resulting costs through insurance or increased revenues, our production, revenues and results of operations could be adversely affected.

Our producing properties are concentrated in the Permian Basin of Southeast New Mexico and West Texas, making us vulnerable to risks associated with operating in one major geographic area. In addition, we have a large amount of proved reserves attributable to a small number of producing horizons within this area.

Our producing properties are geographically concentrated in the Permian Basin of Southeast New Mexico and West Texas. At December 31, 2015, substantially all of our total estimated proved reserves were attributable to properties located in this area. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, processing or transportation capacity constraints, market limitations, severe weather events, water shortages or other drought related conditions or interruption of the processing or transportation of oil, natural gas or natural gas liquids.

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In addition to the geographic concentration of our producing properties described above, at December 31, 2015, approximately: (i) 29 percent of our proved reserves were attributable to the Yeso formation, which includes both the Paddock and Blinebry intervals, underlying our oil and natural gas properties located in Southeast New Mexico; (ii) 25 percent of our proved reserves were attributable to the Bone Spring formation located in the Delaware Basin; and  (iii) 17 percent of our proved reserves were attributable to the Wolfcamp and Spraberry formations in West Texas. This concentration of assets within a small number of producing horizons exposes us to additional risks, such as changes in field-wide rules and regulations that could cause us to permanently or temporarily shut-in all of our wells within a field.

We periodically evaluate our unproved oil and natural gas properties for impairment and could be required to recognize non-cash charges to earnings of future periods.

At December 31, 2015, we carried unproved property costs of $0.9 billion. GAAP requires periodic evaluation of these costs on a project-by-project basis in comparison to their estimated fair value. These evaluations will be affected by the results of exploration activities, intent of future exploration activities, commodity price circumstances, planned future sales or expiration of all or a portion of the leases, future drilling plans, contracts and permits appurtenant to such projects. Based on our evaluations, we may determine that we are unable to fully recover the cost invested in each project, and we will recognize non-cash charges to earnings in future periods.

Part of our strategy involves exploratory drilling, including drilling in new or emerging plays. As a result, our drilling results in these areas are uncertain, and the value of our undeveloped acreage will decline if drilling results are unsuccessful.

The results of our exploratory drilling in new or emerging plays are more uncertain than drilling results in areas that are developed and have established production. Since new or emerging plays and new formations have limited or no production history, we are unable to use past drilling results in those areas to help predict our future drilling results. As a result, our cost of drilling, completing and operating wells in these areas may be higher than initially expected, and the value of our undeveloped acreage will decline if drilling results are unsuccessful.

Our commodity price risk management program may cause us to forego additional future profits or result in our making cash payments to our counterparties.

To reduce our exposure to changes in the prices of commodities, we have entered into and may in the future enter into additional commodity price risk management arrangements for a portion of our oil and natural gas production. The agreements that we have entered into generally have the effect of providing us with a fixed price for a portion of our expected future oil and natural gas production over a fixed period of time. Commodity price risk management arrangements expose us to the risk of financial loss and may limit our ability to benefit from increases in commodity prices in some circumstances, including the following:

·the counterparty to a commodity price risk management contract may default on its contractual obligations to us;

·there may be a change in the expected differential between the underlying price in a commodity price risk management agreement and actual prices received; or

·market prices may exceed the prices which we are contracted to receive, resulting in our need to make significant cash payments to our counterparties.

Our commodity price risk management activities could have the effect of reducing our net income and the value of our securities. At December 31, 2015, the Company had a net derivative asset of approximately $819.5 million. An average increase in the commodity price of $5.00 per barrel of oil and $0.50 per MMBtu for natural gas from the commodity price at December 31, 2015 would have resulted in a decrease in our net asset of approximately $196.9  million. We may continue to incur significant gains or losses in the future from our commodity price risk management activities to the extent market prices increase or decrease and our derivatives contracts remain in place.

Our identified inventory of drilling locations and recompletion opportunities are scheduled out over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.

We have identified and scheduled the drilling of certain of our drilling locations as an estimation of our future multi-year development activities on our existing acreage. These identified locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including: (i) our ability to timely drill

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wells on lands subject to complex development terms and circumstances; (ii) the availability of capital, equipment, services and personnel; (iii) weather conditions; (iv) regulatory and third-party approvals; (v) commodity prices; (vi) access to and availability of water sourcing and distribution systems; and (vii) drilling and recompletion costs and results. Additionally, changes in the laws or regulations on which we rely in planning and executing our drilling programs could adversely impact our ability to successfully complete those programs. Because of these and other potential uncertainties, we may never drill the potential locations we have identified or produce oil or natural gas from these or any other potential locations. As such, our actual development activities may materially differ from those presently identified, which could adversely affect our production, revenues and results of operations.

Unless we replace our oil and natural gas reserves, our reserves and production will decline, which would adversely affect our cash flow, our ability to raise capital and the value of our securities.

Unless we conduct successful development and exploration activities or acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our future oil and natural gas reserves and production, and therefore our cash flow and results of operations, are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. The value of our securities and our ability to raise capital will be adversely impacted if we are not able to replace our reserves that are depleted by production. We may not be able to develop, exploit, find or acquire sufficient additional reserves to replace our current and future production.

The Standardized Measure and PV-10 of our estimated reserves are not accurate estimates of the current fair value of our estimated proved oil and natural gas reserves.

Standardized Measure is a reporting convention that provides a common basis for comparing oil and natural gas companies subject to the rules and regulations of the SEC. Our non-GAAP financial measure, PV-10, is a similar reporting convention that we have disclosed in this report. Both measures require the use of operating and development costs prevailing as of the date of computation. Consequently, they will not reflect the prices ordinarily received or that will be received for oil and natural gas production because of varying market conditions, nor may it reflect the actual costs that will be required to produce or develop the oil and natural gas properties. Accordingly, estimates included herein of future net cash flows may be materially different from the future net cash flows that are ultimately received. In addition, the 10 percent discount factor, which is required by the rules and regulations of the SEC to be used in calculatingdiscounted future net cash flows for reporting purposes, may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with our company or the oil and natural gas industry in general. Therefore, Standardized Measure or PV-10 included in this report should not be construed as accurate estimates of the current fair value of our proved reserves.

Our reserve estimates and our computation of future net cash flows are based on SEC pricing of (i) $46.79  per Bbl WTI posted oil price and (ii) $2.59  per MMBtu Henry Hub spot natural gas price, adjusted for location and quality by property. The SEC pricing for reserves as of December 31, 2015 is higher than the NYMEX oil price and NYMEX natural gas price of $31.48 per Bbl and $1.82 per MMBtu, respectively, at February 22, 2016. If current pricing measures were used, estimates of our reserves and PV-10 would be lower. For example, if average oil prices were $5.00 per barrel lower than the average price we used, our PV-10 at December 31, 2015 would have decreased from $4.3 billion to $3.6 billion. If average natural gas prices were $0.50 per MMBtu lower than the average price we used, our PV-10 at December 31, 2015, would have decreased from $4.3 billion to $4.0 billion. Any adjustments to the estimates of proved reserves or decreases in the price of our commodities may decrease the value of our securities.

We may be unable to make attractive acquisitions or successfully integrate acquired companies or assets, and any inability to do so may disrupt our business and hinder our ability to grow.

One aspect of our business strategy calls for acquisitions of businesses or assets that complement or expand our current business. We may not be able to identify attractive acquisition opportunities. Even if we do identify attractive candidates, we may not be able to complete the acquisition of them or do so on commercially acceptable terms.

In addition, our credit facility and the indentures governing our senior notes impose certain limitations on our ability to enter into mergers or combination transactions. Our credit facility and the indentures governing our senior notes also limit our ability to incur certain indebtedness, which could indirectly limit our ability to engage in acquisitions of businesses or assets. If we desire to engage in an acquisition that is otherwise prohibited by our credit facility or the indentures governing our senior notes, we will be required to seek the consent of our lenders or the holders of the senior notes in accordance with

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the requirements of the credit facility or the indentures, which consent may be withheld by the lenders under our credit facility or such holders of senior notes at their sole discretion.

If we acquire another business or assets, we could have difficulty integrating its operations, systems, management and other personnel and technology with our own. These difficulties could disrupt our ongoing business, distract our management and employees, increase our expenses and adversely affect our results of operations. In addition, we may incur additional debt or issue additional equity to pay for any future acquisitions, subject to the limitations described above.

Any acquisition we complete is subject to substantial risks that could adversely affect our business, including the risk that our acquisitions may prove to be worth less than what we paid because of uncertainties in evaluating recoverable reserves and could expose us to potentially significant liabilities.

We obtained a significant portion of our current reserve base through acquisitions of producing properties and undeveloped acreage. We expect that acquisitions will continue to contribute to our future growth. In connection with these and potential future acquisitions, we are often only able to perform limited due diligence. The success of any acquisition involves potential risks, including among other things:

·the inability to estimate accurately the costs to develop the reserves, recoverable volumes of reserves, rates of future production and future net cash flows attainable from the reserves;

·the assumption of unknown liabilities, including environmental liabilities, and losses or costs for which the Company is not indemnified or for which the indemnity the Company receives is inadequate;

·the effect on our liquidity or financial leverage of using available cash or debt to finance acquisitions;

·the diversion of management's attention from other business concerns; and

·an inability to hire, train or retain qualified personnel to manage and operate our growing business and assets.

Successful acquisitions of oil and natural gas properties require an assessment of a number of factors, including estimates of recoverable reserves, the timing of recovering reserves, exploration potential, future commodity prices, operating costs and potential environmental, regulatory and other liabilities. Such assessments are inexact, and we cannot make these assessments with a high degree of accuracy. In connection with our assessments, we perform a review of the acquired properties that we believe to be generally consistent with industry practices. However, such a review will not reveal all existing or potential problems. In addition, our review may not permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. We do not inspect every well. Even when we inspect a well, we do not always discover structural, subsurface and environmental problems that may exist or arise.

There may be threatened, contemplated, asserted or other claims against the acquired assets related to environmental, title, regulatory, tax, contract, litigation or other matters of which we are unaware, which could materially and adversely affect our production, revenues and results of operations. We are sometimes able to obtain contractual indemnification for preclosing liabilities, including environmental liabilities, but we generally acquire interests in properties on an “as is” basis with limited remedies for breaches of representations and warranties. In addition, even when we are able to obtain such indemnification from the sellers, these indemnification obligations usually expire over time and expose us to potential unindemnified liabilities, which could materially adversely affect our production, revenues and results of operations.

Shortages of oilfield equipment, services and qualified personnel could delay our drilling program and increase the prices we pay to obtain such equipment, services and personnel.

The demand for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry can fluctuate significantly, often in correlation with commodity prices, causing periodic shortages. Historically, there have been shortages of drilling and workover rigs, pipe and other oilfield equipment as demand for rigs and equipment has increased along with the number of wells being drilled. These factors also cause significant increases in costs for equipment, services and personnel. Higher commodity prices generally stimulate demand and result in increased prices for drilling and workover rigs, crews and associated supplies, equipment and services. It is beyond our control and ability to predict whether these conditions will exist in the future and, if so, what their timing and duration will be. These types of shortages or price increases could significantly

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decrease our profit margin, cash flow and operating results, or restrict our ability to drill the wells and conduct the operations which we currently have planned and budgeted or which we may plan in the future.

Our exploration and development drilling may not result in commercially productive reserves.

Drilling activities are subject to many risks, including the risk that commercially productive reservoirs will not be encountered. New wells that we drill may not be productive, or we may not recover all or any portion of our investment in such wells. The seismic data and other technologies we use do not allow us to know conclusively prior to drilling a well that oil or natural gas is present or may be produced economically. Drilling for oil and natural gas often involves unprofitable results, not only from dry holes but also from wells that are productive but do not produce sufficient net reserves to return a profit at then realized prices after deducting drilling, operating and other costs. The cost of drilling, completing and operating a well is often uncertain, and cost factors can adversely affect the economics of a project. Further, our drilling operations may be curtailed, delayed or canceled as a result of numerous factors, including:

·unexpected drilling conditions;

·title problems;

·pressure or irregularities in formations;

·equipment failures or accidents;

·fracture stimulation accidents or failures;

·adverse weather conditions;

·compliance with environmental and other governmental or contractual requirements; and

·increases in the cost of, or shortages or delays in the availability of, electricity, water, supplies, materials, drilling or workover rigs, equipment and services.

We may incur substantial losses and be subject to substantial liability claims as a result of our oil and natural gas operations. In addition, we may not be insured for, or our insurance may be inadequate to protect us against, these risks.

We are not insured against all risks. Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect our business, financial condition or results of operations. Our oil and natural gas exploration and production activities,including well stimulation and completion activities such as hydraulic fracturing, are subject to all of the operating risks associated with drilling for and producing oil and natural gas, including the possibility of:

·environmental hazards, such as uncontrollable flows of oil, natural gas, brine, well fluids, toxic gas or other pollution into the environment, including groundwater contamination;

·abnormally pressured or structured formations;

·mechanical difficulties, such as stuck oilfield drilling and service tools and casing collapse;

·blowouts, cratering, fires, explosions and ruptures of pipelines;

·personal injuries and death; and

·natural disasters.

Any of these risks could adversely affect our ability to conduct operations or result in substantial losses to us as a result of:

·injury or loss of life;

·damage to and destruction of property and equipment;

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·damage to natural resources due to underground migration of hydraulic fracturing fluids;

·pollution and other environmental damage, including spillage or mishandling of recovered hydraulic fracturing fluids;

·regulatory investigations and penalties;

·suspension of our operations; and

·repair and remediation costs.

We may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. The occurrence of an event that is not covered or not fully covered by insurance could have a material adverse effect on our production, revenues and results of operations.

Competition in the oil and natural gas industry is intense, making it more difficult for us to acquire properties, market oil and natural gas and secure trained personnel.

We operate in a highly competitive environment for acquiring properties, marketing oil and natural gas and securing trained personnel. Some of our competitors possess and employ financial, technical and personnel resources substantially greater than ours, which can be particularly important in the areas in which we operate. Those companies may be able to pay more for productive oil and natural gas properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. In addition, those companies may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer. The cost to attract and retain qualified personnel may increase substantially in the future. Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Also, there is substantial competition for capital available for investment in the oil and natural gas industry. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital. Our failure to acquire properties, market oil and natural gas and secure trained personnel and adequately compensate personnel could have a material adverse effect on our production, revenues and results of operations.

Market conditions or operational impediments may hinder our access to oil and natural gas markets or delay our production.

Market conditions or the unavailability of satisfactory oil and natural gas processing or transportation arrangements may hinder our access to oil, natural gas and natural gas liquid markets or delay our production. The availability of a ready market for our oil and natural gas production depends on a number of factors, including the demand for and supply of oil, natural gas and natural gas liquids, the proximity of reserves to pipelines and terminal facilities, competition for such facilities and the inability of such facilities to gather, transport or process our production due to shutdowns or curtailments arising from mechanical, operational or weather related matters, including hurricanes and other severe weather conditions. Our ability to market our production depends in substantial part on the availability and capacity of gathering and transportation systems, pipelines and processing facilities owned and operated by third parties. Our failure to obtain such services on acceptable terms could have a material adverse effect on our business, financial condition and results of operations. We may be required to shut in or otherwise curtail production from wells due to lack of a market or inadequacy or unavailability of oil, natural gas liquid or natural gas pipeline or gathering, transportation or processing capacity. If that were to occur, then we would be unable to realize revenue from those wells until suitable arrangements were made to market our production.

We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, timing, manner or feasibility of conducting our operations or that may subject us to fines or penalties for any failure to comply.

Our oil and natural gas exploration, development and production, and related saltwater disposal operations are subject to complex and stringent laws and regulations. In order to conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state, local and governmental authorities. We may incur substantial costs and experience delays in order to maintain compliance with these existing laws and regulations. If we fail to comply with the existing laws and regulations, we may incur additional costs, including fines and penalties, in order to come back into compliance. In addition, our costs of compliance may increase or our operations may be otherwise adversely affected if existing laws and regulations are revised or reinterpreted or if the

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government agencies responsible for enforcing certain existing laws and regulations applicable to us change their priorities or policies, or if new laws and regulations become applicable to our operations. These and other costs could have a material adverse effect on our production, revenues and results of operations.

Future legislation may impose new taxes or fees on crude oil or natural gas, including by eliminating or reducing certain federal income tax deductions currently available with respect to oil and natural gas exploration and development.

Budgets proposed by President Obama have included proposals that would, among other things, eliminate or reduce certain key United States federal income tax incentives currently available to oil and natural gas exploration and production companies. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain domestic production activities and (iv) an extension of the amortization period for certain geological and geophysical expenditures.

It is unclear whether any such changes will actually be enacted or, if enacted, how soon any such changes could become effective. The passage of any legislation as a result of the budget proposal, tax reform efforts, or any other similar change in United States federal income tax law could affect certain tax deductions that are currently available to us with respect to our oil and natural gas exploration and production activities. Additionally, President Obama has proposed, as part of the Budget of the United States Government for Fiscal Year 2017, to impose an “oil fee” of $10.25 per barrel equivalent of crude oil.  This fee would be collected on domestically produced and imported petroleum products.  If enacted into law, the fee would be phased in over five years, beginning October 1, 2016.  The adoption of this, or similar proposals, could result in increased operating costs and/or reduced consumer demand for petroleum products, which in turn could affect the prices companies such as ours receive for our oil.

Climate change legislation or regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the crude oil and natural gas that we produce.

In response to findings that emissions of carbon dioxide, methane and other “greenhouse gases” present an endangerment to public health and the environment, the EPA has issued regulations to restrict emissions of greenhouse gases under existing provisions of the CAA. These regulations include limits on tailpipe emissions from motor vehicles and preconstruction and operating permit requirements for certain large stationary sources. The EPA has also adopted rules requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States, as well as certain onshore oil and natural gas production facilities, on an annual basis. Recently, in December 2015, the EPA finalized rules that added new sources to the scope of the greenhouse gases monitoring and reporting rule. These new sources include gathering and boosting facilities as well as completions and workovers from hydraulically fractured oil wells. The revisions also include the addition of well identification reporting requirements for certain facilities. In addition, as part of the Obama Administration’s overall strategy to reduce methane emissions from the oil and natural gas sector by up to 45 percent from 2012 levels by 2025, the EPA and other federal agencies have or are in the process of proposing new rules related to the control of methane emissions. For example, in August 2015, the EPA announced proposed rules that would establish new air emission controls for emissions of methane from certain equipment and processes in the oil and natural gas source category, including production, processing, transmission and storage activities. The EPA’s proposed rule package includes first-time standards to address emissions of methane from equipment and processes across the source category, including hydraulically fractured oil and natural gas well completions. More recently, in January 2016, the BLM issued proposed rules limiting the venting and flaring of natural gas from oil and natural gas activities on federal lands. Increased regulation of methane and other GHGs have the potential to result in increased compliance costs and, consequently, adversely affect our operations.

While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce emissions of GHGs in recent years. In the absence of Congressional action, many states have taken legal measures to reduce emissions of GHGs primarily through regional GHG cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and natural gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall GHG emission reduction goal.

The adoption of legislation or regulatory programs to reduce emissions of GHGs could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or to comply with new regulatory or reporting requirements. For example, pursuant to President Obama’s Strategy to Reduce Methane Emissions, the EPA proposed in August 2015 regulations that will set methane emission standards for new and

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modified oil and gas production and natural gas processing and transmission facilities as part of the Administration’s efforts to reduce methane emissions from the oil and natural gas sector by up to 45 percent from 2012 levels by 2025. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produce. Consequently, legislation and regulatory programs to reduce emissions of GHGs could have an adverse effect on our business, financial condition and results of operations. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our financial condition and results of operations.

The adoption of derivatives legislation by Congress could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.

Congress adopted comprehensive financial reform legislation that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, including us, which participate in that market. This legislation, known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Act”), became law on July 21, 2010 and requires the Commodities Futures Trading Commission (the “CFTC”) and the SEC to promulgate rules and regulations implementing the Act. Although the CFTC has finalized certain regulations, others remain to be finalized or implemented and it is not possible at this time to predict when this will be accomplished.

In October 2011, the CFTC issued regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. The initial position limits rule was vacated by the United States District Court for the District of Columbia in September 2012. However, in November 2013, the CFTC proposed new rules that would place limits on positions in certain core futures and equivalent swaps contracts for or linked to certain physical commodities, subject to exceptions for certain bona fide hedging transactions. As these new position limit rules are not yet final, the impact of those provisions on us is uncertain at this time.

The CFTC has designated certain interest rate swaps and credit default swaps for mandatory clearing and the associated rules also will require us, in connection with covered derivative activities, to comply with clearing and trade-execution requirements or take steps to qualify for an exemption to such requirements. The CFTC has not yet proposed rules designating any other classes of swaps, including physical commodity swaps, for mandatory clearing. Although we expect to qualify for the end-user exception from the mandatory clearing requirements for swaps entered to hedge our commercial risks, the application of the mandatory clearing and trade execution requirements to other market participants, such as swap dealers, may change the cost and availability of the swaps that we use for hedging. If our swaps do not qualify for the commercial end-user exception, or if the cost of entering into uncleared swaps becomes prohibitive, we may be required to clear such transactions. The ultimate effect of the rules and any additional regulations on our business is uncertain at this time.

In addition, certain banking regulators and the CFTC have adopted final rules establishing minimum margin requirements for uncleared swaps. Although we expect to qualify for the end-user exception from such margin requirements for swaps entered into to hedge our commercial risks, the application of such requirements to other market participants, such as swap dealers, may change the cost and availability of the swaps that we use for hedging. If any of our swaps do not qualify for the commercial end-user exception, the posting of collateral could reduce our liquidity and cash available for capital expenditures and our ability to manage commodity price volatility and the volatility in cash flows. The impact of those provisions is uncertain at this time.

The full impact of the Act and related regulatory requirements upon our business will not be known until the regulations are implemented and the market for derivatives contracts has adjusted. The Act and any new regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, or reduce our ability to monetize or restructure our existing derivative contracts. If we reduce our use of derivatives as a result of the Act and regulations implementing the Act, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the Act was intended, in part, to reduce the volatility of commodity prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil, natural gas and natural gas liquids. Our revenues could therefore be adversely affected if a consequence of the Act and implementing regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on us, our financial condition and our results of operations.

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The loss of our chief executive officer or other key personnel could negatively impact our ability to execute our business strategy.

We depend, and will continue to depend in the foreseeable future, on the services of our chief executive officer, Timothy A. Leach, and other officers and key employees who have extensive experience and expertise in evaluating and analyzing producing oil and natural gas properties and drilling prospects, maximizing production from oil and natural gas properties, marketing oil and natural gas production, and developing and executing acquisition, financing and hedging strategies. Our ability to hire and retain our officers and key employees is important to our continued success and growth. The unexpected loss of the services of one or more of these individuals could negatively impact our ability to execute our business strategy.

Because we do not operate and therefore control the development of certain of the properties in which we own interests, we may not be able to produce economic quantities of oil and natural gas in a timely manner. 

At December 31, 2015, approximately 8.9 percent of our proved reserves were attributable to properties for which we were not the operator. As a result, the success and timing of drilling and development activities on properties operated by others depend upon a number of factors, including:

·the nature and timing of drilling and operational activities;

·the timing and amount of capital expenditures;

·the operators’ expertise and financial resources;

·the approval of other participants in such properties; and

·the selection and application of suitable technology.

If drilling and development activities are not conducted on these properties or are not conducted on a timely basis, we may be unable to increase our production or offset normal production declines or we will be required to write-off the reserves attributable thereto, which may adversely affect our production, revenues and results of operations. Any such write-offs of our reserves could reduce our ability to borrow money and could reduce the value of our securities.

Uncertainties associated with enhanced recovery methods may result in us not realizing an acceptable return on our investments in such projects.

We inject water into formations on some of our properties to increase the production of oil and natural gas. We may in the future expand these efforts to more of our properties or employ other enhanced recovery methods in our operations. The additional production and reserves, if any, attributable to the use of enhanced recovery methods are inherently difficult to predict. If our enhanced recovery methods do not allow for the extraction of oil and natural gas in a manner or to the extent that we anticipate, we may not realize an acceptable return on our investments in such projects.

Part of our strategy involves using some of the latest available horizontal drilling and completion techniques, which involve risks and uncertainties in their application.

Our operations involve utilizing some of the latest drilling and completion techniques. Risks that we face while drilling horizontal wells include, but are not limited to, the following:

·landing the wellbore in the desired drilling zone;

·staying in the desired drilling zone while drilling horizontally through the formation;

·running casing the entire length of the wellbore; and

·being able to run tools and other equipment consistently through the horizontal wellbore.

Risks that we face while completing wells include, but are not limited to, the following:

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·the ability to fracture stimulate the planned number of stages;

·the ability to run tools the entire length of the wellbore during completion operations; and

·the ability to successfully clean out the wellbore after completion of the final fracture stimulation stage.

A terrorist or cyber-attack or armed conflict could harm our business by decreasing our revenues and increasing our costs.

Terrorist activities, anti-terrorist efforts, cyber-attacks and other armed conflict involving the United States may adversely affect the United States and global economies and could prevent us from meeting our financial and other obligations. If any of these events occur or escalate, the resulting political instability and societal disruption could reduce overall demand for oil and natural gas, potentially putting downward pressure on demand for our production and causing a reduction in our revenue. Oil and natural gas related facilities could be direct targets of terrorist attacks, and our operations could be adversely impacted if significant infrastructure or facilities used for the production, transportation, processing or marketing of oil and natural gas production are destroyed or damaged. Additionally, as an oil and natural gas producer, we may face various cybersecurity threats, including threats to gain unauthorized access to sensitive information or to render data or systems unusable, and there can be no assurance that our implementation of various procedures and controls to monitor and mitigate security threats will be sufficient to prevent security breaches from occurring. Costs for insurance and other security may increase as a result of these threats, and some insurance coverage may become more difficult to obtain, if available at all.

Cybersecurity breaches and information technology failures could harm our business by increasing our costs and negatively impacting our operations.

We rely extensively on information technology systems, including Internet sites, data hosting facilities and other hardware and platforms, some of which are hosted by third parties, to assist in conducting our business. Our information technology systems, as well as those of third parties we use in our operations, may be vulnerable to a variety of cybersecurity risks, such as those involving unauthorized access, malicious software, data privacy breaches by employees or others with authorized access, cyber or phishing-attacks and other security issues.

Although we have implemented information technology controls and systems that are designed to protect information and prevent or minimize the risk of data loss and other cybersecurity risks, such measures cannot entirely eliminate cybersecurity threats, and the enhanced controls we have installed may be breached or may fail. If our information technology systems cease to function properly or our cybersecurity is breached, we could suffer disruptions to our operations and unauthorized persons may gain access to proprietary or confidential information, which could result in loss or disclosure of, or damage to, our or any of our customer’s or supplier’s data or confidential information; misuse or misappropriation of data, funds or other property; and other manipulation or improper use of our systems or networks. This could harm our business by damaging our reputation, subjecting us to potential financial or legal liability, and requiring us to incur significant costs, including costs to repair or restore the security of our internal systems or to take other remedial steps.

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Risks Related to Our Common Stock

Our restated certificate of incorporation, our bylaws and Delaware law contain provisions that could discourage acquisition bids or merger proposals, which may adversely affect the market price of our common stock.

Our restated certificate of incorporation authorizes our board of directors to issue preferred stock without stockholder approval. If our board of directors elects to issue preferred stock, it could be more difficult for a third party to acquire us. In addition, some provisions of our certificate of incorporation, our bylaws and Delaware law could make it more difficult for a third party to acquire control of us, even if the change of control would be beneficial to our stockholders, including:

·the organization of our board of directors as a classified board, which allows no more than approximately one-third of our directors to be elected each year;

·stockholders cannot remove directors from our board of directors except for cause and then only by the holders of not less than 66 2/3 percent of the voting power of all outstanding voting stock;

·the prohibition of stockholder action by written consent; and

·limitations on the ability of our stockholders to call special meetings and establish advance notice provisions for stockholder proposals and nominations for elections to the board of directors to be acted upon at meetings of stockholders.

Because we have no plans to pay dividends on our common stock, investors must look solely to stock appreciation for a return on their investment in us.

We do not anticipate paying any cash dividends on our common stock in the foreseeable future. We currently intend to retain all future earnings to fund the development and growth of our business. Any payment of future dividends will be at the discretion of our board of directors and will depend on, among other things, our earnings, financial condition, capital requirements, level of indebtedness, statutory and contractual restrictions applying to the payment of dividends and other considerations that our board of directors deems relevant. Covenants contained in our credit facility and the indentures governing our senior notes restrict the payment of dividends. Investors must rely on sales of their common stock after price appreciation, which may never occur, as the only way to realize a return on their investment. Investors seeking cash dividends should not purchase our common stock.

The availability of shares for sale in the future could reduce the market price of our common stock.

In the future, we may issue securities to raise cash for acquisitions. We may also acquire interests in other companies by using a combination of cash and our common stock or just our common stock. We may also issue securities convertible into, or exchangeable for, or that represent the right to receive, our common stock. Any of these events may dilute your ownership interest in our company, reduce our earnings per share and have an adverse impact on the price of our common stock.

In addition, sales of a substantial amount of our common stock in the public market, or the perception that these sales may occur, could reduce the market price of our common stock. This could also impair our ability to raise additional capital through the sale of our securities.

The market price and trading volume of our common stock may be volatile, which could result in losses for our stockholders.

The market price of our common stock may be volatile and could be subject to wide fluctuations. In addition, the trading volume of our common stock may fluctuate and cause price variations to occur. The market price of our common stock may fluctuate or decline significantly in the future. If the market price of our common stock declines, you may be unable to sell your shares of common stock at or above your purchase price. Some of the factors that could negatively affect the price of our common stock, or result in fluctuations in the price or trading volume of our common stock, include:

·fluctuations in the price of oil or natural gas;

·variations in our quarterly operating results or failure to meet analysts’ earnings expectations;

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·publication of negative research reports about us or the oil and natural gas industry or adverse publicity about the oil and natural gas industry;

·adverse market reaction to any indebtedness we may incur or securities we may issue in the future or actions by our stockholders;

·sales of a large number of our common stock or the perception that such sales could occur;

·changes in market valuations of similar companies;

·the effects of government regulation, permitting and other legal requirements, including new legislation or regulation of hydraulic fracturing and the export of oil and natural gas;

·litigation and governmental investigations; and

·general economic and business conditions, either internationally or domestically.

Item 1B.  Unresolved Staff Comments

There are no unresolved staff comments.

Item 2.  Properties

Our Oil and Natural Gas Reserves

The estimates of our proved reserves at December 31, 2015, all of which were located in the United States, were based on evaluations prepared by the independent petroleum engineering firms of Cawley, Gillespie & Associates, Inc. (“CGA”) and Netherland, Sewell & Associates, Inc. (“NSAI”) (collectively, our “external engineers”). Reserves were estimated in accordance with guidelines established by the SEC and the Financial Accounting Standards Board (the “FASB”).

Internal controls. Our proved reserves are estimated at the property level and compiled for reporting purposes by our corporate reservoir engineering staff, all of whom are independent of our operating teams. We maintain our internal evaluations of our reserves in a secure reserve engineering database. The corporate reservoir engineering staff interact with our internal staff of petroleum engineers and geoscience professionals in each of our operating areas and with accounting and marketing employees to obtain the necessary data for the reserves estimation process. Reserves are reviewed and approved internally by members of our senior management and the reserves committee.

Our internal professional staff works closely with our external engineers to ensure the integrity, accuracy and timeliness of data that is furnished to them for their reserve estimation process. All of the reserve information maintained in our secure reserve engineering database is provided to the external engineers. In addition, other pertinent data is provided such as seismic information, geologic maps, well logs, production tests, material balance calculations, well performance data, operating procedures and relevant economic criteria. We make available all information requested, including our pertinent personnel, to the external engineers as part of their preparation of our reserves.

Qualifications of responsible technical persons

J. Steve Guthrie has been our Senior Vice President of Business Operations and Engineering since November 2013. Mr. Guthrie previously served as the Vice President of Texas from October 2010 to November2013. Mr. Guthrie also served as Texas Asset Manager from July 2008 to October 2010 and as Corporate Engineering Manager from August 2004 to July 2008. Prior to joining the Company in 2004, Mr. Guthrie was employed by Moriah Resources as Business Development Manager, by Henry Petroleum in various engineering and operations capacities and by Exxon in several engineering and operations positions. Mr. Guthrie is a graduate of Texas Tech University with a Bachelor of Science degree in Petroleum Engineering.

Rick Morton joined the Company in 2011 as Corporate Engineering Manager. Prior to joining the Company, Mr. Morton served as Division Acquisition Coordinator for EOG Resources, Inc. Mr. Morton was also previously employed by Southwest Royalties, Inc. as Vice President and Exploitation Manager, and by Merit Energy Company in various engineering

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positions. Mr. Morton began his career in 1983 with Arco Oil and Gas Company as an Operations/Analytical Engineer before moving to a Production Supervisor position. He is a graduate of Texas A&M University with a Bachelor of Science degree in Petroleum Engineering.

CGA. Approximately 72 percent of the proved reserves estimates shown herein at December 31, 2015 have been independently prepared by CGA, a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies. CGA was founded in 1960 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-693. Within CGA, the technical person primarily responsible for preparing the estimates set forth in the CGA letter dated January 20, 2016, filed as an exhibit to this Annual Report on Form 10-K, was Mr. Zane Meekins. Mr. Meekins has been a practicing consulting petroleum engineer at CGA since 1989. Mr. Meekins is a Registered Professional Engineer in the State of Texas (License No. 71055) and has over 25 years of practical experience in petroleum engineering, with over 20 years of experience in the estimation and evaluation of reserves. He graduated from Texas A&M University in 1987 with a Bachelor of Science degree in Petroleum Engineering. Mr. Meekins meets or exceeds the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; he is proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserve definitions and guidelines.

NSAI. Approximately 28 percent of the proved reserve estimates shown herein at December 31, 2015 have been independently prepared by NSAI, a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies. NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-2699. Within NSAI, the technical person primarily responsible for preparing the estimates set forth in the NSAI letter dated January 22, 2016, filed as an exhibit to this Annual Report on Form 10-K, was Mr. Michael Begland. Mr. Begland, a Licensed Professional Engineer in the State of Texas (License No. 104898), has been practicing consulting petroleum engineering at NSAI since 1993 and has over seven years of prior industry experience. He graduated from Ohio State University in 1983 with a Bachelor of Science Degree in Chemical Engineering. Mr. Begland meets or exceeds the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; he is proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserve definitions and guidelines.

Our oil and natural gas reserves. The following table sets forth our estimated proved oil and natural gas reserves, PV-10 and Standardized Measure at December 31, 2015. PV-10 and Standardized Measure include the present value of our estimated future abandonment and site restoration costs for proved properties net of the present value of estimated salvage proceeds from each of these properties. Our reserve estimates and our computation of future net cash flows are based on SEC pricing of (i) $46.79 per Bbl WTI posted oil price and (ii) $2.59 per MMBtu Henry Hub spot natural gas price, adjusted for location and quality by property.

		Oil	Natural Gas	Total		PV-10 (a)
		(MBbl)	(MMcf)	(MBoe)		(in millions)
Core Operating Areas:
	New Mexico Shelf	113,923	500,467	197,334	$	1,309.8
	Delaware Basin	184,335	789,009	315,837		2,235.2
	Midland Basin	69,518	243,070	110,030		716.3
Other		8	1,517	260		2.0
	Total	367,784	1,534,063	623,461		4,263.3
Present value of future income taxes discounted at 10%						(523.8)
Standardized Measure					$	3,739.5

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The following table sets forth our estimated proved reserves by category at December 31, 2015:

		Oil	Natural Gas	Total	Percent of		PV-10 (a) (in millions)
		(MBbl)	(MMcf)	(MBoe)	Total
Proved developed producing		188,374	876,843	334,515	53.7%	$	3,340.7
Proved developed non-producing		15,506	49,786	23,803	3.8%		102.0
Proved undeveloped		163,904	607,434	265,143	42.5%		820.6
	Total proved	367,784	1,534,063	623,461	100.0%	$	4,263.3
Total proved developed		203,880	926,629	358,318	57.5%	$	3,442.7

(a)Our Standardized Measure at December 31, 2015 was $3.7 billion. PV-10 is a Non-GAAP financial measure and is derived from the Standardized Measure which is the most directly comparable GAAP financial measure. PV-10 is a computation of the Standardized Measure on a pre-tax basis. PV-10 is equal to the Standardized Measure at the applicable date, before deducting future income taxes, discounted at 10 percent. We believe that the presentation of PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to our estimated proved reserves prior to taking into account future corporate income taxes, and it is a useful measure for evaluating the relative monetary significance of our oil and natural gas assets. Further, investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies. We use this measure when assessing the potential return on investment related to our oil and natural gas assets. PV-10, however, is not a substitute for the Standardized Measure. Our PV-10 measure and the Standardized Measure do not purport to present the fair value of our oil and natural gas reserves. See “Item 1. Business —Non-GAAP Financial Measures and Reconciliations.”

___________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________

Changes to proved reserves. The following table sets forth the changes in our proved reserve volumes by area during the year ended December 31, 2015 (in MBoe):

				Purchases of	Sales of	Revisions of
			Extensions and	Minerals-in-	Minerals-in-	Previous
		Production	Discoveries	Place	Place	Estimates
Core Operating Areas:
	New Mexico Shelf	(11,473)	25,031	71	-	(64,114)
	Delaware Basin	(31,175)	98,110	11,449	-	(6,394)
	Midland Basin	(9,632)	33,926	183	(1,379)	(58,481)
Other		(8)	1	-	-	163
	Total	(52,288)	157,068	11,703	(1,379)	(128,826)

Extensions and discoveries. Extensions and discoveries of approximately 157.1 MMBoe are primarily the result of our continued success from our extension and infill horizontal drilling programs in our core operating areas. Proved developed reserves increased approximately 54.8 MMBoe due to our exploratory drilling activity in 2015. Based upon this activity, approximately 102.3 MMBoe of new proved undeveloped locations were added, of which the vast majority are one offset location from an existing producing well.

Purchases and sales of minerals-in-place.  Our purchases of minerals-in-place are composed of approximately 11.7 MMBoe from various acquisitions and 1.4 MMBoe from various divestitures throughout the year.

Revisions of previous estimates.  Revisions of previous estimates are comprised of (i) 112.2 MMBoe of negative price revisions, (ii) 10.9 MMBoe of negative revisions due to proved undeveloped reserves reclassified to unproved reserves because they are no longer expected to be developed within the five years of their initial recording required by SEC rules and (iii) 5.7 MMBoe of negative revisions resulting from technical and performance evaluations. Our proved reserves at December 31, 2015 were determined using the SEC prices of $46.79 per Bbl of oil for WTI and $2.59 per MMBtu of natural gas for Henry Hub spot, compared to corresponding prices of $91.48 per Bbl of oil and $4.35 per MMBtu of natural gas at December 31, 2014.

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Proved undeveloped reserves.  At December 31, 2015, we had approximately 265.1MMBoe of proved undeveloped reserves as compared to 260.3 MMBoe at December 31, 2014.

The following table summarizes the changes in our proved undeveloped reserves during 2015 (in MBoe):

At December 31, 2014		260,309
	Extensions and discoveries	102,327
	Purchases of minerals-in-place	8,680
	Sales of minerals-in-place	(883)
	Revisions of previous estimates	(74,961)
	Conversion to proved developed reserves	(30,329)
At December 31, 2015		265,143

Extensions and discoveries of approximately 102.3 MMBoe are primarily the result of new proved undeveloped locations that were added, of which the vast majority are one offset location from an existing producing well.

Net negative revisions of previous estimates of approximately 75.0 MMBoe are primarily attributable to (i) 50.5 MMBoe of negative price revisions, (ii) 10.9 MMBoe of negative revisions due to proved undeveloped reserves reclassified to unproved reserves because they are no longer expected to be developed within the five years of their initial recording as required by SEC rules, primarily as a result of our transition from vertical to horizontal development and (iii) 13.6 MMBoe of net negative miscellaneous revisions.

The following table sets forth proved undeveloped reserves converted to proved developed reserves during the respective year and the investment required to convert proved undeveloped reserves to proved developed reserves:

		Proved Undeveloped Reserves			Investment in Conversion
Years Ended		Converted to			of Proved Undeveloped Reserves
December 31,		Proved Developed Reserves			to Proved Developed Reserves
		Oil (MBbls)	Natural Gas (MMcf)	Total (MBoe)
							(in thousands)
2011		25,201	68,495	36,616		$	491,602
2012		19,132	60,388	29,196			411,576
2013		17,050	52,237	25,756			441,998
2014		20,970	75,266	33,514			561,198
2015		19,465	65,181	30,329			464,697
	Total	101,818	321,567	155,411		$	2,371,071

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The following table sets forth the estimated timing and cash flows of developing our proved undeveloped reserves at December 31, 2015 (dollars in thousands):

		Future		Future		Future		Future
Years Ended		Production		Cash		Production		Development		Future Net
December 31, (a)		(MBoe)		Inflows (b)		Costs		Costs		Cash Flows
2016		5,283	$	180,359	$	(26,510)	$	(385,126)	$	(231,277)
2017		12,733		439,154		(62,964)		(668,922)		(292,732)
2018		21,078		724,073		(105,607)		(846,941)		(228,475)
2019		25,689		865,107		(136,946)		(623,922)		104,239
2020		26,910		892,311		(151,847)		(450,208)		290,256
Thereafter		173,450		5,618,445		(2,056,069)		(25,644)		3,536,732
	Total	265,143	$	8,719,449	$	(2,539,943)	$	(3,000,763)	$	3,178,743
(a)	Beginning in 2016 and thereafter, the production and cash flows represent the drilling results from the respective year plus the incremental effects from the results of proved undeveloped drilling from previous years.
(b)	Computation is based on SEC pricing of (i) $46.79 per Bbl WTI posted oil price and (ii) $2.59 per MMBtu Henry Hub spot natural gas price, adjusted for location and quality by property.

Historically, our drilling programs were substantially funded from our cash flow and borrowings from our credit facility and were weighted towards drilling unproven locations. Based on our current expectations over the next 5 years of our cash flows and drilling programs, which includes drilling of proved undeveloped and unproven locations, we believe that we can continue to substantially fund our drilling activities from our cash flow and with borrowings from our credit facility, if needed.

Developed and Undeveloped Acreage

The following table presents our total gross and net developed and undeveloped acreage by area at December 31, 2015:

		Developed Acres		Undeveloped Acres		Total Acres
		Gross	Net	Gross	Net	Gross	Net
Core Operating Areas:
	New Mexico Shelf	123,879	84,258	26,669	18,440	150,548	102,698
	Delaware Basin	419,380	292,350	173,894	127,670	593,274	420,020
	Midland Basin	257,905	148,860	6,001	2,942	263,906	151,802
Other		3,052	1,891	981	981	4,033	2,872
	Total	804,216	527,359	207,545	150,033	1,011,761	677,392

The following table sets forth the future expiration amounts of our gross and net undeveloped acreage at December 31, 2015 by area:

			2016		2017		2018		Thereafter
			Gross	Net	Gross	Net	Gross	Net	Gross	Net
Core Operating Areas:
	New Mexico Shelf (a)		15,783	12,149	4,332	2,573	1,324	545	1,200	875
	Delaware Basin (b)		98,381	79,705	21,582	10,445	19,006	7,789	14,408	12,151
	Midland Basin		1,415	814	3,109	840	161	33	186	31
Other			981	981	-	-	-	-	-	-
		Total	116,560	93,649	29,023	13,858	20,491	8,367	15,794	13,057
(a)		Amounts include 18,910 gross (14,959 net) acres that we have no current plans to explore.
(b)		Amounts include 79,830 gross (72,472 net) acres primarily in the outer limits of our southern Delaware Basin core area that we have no current plans to explore.  The majority of these acres expire in 2016.

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Drilling Activities

For summary tables that set forth information with respect to wells drilled and completed for the years ended December 31, 2015, 2014 and 2013, see “Item 1. Business —Drilling Activities.”

Our Production, Prices and Expenses

For a summary table that sets forth information concerning our production and operating data from continuing operations for the years ended December 31, 2015, 2014 and 2013, see “Item 1. Business —Our Production, Prices and Expenses.”

Productive Wells

For a summary table that sets forth the number of productive oil and natural gas wells on our properties at December 31, 2015, 2014 and 2013, see “Item 1. Business —Productive Wells.”

Title to Our Properties

As is customary in the oil and natural gas industry, we initially conduct only a cursory review of the title to our properties on which we do not have proved reserves. Prior to the commencement of drilling operations on those properties, we conduct a more thorough title examination and perform curative work with respect to significant defects. To the extent title opinions or other investigations reflect defects affecting those properties, we are typically responsible for curing any such defects at our expense. We generally will not commence drilling operations on a property until we have cured known material title defects on such property. We have reviewed the title to substantially all of our producing properties and believe that we have satisfactory title to our producing properties in accordance with standards generally accepted in the oil and natural gas industry. Prior to completing an acquisition of producing oil and natural gas properties, we perform title reviews on the most significant properties and, depending on the materiality of properties, we may obtain a title opinion or review or update previously obtained title opinions. Our oil and natural gas properties are subject to customary royalty and other interests, liens to secure borrowings under our credit facility, liens for current taxes and other burdens which we believe do not materially interfere with the use or affect our carrying value of the properties.

Item 3.  Legal Proceedings

We are a party to proceedings and claims incidental to our business. While many of these other matters involve inherent uncertainty, we believe that the liability, if any, ultimately incurred with respect to such other proceedings and claims will not have a material adverse effect on our consolidated financial position as a whole or on our liquidity, capital resources or future results of operations. We will continue to evaluate proceedings and claims involving us on a regular basis and will establish and adjust any reserves as appropriate to reflect our assessment of the then current status of the matters.

Item 4. Mine Safety Disclosures

Not applicable.

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PART II

Item 5.  Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Market Information

     Our common stock trades on the NYSE under the symbol “CXO.” The following table shows, for the periods indicated, the high and low sales prices for our common stock, as reported on the NYSE.

		Price Per Share
		High		Low
2014:
	First Quarter	$	125.15	$	94.51
	Second Quarter	$	145.70	$	120.57
	Third Quarter	$	148.61	$	123.94
	Fourth Quarter	$	128.05	$	77.22
2015:
	First Quarter	$	122.14	$	91.26
	Second Quarter	$	134.13	$	110.44
	Third Quarter	$	115.13	$	92.41
	Fourth Quarter	$	120.41	$	85.87

On February 22, 2016, the last sales price of our common stock as reported on the NYSE was $94.97 per share.

As of February 22, 2016, there were 1,087 holders of record of our common stock.

Dividend Policy

We have not paid, and do not intend to pay in the foreseeable future, cash dividends on our common stock. Covenants contained in our credit facility and the indentures governing our senior notes limit the payment of dividends on our common stock. We currently intend to retain all future earnings to fund the development and growth of our business. Any payment of future dividends will be at the discretion of our board of directors and will depend on, among other things, our earnings, financial condition, capital requirements, level of indebtedness, statutory and contractual restrictions applying to the payment of dividends and other considerations that our board of directors deems relevant. See Note 9 of the Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional information.

Repurchases of Equity Securities

Period		Total number of shares withheld (a)	Average price per share		Total number of shares purchased as part of publicly announced plans	Maximum number of shares that may yet be purchased under the plan
October 1, 2015 - October 31, 2015		368	$	113.63	-
November 1, 2015 - November 30, 2015		102	$	109.21	-
December 1, 2015 - December 31, 2015		1,108	$	103.48	-
(a)	Represents shares that were withheld by us to satisfy tax withholding obligations of certain of our officers and key employees that arose upon the lapse of restrictions on restricted stock.

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Item 6.  Selected Financial Data

This section presents our selected historical consolidated financial data. The selected historical consolidated financial data presented below is not intended to replace our historical consolidated financial statements. You should read the following data along with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the consolidated financial statements and related notes, each of which is included in this report.

Selected Historical Financial Information

Our results of operations for the periods presented below may not be comparable either from period to period or going forward for the following reasons:

·in June 2013, we issued $850 million in aggregate principal amount of 5.5% senior notes due 2023 at 103.75 percent of par, for which we received net proceeds of approximately $867.8 million. We used a portion of the net proceeds from the offering to fund the tender offer and redemption of the 8.625% Notes at a price of 106.922 percent of the unpaid principal amount. The remaining proceeds were used to pay down amounts outstanding on the credit facility;

·in May 2014, we issued in a secondary public offering 7.5 million shares of our common stock at $129.00 per share, and we received net proceeds of approximately $932.0 million;

·in March 2015, we issued 6.9 million shares of our common stock in a public offering at $107.49 per share, and we received net proceeds of approximately $741.5 million;

·in October 2015, we issued approximately 8.9 million shares of our common stock in a public offering at $92.50 per share, and we received net proceeds of approximately $794.2 million; and

·in December 2015, we completed an acreage exchange with Clayton Williams Energy, Inc. that consolidated acres into a concentrated, operated position in the southern Delaware Basin. We recognized a loss on disposition of assets of approximately $50.0 million related to the acreage exchange.

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Our financial data below is derived from (i) our audited consolidated financial statements included in this report and (ii) other audited consolidated financial statements of ours not included in this report, after taking into consideration the retrospective adoption of Accounting Standards Update (“ASU”) No. 2015-03 and 2015-17. See Note 2 of the Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional information.

				Years Ended December 31,
(in thousands, except per share amounts)				2015		2014		2013		2012 (a)		2011
Statement of operations data:
	Total operating revenues		$	1,803,573	$	2,660,147	$	2,319,919	$	1,819,814	$	1,617,771
	Total operating costs and expenses			(1,422,570)		(1,570,402)		(1,702,482)		(969,251)		(814,103)
Income from operations			$	381,003	$	1,089,745	$	617,437	$	850,563	$	803,668
Income from continuing operations, net of tax			$	65,900	$	538,175	$	238,922	$	408,230	$	419,534
Income from discontinued operations, net of tax				-		-		12,081		23,459		128,603
Net income attributable to common shareholders			$	65,900	$	538,175	$	251,003	$	431,689	$	548,137
Basic earnings per share:
	Income from continuing operations		$	0.54	$	4.89	$	2.28	$	3.96	$	4.09
	Income from discontinued operations, net of tax			-		-		0.11		0.22		1.25
		Net income attributable to common shareholders	$	0.54	$	4.89	$	2.39	$	4.18	$	5.34
Diluted earnings per share:
	Income from continuing operations		$	0.54	$	4.88	$	2.28	$	3.93	$	4.05
	Income from discontinued operations, net of tax			-		-		0.11		0.22		1.23
		Net income attributable to common shareholders	$	0.54	$	4.88	$	2.39	$	4.15	$	5.28
Other financial data:
	Net cash provided by operations		$	897,505	$	1,673,787	$	1,362,020	$	1,237,478	$	1,199,458
	Net cash used in investing activities		$	1,969,725	$	2,545,996	$	1,896,794	$	2,240,444	$	1,651,418
	Net cash provided by financing activities		$	1,300,749	$	872,209	$	531,915	$	1,005,504	$	451,918
	EBITDAX (b)		$	1,712,910	$	2,033,225	$	1,685,592	$	1,475,628	$	1,275,159
				December 31,
(in thousands)				2015		2014		2013		2012 (a)		2011
Balance sheet data:
	Cash and cash equivalents		$	228,550	$	21	$	21	$	2,880	$	342
	Property and equipment, net			10,976,947		10,206,014		8,946,048		7,993,424		6,290,118
	Total assets (c) (d)			12,641,876		11,751,780		9,507,931		8,540,234		6,789,636
	Long-term debt, including current maturities (c)			3,332,188		3,469,137		3,577,257		3,051,900		2,048,994
	Stockholders' equity			6,942,551		5,280,788		3,757,949		3,466,196		2,980,739

(a)The acquisition of producing and non-producing assets from Three Rivers Operating Company LLC and certain affiliated entities closed in July 2012. 

(b)EBITDAX is defined 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) (gain) loss on derivatives, (7) cash receipts from (payments on) derivatives, (8) loss on disposition of assets and other, (9) interest expense, (10) loss on extinguishment of debt, (11) federal and state income taxes on continuing operations and (12) similar items listed above that are presented in discontinued operations. See “Item 1. Business —Non-GAAP Financial Measures and Reconciliations.”

(c)Amounts related to deferred loan costs have been retrospectively adjusted for years 2011 through 2014 due to early adoption of ASU No. 2015-03.  See Note 2 of the Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional information.

(d)Amounts related to deferred taxes have been retrospectively adjusted for years 2011 through 2014 due to early adoption of ASU No. 2015-17. See Note 2 of the Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional information. _______________________________________________________________________________________________________________________

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

The following discussion is intended to assist you in understanding our business and results of operations together with our present financial condition. This section should be read in conjunction with our historical consolidated financial statements and notes, as well as the selected historical consolidated financial data included elsewhere in this report.

Certain statements in our discussion below are forward-looking statements. These forward-looking statements involve risks and uncertainties. We caution that a number of factors could cause actual results to differ materially from those implied or expressed by the forward-looking statements. Please see “Cautionary Statement Regarding Forward-Looking Statements.”

Overview

We are an independent oil and natural gas company engaged in the acquisition, development, exploration and production of oil and natural gas properties. Our core operations are primarily focused in the Permian Basin of Southeast New Mexico and West Texas. Concho’s legacy in the Permian Basin provides us a deep understanding of operating and geological trends. We are also at the forefront of applying new technologies, such as horizontal drilling and enhanced completion techniques, throughout our three core operating areas: the New Mexico Shelf, the Delaware Basin and the Midland Basin. In the New Mexico Shelf, we primarily target the Yeso formation with horizontal drilling, in the Delaware Basin, we use horizontal drilling to target the Bone Spring formation (including the Avalon shale and the Bone Spring sands) and the Wolfcamp shale formation; and in the Midland Basin, we target the Wolfcamp and Spraberry formations with horizontal drilling.  Oil comprised 59 percent of our 623.5 MMBoe of estimated proved reserves at December 31, 2015 and 65.9 percent of our 52.3 MMBoe of production for 2015. We seek to operate the wells in which we own an interest, and we operated wells that accounted for 93 percent of our proved developed producing PV-10 and 78.9 percent of our 7,636 gross wells at December 31, 2015. By controlling operations, we are able to more effectively manage the cost and timing of exploration and development of our properties, including the drilling and stimulation methods used.

46

Financial and Operating Performance

Our financial and operating performance for 2015 included the following highlights:

·Net income was $65.9 million ($0.54per diluted share), as compared to net income of $538.2million ($4.88  per diluted share) in 2014. The decrease in net income was primarily due to:

•$856.6 million decrease in oil and natural gas revenues as a result of a 47 percent decrease in commodity price realizations per Boe (excluding the effects of derivative activities), partially offset by a 28percent increase in production;

•$243.5 million increase in depreciation, depletion and amortization expense, primarily due to increased production associated with new wells that were successfully drilled and completed in 2014  and 2015; 

•$191.2 million decrease in the gain on derivatives in 2015 as compared to 2014;

•$26.6 million increase in general and administrative expense due to an increase in the number of employees and related personnel expenses; and

•$44.5 million increase in loss on disposition of assets, net, primarily as a result of the acreage exchange with Clayton Williams Energy, Inc.;

partially offset by:

•$386.6 million decrease in non-cash impairment charges due to a $447.2 million non-cash impairment charge in 2014 as compared to $60.5 million in non-cash impairment charges in 2015;

•$286.4 million change in our income tax expense due to the decrease in income before income taxes; and

•$226.0 million decrease in exploration and abandonment expense due primarily to a reduction in geological and geophysical expense, exploratory dry hole costs and leasehold abandonments in 2015 as compared to 2014. 

·Average daily sales volumes increased by 28 percent from 111,987 Boe per day during 2014 to 143,256 Boe per day during 2015. The increase is primarily attributable to our successful drilling and completion efforts during 2014  and 2015. 

·Net cash provided by operating activities decreased by approximately $776.3 million to $897.5 million for 2015, as compared to $1,673.8 million in 2014, primarily due to a decrease in oil and natural gas revenues offset partially by positive variances in working capital changes.

·Our 2015 capital spending plan was weighted toward the first half of the year as we completed wells we commenced drilling in 2014. We used borrowings under our credit facility and proceeds from our March and October 2015 equity offerings to fund our drilling and completions activity as well as acquisitions. The net result of our capital spending and equity offerings was a decrease in long-term debt of approximately $0.1billion during 2015, and we had cash on hand of approximately $228.6 million at December 31, 2015.

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Commodity Prices

Our results of operations are heavily influenced by commodity prices. Commodity prices may fluctuate widely in response to (i) relatively minor changes in the supply of and demand for oil, natural gas and natural gas liquids, (ii) market uncertainty and (iii) a variety of additional factors that are beyond our control. Factors that may impact future commodity prices, including the price of oil, natural gas and natural gas liquids, include:

·continuing economic uncertainty worldwide;

·political and economic developments in oil and natural gas producing regions, including Africa, South America and the Middle East;

·the extent to which members of the Organization of Petroleum Exporting Countries and other oil exporting nations are able to continue to manage oil prices and production controls;

·technological advances affecting energy consumption and energy supply;

·the effect of energy conservation efforts;

·the price and availability of alternative fuels;

·domestic and foreign governmental regulations, including limits on the United States’ ability to export crude oil, and taxation;

·the level of global inventories;

·the proximity, capacity, cost and availability of pipelines and other transportation facilities, as well as the availability of commodity processing and gathering and refining capacity;

·risks related to the concentration of our operations in the Permian Basin of Southeast New Mexico and West Texas and the level of commodity inventory in the Permian Basin;

·the quality of the oil we produce;

·the overall global demand for oil, natural gas and natural gas liquids;

·the domestic and foreign supply of oil, natural gas and natural gas liquids; and

·overall North American oil and natural gas supply and demand fundamentals, including:

•the United States economy impact,

•weather conditions, and

•liquefied natural gas deliveries to and exports from the United States.

Although we cannot predict the occurrence of events that may affect future commodity prices or the degree to which these prices will be affected, the prices for any commodity that we produce will generally approximate current market prices in the geographic region of the production. From time to time, we expect that we may economically hedge a portion of our commodity price risk to mitigate the impact of price volatility on our business. See Notes 8 and 17 of the Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional information regarding our commodity derivative positions at December 31, 2015 and additional derivative contracts entered into subsequent to December 31, 2015, respectively.

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Oil and natural gas prices have been subject to significant fluctuations during the past several years. In general, average oil and natural gas prices were significantly lower during 2015 compared to 2014. The following table sets forth the average NYMEX oil and natural gas prices for the years ended December 31, 2015, 2014 and 2013, as well as the high and low NYMEX prices for the same periods:

			Years Ended December 31,
			2015		2014		2013
Average NYMEX prices:
	Oil (Bbl)		$	48.84	$	92.94	$	98.05
	Natural gas (MMBtu)		$	2.63	$	4.27	$	3.73
High and Low NYMEX prices:
	Oil (Bbl):
		High	$	61.43	$	107.26	$	110.53
		Low	$	34.73	$	53.27	$	86.68
	Natural gas (MMBtu):
		High	$	3.23	$	6.15	$	4.46
		Low	$	1.76	$	2.89	$	3.11

Further, the NYMEX oil price and NYMEX natural gas price reached highs and lows of $37.04 and $26.21 per Bbl and $2.47 and $1.80 per MMBtu, respectively, during the period from January 1, 2016 to February 22, 2016. At February 22, 2016, the NYMEX oil price and NYMEX natural gas price were $31.48 per Bbl and $1.82 per MMBtu, respectively.

Our total natural gas revenues are derived from the value of the natural gas liquids contained in our natural gas, with the remaining portion coming from the value of the dry natural gas residue. In the past, our liquids-rich natural gas stream and the related value of the natural gas liquids included in our natural gas revenues resulted in our realized natural gas price (excluding the effects of derivatives) being greater than the related NYMEX natural gas price. However, during the year ended December 31, 2015, our realized natural gas price (excluding the effects of derivatives) fell below the related NYMEX natural gas price primarily due to the average Mont Belvieu price for a blended barrel of natural gas liquids decreasing to $17.80 per Bbl, as compared to $34.58 per Bbl during the year ended December 31, 2014.

49

Recent Events

2016 capital budget.In November 2015, we announced our 2016 base capital budget, excluding acquisitions, of approximately $1.4 billion, with drilling and completion capital accounting for approximately $1.2 billion.

During 2016, our current intent is to adjust our capital spending to be within our cash flows. Based on current commodity prices and costs, our capital plan is in the range of $1.1 billion to $1.3 billion. However, if we were to outspend our cash flows, we expect to be able to use our (i) cash on hand, (ii) credit facility and (iii) other financing sources. The actual amount and timing of our expenditures may differ materially from our estimates as a result of, among other things, actual drilling results, the timing of expenditures by third parties on projects that we do not operate, the costs of drilling rigs and other services and equipment, regulatory, technological and competitive developments and market conditions. In addition, under certain circumstances, we may consider increasing, decreasing or reallocating our capital spending plans. Our 2016 capital program is expected to continue focusing on horizontal drilling in the Delaware Basin and Midland Basin.

Acreage exchange.In December 2015, we completed an acreage exchange with Clayton Williams Energy, Inc. that consolidated acres into a concentrated, operated position in the southern Delaware Basin. We recognized a loss on disposition of assets of approximately $50.0 million related to the acreage exchange, which is presented in loss on disposition of assets, net, in the consolidated statement of operations for the year ended December 31, 2015.

Midstream investment. In December 2015, we purchased a 25 percent member interest in an entity, which is constructing a crude oil gathering and transportation system in the southern Delaware Basin. The system is expected to be completed and operational during 2016.

Common stock offering. In October 2015, we issued approximately 8.9 million shares of our common stock in a public offering at $92.50 per share and received net proceeds of approximately $794.2 million. We used a portion of the net proceeds from this offering to repay all outstanding borrowings under our credit facility, which were used in part to finance acquisitions at the time. The remaining net proceeds have been used for general corporate purpose while maintaining a cash balance of $228.6 million at December 31, 2015. This balance could be used in the future for items such as potential future acquisitions as well as general corporate purposes.

Asset acquisition. In January 2016, we entered into an asset purchase agreement to acquire 80 percent of the seller’s interest in certain oil and natural gas properties and related assets in the southern Delaware Basin. As consideration for the acquisition, we agreed to issue to the seller approximately 2.2 million shares of our common stock, $150.0 million in cash and $40.0 million to carry a portion of the seller’s future development costs in these properties. The acquisition is expected to close during the first quarter of 2016, subject to customary closing conditions.

Asset divestiture. In January 2016, we entered into an agreement to sell certain assets in the northern Delaware Basin for cash proceeds of approximately $290.0 million. The sale is expected to close during the first quarter of 2016, subject to customary closing conditions. 

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Derivative Financial Instruments

Derivative financial instrument exposure.  At December 31, 2015, the fair value of our financial derivatives was a net asset of $819.5million. All of our counterparties to these financial derivatives are parties to our credit facility and have their outstanding debt commitments and derivative exposures collateralized pursuant to our credit facility. Under the terms of our financial derivative instruments and their collateralization under our credit facility, we do not have exposure to potential “margin calls” on our financial derivative instruments. We currently have no reason to believe that our counterparties to these commodity derivative contracts are not financially viable. See Note 12 of the Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional information. Our credit facility does not allow us to offset amounts we may owe a lender against amounts we may be owed related to our financial instruments with such party.

New commodity derivative contracts. After December 31, 2015, we entered into the following additional oil price swaps and oil basis swaps to hedge additional amounts of our estimated future production:

				First		Second		Third		Fourth
				Quarter		Quarter		Quarter		Quarter		Total
Oil Swaps: (a)
	2017:
		Volume (Bbl)		180,000		180,000		750,000		750,000		1,860,000
		Price per Bbl	$	42.55	$	42.55	$	43.63	$	43.63	$	43.42
Oil Basis Swaps: (b)
	2016:
		Volume (Bbl)		120,000		182,000		-		-		302,000
		Price per Bbl	$	(0.25)	$	(0.25)	$	-	$	-	$	(0.25)
	2017:
		Volume (Bbl)		360,000		242,000		2,024,000		2,024,000		4,650,000
		Price per Bbl	$	(0.41)	$	(0.38)	$	(0.38)	$	(0.38)	$	(0.38)
(a)		The index prices for the oil price swaps are based on the New York Mercantile Exchange ("NYMEX") – West Texas Intermediate ("WTI") monthly average futures price.
(b)		The basis differential price is between Midland – WTI and Cushing – WTI.

51

Results of Operations

The following table sets forth summary information concerning our production and operating data for the years ended December 31, 2015, 2014 and 2013. Because of normal production declines, increased or decreased drilling activities, fluctuations in commodity prices and the effects of acquisitions or divestitures, the historical information presented below should not be interpreted as being indicative of future results.

					Years Ended December 31,
					2015		2014		2013
Production and operating data:
	Net production volumes:
		Oil (MBbl)				34,457		26,319		21,126
		Natural gas (MMcf)				106,987		87,336		75,054
		Total (MBoe)				52,288		40,875		33,635
	Average daily production volumes:
		Oil (Bbl)				94,403		72,107		57,879
		Natural gas (Mcf)				293,115		239,277		205,627
		Total (Boe)				143,256		111,987		92,150
	Average prices:
		Oil, without derivatives (Bbl)			$	44.69	$	83.17	$	91.76
		Oil, with derivatives (Bbl) (a)			$	62.03	$	86.07	$	89.79
		Natural gas, without derivatives (Mcf)			$	2.46	$	5.39	$	5.08
		Natural gas, with derivatives (Mcf) (a)			$	2.80	$	5.34	$	5.21
		Total, without derivatives (Boe)			$	34.49	$	65.08	$	68.97
		Total, with derivatives (Boe) (a)			$	46.60	$	66.84	$	68.01
	Operating costs and expenses per Boe:
		Lease operating expenses and workover costs			$	7.46	$	8.05	$	7.85
		Oil and natural gas taxes			$	2.90	$	5.12	$	5.69
		Depreciation, depletion and amortization			$	23.40	$	23.97	$	22.97
		General and administrative			$	4.42	$	4.99	$	5.04
	(a)	Includes the effect of cash receipts from (payments on) derivatives:
					Years Ended December 31,
		(in thousands)			2015		2014		2013
		Cash receipts from (payments on) derivatives:
			Oil derivatives		$	597,297	$	76,335	$	(41,616)
			Natural gas derivatives			35,619		(4,352)		9,275
				Total	$	632,916	$	71,983	$	(32,341)
		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 our statements of cash flows. 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.

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The following table presents selected production data for the fields which represent greater than 15 percent of our total proved reserves at December 31, 2015, 2014 and 2013:

			Year Ended December 31,
			2015	2014	2013
Production:
	South Basin Wolfcamp Bone Spring:
		Oil (MBbl)	9,742	6,024	(a)
		Natural gas (MMcf)	36,895	25,447	(a)
		Total (MBoe)	15,891	10,265	(a)
	Yeso:
		Oil (MBbl)	6,986	6,929	7,949
		Natural gas (MMcf)	26,833	27,409	26,207
		Total (MBoe)	11,458	11,497	12,317
	Wolfberry West:
		Oil (MBbl)	(a)	(a)	3,509
		Natural gas (MMcf)	(a)	(a)	11,238
		Total (MBoe)	(a)	(a)	5,382
(a) Represented less than 15% of the Company's total proved reserves for the year indicated.

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Year Ended December 31, 2015 Compared to Year Ended December 31, 2014

Oil and natural gas revenues.  Revenue from oil and natural gas operations was$1,803.6 million for the year ended December 31, 2015, a decrease of$856.5 million (32 percent) from $2,660.1 million for the year ended December 31, 2014. This decrease was primarily due to a decrease in realized oil and natural gas prices, offset partially by increased production due to our successful drilling efforts during 2014  and 2015. Specific factors affecting oil and natural gas revenues include the following:

·total oil production was 34,457 MBbl  for the year ended December 31, 2015, an increase  of 8,138 MBbl  (31 percent) from 26,319 MBbl  for the year ended December 31, 2014; 

·average realized oil price (excluding the effects of derivative activities) was $44.69 per Bbl during the year ended December 31, 2015, a decrease of 46 percent  from $83.17  per Bbl during the year ended December 31, 2014. For the year ended December 31, 2015 and 2014, we realized approximately 91.5 percent and 89.5 percent, respectively, of the average NYMEX oil prices for the respective periods. The basis differential between the location of Midland, Texas and Cushing, Oklahoma (NYMEX pricing location) for our oil has a direct effect on our realized oil price. For the years ended December 31, 2015 and 2014, the market basis differential between WTI-Midland and WTI-Cushing (sweet barrel) was a price reduction of $0.41 per Bbl and $6.91 per Bbl, respectively;

·total natural gas production was 106,987 MMcf  for the year ended December 31, 2015, an increase  of 19,651 MMcf  (23 percent) from 87,336 MMcf  for the year ended December 31, 2014; and

·average realized natural gas price (excluding the effects of derivative activities) was $2.46 per Mcf during the year ended December 31, 2015, a decrease of 54 percent  from $5.39 per Mcf during the year ended December 31, 2014. For the years ended December 31, 2015 and 2014, we realized approximately 93.5 percent and 126.2 percent, respectively, of the average NYMEX natural gas prices for the respective periods. Our total natural gas revenues are derived from the value of the natural gas liquids, with the remaining portion coming from the value of the dry natural gas residue. In the past, our liquids-rich natural gas stream and the related value of the natural gas liquids being included in our natural gas revenues resulted in our realized natural gas price (excluding the effects of derivatives) being greater than the related NYMEX natural gas price. However, during the year ended December 31, 2015, our realized natural gas price (excluding the effects of derivatives) fell below the related NYMEX natural gas price primarily due to the average Mont Belvieu price for a blended barrel of natural gas liquids decreasing to $17.80 per Bbl, as compared to $34.58 per Bbl during the year ended December 31, 2014.

During the fourth quarter of 2015, winter weather events across southeast New Mexico had an impact on our production and drilling operations. We experienced power outages, heavy icing and facility freeze-ups across our New Mexico Shelf and Delaware Basin core areas. We estimate that these weather events negatively impacted production for the quarter ended December 31, 2015 by approximately 4.6 MBoepd. Our operations were back to pre-weather levels during mid-January 2016.

Additionally, a third-party natural gas processing plant located in the northern Delaware Basin became inoperable following an explosion in early December 2015. We estimate that this event negatively impacted production for the quarter ended December 31, 2015 by approximately 1.5 MBoepd. We do not expect the plant to be back to full capacity until sometime during the second quarter of 2016.

Heavy rainfall and flooding during the latter part of September 2014 disrupted our operations, primarily in southeast New Mexico, causing shut-in production, road closures and drilling and completion delays. We estimate this weather-related downtime negatively impacted production for the quarter ended December 31, 2014 by approximately 1.6 MBoepd. We estimate that during the quarter ended December 31, 2014 approximately $1.7 million of repairs was due to this event.

54

Production expenses.  The following table provides the components of our total oil and natural gas production costs for the years ended December 31, 2015 and 2014:

			Years Ended December 31,
			2015				2014
						Per				Per
(in thousands, except per unit amounts)				Amount		Boe		Amount		Boe
Lease operating expenses			$	362,114	$	6.93	$	310,284	$	7.59
Workover costs				27,590		0.53		18,967		0.46
Taxes:
	Ad valorem			22,921		0.44		20,775		0.51
	Production			128,734		2.46		188,348		4.61
		Total oil and natural gas production expenses	$	541,359	$	10.36	$	538,374	$	13.17

Among the cost components of production expenses, we have some control over lease operating expenses and workover costs on properties we operate, but production and ad valorem taxes are related to commodity prices.

Lease operating expenses were $362.1 million ($6.93 per Boe) for the year ended December 31, 2015, which was an increase of $51.8 million (17 percent) from $310.3 million ($7.59 per Boe) for the year ended December 31, 2014. The increase in lease operating expenses was primarily due to increased production associated with our wells successfully drilled and completed in 2014  and 2015. The decrease in lease operating expenses per Boe was primarily due to increased production efficiencies resulting in higher volume wells successfully drilled and completed during the year ended December 31, 2015 and 2014. 

Workover expenses were approximately $27.6 million and $19.0 million for the years ended December 31, 2015 and 2014, respectively. The increase was primarily related to a higher volume of workovers performed on electrical submersible pumps in the Delaware Basin area where they were utilized more in 2015 as compared to 2014.

Production taxes per unit of production were $2.46 per Boe during the year ended December 31, 2015, a decrease of 47 percent from $4.61 per Boe during the year ended December 31, 2014. The decrease was directly related to the decrease in oil and natural gas prices. Over the same period, our per Boe prices (excluding the effects of derivatives) decreased 47 percent.

Exploration and abandonments expense. The following table provides a breakdown of our exploration and abandonments expense for the years ended December 31, 2015 and 2014:

		Years Ended December 31,
(in thousands)		2015		2014
Geological and geophysical		$	9,694	$	19,268
Exploratory dry hole costs			9,205		44,180
Leasehold abandonments			34,532		217,326
Other			5,416		4,047
	Total exploration and abandonments	$	58,847	$	284,821

Our geological and geophysical expense for the periods presented above primarily consists of the costs of acquiring and processing geophysical data and core analysis. During the year ended December 31, 2014, we acquired geological and geophysical data related to our northern Delaware Basin acreage.

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Our exploratory dry hole costs during the year ended December 31, 2015 were primarily related to (i) an uneconomic well in our Delaware Basin area that was attempting to establish production in an unconventional zone for the area and (ii) expensing an unsuccessful well, which we did not operate, that was located in our New Mexico Shelf area.

During the year ended December 31, 2015, we recognized leasehold abandonment expense of approximately $34.5 million primarily related to expired and abandoned acreage in our Delaware Basin area where we currently have no intent to drill.

During the fourth quarter of 2014, we completed our assessment of our activity in the outer limits of our southern Delaware Basin acreage position. Based on our analysis and marginal results of our exploratory wells on this acreage, we have no further plans to invest in this position. Accordingly, we recognized approximately $32.7 million in exploratory dry hole costs and approximately $96.4 million in leasehold abandonments in 2014. In addition to the $32.7 million in exploratory dry holes, we recognized approximately $6.3 million in dry hole costs related to two unsuccessful wells in our New Mexico Shelf area that encountered mechanical issues during drilling and one Delaware Basin well targeting the Brushy Canyon horizon that was testing the outer limits of our acreage.

During the year ended December 31, 2014, we recognized leasehold abandonment expense of approximately $217.3 million primarily related to (i) the Delaware Basin abandonment discussed above and (ii) an $86.0 million charge related to properties in our Midland Basin core area that, based on our historical results and our estimate of reduced future commodity price, we have no future intent to drill based on expected low rates of return. The remaining abandonment charges during 2014 are associated with expiring acreage and acreage determined to be outside of our economically productive reservoirs.

Depreciation, depletion and amortization expense.  The following table provides components of our depreciation, depletion and amortization expense for the years ended December 31, 2015 and 2014:

		Years Ended December 31,
		2015				2014
					Per				Per
(in thousands, except per unit amounts)			Amount		Boe		Amount		Boe
Depletion of proved oil and natural gas properties		$	1,203,469	$	23.02	$	960,931	$	23.51
Depreciation of  other property and equipment			18,323		0.35		17,348		0.42
Amortization of intangible asset - operating rights			1,461		0.03		1,461		0.04
	Total depletion, depreciation and amortization	$	1,223,253	$	23.40	$	979,740	$	23.97
Oil price used to estimate proved oil reserves at period end		$	46.79			$	91.48
Natural gas price used to estimate proved natural gas reserves at period end		$	2.59			$	4.35

Depletion of proved oil and natural gas properties was $1,203.5 million ($23.02 per Boe) for the year ended December 31, 2015, an increase of $242.6 million (25 percent) from $960.9 million ($23.51 per Boe) for the year ended December 31, 2014. The increase in depletion expense was primarily due to increased production associated with new wells that were successfully drilled and completed in 2014 and 2015. The decrease in depletion expense per Boe period over period was primarily due to a reduction in the net book value of our oil and natural gas properties due to non-cash impairment charges of approximately $431.7 million recorded in the fourth quarter of 2014 and increased reserves supported by (i) one or more reliable technologies and (ii) our successful exploratory drilling program, partially offset by decreased proved reserves primarily as a result of lower commodity prices.

The increase in depreciation expense was primarily associated with additional other property and equipment related to buildings and other items.

Impairments of long-lived assets.We periodically review our long-lived assets to be held and used, including proved oil and natural gas properties and their integrated assets, whenever events or circumstances indicate that the carrying value of those assets may not be recoverable, for instance when there are declines in commodity prices or well performance. We review our oil and natural gas properties by depletion base or by individual well for those wells not constituting part of a depletion base. An impairment loss is indicated if the sum of the expected undiscounted future net cash flows is less than the carrying amount of the assets. If the estimated undiscounted future net cash flows are less than the carrying amount of our

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assets, we recognize an impairment loss for the amount by which the carrying amount of the asset exceeds the estimated fair value of the asset.

We calculate the expected undiscounted future net cash flows of our long-lived assets and their integrated assets using management’s assumptions and expectations of (i) commodity prices, which are based on the NYMEX strip, (ii) pricing adjustments for differentials, (iii) production costs, (iv) capital expenditures, (v) production volumes, (vi) proved reserves and risk-adjusted probable and possible reserves, and (vii) other sources of income and expenses from integrated assets.

We calculate the estimated fair values of our long-lived assets and their integrated assets using a discounted future cash flow model. Fair value assumptions associated with the calculation of discounted future net cash flows include (i) market estimates of commodity prices, (ii) pricing adjustments for differentials, (iii) production costs, (iv) capital expenditures, (v) production volumes, (vi) estimated proved reserves and risk-adjusted probable and possible reserves, (vii) prevailing market rates of income and expenses from integrated assets and (viii) discount rate. We discount the future net cash flows using a market-based weighted average cost of capital rate determined appropriate at the time.

As a result of the carrying amount of certain of our long-lived assets and their integrated assets being less than their expected undiscounted future net cash flows, we recognized a non-cash charge against earnings for the amount by which the carrying amount exceeded the estimated fair value of the assets. For the year ended December 31, 2015, this amount was approximately $60.5 million and was primarily attributable to properties in our eastern Midland Basin area.

As a result of the carrying amount of certain of our long-lived assets being less than their expected undiscounted future net cash flows, we recognized a non-cash charge against earnings of $447.2 million during the year ended December 31, 2014, which was primarily attributable to (i) non-core properties in our Delaware Basin area, (ii) properties producing from the Grayburg San Andres reservoir in our New Mexico Shelf area and (iii) properties producing from the Canyon and Wolfcamp reservoirs primarily in Irion and Glasscock counties in our Midland Basin core area.

It is reasonably possible that the estimate of undiscounted future net cash flows may change in the future resulting in the need to impair carrying values. The primary factors that may affect estimates of future net cash flows are (i) commodity prices, (ii) increases or decreases in production and capital costs, (iii) future reserve adjustments, both positive and negative, to proved reserves and appropriate risk-adjusted probable and possible reserves, (iv) results of future drilling activities and (v) changes in income and expenses from integrated assets.

Based on economic factors as of December 31, 2015, we determined that undiscounted future cash flows attributable to certain depletion groups with net book value of approximately $5.2 billion indicated that their carrying amounts were expected to be recovered; however, they may be at risk for impairment if management’s estimates of future cash flows decline, including as a result of further declines in projected commodity prices (and the resulting impact of future cash flows) since December 31, 2015. We estimate that, if these depletion groups were to become impaired in a future period, we could recognize non-cash impairment in that period of approximately $2.5 billion.

General and administrative expenses.The following table provides components of our general and administrative expenses for the years ended December 31, 2015 and 2014:

		Years Ended December 31,
		2015				2014
				Per				Per
(in thousands, except per unit amounts)		Amount		Boe		Amount		Boe
General and administrative expenses		$	191,933	$	3.67	$	180,278	$	4.41
Non-cash stock-based compensation			63,073		1.21		47,130		1.15
Less: Third-party operating fee reimbursements			(24,272)		(0.46)		(23,247)		(0.57)
	Total general and administrative expenses	$	230,734	$	4.42	$	204,161	$	4.99

General and administrative expenses were approximately $230.7 million ($4.42 per Boe) for the year ended December 31, 2015, an increase of $26.5 million (13 percent) from $204.2 million ($4.99 per Boe) for the year ended December 31, 2014. The increase in general and administrative expenses was primarily due to an increase in the number of

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employees and related personnel expenses. The increase in non-cash stock-based compensation was primarily due to performance units granted during January 2015. Due to lower commodity prices and a reduction in activity, we began to slow our hiring rate during 2015. The decrease in total general and administrative expenses per Boe was primarily due to increased production from our wells successfully drilled and completed in 2014 and 2015, partially offset by an increase in the number of employees and related personnel expenses in order to manage our activities.

As the operator of certain oil and natural gas properties in which we own an interest, we earn overhead reimbursements during the drilling and production phases of the property. We earned reimbursements of $24.3 million and $23.2 million during the years ended December 31, 2015 and 2014, respectively. This reimbursement is reflected as a reduction of general and administrative expenses in the consolidated statements of operations. The increase in third-party operating fee reimbursements was primarily due to increased reimbursements attributable to more wells operated as a result of continued drilling activity, partially offset by our decreased drilling and completion activity during the second half of 2015.

Gain (loss) on derivatives.The following table sets forth the gain (loss) on derivatives for the years ended December 31, 2015 and 2014:

			Years Ended
			December 31,
(in thousands)				2015		2014
Gain (loss) on derivatives:
	Oil derivatives		$	675,303	$	869,421
	Natural gas derivatives			24,449		21,496
		Total	$	699,752	$	890,917
The following table represents our cash receipts from (payments on) derivatives for the years ended December 31, 2015 and 2014:
			Years Ended
			December 31,
(in thousands)				2015		2014
Cash receipts from (payments on) derivatives:
	Oil derivatives		$	597,297	$	76,335
	Natural gas derivatives			35,619		(4,352)
		Total	$	632,916	$	71,983

Our earnings are affected by the changes in value of our derivatives portfolio between periods and the related cash settlements of those derivatives, which could be significant. To the extent the future commodity price outlook declines between measurement periods, we will have mark-to-market gains, while to the extent future commodity price outlook increases between measurement periods, we will have mark-to-market losses.

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Interest expense.The following table sets forth interest expense, weighted average interest rates and weighted average debt balances for the years ended December 31, 2015 and 2014:

		Years Ended December 31,
(dollars in thousands)		2015		2014
Interest expense		$	215,384	$	216,661
Capitalized interest			4,913		2,282
	Interest expense, excluding impact of capitalized interest	$	220,297	$	218,943
Weighted average interest rate - credit facility			2.4%		2.4%
Weighted average interest rate - senior notes			5.9%		5.9%
Total weighted average interest rate			5.8%		5.8%
Weighted average credit facility balance		$	195,225	$	144,966
Weighted average senior notes balance			3,350,000		3,350,000
	Total weighted average debt balance	$	3,545,225	$	3,494,966

The increase in the weighted average debt balance during the year ended December 31, 2015 as compared to the corresponding period in 2014 was due to 2015 capital expenditures in excess of our cash flows, primarily related to our drilling program and acquisitions, offset in part by cash received from our March 2015 and October 2015 equity offerings.

Loss on extinguishment of debt.  In May 2014, we amended and restated our credit facility. We recorded a loss on extinguishment of debt of $4.3 million for the year ended December 31, 2014, representing the proportional amount of unamortized deferred loan costs associated with banks with lesser commitments in the amended credit facility syndicate.

Loss on disposition of assets, net.In December 2015, we completed an acreage exchange with Clayton Williams Energy, Inc. that consolidated acres into a concentrated, operated position in the southern Delaware Basin. We recognized a loss on disposition of assets of approximately $50.0 million related to the acreage exchange, which is presented in loss on disposition of assets, net, in the consolidated statement of operations for the year ended December 31, 2015.

Income tax provisions.  We recorded income tax expense of $31.4 million and $317.8 million for the years ended December 31, 2015 and 2014, respectively. The effective income tax rate for the years ended December 31, 2015 and 2014 were 32.3 percent and 37.1 percent, respectively.

We evaluate changes to our industry, production, market conditions and changes in our forecasted drilling plan by tax jurisdiction. As such, we recognized an overall deferred tax benefit of $9.0 million and $7.9 million for 2015 and 2014, respectively. This deferred tax benefit recorded in 2015, was the primary driver for our lower effective tax rate as compared to 2014.

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Year Ended December 31, 2014 Compared to Year Ended December 31, 2013

Oil and natural gas revenues.  Revenue from oil and natural gas operations was $2,660.1 million for the year ended December 31, 2014, an increase of $340.2 million (15 percent) from $2,319.9 million for the year ended December 31, 2013. This increase was primarily due to increased production due to our successful drilling efforts during 2013 and 2014 as well as an increase in the realized natural gas prices, partially offset by the decrease in realized oil prices. Specific factors affecting oil and natural gas revenues include the following:

·total oil production was 26,319 MBbl for the year ended December 31, 2014, an increase of 5,193 MBbl (25 percent) from 21,126 MBbl for the year ended December 31, 2013;

·average realized oil price (excluding the effects of derivative activities) was $83.17 per Bbl during the year ended December 31, 2014, a decrease of 9 percent from $91.76 per Bbl during the year ended December 31, 2013. For the year ended December 31, 2014 and 2013, we realized approximately 89.5 percent and 93.6 percent, respectively, of the average NYMEX oil prices for the respective periods. The basis differential between the location of Midland, Texas and Cushing, Oklahoma (NYMEX pricing location) for our oil has a direct effect on our realized oil price. For the years ended December 31, 2014 and 2013, the market basis differential between WTI-Midland and WTI-Cushing (sweet barrel) was a price reduction of $6.91 per Bbl and $2.63 per Bbl, respectively;

·total natural gas production was 87,336 MMcf for the year ended December 31, 2014, an increase of 12,282 MMcf (16 percent) from 75,054 MMcf for the year ended December 31, 2013; and

·average realized natural gas price (excluding the effects of derivative activities) was $5.39 per Mcf during the year ended December 31, 2014, an increase of 6 percent from $5.08 per Mcf during the year ended December 31, 2013. For the years ended December 31, 2014 and 2013, we realized approximately 126.2 percent and 136.2 percent, respectively, of the average NYMEX natural gas prices for the respective periods. Historically, approximately 55 to 80 percent of our total natural gas revenues were derived from the value of the natural gas liquids, with the remaining portion coming from the value of the dry natural gas residue. Because of our liquids-rich natural gas stream and the related value of the natural gas liquids being included in our natural gas revenues historically, our realized natural gas price (excluding the effects of derivatives) has reflected a price greater than the related NYMEX natural gas price. The deterioration of our realization percentage between comparable periods was primarily related to a combination of (i) a higher average NYMEX natural gas price between comparable periods ($4.27 per MMBtu in 2014 compared to $3.73 per MMBtu in 2013) and (ii) a lower price being received for the value of our natural gas liquids included within our natural gas revenue stream. We estimate that between the comparable periods, the value we received per gallon of natural gas liquids decreased approximately 4 percent, which is primarily the result of an increase in the supply of natural gas liquids from the significant industry drilling in liquid-prone areas.

Heavy rainfall and flooding during the latter part of September 2014 disrupted our operations, primarily in southeast New Mexico, causing shut-in production, road closures and drilling and completion delays. We estimate this weather-related downtime negatively impacted production for the quarter ended December 31, 2014 by approximately 1.6 MBoepd. We estimate that during the quarter ended December 31, 2014 approximately $1.7 million of repairs was due to this event.

During the fourth quarter of 2013, severe winter weather events across the Permian Basin had a significant impact on our production and drilling operations. We experienced widespread power outages, heavy icing, trucking curtailments, and facility freeze-ups across all three of our core areas. We estimate that these weather events reduced our volumes for 2013 by approximately 114 MBoe.

During 2013, the natural gas processing infrastructure in our New Mexico Shelf area struggled to support the rapid growth of natural gas supply due to increased drilling by us and other producers over the recent past. During the second quarter of 2013, we noted that (i) certain additional natural gas processing capacity that was scheduled to be operational had been delayed to later in 2013 and (ii) approximately 20 MMcf per day of natural gas processing capacity, located near our recent drilling activity, had been taken out of service due to mechanical issues. During the second half of 2013, some of the effects of these infrastructure issues were mitigated through (i) temporarily moving additional natural gas volumes to other third-party processors and (ii) an improvement in operating run times and operational efficiencies of certain third-party processors. We estimate these infrastructure constraints, which in part caused us to flare limited natural gas volumes, reduced our volumes for 2013 by approximately 515 MBoe.

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Production expenses.  The following table provides the components of our total oil and natural gas production costs for the years ended December 31, 2014 and 2013:

			Years Ended December 31,
			2014				2013
						Per				Per
(in thousands, except per unit amounts)				Amount		Boe		Amount		Boe
Lease operating expenses			$	310,284	$	7.59	$	248,436	$	7.39
Workover costs				18,967		0.46		15,436		0.46
Taxes:
	Ad valorem			20,775		0.51		22,979		0.68
	Production			188,348		4.61		168,585		5.01
		Total oil and natural gas production expenses	$	538,374	$	13.17	$	455,436	$	13.54

Among the cost components of production expenses, we have some control over lease operating expenses and workover costs on properties we operate, but production and ad valorem taxes are related to commodity prices.

Lease operating expenses were $310.3 million ($7.59 per Boe) for the year ended December 31, 2014, which was an increase of $61.9 million (25 percent) from $248.4 million ($7.39 per Boe) for the year ended December 31, 2013. The increase in lease operating expenses was primarily due to increased production associated with our wells successfully drilled and completed in 2013 and 2014. The increase in lease operating expenses per Boe was primarily due to expansion of our production in areas with underdeveloped infrastructure. We estimate that during the year ended December 31, 2014 approximately $2.5 million ($0.06 per Boe) of repairs was due to weather events.

Workover expenses were approximately $19.0 million and $15.4 million for the years ended December 31, 2014 and 2013, respectively. The 2014 and 2013 expenses related primarily to routine workovers performed to increase or restore production.

Production taxes per unit of production were $4.61 per Boe during the year ended December 31, 2014, a decrease of 8 percent from $5.01 per Boe during the year ended December 31, 2013. The decrease was directly related to the decrease in oil prices. Over the same period, our per Boe prices (excluding the effects of derivatives) decreased 6 percent.

Exploration and abandonments expense. The following table provides a breakdown of our exploration and abandonments expense for the years ended December 31, 2014 and 2013:

		Years Ended December 31,
(in thousands)		2014		2013
Geological and geophysical		$	19,268	$	27,690
Exploratory dry hole costs			44,180		29,514
Leasehold abandonments			217,326		49,758
Other			4,047		2,587
	Total exploration and abandonments	$	284,821	$	109,549

Our geological and geophysical expense primarily consists of the costs of acquiring and processing geophysical data and core analysis, mostly related to our Delaware Basin and Midland Basin areas. During the year ended December 31, 2014, we acquired geological and geophysical data related to our northern Delaware Basin acreage. During the year ended December 31, 2013, we had multiple seismic projects ongoing, which were completed during the second half of 2013. These projects were related to our increase in drilling and exploration activity in the Delaware Basin and Midland Basin core areas.

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During the fourth quarter of 2014, we completed our assessment of our activity in the outer limits of our southern Delaware Basin acreage position. Based on our analysis and marginal results of our exploratory wells on this acreage, we have no further plans to invest in this position. Accordingly, we recognized approximately $32.7 million in exploratory dry hole costs and approximately $96.4 million in leasehold abandonments in 2014. 

During 2014, we recognized exploratory dry hole costs of approximately $44.2 million. In addition to the $32.7 million (discussed above), we recognized $6.3 million of dry hole costs related to two New Mexico Shelf wells that encountered mechanical issues while drilling and one Delaware Basin well targeting the Brushy Canyon horizon that was testing the outer limits of our acreage.

During the year ended December 31, 2014, we recognized leasehold abandonment expense of approximately $217.3 million primarily related to (i) the Delaware Basin abandonment discussed above, as well as (ii) an $86.0 million charge related to properties in our Midland Basin core area that, based on our historical results and our estimate of reduced future commodity price, we have no future intent to drill based on expected low rates of return. The remaining abandonment charges are associated with expiring acreage and acreage determined to be outside of our economically productive reservoirs.

During the fourth quarter of 2013, we completed our assessment of our activity on our northern Midland Basin acreage position. Our initial wells on this acreage were uneconomic. We have no further plans to invest in this position. Accordingly, we recognized $14.8 million in exploratory dry hole costs and $34.9 million in leasehold abandonments in 2013.

Our exploratory dry hole costs during the year ended December 31, 2013 were primarily related to (i) partial expensing of unsuccessful horizontal laterals on two wells in the Delaware Basin, (ii) an unsuccessful vertical well in the New Mexico Shelf area that was testing the eastern boundaries of the area, (iii) partial expensing of unsuccessful horizontal laterals in the New Mexico Shelf area and (iv) the northern Midland Basin wells (noted above).

Depreciation, depletion and amortization expense.  The following table provides components of our depreciation, depletion and amortization expense for the years ended December 31, 2014 and 2013:

		Years Ended December 31,
		2014				2013
					Per				Per
(in thousands, except per unit amounts)			Amount		Boe		Amount		Boe
Depletion of proved oil and natural gas properties		$	960,931	$	23.51	$	755,952	$	22.48
Depreciation of  other property and equipment			17,348		0.42		15,195		0.45
Amortization of intangible asset - operating rights			1,461		0.04		1,461		0.04
	Total depletion, depreciation and amortization	$	979,740	$	23.97	$	772,608	$	22.97
Oil price used to estimate proved oil reserves at period end		$	91.48			$	93.42
Natural gas price used to estimate proved natural gas reserves at period end		$	4.35			$	3.67

Depletion of proved oil and natural gas properties was $960.9 million ($23.51 per Boe) for the year ended December 31, 2014, an increase of $204.9 million (27 percent) from $756.0 million ($22.48 per Boe) for the year ended December 31, 2013. The increase in depletion expense was primarily due to increased production associated with new wells that were successfully drilled and completed in 2013 and 2014 and a higher per unit depletion rate. The increase in depletion expense per Boe was primarily due to (i) drilling deeper, higher cost wells in less proven areas and (ii) increasing production in our newer asset areas, such as the Delaware Basin, where we have a higher depletion rate than our legacy assets, such as the New Mexico Shelf.

The increase in depreciation expense was primarily associated with our increase in depreciation of other property and equipment related to buildings and other items as a result of our increased number of employees.

Impairments of long-lived assets.We periodically review our long-lived assets to be held and used, including proved oil and natural gas properties accounted for under the successful efforts method of accounting. Due primarily to a decrease in our estimated future cash flows related to management’s outlook of future commodity prices and costs, we recognized a non-cash charge against earnings of $447.2 million during the year ended December 31, 2014, which was primarily attributable to

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(i) non-core properties in our Delaware Basin area, (ii) properties producing from the Grayburg San Andres reservoir in our New Mexico Shelf area and (iii) properties producing from the Canyon and Wolfcamp reservoirs primarily in Irion and Glasscock counties in our Midland Basin core area. Due primarily to downward adjustments to the economically recoverable proved reserves associated with declines in well performance and decreases in estimated realized natural gas prices, we recognized a non-cash charge against earnings of $65.4 million during the second quarter of 2013, which was primarily attributable to non-core natural gas related properties in our New Mexico Shelf area.

General and administrative expenses.The following table provides components of our general and administrative expenses for the years ended December 31, 2014 and 2013:

		Years Ended December 31,
		2014				2013
				Per				Per
(in thousands, except per unit amounts)		Amount		Boe		Amount		Boe
General and administrative expenses		$	180,278	$	4.41	$	153,199	$	4.55
Non-cash stock-based compensation			47,130		1.15		35,078		1.04
Less: Third-party operating fee reimbursements			(23,247)		(0.57)		(18,462)		(0.55)
	Total general and administrative expenses	$	204,161	$	4.99	$	169,815	$	5.04

General and administrative expenses were approximately $204.2 million ($4.99 per Boe) for the year ended December 31, 2014, an increase of $34.4 million (20 percent) from $169.8 million ($5.04 per Boe) for the year ended December 31, 2013.

The increase in cash general and administrative expenses of approximately $27.1 million was primarily due to an increase in the number of employees and related personnel expenses. The increase in non-cash stock-based compensation of approximately $12.1 million was primarily due to (i) an increase in the number of employees in order to manage our increased activities directly related to our increased drilling and exploration activities and (ii) a $2.3 million ($0.07 per Boe) net benefit to stock-based compensation related to forfeitures and modifications of stock-based awards associated with two officer resignations included in 2013.

As the operator of certain oil and natural gas properties in which we own an interest, we earn overhead reimbursements during the drilling and production phases of the property. We earned reimbursements of $23.2 million and $18.5 million during the years ended December 31, 2014 and 2013, respectively. This reimbursement is reflected as a reduction of general and administrative expenses in the consolidated statements of operations. The increase in third-party operating fee reimbursements was primarily due to increased reimbursements attributable to more wells operated as a result of continued drilling activity period over period.

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Gain (loss) on derivatives.The following table sets forth the gain (loss) on derivatives for the years ended December 31, 2014 and 2013:

			Years Ended
			December 31,
(in thousands)				2014		2013
Gain (loss) on derivatives:
	Oil derivatives		$	869,421	$	(133,890)
	Natural gas derivatives			21,496		10,238
		Total	$	890,917	$	(123,652)
The following table represents our cash receipts from (payments on) derivatives for the years ended December 31, 2014 and 2013:
			Years Ended
			December 31,
(in thousands)				2014		2013
Cash receipts from (payments on) derivatives:
	Oil derivatives		$	76,335	$	(41,616)
	Natural gas derivatives			(4,352)		9,275
		Total	$	71,983	$	(32,341)

Our earnings are affected by the changes in value of our derivatives portfolio between periods and the related cash settlements of those derivatives, which could be significant. To the extent the future commodity price outlook declines between measurement periods, we will have mark-to-market gains, while to the extent future commodity price outlook increases between measurement periods, we will have mark-to-market losses.

Interest expense.The following table sets forth interest expense, weighted average interest rates and weighted average debt balances for the years ended December 31, 2014 and 2013:

		Years Ended December 31,
(dollars in thousands)		2014		2013
Interest expense		$	216,661	$	218,581
Capitalized interest			2,282		-
	Interest expense, excluding impact of capitalized interest	$	218,943	$	218,581
Weighted average interest rate - credit facility			2.4%		2.3%
Weighted average interest rate - senior notes			5.9%		6.1%
Total weighted average interest rate			5.8%		5.7%
Weighted average credit facility balance		$	144,966	$	327,488
Weighted average senior notes balance			3,350,000		3,117,222
	Total weighted average debt balance	$	3,494,966	$	3,444,710

The increase in weighted average debt balance during the year ended December 31, 2014 as compared to the corresponding period in 2013 was due to capital expenditures primarily related to our drilling program in excess of our cash flows, offset by cash received from our equity offering. The increase in interest expense was due to an overall increase in the weighted average debt balance and interest rate.

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Loss on extinguishment of debt.We recorded a loss on extinguishment of debt of $4.3 million and $28.6 million for the years ended December 31, 2014 and 2013, respectively. The 2014 amount represents the proportional amount of unamortized deferred loan costs associated with banks with lesser commitments in the amended credit facility syndicate. The 2013 amount includes approximately $20.4 million associated with the premium paid for the tender and redemption of the 8.625% Notes, approximately $5.5 million of unamortized deferred loan costs associated with the 8.625% Notes and approximately $2.7 million of unamortized discount on the 8.625% Notes.

Income tax provisions.  We recorded an income tax expense of $317.8 million and $118.2 million for the years ended December 31, 2014 and 2013, respectively. The effective income tax rate for the years ended December 31, 2014 and 2013 was 37.1 percent and 33.1 percent, respectively.

We recorded a $7.9 million and $21.9 million income tax benefit in the fourth quarter of 2014 and 2013, respectively, due to a decrease in our estimated overall state tax rate utilized to record our net deferred tax liability. During 2013, the state of New Mexico passed legislation to phase in a tax rate reduction over the next five years from 7.6 percent in 2013 to 5.9 percent in 2018. Additionally, we continuously evaluate the state apportionment, and based on our current forecast, along with the New Mexico rate declines, we have revised our state rate. During 2014, the change in our blended state rate did not have a material effect on our overall effective tax rate. Excluding the effect of the New Mexico state rate reduction, our effective rate would have been 39.2 percent in 2013, which would approximate a more “normalized” effective income tax rate.

Income from discontinued operations, net of tax. In December 2012, we closed the sale of certain of our non-core assets for cash consideration of approximately $503.1 million. As a result of post-closing adjustments during the year ended December 31, 2013, we made a positive adjustment to gain (loss) on disposition of assets of approximately $19.6 million. We recognized income from discontinued operations, net of tax of $12.1 million for the year ended December 31, 2013. The results of operations of these assets are reported as discontinued operations in the accompanying consolidated statements of operations.

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Capital Commitments, Capital Resources and Liquidity

Capital commitments.  Our primary needs for cash are development, exploration and acquisition of oil and natural gas assets, payment of contractual obligations and working capital obligations. Funding for these cash needs may be provided by any combination of internally-generated cash flow, financing under our credit facility, proceeds from the disposition of assets or alternative financing sources, as discussed in “— Capital resources” below.

Oil and natural gas properties. Our costs incurred on oil and natural gas properties, excluding acquisitions and asset retirement obligations, during the years ended December 31, 2015, 2014 and 2013 totaled $1.8billion, $2.5 billion and $1.8 billion, respectively. The decrease from 2014 to 2015 was primarily due to our reduced drilling and completion activity level during the second half of 2015. The primary reason for the differences in the costs incurred and cash flow expenditures is the timing of payments. The 2015 expenditures were funded in part from borrowings under our credit facility and proceeds from our equity offerings in March 2015 and October 2015.

2016 capital budget. In November 2015, we announced our 2016 base capital budget, excluding acquisitions, of approximately $1.4 billion, with drilling and completion capital accounting for approximately $1.2 billion.

During 2016, our current intent is to adjust our capital spending to be within our cash flows. Based on current commodity prices and costs, our capital plan is in the range of $1.1 billion to $1.3 billion. However, if we were to outspend our cash flows, we expect to be able to use our (i) cash on hand, (ii) credit facility and (iii) other financing sources. The actual amount and timing of our expenditures may differ materially from our estimates as a result of, among other things, actual drilling results, the timing of expenditures by third parties on projects that we do not operate, the costs of drilling rigs and other services and equipment, regulatory, technological and competitive developments and market conditions. In addition, under certain circumstances, we may consider increasing, decreasing or reallocating our capital spending plans. Our 2016 capital program is expected to continue focusing on horizontal drilling in the Delaware Basin and Midland Basin.

Other than the customary purchase of leasehold acreage, our capital budgets are exclusive of acquisitions. We do not have a specific acquisition budget, since the timing and size of acquisitions are difficult to forecast. We evaluate opportunities to purchase or sell oil and natural gas properties in the marketplace and could participate as a buyer or seller of properties at various times. We seek to acquire oil and natural gas properties that provide opportunities for the addition of reserves and production through a combination of development, high-potential exploration and control of operations that will allow us to apply our operating expertise.

Acquisitions. The following table reflects our expenditures for acquisitions of proved and unproved properties for the years ended December 31, 2015, 2014 and 2013:

			Years Ended December 31,
(in thousands)			2015		2014		2013
Property acquisition costs:
	Proved		$	57,190	$	99,362	$	11,499
	Unproved (a)			206,214		292,363		85,538
		Total property acquisition costs	$	263,404	$	391,725	$	97,037
(a)	Included in the unproved property acquisition costs above are budgeted leasehold acreage acquisitions of $69.1 million, $89.1 million and $67.6 million for the years ended December 31, 2015, 2014 and 2013, respectively.

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Contractual obligations. We had the following contractual obligations atDecember 31, 2015:

		Payments Due by Period
				Less than		1 - 3		3 - 5		More than
(in thousands)		Total		1 year		years		years		5 years
Long-term debt (a)		$	3,350,000	$	-	$	-	$	-	$	3,350,000
Cash interest expense on debt (b)			1,357,576		268,175		398,500		398,500		292,401
Asset retirement obligations (c)			119,945		8,626		12,393		4,012		94,914
Employment agreements with officers (d)			8,545		8,545		-		-		-
Purchase obligations (e)			160,096		51,710		42,404		20,531		45,451
Operating lease obligations (f)			38,385		7,941		14,964		10,389		5,091
	Total contractual obligations	$	5,034,547	$	344,997	$	468,261	$	433,432	$	3,787,857

(a)See Note 9 of the Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for information regarding future interest payment obligations on our long-term debt. The amounts included in the table above represent principal maturities only.

(b)Cash interest expense on our senior notes is estimated assuming no principal repayment until their maturity dates. Also included in the “Less than 1 year” column is accrued interest at December 31, 2015 of approximately $68.9 million.

(c)Amounts represent costs related to expected oil and natural gas property abandonments related to proved reserves by period, net of any future accretion.

(d)Represents amounts of cash compensation we are obligated to pay to our officers under employment agreements assuming such employees continue to serve the entire term of their employment agreement and their cash compensation is not adjusted.

(e)Relates to purchase agreements we have entered into including daywork drilling contracts, water commitment agreements, throughput volume delivery commitments, power commitments and maintenance commitments.

(f)We lease vehicles, equipment and office facilities under non-cancellable operating leases.

____________________________________________________________________________________________________

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Off-balance sheet arrangements. Currently, we do not have any material off-balance sheet arrangements.

Capital resources. Our primary sources of liquidity have been cash flows generated from (i) operating activities and cash settlements received from derivatives, (ii) borrowings under our credit facility and (iii) proceeds from bond and equity offerings. In November 2015, we announced our 2016 base capital budget, excluding acquisitions, of approximately $1.4 billion. During 2016, our current intent is to adjust our capital spending to be within our cash flows. Based on current commodity prices and costs, our capital plan is in the range of $1.1 billion to $1.3 billion. However, if we were to outspend our cash flows, we could use our (i) cash on hand, (ii) credit facility and (iii) other financing sources. We believe that we have adequate availability under our credit facility to fund any cash flow deficits.

The following table summarizes our net increase (decrease) in cash and cash equivalents for the years ended December 31, 2015, 2014 and 2013:

	Years Ended December 31,
(in thousands)	2015		2014		2013
Net cash provided by operating activities	$	897,505	$	1,673,787	$	1,362,020
Net cash used in investing activities		(1,969,725)		(2,545,996)		(1,896,794)
Net cash provided by financing activities		1,300,749		872,209		531,915
Net increase (decrease) in cash and cash equivalents	$	228,529	$	-	$	(2,859)

Cash flow from operating activities. The decrease in operating cash flows during the year  ended December 31, 2015 as compared to 2014 was primarily due to (i) a decrease in oil and natural gas revenues of approximately $856.6 million and (ii) a cash increase in general and administrative expense of approximately $10.6 million, offset in part by (i) approximately $78.6 million of positive variances in operating assets and liabilities and (ii) a cash decrease in tax expense of approximately $19.9 million.

The increase in operating cash flows during the year ended December 31, 2014 as compared to 2013 was primarily due to (i) an increase in oil and natural gas revenues of approximately $340.2 million and (ii) approximately $43.5 million of negative variances in operating assets and liabilities compared to $83.6 million of negative variances in operating assets and liabilities in 2013, partially offset by cash increases in oil and natural gas production costs of approximately $82.9 million.

Cash flow used in investing activities. During the years ended December 31, 2015, 2014 and 2013, we invested $2.4 billion, $2.6 billion and $1.9 billion, respectively, for capital expenditures on oil and natural gas properties and acquisitions. The primary reason for the differences in the costs incurred and cash flow expenditures is the timing of payments. The 2015, 2014 and 2013 expenditures were funded in part from borrowings under our credit facility and our equity offerings in 2014 and 2015.

Cash flows used in investing activities decreased during the year ended December 31, 2015 as compared to 2014, primarily due to (i) the decrease in amounts invested in oil and natural gas properties during 2015 and 2014 discussed above and (ii) $632.9 million of receipts from derivatives during 2015 compared to receipts of $72.0 million during 2014, partially offset by (i) contributions to our equity method investments of $91.3 million during 2015 compared to contributions of $30.1 million during 2014 and (ii) $67.7 million invested in other property and equipment during 2015 compared to $34.3 million in 2014.

Cash flows used in investing activities were increased during the year ended December 31, 2014 as compared to 2013, primarily due to (i) the increase in amounts invested in oil and natural gas properties during 2014 and 2013 discussed above, (ii) contributions to our equity method investment of $30.1 million during 2014 and (iii) $15.2 million of proceeds from the dispositions of assets during 2013 compared to $1.3 million of proceeds from the dispositions of assets during 2014, partially offset by $72.0 million of receipts from derivatives during 2014 compared to payments of $32.3 million during 2013.  

Cash flow from financing activities.Below is a description of our financing activities. During 2015, 2014 and 2013 we completed the following significant capital markets activities:

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·In October 2015, we issued shares of our common stock in a public offering and received net proceeds of approximately $794.2 million. We used a portion of the net proceeds from this offering to repay all outstanding borrowings under our credit facility, which were used in part to finance acquisitions at the time. The remaining net proceeds have been used for general corporate purpose while maintaining a cash balance of $228.6 million at December 31, 2015. This balance could be used in the future for items such as potential future acquisitions as well as general corporate purposes.

·In March 2015, we issued shares of our common stock in a public offering and received net proceeds of approximately $741.5 million. We used a portion of the net proceeds from this offering to repay all outstanding borrowings under our credit facility and the remainder for general corporate purposes.

·In May 2014, we issued in a public offering 7.5 million shares of our common stock, and we received net proceeds of approximately $932.0 million. We used a portion of the net proceeds from this offering to repay all outstanding borrowings under our credit facility and used the remainder for general corporate purposes, including funding our drilling program and capital commitments associated with the midstream joint venture.

·In June 2013, we issued $850 million in aggregate principal amount of 5.5% senior notes due 2023 at 103.75 percent of par, for which we received net proceeds of approximately $867.8 million. We used a portion of the net proceeds from the offering to fund the tender offer and redemption of the 8.625% Notes at a price of 106.922 percent of the unpaid principal amount. The remaining proceeds were used to pay down amounts outstanding on the credit facility.

Our credit facility has a maturity date of May 9, 2019. Our borrowing base is $3.25 billion until the next scheduled borrowing base redetermination in May 2016, and commitments from our bank group total $2.5 billion. Between scheduled borrowing base redeterminations, the Company and the lenders (requiring a 66 2/3 percent vote), may each request one special redetermination. At December 31, 2015 we had unused commitments of approximately $2.5 billion based on bank commitments of $2.5 billion. 

Advances on our credit facility bear interest, at our option, based on (i) the prime rate of JPMorgan Chase Bank (“JPM Prime Rate”) (3.50 percent at December 31, 2015) or (ii) a Eurodollar rate (substantially equal to the LIBOR). The credit facility’s interest rates of Eurodollar rate advances and JPM Prime Rate advances varied, with interest margins ranging from 125 to 225 basis points and 25 to 125 basis points, respectively, per annum depending on the debt balance outstanding on our credit facility. Under our current credit facility, we pay commitment fees on the unused portion of the available commitment ranging from 30 to 37.5 basis points per annum, depending on utilization of the borrowing base.

In conducting our business, we may utilize various financing sources, including the issuance of (i) fixed and floating rate debt, (ii) convertible securities, (iii) preferred stock, (iv) common stock and (v) other securities. Over the last three years, we have demonstrated our use of capital markets by issuing senior unsecured debt and common stock. There are no assurances that we can access capital markets to obtain additional funding, if needed, and at what cost and terms. We may also sell assets and issue securities in exchange for oil and natural gas assets or interests in oil and natural gas companies. Additional securities may be of a class senior to common stock with respect to such matters as dividends and liquidation rights and may also have other rights and preferences as determined from time-to-time by our board of directors. Utilization of some of these financing sources may require approval from the lenders under our credit facility.

Liquidity. Our principal sources of liquidity are cash on hand and available borrowing capacity under our credit facility. At December 31, 2015, we had approximately $228.6 million of cash on hand. Assuming closing of our recently announced acquisition and disposition in the first quarter of 2016, we expect to increase our cash position by approximately $140.0 million.

At December 31, 2015, commitments from our bank group totaled $2.5 billion. In April 2015, we amended our credit agreement to remove the current ratio financial covenant. Our borrowing base is $3.25 billion until our next scheduled borrowing base redetermination in May 2016. There is no assurance that our borrowing base will not be reduced, which could affect our liquidity. Upon a redetermination, our borrowing base could be substantially reduced.

We may from time to time seek to retire or purchase our outstanding debt through cash purchases and/or exchanges for other debt or equity securities, in open market purchases, privately negotiated transactions or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.

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Debt ratings. We receive debt credit ratings from Standard & Poor’s Ratings Group, Inc. (“S&P”) and Moody’s Investors Service, Inc. (“Moody’s”), which are subject to regular reviews. S&P and Moody’s consider many factors in determining our ratings including: production growth opportunities, liquidity, debt levels and asset and reserve mix.

On December 16, 2015, Moody’s announced that it placed the ratings of 29 U.S. exploration and production companies, including us, on review for downgrade. At December 31, 2015, our long-term debt was rated “Ba1” with an outlook under review. Since that action, Moody’s lowered its oil price estimates and placed additional exploration and production companies on review for downgrade. With Moody’s reduced expectations for the likely range of prices and deteriorating industry conditions, there is an increased possibility for multi-notch downgrades as an outcome of the review process. The ultimate outcome of the ratings review for any particular exploration and production company will depend on such company’s particular credit attributes. On February 11, 2016, Moody’s affirmed our rating as “Ba1” and assigned a stable outlook.

At December 31, 2015, our long-term debt was rated BB+ with a stable outlook by S&P. On February 9, 2016, S&P affirmed our rating as part of a broader review of 45 exploration and production companies. Of the 45 companies under review by S&P, 20 companies’ ratings were affirmed while 25 companies’ ratings were downgraded.

A downgrade in our credit ratings could negatively impact our costs of capital and our ability to effectively execute aspects of our strategy. Further, a downgrade in our credit ratings could affect our ability to raise debt in the public debt markets, and the cost of any new debt could be much higher than our outstanding debt. These and other impacts of a downgrade in our credit ratings could have a material adverse effect on our business, financial conditions and results of operations.

As of the filing of this report, no additional changes in our credit ratings have occurred; however, we cannot be assured that our credit ratings will not be downgraded in the future.

Book capitalization and current ratio.  Our book capitalization at December 31, 2015 was $10.2billion, consisting of debt of $3.3 billion and stockholders’ equity of $6.9 billion. Our debt to book capitalization was 32percent and 40 percent at December 31, 2015 and 2014, respectively. Our ratio of current assets to current liabilities was 2.20to 1.0 at December 31, 2015 as compared to 0.94 to 1.0 at December 31, 2014. The debt to book capitalization and ratio of current assets to current liabilities at December 31, 2014 reflect the retrospective adoption of ASU No. 2015-03 and 2015-17. See Note 2 of the Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional information.

Inflation and changes in prices.  Our revenues, the value of our assets, and our ability to obtain bank financing or additional capital on attractive terms have been and will continue to be affected by changes in commodity prices and the costs to produce our reserves. Commodity prices are subject to significant fluctuations that we are unable to control or predict. During the year ended December 31, 2015, we received an average of $44.69per barrel of oil and $2.46per Mcf of natural gas before consideration of commodity derivative contracts compared to $83.17 and $91.76per barrel of oil and $5.39 and $5.08per Mcf of natural gas in the years ended December 31, 2014 and 2013, respectively. Although certain of our costs are affected by general inflation, inflation does not normally have a significant effect on our business.

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Critical Accounting Policies and Practices

Our historical consolidated financial statements and related notes to consolidated financial statements contain information that is pertinent to our management’s discussion and analysis of financial condition and results of operations. Preparation of financial statements in conformity with accounting principles generally accepted in the United States requires that our management make estimates, judgments and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and the disclosure of contingent assets and liabilities. However, the accounting principles used by us generally do not change our reported cash flows or liquidity. Interpretation of the existing rules must be done and judgments made on how the specifics of a given rule apply to us. 

In management’s opinion, the more significant reporting areas impacted by management’s judgments and estimates are the choice of accounting method for oil and natural gas activities, oil and natural gas reserve estimation, asset retirement obligations, impairment of long-lived assets, valuation of stock-based compensation, valuation of business combinations, valuation of financial derivative instruments and income taxes. Management’s judgments and estimates in these areas are based on information available from both internal and external sources, including engineers, geologists and historical experience in similar matters. Actual results could differ from the estimates as additional information becomes known.

Successful Efforts Method of Accounting

We utilize the successful efforts method of accounting for our oil and natural gas exploration and development activities. Under this method, exploration expenses, including geological and geophysical costs, lease rentals and exploratory dry holes, are charged against income as incurred. Costs of successful wells and related production equipment, undeveloped leases and developmental dry holes are capitalized. Exploratory drilling costs are initially capitalized, but are charged to expense if and when the well is determined not to have found proved reserves. Generally, a gain or loss is recognized when producing fields are sold. This accounting method may yield significantly different results than the full cost method of accounting.

The application of the successful efforts method of accounting requires management’s judgment to determine the proper designation of wells as either developmental or exploratory, which will ultimately determine the proper accounting treatment of costs of dry holes. Once a well is drilled, the determination that proved reserves have been discovered may take considerable time, and requires both judgment and application of industry experience. The evaluation of oil and natural gas leasehold acquisition costs included in unproved properties requires management’s judgment to estimate the fair value of such properties. Drilling activities in an area by other companies may also effectively condemn our leasehold positions.

Non-producing properties consist of undeveloped leasehold costs and costs associated with the purchase of certain proved undeveloped reserves. Individually significant non-producing properties or projects are periodically assessed for impairment of value by considering future drilling plans, the results of exploration activities, commodity price outlooks, planned future sales or expiration of all or a portion of such projects.

Depletion of capitalized drilling and development costs of oil and natural gas properties is computed using the unit-of-production method on total estimated proved developed oil and natural gas reserves. Depletion of producing leaseholds is based on the unit-of-production method using our total estimated proved reserves. In arriving at rates under the unit-of-production method, the quantities of recoverable oil and natural gas are established based on estimates made by our geologists and engineers and independent engineers. Service properties, equipment and other assets are depreciated using the straight-line method over estimated useful lives of two to 31 years. Upon sale or retirement of depreciable or depletable property, the cost and related accumulated depreciation and depletion are eliminated from the accounts and the resulting gain or loss is recognized.

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Oil and Natural Gas Reserves and Standardized Measure of Discounted Net Future Cash Flows

This report presents estimates of our proved reserves as of December 31, 2015, which have been prepared and presented in accordance with SEC guidelines. The pricing that was used for estimates of our reserves as of December 31, 2015 was based on an unweighted average twelve month WTI posted price of $46.79per Bbl for oil and a Henry Hub spot natural gas price of $2.59per MMBtu for natural gas.

Our independent engineers and technical staff prepare the estimates of our oil and natural gas reserves and associated future net cash flows. Even though our independent engineers and technical staff are knowledgeable and follow authoritative guidelines for estimating reserves, they must make a number of subjective assumptions based on professional judgments in developing the reserve estimates. Reserve estimates are updated at least annually and consider recent production levels and other technical information about each field. Periodic revisions to the estimated reserves and future net cash flows may be necessary as a result of a number of factors, including reservoir performance, new drilling, oil and natural gas prices, cost changes, technological advances, new geological or geophysical data, or other economic factors. We cannot predict the amounts or timing of future reserve revisions. If such revisions are significant, they could significantly alter future depletion and result in impairment of long-lived assets that may be material.

It should not be assumed that the Standardized Measure included in this report as of December 31, 2015 is the current market value of our estimated proved reserves. In accordance with SEC requirements, we based the 2015 Standardized Measure on a 12-month average of commodity prices on the first day of the month and prevailing costs on the date of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs utilized in the estimate. See “Item 1A. Risk Factors” and “Item 2. Properties” for additional information regarding estimates of proved reserves.

Our estimates of proved reserves materially impact depletion expense. If the estimates of proved reserves decline, the rate at which we record depletion expense will increase, reducing future earnings. Such a decline may result from lower commodity prices, which may make it uneconomical to drill for and produce higher cost fields. In addition, a decline in proved reserve estimates may impact the outcome of our assessment of our proved properties for impairment.

Asset Retirement Obligations

There are legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and the normal operation of a long-lived asset. The primary impact of this relates to oil and natural gas wells on which we have a legal obligation to plug and abandon. We record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and, generally, a corresponding increase in the carrying amount of the related long-lived asset. The determination of the fair value of the liability requires us to make numerous judgments and estimates, including judgments and estimates related to future costs to plug and abandon wells, future inflation rates and estimated lives of the related assets.  When the judgments used to estimate the initial fair value of the asset retirement obligation change, an adjustment is recorded to both the obligation and the carrying amount of the related long-lived asset.

Impairment of Long-Lived Assets

All of our long-lived assets are monitored for potential impairment when circumstances indicate that the carrying value of an asset may be greater than management’s estimates of its future net cash flows, including cash flows from proved reserves, risk-adjusted probable and possible reserves, and integrated assets. If the carrying value of the long-lived assets exceeds the sum of estimated undiscounted future net cash flows, an impairment loss is recognized for the difference between the estimated fair value and the carrying value of the assets. The evaluations involve a significant amount of judgment since the results are based on estimated future events, such as future sales prices for oil and natural gas, future costs to produce these products, estimates of future oil and natural gas reserves to be recovered and the timing thereof, the economic and regulatory climates, cash flows from integrated assets and other factors. The need to test an asset for impairment may result from significant declines in sales prices or downward revisions in estimated quantities of oil and natural gas reserves. Any assets held for sale are reviewed for impairment when we approve the plan to sell. Estimates of anticipated sales prices are highly judgmental and subject to material revision in future periods. Because of the uncertainty inherent in these factors, we cannot predict when or if future impairment charges will be recorded.

Valuation of Stock-Based Compensation

In accordance with GAAP, we calculate the fair value of stock-based compensation using various valuation methods. The valuation methods require the use of estimates to derive the inputs necessary to determine fair value. We utilize (a) the Black-Scholes option pricing model to measure the fair value of stock options, (b) the average of the high and low stock price

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on the date of grant for the fair value of restricted stock awards and (c) the Monte Carlo simulation method for the fair value of performance unit awards. The significant assumptions used in these models include expected volatility, expected term, risk-free interest rate, forfeiture rate, and the probability of meeting performance targets. Each of these valuation methods were chosen as management believes they give the best estimate of fair value for the respective stock-based awards. See Note 6 of the Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for information regarding our stock-based compensation.

Valuation of Business Combinations

In connection with a purchase business combination, the acquiring company must record assets acquired and liabilities assumed based on fair values as of the acquisition date. Deferred taxes must be recorded for any differences between the assigned values and tax bases of assets and liabilities. Any excess of purchase price over amounts assigned to assets and liabilities is recorded as goodwill. The amount of goodwill recorded in any particular business combination can vary significantly depending upon the value attributed to assets acquired and liabilities assumed.

In estimating the fair values of assets acquired and liabilities assumed, we make various assumptions. The most significant assumptions related to the estimated fair values assigned to proved and unproved oil and natural gas properties and integrated assets. To estimate the fair values of these properties, we utilize estimates of oil and natural gas reserves. We make future price assumptions to apply to the estimated reserves quantities acquired and estimate future operating and development costs to arrive at estimates of future net cash flows. For estimated proved reserves, the future net cash flows were discounted using a market-based weighted average cost of capital rates determined appropriate at the time of the acquisition. The market-based weighted average cost of capital rates are subject to additional project-specific risking factors. To estimate the fair value of unproved, we apply risk-weighting factors of the future net cash flows of unproved reserves, or we may evaluate acreage values through recent market transactions in the area.

Estimated fair values assigned to assets acquired can have a significant effect on results of operations in the future. A higher fair value assigned to a property results in a higher depletion expense, which results in lower net earnings. Fair values are based on estimates of future commodity prices, reserves quantities, operating expenses and development costs. This increases the likelihood of impairment if future commodity prices or reserves quantities are lower than those originally used to determine fair value or if future operating expenses or development costs are higher than those originally used to determine fair value. Impairment would have no effect on cash flows but would result in a decrease in net income for the period in which the impairment is recorded.

Valuation of Nonmonetary Exchanges

In connection with a nonmonetary exchange, we must record assets received based on the fair value of assets surrendered. Any resulting difference between the fair value of the assets surrendered and their carrying value is recorded as a gain or loss in the consolidated statement of operations.

In estimating the fair values of assets surrendered, we make various assumptions. The most significant assumptions are related to the estimated fair values assigned to proved and unproved oil and natural gas properties, similar to our valuation of the fair value of oil and natural gas assets acquired a business combination.

Estimated fair values assigned to assets exchanged can have a significant effect on results of operations. A lower fair value assigned to a property disposed may result in a higher loss, which affects net earnings. Fair values are based on estimates of future commodity prices, reserves quantities, operating expenses and development costs. This increases the likelihood of impairment if future commodity prices or reserves quantities are lower than those originally used to determine fair value or if future operating expenses or development costs are higher than those originally used to determine fair value. Impairment would have no effect on cash flows but would result in a decrease in net income for the period in which the impairment is recorded.

Valuation of Financial Derivative Instruments

In order to reduce commodity price uncertainty and increase cash flow predictability relating to the marketing of our oil and natural gas, we enter into commodity price hedging arrangements with respect to a portion of our expected production. In addition, we have used derivative instruments in connection with acquisitions and certain price-sensitive projects. Management exercises significant judgment in determining the types of instruments to be used, production volumes to be hedged, prices at which to hedge and the counterparties’ creditworthiness. All derivative instruments are reflected at fair value in our consolidated balance sheets.

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Our open commodity derivative instruments were in a net asset position with a fair value of $819.5 million at December 31, 2015. In order to determine the fair value at the end of each reporting period, we compute discounted cash flows for the duration of each commodity derivative instrument using the terms of the related contract. Inputs consist of published forward commodity price curves as of the date of the estimate. We compare these prices to the price parameters contained in our hedge contracts to determine estimated future cash inflows or outflows. We then discount the cash inflows or outflows using a combination of published LIBOR rates and Eurodollar futures rates. The fair values of our commodity derivative assets and liabilities include a measure of credit risk based on average published yields by credit rating. In addition, for collars, we estimate the option value of the contract floors and ceilings using an option pricing model which takes into account market volatility, market prices and contract parameters.

Changes in the fair values of our commodity derivative instruments have a significant impact on our net income because we follow mark-to-market accounting and recognize all gains and losses on such instruments in earnings in the period in which they occur. For the year ended December 31, 2015, we reported a $699.8 million gain on commodity derivative instruments.

We compare our estimates of the fair values of our commodity derivative instruments with those provided by our counterparties. There have been no significant differences.

Income Taxes

Our provision for income taxes includes both federal and state taxes in jurisdictions in which we operate. We estimate our overall tax rate using a combination of the federal tax rate and a blend of enacted state tax rates. Acquisitions or dispositions of assets and changes in drilling plan by tax jurisdiction could change the apportionment of our state taxes, which would impact our overall tax rate.

Our federal and state income tax returns are generally not prepared or filed before the consolidated financial statements are prepared; therefore, we estimate the tax basis of our assets and liabilities, which are based on numerous judgments and assumptions inherent in the determination of future taxable income, at the end of each period as well as the effects of tax rate changes and tax credits. Adjustments related to these estimates are recorded in our tax provision in the period in which we finalize our income tax returns. Material changes to our tax accruals may occur in the future based on audits, changes in legislation or resolution of pending matters.

Recent Accounting Pronouncements

In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606),” which outlines a new, single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. This new revenue recognition model provides a five-step analysis in determining when and how revenue is recognized. The new model will require revenue recognition to depict the transfer of promised goods or services to customers in an amount that reflects the consideration a company expects to receive in exchange for those goods or services.

In August 2015, the FASB issued ASU No. 2015-14, “Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date,” which deferred the effective date of ASU 2014-09 by one year. That new standard is now effective for annual reporting periods beginning after December 15, 2017. An entity can apply ASU 2014-09 using either a full retrospective method, meaning the standard is applied to all of the periods presented, or a modified retrospective method, meaning the cumulative effect of initially applying the standard is recognized in the most current period presented in the financial statements. We are evaluating the impact that this new guidance will have on our consolidated financial statements.

In April 2015, the FASB issued ASU No. 2015-03, “Interest-Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs,” which requires net deferred loan costs directly related to our senior notes to be classified as a direct deduction from the carrying amount of the related senior notes. We early adopted the ASU for the interim period ended December 31, 2015 and reclassified $48.2 million at December 31, 2014 from a noncurrent asset to a deduction from long-term debt. The deferred loan costs related to our credit facility remain classified as a noncurrent asset due to the revolving nature of that facility. The provisions of the ASU were adopted primarily to simplify the required reporting for subsequent registration filings and were done so retrospectively.

In November 2015, the FASB issued ASU No. 2015-17, “Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes,” which requires that all deferred tax assets and liabilities, along with any related valuation allowance, be

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classified as noncurrent on the balance sheet. We early adopted the ASU for the interim period ended December 31, 2015, which resulted in our current deferred income tax liability of $162.6 million at December 31, 2014 to be reclassified as a noncurrent deferred income tax liability in our consolidated balance sheet. The provisions of the ASU were adopted primarily to simplify the required reporting for subsequent registration filings and were done so retrospectively. We previously classified deferred income tax liabilities and assets separately to current and noncurrent.

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Item 7A.  Quantitative and Qualitative Disclosures About Market Risk

We are exposed to a variety of market risks including credit risk, commodity price risk and interest rate risk. We address these risks through a program of risk management which includes the use of derivative instruments. The following quantitative and qualitative information is provided about financial instruments to which we are a party at December 31, 2015, and from which we may incur future gains or losses from changes in market interest rates or commodity prices and losses from extension of credit. We do not enter into derivative or other financial instruments for speculative or trading purposes.

Hypothetical changes in interest rates and commodity prices chosen for the following estimated sensitivity analysis are considered to be reasonably possible near-term changes generally based on consideration of past fluctuations for each risk category. However, since it is not possible to accurately predict future changes in interest rates and commodity prices, these hypothetical changes may not necessarily be an indicator of probable future fluctuations.

Credit risk. We monitor our risk of loss due to non-performance by counterparties of their contractual obligations. Our principal exposure to credit risk is through the sale of our oil and natural gas production, which we market to energy marketing companies and refineries and to a lesser extent our derivative counterparties. We monitor our exposure to these counterparties primarily by reviewing credit ratings, financial statements and payment history. We extend credit terms based on our evaluation of each counterparty’s creditworthiness. Although we have not generally required our counterparties to provide collateral to support their obligation to us, we may, if circumstances dictate, require collateral in the future. In this manner, we reduce credit risk.

We have entered into International Swap Dealers Association Master Agreements (“ISDA Agreements”) with each of our derivative counterparties. The terms of the ISDA Agreements provide us and the counterparties with rights of set off upon the occurrence of defined acts of default by either us or a counterparty to a derivative, whereby the party not in default may set off all derivative liabilities owed to the defaulting party against all derivative asset receivables from the defaulting party. See Note 8 of the Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional information regarding our derivative activities.

Commodity price risk.  We are exposed to market risk as the prices of our commodities are subject to fluctuations resulting from changes in supply and demand. To reduce our exposure to changes in the prices of our commodities, we have entered into, and may in the future enter into, commodity price risk management arrangements for a portion of our oil and natural gas production. The agreements that we have entered into generally have the effect of providing us with a fixed price for a portion of our expected future oil and natural gas production over a fixed period of time. Our commodity price risk management arrangements are recorded at fair value and thus changes to the future commodity prices will have an impact on net income. The following table sets forth the hypothetical impact on the fair value of the commodity price risk management arrangements from an average increase and decrease in the commodity price of $5.00 per Bbl of oil and $0.50 per MMBtu of natural gas from the commodity prices at December 31, 2015:

				Increase of		Decrease of
				$5 per Bbl and		$5 per Bbl and
(in thousands)				$0.50 per MMBtu		$0.50 per MMBtu
Gain (loss):
	Oil derivatives		$	(183,536)	$	183,536
	Natural gas derivatives			(13,353)		13,353
		Total	$	(196,889)	$	196,889

Our commodity price risk management arrangements expose us to risk of non-performance by the counterparty to the agreements. Our exposure to the risk of non-performance is diversified over large, investment grade financial institutions. In addition, we have master netting agreements with the counterparties that allow for offsetting payables against receivables from separate contracts with the same counterparty. At December 31, 2015, the counterparties to our commodity price risk management arrangements include fourteen financial institutions, all of which are secured lenders to our credit facility. Counterparty risk of non-performance is considered when determining the fair value of our commodity price risk management arrangements. The fair value adjustment for non-performance risk was immaterial at both December 31, 2015 and 2014. If at any point a counterparty’s financial position deteriorates, such deterioration could have a significant impact on

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the collectability of that counterparty’s related commodity price risk management arrangement asset. See Note 12 of the Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for a list of our significant counterparties.

At December 31, 2015, we had (i) oil price swaps that settle on a monthly basis covering future oil production from January 1, 2016 through December 31, 2017 and (ii) oil basis swaps covering our Midland to Cushing basis differential from January 1, 2016 to December 31, 2017. See Note 8 of the Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional information on the commodity derivative instruments. The average NYMEX oil price for the year ended December 31, 2015, was $48.84 per Bbl. At February 22, 2016, the NYMEX oil price was $31.48 per Bbl.

At December 31, 2015, we had natural gas price swaps that settle on a monthly basis covering future natural gas production from January 1, 2016 to December 31, 2016. See Note 8 of the Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional information on our commodity derivative instruments. The average NYMEX natural gas price for the year ended December 31, 2015, was $2.63 per MMBtu. At February 22, 2016, the NYMEX natural gas price was $1.82 per MMBtu.

A decrease in the average NYMEX oil and natural gas prices below those at December 31, 2015 would increase the fair value asset of our commodity derivative contracts from their recorded balance at December 31, 2015. Changes in the recorded fair value of the undesignated commodity derivative contracts are marked to market through earnings as gains or losses. The potential increase in our fair value asset would be recorded in earnings as a gain. However, an increase in the average NYMEX oil and natural gas prices above those at December 31, 2015 would decrease the fair value asset of our commodity derivative contracts from their recorded balance at December 31, 2015. The potential decrease in our fair value asset would be recorded in earnings as a loss. We are currently unable to estimate the effects on the earnings of future periods resulting from changes in the market value of our commodity derivative contracts.

We recorded a gain on derivatives of $699.8 million for the year ended December 31, 2015, compared to a gain of $890.9 million for the year ended December 31, 2014. The largest factor in the change from 2014 to 2015 primarily related to the decline in commodity future price curves at the respective measurement periods.

The fair value of our derivative instruments is determined based on our valuation models. We did not change our valuation method during the year ended December 31, 2015. During the year ended December 31, 2015, we were party to commodity derivative instruments. See Note 8 of the Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional information regarding our derivative instruments. The following table reconciles the changes that occurred in the fair values of our derivative instruments during the year ended December 31, 2015:

		Commodity Derivative
		Instruments
(in thousands)		Net Assets (Liabilities) (a)
Fair value of contracts outstanding at December 31, 2014			$	752,700
	Changes in fair values (b)			699,752
	Contract maturities			(632,916)
Fair value of contracts outstanding at December 31, 2015			$	819,536
(a)	Represents the fair values of open derivative contracts subject to market risk.
(b)	At inception, new derivative contracts entered into by us have no intrinsic value.

Interest rate risk.  Our exposure to changes in interest rates relates primarily to debt obligations. We manage our interest rate exposure by limiting our variable-rate debt to a certain percentage of total capitalization and by monitoring the effects of market changes in interest rates. To reduce our exposure to changes in interest rates we have entered into, and may in the future enter into additional interest rate risk management arrangements for a portion of our outstanding debt. The agreements that we have entered into generally have the effect of providing us with a fixed interest rate for a portion of our variable rate debt. We may utilize interest rate derivatives to alter interest rate exposure in an attempt to reduce interest rate expense related to existing debt issues. Interest rate derivatives are used solely to modify interest rate exposure and not to modify the

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overall leverage of the debt portfolio. We are exposed to changes in interest rates as a result of our credit facility, and the terms of our credit facility require us to pay higher interest rate margins as we utilize a larger percentage of our available commitments.

We had no indebtedness outstanding under our credit facility at December 31, 2015.

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Item 8.  Financial Statements and Supplementary Data

Our consolidated financial statements and supplementary data are included in this report beginning on page F-1.

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

We had no changes in, and no disagreements with, our accountants on accounting and financial disclosure.

Item 9A. Controls and Procedures

Evaluation of Disclosure Controls and Procedures. As required by Rule 13a-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon the evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective at December 31, 2015 at the reasonable assurance level.

Changes in Internal Control over Financial Reporting. There have been no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that occurred during our last fiscal quarter that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.

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MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting. The Company’s internal control over financial reporting is a process designed under the supervision of the Company’s Chief Executive Officer and Chief Financial Officer to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the Company’s financial statements for external purposes in accordance with generally accepted accounting principles.

As of December 31, 2015, management assessed the effectiveness of the Company’s internal control over financial reporting based on the criteria for effective internal control over financial reporting established in the 2013 “Internal Control - Integrated Framework,” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our assessment and those criteria, management determined that the Company maintained effective internal control over financial reporting at December 31, 2015.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Grant Thornton LLP, the independent registered public accounting firm that audited the consolidated financial statements of the Company included in this annual report on Form 10-K, has issued their report on the effectiveness of the Company’s internal control over financial reporting at December 31, 2015. The report, which expresses an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting at December 31, 2015, is included in this Item under the heading “Report of Independent Registered Public Accounting Firm.”

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REPORT OF INDEPENDENT REGISTERED PUBLICACCOUNTING FIRM

Board of Directors and Stockholders

Concho Resources Inc.

We have audited the internal control over financial reporting of Concho Resources Inc. (a Delaware corporation) and subsidiaries (the “Company”) as of December 31, 2015, based on criteria established in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2015, based on criteria established in the 2013 Internal Control—Integrated Framework issued by COSO.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidatedfinancial statements of the Company as of and for the year ended December 31, 2015, and our report dated February 25, 2016 expressed an unqualified opinionon those financial statements.

/s/ GRANT THORNTON LLP

Tulsa, Oklahoma

February 25, 2016

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Item 9B. Other Information

None.

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PART III

Item 10.Directors, Executive Officers and Corporate Governance

Item 10 will be incorporated by reference pursuant to Regulation 14A under the Exchange Act. We expect to file a definitive proxy statement with the SEC within 120 days after the close of the year ended December 31, 2015.

Item 11.Executive Compensation

Item 11 will be incorporated by reference pursuant to Regulation 14A under the Exchange Act. We expect to file a definitive proxy statement with the SEC within 120 days after the close of the year ended December 31, 2015.

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

Equity compensation plans. At December 31, 2015, a total of 10,500,000 shares of common stock were authorized for issuance under our equity compensation plan. In the table below, we describe certain information about these shares and the equity compensation plan which provides for their authorization and issuance. Performance units are included at the maximum potential payout percentage, except for the performance units in column (1) relating to the performance period that ended on December 31, 2015, which are included at the actual payout percentage of 162.5 percent. You can find descriptions of our stock incentive plan under Note 6 of the Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data.”

		(1)		(2)		(3)
		Number of				Number of securities
		securities to be				remaining available for
		issued upon	Weighted average			future issuance under
		exercise of	exercise			equity compensation
		outstanding	price of			plans (excluding
		options, warrants	outstanding			securities reflected in
Plan category		and rights	options			column (1))
Equity compensation plan approved by the security holders (a)		1,170,365	$	18.10	(c)	2,921,610
Equity compensation plan not approved by the security holders (b)		-	$	-		-
	Total	1,170,365				2,921,610
(a)	2015 Stock Incentive Plan. See Note 6 of the Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data.”
(b)	None.
(c)	Performance unit awards do not have an exercise price and, therefore, have been excluded from the weighted average exercise price calculation in column (2).

The remaining information required by Item 12 will be incorporated by reference pursuant to Regulation 14A under the Exchange Act. We expect to file a definitive proxy statement with the SEC within 120 days after the close of the year ended December 31, 2015.

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Item 13.Certain Relationships and Related Transactions, and Director Independence

Item 13 will be incorporated by reference pursuant to Regulation 14A under the Exchange Act. We expect to file a definitive proxy statement with the SEC within 120 days after the close of the year ended December 31, 2015.

Item 14.Principal Accounting Fees and Services

Item 14 will be incorporated by reference pursuant to Regulation 14A under the Exchange Act. We expect to file a definitive proxy statement with the SEC within 120 days after the close of the year ended December 31, 2015.

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PART IV

Item 15.Exhibits, Financial Statement Schedules

(a)Listing of Financial Statements

Financial Statements

The following consolidated financial statements are included in “Item 8. Financial Statements and Supplementary Data”:

Report of Independent Registered Public Accounting Firm

Consolidated Balance Sheets at December 31, 2015 and 2014

Consolidated Statements of Operations for the Years Ended December 31, 2015, 2014 and 2013

Consolidated Statements of Stockholders’ Equity for the Years Ended December 31, 2015, 2014 and 2013

Consolidated Statements of Cash Flows for the Years Ended December 31, 2015, 2014 and 2013

Notes to Consolidated Financial Statements

Unaudited Supplementary Data

(b)Exhibits 

The exhibits to this report required to be filed pursuant to Item 15(b) are listed below and in the “Index to Exhibits” attached hereto.

(c)Financial Statement Schedules

No financial statement schedules are required to be filed as part of this report or they are inapplicable.

Exhibits

Exhibit

Number                                                                              Description                                                                                           

3.1                            Restated Certificate of Incorporation (filed as Exhibit 3.1 to the Company’s Current Report on Form 8-K on August 8, 2007, and incorporated herein by reference).

3.2                            Second Amended and Restated Bylaws of Concho Resources Inc., as amended November 7, 2012 (filed as Exhibit 3.1 to the Company’s Current Report on Form 8-K on November 8, 2012, and incorporated herein by reference).

4.1                            Specimen Common Stock Certificate (filed as Exhibit 4.1 to the Company’s Annual Report on Form 10-K on February 22, 2013, and incorporated herein by reference).

4.2                            Indenture, dated September 18, 2009, between Concho Resources Inc., the subsidiary guarantors named therein, and Wells Fargo Bank, National Association, as trustee (filed as Exhibit 4.1 to the Company’s Current Report on Form 8-K on September 22, 2009, and incorporated herein by reference).

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Exhibit

NumberDescription

4.3                            First Supplemental Indenture, dated September 18, 2009, between Concho Resources Inc., the subsidiary guarantors named therein, and Wells Fargo Bank, National Association, as trustee (filed as Exhibit 4.2 to the Company’s Current Report on Form 8-K on September 22, 2009, and incorporated herein by reference).

4.4                            Second Supplemental Indenture, dated November 3, 2010, between Concho Resources Inc., the subsidiary guarantors named therein, and Wells Fargo Bank, National Association, as trustee (filed as Exhibit 4.4 to the Post-Effective Amendment to the Company’s Registration Statement on Form S-3 on December 7, 2010, and incorporated herein by reference).

4.5                            Third Supplemental Indenture, dated December 14, 2010, between Concho Resources Inc., the subsidiary guarantors named therein, and Wells Fargo Bank, National Association, as trustee (filed as Exhibit 4.1 to the Company’s Current Report on Form 8-K on December 14, 2010, and incorporated herein by reference).

4.6                            Fourth Supplemental Indenture, dated May 23, 2011, between Concho Resources Inc., the subsidiary guarantors named therein, and Wells Fargo Bank, National Association, as trustee (filed as Exhibit 4.1 to the Company’s Current Report on Form 8-K on May 23, 2011, and incorporated herein by reference).

4.7                            Fifth Supplemental Indenture, dated December 12, 2011, between Concho Resources Inc., the subsidiary guarantors named therein, and Wells Fargo Bank, National Association, as trustee (filed as Exhibit 4.7 to the Company’s Annual Report on Form 10-K on February 24, 2012, and incorporated herein by reference).

4.8                            Sixth Supplemental Indenture, dated March 12, 2012, between Concho Resources Inc., the subsidiary guarantors named therein, and Wells Fargo Bank, National Association, as trustee (filed as Exhibit 4.1 to the Company’s Current Report on Form 8-K on March 12, 2012, and incorporated herein by reference).

4.9                            Seventh Supplemental Indenture, dated August 17, 2012, between Concho Resources Inc., the subsidiary guarantors named therein, and Wells Fargo Bank, National Association, as trustee (filed as Exhibit 4.1 to the Company’s Current Report on Form 8-K on August 17, 2012, and incorporated herein by reference).

4.10                          Eighth Supplemental Indenture, dated June 3, 2013, between Concho Resources Inc., the subsidiary guarantors named therein, and Wells Fargo Bank, National Association, as trustee (filed as Exhibit 4.1 to the Company’s Current Report on Form 8-K on June 6, 2013, and incorporated herein by reference).

4.11                          Form of 7.0% Senior Notes due 2021 (included in Exhibit 4.1 to the Company’s Current Report on Form 8-K on December 14, 2010, and incorporated herein by reference).

4.12                          Form of 6.5% Senior Notes due 2022 (included in Exhibit 4.1 to the Company’s Current Report on Form 8-K on May 23, 2011, and incorporated herein by reference).

4.13                          Form of 5.5% Senior Notes due 2022 (included in Exhibit 4.2 to the Company’s Current Report on Form 8-K on March 12, 2012, and incorporated herein by reference).

4.14                          Form of 5.5% Senior Notes due 2023 (included in Exhibit 4.1 to the Company’s Current Report on Form 8-K on August 17, 2012, and incorporated herein by reference).

10.1            **         Form of Performance Unit Award Agreement (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on January 4, 2013, and incorporated herein by reference).

10.2            **         Concho Resources Inc. 2015 Stock Incentive Plan (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on June 5, 2015, and incorporated herein by reference).

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Exhibit

NumberDescription

10.3            **         Form of Nonstatutory Stock Option Agreement (filed as Exhibit 10.16 to the Company’s Annual Report on Form 10-K on March 28, 2008, and incorporated herein by reference).

10.4            **         Form of Restricted Stock Agreement (for officers) (filed as Exhibit 10.11 to the Company’s Annual Report on Form 10-K on February 22, 2013, and incorporated herein by reference).

10.5            **         Form of Restricted Stock Agreement (for non-employee directors) (filed as Exhibit 10.18 to the Company’s Annual Report on Form 10-K on March 28, 2008, and incorporated herein by reference).

10.6            **         Employment Agreement dated December 19, 2008, between Concho Resources Inc. and Timothy A. Leach (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on December 19, 2008, and incorporated herein by reference).

10.7            **         Employment Agreement dated December 19, 2008, between Concho Resources Inc. and E. Joseph Wright (filed as Exhibit 10.3 to the Company’s Current Report on Form 8-K on December 19, 2008, and incorporated herein by reference).

10.8            **         Employment Agreement dated December 19, 2008, between Concho Resources Inc. and Darin G. Holderness (filed as Exhibit 10.4 to the Company’s Current Report on Form 8-K on December 19, 2008, and incorporated herein by reference).

10.9            **         Employment Agreement dated December 19, 2008, between Concho Resources Inc. and Matthew G. Hyde (filed as Exhibit 10.6 to the Company’s Current Report on Form 8-K on December 19, 2008, and incorporated herein by reference).

10.10          **         Employment Agreement dated November 5, 2009, between Concho Resources Inc. and C. William Giraud (filed as Exhibit 10.18 to the Company’s Annual Report on Form 10-K on February 26, 2010, and incorporated herein by reference).

10.11          **         Employment Agreement dated March 19, 2014, between Concho Resources Inc. and Jack F. Harper (filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K on March 24, 2014, and incorporated herein by reference).

10.12          **         Form of First Amendment to Employment Agreement between Concho Resources Inc. and each of Messrs. Leach, Giraud, Holderness, Hyde and Wright (filed as Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q on May 6, 2011, and incorporated herein by reference).

10.13          **         Form of Indemnification Agreement between Concho Resources Inc. and each of the officers and directors thereof (filed as Exhibit 10.23 to the Company’s Registration Statement on Form S-1 on April 24, 2007, and incorporated herein by reference).

10.14          **         Indemnification Agreement, dated February 27, 2008, by and between Concho Resources, Inc. and William H. Easter III (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on March 4, 2008, and incorporated herein by reference).

10.15          **         Indemnification Agreement, dated May 21, 2008, by and between Concho Resources, Inc. and Matthew G. Hyde (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on May 28, 2008, and incorporated herein by reference).

10.16          **         Indemnification Agreement, dated August 25, 2008, by and between Concho Resources, Inc. and Darin G. Holderness (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on August 29, 2008, and incorporated herein by reference).

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Exhibit

NumberDescription

10.17          **         Indemnification Agreement, dated November 5, 2009, by and between Concho Resources, Inc. and Mark B. Puckett (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on November 12, 2009, and incorporated herein by reference).

10.18          **         Indemnification Agreement, dated November 5, 2009, by and between Concho Resources, Inc. and C. William Giraud (filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K on November 12, 2009, and incorporated herein by reference).

10.19          **         Form of Director and Officer Indemnification Agreement between Concho Resources Inc. and each of Messrs. Surma and Harper (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on March 24, 2014, and incorporated herein by reference).

10.20          **         Indemnification Agreement, dated January 10, 2012, between Concho Resources Inc. and Gary A. Merriman (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on January 12, 2012, and incorporated herein by reference).

10.21                        Second Amended and Restated Credit Agreement, dated as of May 9, 2014, among Concho Resources Inc., the lenders party thereto and JPMorgan Chase Bank, N.A., as Administrative Agent (filed as Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q on May 12, 2014, and incorporated herein by reference).

10.22                        First Amendment to Second Amended and Restated Credit Agreement, dated as of April 8, 2015, among Concho Resources Inc., the lenders party thereto and JPMorgan Chase Bank, N.A., as Administrative Agent (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on April 9, 2015, and incorporated herein by reference).

10.23                        Registration Rights Agreement, dated February 27, 2006, among Concho Resources Inc. and the other signatories thereto (filed as Exhibit 10.12 to the Company’s Registration Statement on Form S-1 on April 24, 2007, and incorporated herein by reference).

12.1            (a)         Ratio of Earnings to Fixed Charges and Ratio of Earnings to Fixed Charges and Preferred Stock Dividends.

21.1            (a)         Subsidiaries of Concho Resources Inc.

23.1            (a)         Consent of Grant Thornton LLP.

23.2            (a)         Consent of Netherland, Sewell & Associates, Inc.

23.3            (a)         Consent of Cawley, Gillespie & Associates, Inc.

31.1            (a)         Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2            (a)         Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1            (b)         Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2            (b)         Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

99.1            (a)         Netherland, Sewell & Associates, Inc. Reserve Report.

99.2            (a)         Cawley, Gillespie & Associates, Inc. Reserve Report.

101.INS     (a)         XBRL Instance Document.

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Exhibit

NumberDescription

101.SCH   (a)         XBRL Schema Document.

101.CAL   (a)         XBRL Calculation Linkbase Document.

101.DEF    (a)         XBRL Definition Linkbase Document.

101.LAB   (a)         XBRL Labels Linkbase Document.

101.PRE    (a)         XBRL Presentation Linkbase Document.

(a)  Filed herewith.

(b)  Furnished herewith.

**   Management contract or compensatory plan or agreement

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GLOSSARY OF TERMS

The following terms are used throughout this report:

Bbl                                                     One stock tank barrel, of 42 United States gallons liquid volume, used herein in reference to oil, condensate or natural gas liquids.

Boe                                                     One barrel of oil equivalent, a standard convention used to express oil and natural gas volumes on a comparable oil equivalent basis.  Natural gas equivalents are determined under the relative energy content method by using the ratio of 6.0 Mcf of natural gas to 1.0 Bbl of oil or condensate.

Basin                                                 A large natural depression on the earth’s surface in which sediments accumulate.

Developmentwells                          Wells drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

Dry hole                                            A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production would exceed production expenses, taxes and the royalty burden.

Exploratory wells                          Wells drilled to find and produce oil or natural gas in an unproved area, to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir, or to extend a known reservoir.

Field                                                  An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.

GAAP                                                Generally accepted accounting principles in the United States of America.

Gross wells                                       The number of wells in which a working interest is owned.

Horizontal drilling                        A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a high angle to vertical (which can be greater than 90 degrees) in order to stay within a specified interval.

Infill drilling                                   Drilling into the same pool as known producing wells so that oil or natural gas does not have to travel as far through the formation.

LIBOR                                              London Interbank Offered Rate, which is a market rate of interest.

MBbl                                                 One thousand barrels of oil, condensate or natural gas liquids.

MBoe                                                 One thousand Boe.

Mcf                                                    One thousand cubic feet of natural gas.

MMBoe                                             One million Boe.

MMBtu                                             One million British thermal units.

MMcf                                                One million cubic feet of natural gas.

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NYMEX                                            The New York Mercantile Exchange.

NYSE                                                 The New York Stock Exchange.

Net acres                                           The percentage of total acres an owner owns out of a particular number of acres within a specified tract. For example, an owner who has a 50 percent interest in 100 acres owns 50 net acres.

Net wells                                           The total of fractional working interests owned in gross wells.

PV-10                                                When used with respect to oil and natural gas reserves, PV-10 means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development and abandonment costs, using prices and costs in effect at the determination date, before income taxes, and without giving effect to non-property-related expenses except for specific general and administrative expenses incurred to operate the properties, discounted to a present value using an annual discount rate of 10 percent. PV-10 is a non-GAAP financial measure.

Productive wells                             Wells that produce commercial quantities of hydrocarbons, exclusive of their capacity to produce at a reasonable rate of return.

Proved developed reserves          Proved developed reserves are proved reserves that can be expected to be recovered:

(i)through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii)through installed extraction equipment and infrastructure operational at the time of the reserve estimate if the extraction is by means not involving a well.

Supplemental definitions from the 2007 Petroleum Resources Management System:

Proved Developed Producing Reserves – Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate. Improved recovery reserves are considered producing only after the improved recovery project is in operation.

Proved Developed Non-Producing Reserves – Developed Non-Producing Reserves include shut-in and behind-pipe Reserves. Shut-in Reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not yet started producing, (2) wells which were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe Reserves are expected to be recovered from zones in existing wells which will require additional completion work or future recompletion prior to start of production. In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

Proved reserves                              Proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

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(i)        The area of the reservoir considered as proved includes:

(A) the area identified by drilling and limited by fluid contacts, if any, and

(B)  adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or natural gas on the basis of available geoscience and engineering data.

(ii)       In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (“LKH”) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii)      Where direct observation from well penetrations has defined a highest known oil (“HKO”) elevation and the potential exists for an associated natural gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv)      Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A)successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

(B)the project has been approved for development by all necessary parties and entities, including governmental entities.

(v)       Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

Proved undeveloped reserves     Proved undeveloped oil and natural gas reserves are proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(i)Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii)Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

Recompletion                                  The addition of production from another interval or formation in an existing wellbore.

Reservoir                                         A formation beneath the surface of the earth from which hydrocarbons may be present. Its make-up is sufficiently homogenous to differentiate it from other formations.

Spacing                                             The distance between wells producing from the same reservoir. Spacing is expressed in terms of acres, e.g., 40-acre spacing, and is established by regulatory agencies.

92

Standardized Measure                  The present value (discounted at an annual rate of 10 percent) of estimated future net revenues to be generated from the production of proved reserves net of estimated income taxes associated with such net revenues, as determined in accordance with FASB guidelines, without giving effect to non-property related expenses such as indirect general and administrative expenses, and debt service or to depreciation, depletion and amortization. Standardized measure does not give effect to derivative transactions.

Undeveloped acreage                    Acreage owned or leased on which wells can be drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.

Wellbore                                          The hole drilled by the bit that is equipped for oil or natural gas production on a completed well. Also called a well or borehole.

Working interest                            The right granted to the lessee of a property to explore for and to produce and own oil, natural gas, or other minerals. The working interest owners bear the exploration, development, and operating costs on either a cash, penalty, or carried basis.

Workover                                        Operations on a producing well to restore or increase production.

WTI                                                   West Texas Intermediate - light, sweet blend of oil produced from fields in western Texas.

93

SIGNATURES

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

CONCHO RESOURCES INC.
Date:	February 25, 2016	By	/s/  Timothy A. Leach
			Timothy A. Leach
			Director, Chairman of the Board of Directors, Chief Executive
			Officer and President (Principal Executive Officer)

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

Signature	Title	Date
/s/  TIMOTHY A. LEACH	Director, Chairman of the Board of Directors, Chief Executive Officer and President (Principal Executive Officer)	February 25, 2016
Timothy A. Leach
/s/ DARIN G. HOLDERNESS	Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)	February 25, 2016
Darin G. Holderness
/s/ BRENDA R. SCHROER	Vice President and Chief Accounting Officer (Principal Accounting Officer)	February 25, 2016
Brenda R. Schroer
/s/ STEVEN L. BEAL	Director	February 25, 2016
Steven L. Beal
/s/ TUCKER S. BRIDWELL	Director	February 25, 2016
Tucker S. Bridwell
/s/ WILLIAM H. EASTER III	Director	February 25, 2016
William H. Easter III
/s/ GARY A. MERRIMAN	Director	February 25, 2016
Gary A. Merriman
/s/ RAY M. POAGE	Director	February 25, 2016
Ray M. Poage
/s/ MARK B. PUCKETT	Director	February 25, 2016
Mark B. Puckett
/s/ JOHN P. SURMA	Director	February 25, 2016
John P. Surma

94

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

Consolidated Financial Statements of Concho Resources Inc.:

Report of Independent Registered Public Accounting Firm	F-2
Consolidated Balance Sheets at December 31, 2015 and 2014	F-3
Consolidated Statements of Operations for the Years Ended December 31, 2015, 2014 and 2013	F-4
Consolidated Statements of Stockholders' Equity for the Years Ended December 31, 2015, 2014 and 2013	F-5
Consolidated Statements of Cash Flows for the Years Ended December 31, 2015, 2014 and 2013	F-6
Notes to Consolidated Financial Statements	F-7
Unaudited Supplementary Data	F-41

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Stockholders

Concho Resources Inc.

We have audited the accompanying consolidated balance sheets of Concho Resources Inc. (a Delaware corporation) and subsidiaries (the “Company”) as of December 31, 2015 and 2014, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2015. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

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

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Concho Resources Inc. and subsidiaries as of December 31, 2015 and 2014, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2015 in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 2 to the consolidated financial statements, the Company adopted new accounting guidance in 2015 and 2014, related to the presentation of deferred loan costs and deferred income taxes.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company's internal control over financial reporting as of December 31, 2015, based on criteria established in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 25, 2016 expressed an unqualified opinion thereon.

/s/ GRANT THORNTON LLP

Tulsa, Oklahoma

February 25, 2016

F-2

Concho Resources Inc.
Consolidated Balance Sheets
				December 31,
(in thousands, except share and per share amounts)					2015		2014
Assets
Current assets:
	Cash and cash equivalents			$	228,550	$	21
	Accounts receivable, net of allowance for doubtful accounts:
		Oil and natural gas			203,972		250,600
		Joint operations and other			190,608		409,665
	Derivative instruments				652,498		490,351
	Prepaid costs and other				38,922		37,759
			Total current assets		1,314,550		1,188,396
Property and equipment:
	Oil and natural gas properties, successful efforts method				15,846,307		13,867,831
	Accumulated depletion and depreciation				(5,047,810)		(3,790,953)
		Total oil and natural gas properties, net			10,798,497		10,076,878
	Other property and equipment, net				178,450		129,136
		Total property and equipment, net			10,976,947		10,206,014
Deferred loan costs, net					15,585		20,260
Intangible asset - operating rights, net					25,693		27,154
Inventory					19,118		14,435
Noncurrent derivative instruments					167,038		262,349
Other assets					122,945		33,172
	Total assets			$	12,641,876	$	11,751,780
Liabilities and Stockholders’ Equity
Current liabilities:
	Accounts payable - trade			$	13,200	$	20,380
	Bank overdrafts				-		92,541
	Revenue payable				169,787		238,098
	Accrued and prepaid drilling costs				228,523		718,300
	Other current liabilities				184,910		195,308
			Total current liabilities		596,420		1,264,627
Long-term debt					3,332,188		3,469,137
Deferred income taxes					1,630,373		1,600,751
Asset retirement obligations and other long-term liabilities					140,344		136,477
Commitments and contingencies (Note 10)
Stockholders’ equity:
	Common stock, $0.001 par value; 300,000,000 authorized; 129,444,042 and 113,264,918
		shares issued at December 31, 2015 and 2014, respectively			129		113
	Additional paid-in capital				4,628,390		3,027,412
	Retained earnings				2,345,641		2,279,741
	Treasury stock, at cost; 306,061 and 260,124 shares at December 31, 2015 and 2014,
		respectively			(31,609)		(26,478)
			Total stockholders’ equity		6,942,551		5,280,788
	Total liabilities and stockholders’ equity			$	12,641,876	$	11,751,780
The accompanying notes are an integral part of these consolidated financial statements.

F-3

Concho Resources Inc.
Consolidated Statements of Operations
			Years Ended December 31,
(in thousands, except per share amounts)				2015		2014		2013
Operating revenues:
	Oil sales		$	1,539,917	$	2,189,072	$	1,938,433
	Natural gas sales			263,656		471,075		381,486
		Total operating revenues		1,803,573		2,660,147		2,319,919
Operating costs and expenses:
	Oil and natural gas production			541,359		538,374		455,436
	Exploration and abandonments			58,847		284,821		109,549
	Depreciation, depletion and amortization			1,223,253		979,740		772,608
	Accretion of discount on asset retirement obligations			7,600		7,072		6,047
	Impairments of long-lived assets			60,529		447,151		65,375
	General and administrative (including non-cash stock-based compensation of $63,073,
		$47,130 and $35,078 for the years ended December 31, 2015, 2014 and 2013, respectively)		230,734		204,161		169,815
	(Gain) loss on derivatives			(699,752)		(890,917)		123,652
		Total operating costs and expenses		1,422,570		1,570,402		1,702,482
Income from operations				381,003		1,089,745		617,437
Other income (expense):
	Interest expense			(215,384)		(216,661)		(218,581)
	Loss on extinguishment of debt			-		(4,316)		(28,616)
	Loss on disposition of assets, net			(53,789)		(9,308)		(1,268)
	Other, net			(14,559)		(3,500)		(11,813)
		Total other expense		(283,732)		(233,785)		(260,278)
Income from continuing operations before income taxes				97,271		855,960		357,159
	Income tax expense			(31,371)		(317,785)		(118,237)
Income from continuing operations				65,900		538,175		238,922
Income from discontinued operations, net of tax				-		-		12,081
Net income			$	65,900	$	538,175	$	251,003
Basic earnings per share:
	Income from continuing operations		$	0.54	$	4.89	$	2.28
	Income from discontinued operations, net of tax			-		-		0.11
		Net income	$	0.54	$	4.89	$	2.39
Diluted earnings per share:
	Income from continuing operations		$	0.54	$	4.88	$	2.28
	Income from discontinued operations, net of tax			-		-		0.11
		Net income	$	0.54	$	4.88	$	2.39
The accompanying notes are an integral part of these consolidated financial statements.

F-4

Concho Resources Inc.
Consolidated Statements of Stockholders’ Equity
							Additional							Total
			Common Stock Issued				Paid-in		Retained	Treasury Stock			Stockholders’
(in thousands)			Shares		Amount		Capital		Earnings	Shares		Amount		Equity
BALANCE AT JANUARY 1, 2013			104,668	$	105	$	1,982,714	$	1,490,563	87	$	(7,186)	$	3,466,196
	Net income		-		-		-		251,003	-		-		251,003
	Stock options exercised		174		-		3,223		-	-		-		3,223
	Grants of restricted stock		499		-		-		-	-		-		-
	Cancellation of restricted stock		(118)		-		-		-	-		-		-
	Stock-based compensation		-		-		35,078		-	-		-		35,078
	Excess tax benefits related to stock-based
		compensation	-		-		6,147		-	-		-		6,147
	Purchase of treasury stock		-		-		-		-	40		(3,698)		(3,698)
BALANCE AT DECEMBER 31, 2013			105,223		105		2,027,162		1,741,566	127		(10,884)		3,757,949
	Net income		-		-		-		538,175	-		-		538,175
	Issuance of common stock		7,475		7		931,982		-	-		-		931,989
	Stock options exercised		208		1		4,658		-	-		-		4,659
	Grants of restricted stock		448		-		-		-	-		-		-
	Cancellation of restricted stock		(89)		-		-		-	-		-		-
	Stock-based compensation		-		-		47,130		-	-		-		47,130
	Excess tax benefits related to stock-based
		compensation	-		-		16,480		-	-		-		16,480
	Purchase of treasury stock		-		-		-		-	133		(15,594)		(15,594)
BALANCE AT DECEMBER 31, 2014			113,265		113		3,027,412		2,279,741	260		(26,478)		5,280,788
	Net income		-		-		-		65,900	-		-		65,900
	Issuance of common stock		15,755		16		1,535,696		-	-		-		1,535,712
	Stock options exercised		5		-		59		-	-		-		59
	Grants of restricted stock		452		-		-		-	-		-		-
	Cancellation of restricted stock		(33)		-		-		-	-		-		-
	Stock-based compensation		-		-		63,073		-	-		-		63,073
	Excess tax benefits related to stock-based
		compensation	-		-		2,150		-	-		-		2,150
	Purchase of treasury stock		-		-		-		-	46		(5,131)		(5,131)
BALANCE AT DECEMBER 31, 2015			129,444	$	129	$	4,628,390	$	2,345,641	306	$	(31,609)	$	6,942,551
The accompanying notes are an integral part of these consolidated financial statements.

F-5

Concho Resources Inc.
Consolidated Statements of Cash Flows
					Years Ended December 31,
(in thousands)					2015		2014			2013
CASH FLOWS FROM OPERATING ACTIVITIES:
	Net income				$	65,900	$	538,175	$	251,003
	Adjustments to reconcile net income to net cash provided by operating activities:
		Depreciation, depletion and amortization				1,223,253		979,740		772,608
		Accretion of discount on asset retirement obligations				7,600		7,072		6,047
		Impairments of long-lived assets				60,529		447,151		65,375
		Exploration and abandonments, including dry holes				43,737		265,064		80,714
		Non-cash stock-based compensation expense				63,073		47,130		35,078
		Deferred income taxes				29,622		296,167		102,427
		Loss on disposition of assets and other				53,789		9,308		1,268
		(Gain) loss on derivatives				(699,752)		(890,917)		123,652
		Discontinued operations				-		-		(12,250)
		Other non-cash items				14,639		18,379		19,720
	Changes in operating assets and liabilities, net of acquisitions and dispositions:
			Accounts receivable			117,716		(104,988)		(40,009)
			Prepaid costs and other			(3,726)		(23,628)		4,945
			Inventory			(5,154)		2,441		509
			Accounts payable			(17,689)		1,566		(18,469)
			Revenue payable			(68,311)		60,481		28,593
			Other current liabilities			12,279		20,646		(59,191)
				Net cash provided by operating activities		897,505		1,673,787		1,362,020
CASH FLOWS FROM INVESTING ACTIVITIES:
	Capital expenditures on oil and natural gas properties					(2,443,704)		(2,554,914)		(1,850,992)
	Additions to property, equipment and other assets					(67,699)		(34,320)		(28,678)
	Proceeds from the disposition of assets					104		1,305		15,217
	Contributions to equity method investments					(91,342)		(30,050)		-
	Settlements received from (paid on) derivatives					632,916		71,983		(32,341)
				Net cash used in investing activities		(1,969,725)		(2,545,996)		(1,896,794)
CASH FLOWS FROM FINANCING ACTIVITIES:
	Proceeds from issuance of debt					1,490,900		2,081,000		3,257,575
	Payments of debt					(1,630,400)		(2,191,500)		(2,729,700)
	Exercise of stock options					59		4,659		3,223
	Excess tax benefit from stock-based compensation					2,150		16,480		6,147
	Net proceeds from issuance of common stock					1,535,712		931,989		-
	Payments for loan costs					-		(10,648)		(14,075)
	Purchase of treasury stock					(5,131)		(15,594)		(3,698)
	Increase (decrease) in bank overdrafts					(92,541)		55,823		12,443
				Net cash provided by financing activities		1,300,749		872,209		531,915
				Net increase (decrease) in cash and cash equivalents		228,529		-		(2,859)
Cash and cash equivalents at beginning of period						21		21		2,880
Cash and cash equivalents at end of period					$	228,550	$	21	$	21
SUPPLEMENTAL CASH FLOWS:
	Cash paid for interest				$	211,443	$	211,342	$	200,961
	Cash paid for income taxes				$	3,950	$	27,844	$	21,376
The accompanying notes are an integral part of these consolidated financial statements.

F-6

Concho Resources Inc.

Notes to Consolidated Financial Statements

December 31, 2015, 2014 and 2013

Note 1. Organization and nature of operations

Concho Resources Inc. (the “Company”) is a Delaware corporation formed on February 22, 2006. The Company’s principal business is the acquisition, development and exploration of oil and natural gas properties primarily located in the Permian Basin of Southeast New Mexico and West Texas.

Note 2. Summary of significant accounting policies

Principles of consolidation. The consolidated financial statements of the Company include the accounts of the Company and its 100 percent owned subsidiaries. The Company consolidates the financial statements of these entities. All material intercompany balances and transactions have been eliminated.

Retrospective adjustments and reclassifications. Certain reclassifications have been made to the 2014 amounts in order to conform to the 2015 presentation and for the retrospective application resulting from the early adoption of Accounting Standards Update (“ASU”) No. 2015-03 and 2015-17. The retrospective application of ASU 2015-03 resulted in $48.2 million of net deferred loan costs directly related to the Company’s senior notes being reclassified from a noncurrent asset to a direct deduction from the carrying amount of the related senior notes at December 31, 2014. The retrospective application of ASU 2015-17 resulted in the current deferred income tax liability of $162.6 million at December 31, 2014 to be reclassified as a noncurrent deferred income tax liability in the Company’s consolidated balance sheet.

Other certain prior period amounts have been reclassified to conform to the 2015 presentation. These reclassifications had no impact on the balance sheet, net income (loss) or cash flows.

Discontinued operations. In December 2012, the Company closed the sale of certain of its non-core assets for cash consideration of approximately $503.1 million, which resulted in a pre-tax gain of approximately $0.9 million. As a result of post-closing adjustments during the year ended December 31, 2013, the Company made a positive adjustment to gain (loss) on disposition of assets of approximately $19.6 million, before income tax expense of approximately $7.5 million. The Company recognized income from discontinued operations, net of tax of $12.1 million for the year ended December 31, 2013.

Use of estimates in the preparation of financial statements. Preparation of financial statements in conformity with generally accepted accounting principles in the United States of America (“U.S. GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from these estimates. Depletion of oil and natural gas properties is determined using estimates of proved oil and natural gas reserves. There are numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. Similarly, evaluations for impairment of proved and unproved oil and natural gas properties are subject to numerous uncertainties including, among others, estimates of future recoverable reserves, commodity price outlooks and prevailing market rates of other sources of income and costs. Other significant estimates include, but are not limited to, asset retirement obligations, fair value of derivative financial instruments, fair value of business combinations, fair value of nonmonetary exchanges, fair value of stock-based compensation and income taxes.

Cash equivalents. The Company considers all cash on hand, depository accounts held by banks, money market accounts and investments with an original maturity of three months or less to be cash equivalents. The Company’s cash and cash equivalents are held in financial institutions in amounts that exceed the insurance limits of the Federal Deposit Insurance Corporation. However, management believes that the Company’s counterparty risks are minimal based on the reputation and history of the institutions selected.

Accounts receivable. The Company sells oil and natural gas to various customers and participates with other parties in the drilling, completion and operation of oil and natural gas wells. Joint interest and oil and natural gas sales receivables related to these operations are generally unsecured. The Company determines joint interest operations accounts receivable allowances based on management’s assessment of the creditworthiness of the joint interest owners and the Company’s ability

F-7

Concho Resources Inc.

Notes to Consolidated Financial Statements

December 31, 2015, 2014 and 2013

to realize the receivables through netting of anticipated future production revenues. Receivables are considered past due if full payment is not received by the contractual due date. Past due accounts are generally written off against the allowance for doubtful accounts only after all collection attempts have been exhausted. The Company had an allowance for doubtful accounts of approximately $1.2million and $0.7million at December 31, 2015 and December 31, 2014, respectively.

Inventory. Inventory consists primarily of tubular goods, water and other oilfield equipment that the Company plans to utilize in its ongoing exploration and development activities and is carried at the lower of cost or market value, on a weighted average cost basis.

Deferred loan costs. Deferred loan costs are stated at cost, net of amortization, which is computed using the effective interest method and straight-line methods. For the interim period ended December 31, 2015, the Company early adopted ASU No. 2015-03, “Interest-Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs,” which requires net deferred loan costs directly related to the Company’s senior notes to be classified as a direct deduction from the carrying amount of the related senior notes. The Company retrospectively adopted the ASU and reclassified $48.2 million at December 31, 2014 from a noncurrent asset to a deduction from long-term debt. The deferred loan costs related to the Company’s credit facility remain classified as a noncurrent asset due to the revolving nature of that facility. The provisions of the ASU were adopted primarily to simplify the required reporting for subsequent registration filings. The Company had deferred loan costs related to its senior notes of $42.9 million and $48.2 million, net of accumulated amortization of $18.7 million and $13.4 million, as a reduction of long-term debt at December 31, 2015 and December 31, 2014, respectively.

The Company had deferred loan costs related to the credit facility of $15.6 million and $20.3 million, net of accumulated amortization of $51.0 million and $46.3 million, in noncurrent assets at December 31, 2015 and December 31, 2014, respectively.

Oil and natural gas properties. The Company utilizes the successful efforts method of accounting for its oil and natural gas properties. Under this method all costs associated with productive wells and nonproductive development wells are capitalized, while nonproductive exploration costs are expensed. Capitalized acquisition costs relating to proved properties are depleted using the unit-of-production method based on proved reserves. The depletion of capitalized drilling and development costs and integrated assets is based on the unit-of-production method using proved developed reserves. During the years ended December 31, 2015, 2014 and 2013, the Company recognized depletion expense from continuing operations of $1,203.5 million, $960.9 million and $756.0 million, respectively.

The Company generally does not carry the costs of drilling an exploratory well as an asset in its consolidated balance sheets following the completion of drilling unless both of the following conditions are met:

(i)the well has found a sufficient quantity of reserves to justify its completion as a producing well; and

(ii)the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project.

Due to the capital intensive nature and the geographical location of certain projects, it may take the Company longer than one year to evaluate the future potential of the exploration well and economics associated with making a determination on its commercial viability. In these instances, the project’s feasibility is not contingent upon price improvements or advances in technology, but rather the Company’s ongoing efforts and expenditures related to accurately predicting the hydrocarbon recoverability based on well information, gaining access to other companies’ production, transportation or processing facilities and/or getting partner approval to drill additional appraisal wells. These activities are ongoing and being pursued constantly. Consequently, the Company’s assessment of suspended exploratory well costs is continuous until a decision can be made that the well has found proved reserves or is noncommercial and is charged to exploration and abandonments expense. See Note 3 for additional information regarding the Company’s suspended exploratory well costs.

Proceeds from the sales of individual properties and the capitalized costs of individual properties sold or abandoned are credited and charged, respectively, to accumulated depletion. Generally, no gain or loss is recognized until the entire

F-8

Concho Resources Inc.

Notes to Consolidated Financial Statements

December 31, 2015, 2014 and 2013

depletion base is sold. However, gain or loss is recognized from the sale of less than an entire depletion base if the disposition is significant enough to materially impact the depletion rate of the remaining properties in the depletion base. Ordinary maintenance and repair costs are expensed as incurred.

Costs of significant nonproducing properties, wells in the process of being drilled and completed and development projects are excluded from depletion until the related project is completed and proved developed reserves are established or, if unsuccessful, impairment is determined. The Company capitalizes interest, if debt is outstanding, on expenditures for significant development projects until such projects are ready for their intended use. During the years ended December 31, 2015 and 2014, the Company had capitalized interest of $0.7  million and $1.4  million, respectively. The Company did not capitalize interest during 2013.

The Company reviews its long-lived assets to be held and used, including proved oil and natural gas properties, whenever events or circumstances indicate that the carrying value of those assets may not be recoverable. An impairment loss is indicated if the sum of the expected future cash flows is less than the carrying amount of the assets. In this circumstance, the Company recognizes an impairment loss for the amount by which the carrying amount of the asset exceeds the estimated fair value of the asset. The Company reviews its oil and natural gas properties by depletion base or by individual well for those wells not constituting part of a depletion base. For each property determined to be impaired, an impairment loss equal to the difference between the carrying value of the properties and the estimated fair value (discounted future cash flows) of the properties and integrated assets would be recognized at that time. Estimating future cash flows involves the use of judgments, including estimation of the proved and risk-adjusted unproved oil and natural gas reserve quantities, timing of development and production, expected future commodity prices, capital expenditures and production costs and cash flows from integrated assets. The Company recognized impairment expense of $60.5 million, $447.2 million, and $65.4 million during the years ended December 31, 2015, 2014 and 2013, respectively, related to its proved oil and natural gas properties.

Unproved oil and natural gas properties are each periodically assessed for impairment by considering future drilling plans, the results of exploration activities, commodity price outlooks, planned future sales or expiration of all or a portion of such projects. During the years ended December 31, 2015, 2014 and 2013, the Company recognized expense of $34.5 million, $217.3  million and $49.8  million, respectively, related to abandoned prospects and expiring acreage, which is included in exploration and abandonments expensein the accompanying consolidated statements of operations.

Other property and equipment.  Other capital assets include buildings, transportation equipment, computer equipment and software, telecommunications equipment, leasehold improvements and furniture and fixtures. These items are recorded at cost, or fair value if acquired, and are depreciated using the straight-line method based on expected lives of the individual assets or group of assets ranging from two to 31 years. The Company had other capital assets of $178.5 million and $129.1 million, net of accumulated depreciation of $54.4 million and $52.5 million, at December 31, 2015 and December 31, 2014, respectively. During the years ended December 31, 2015, 2014 and 2013, the Company recognized depreciation expense of $18.3 million, $17.3 million and $15.2 million, respectively.

Intangible assets.  The Company has capitalized certain operating rights acquired in an acquisition. The gross operating rights, which have no residual value, are amortized over the estimated economic life of 25 years. Impairment will be assessed if indicators of potential impairment exist or when there is a material change in the remaining useful economic life. The following table reflects the gross and net intangible assets at December 31, 2015 and 2014, respectively:

			December 31,
(in thousands)			2015		2014
Gross intangible - operating rights		$	36,557	$	36,557
Accumulated amortization			(10,864)		(9,403)
	Net intangible - operating rights	$	25,693	$	27,154

F-9

Concho Resources Inc.

Notes to Consolidated Financial Statements

December 31, 2015, 2014 and 2013

The following table reflects amortization expense from continuing operations for the years ended December 31, 2015, 2014 and 2013:

	Years Ending December 31,
(in thousands)	2015		2014		2013
Amortization expense	$	1,461	$	1,461	$	1,461

The following table reflects the estimated aggregate amortization expense for each of the periods presented below at December 31, 2015:

(in thousands)
2016		$	1,461
2017			1,461
2018			1,461
2019			1,461
2020			1,461
Thereafter			18,388
	Total	$	25,693

Equity method investments. The Company owns a 50 percent member interest in a midstream joint venture, Alpha Crude Connector, LLC (“ACC”), to construct a crude oil gathering and transportation system in the northern Delaware Basin. The Company has the option to purchase the member interest of the other investor in ACC. This purchase option becomes exercisable three months after the completion date of the pipeline and remains exercisable for a period of twelve months. The Company accounts for its investment in ACC under the equity method of accounting for investments in unconsolidated affiliates. The Company’s net investment in ACC was approximately $98.9 million and $29.5 million at December 31, 2015 and December 31, 2014, respectively, and was included in other assets in the Company’s consolidated balance sheet. The equity loss for the years ended December 31, 2015 and 2014 was approximately $4.1 million and $1.3 million, respectively, and was included in other expense in the Company’s consolidated statement of operations. During 2015 and 2014, the Company recorded approximately $2.9 million and $0.7 million, respectively, of capitalized interest on its investment in ACC. ACC started partial operations in late 2015. The Company expects the system to be fully operational during 2016.

During 2015, the Company purchased a 25 percent member interest in an entity, which is constructing a crude oil gathering and transportation system in the southern Delaware Basin. The system is expected to be completed and operational during 2016. The Company accounts for its investment under the equity method of accounting for investments in unconsolidated affiliates. The Company’s net investment is approximately $20.8 million at December 31, 2015 and is included in other assets in the Company’s consolidated balance sheet.

Environmental. The Company is subject to extensive federal, state and local environmental laws and regulations. These laws, which are often changing, regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures of a noncapital nature are recorded when environmental assessment and/or remediation is probable and the costs can be reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash payments is fixed and readily determinable. At December 31, 2015 and 2014, the Company has accrued approximately $1.0 million and $1.7  million, respectively, related to environmental liabilities. During the years ended December 31, 2015, 2014 and 2013, the Company recognized environmental charges of

F-10

Concho Resources Inc.

Notes to Consolidated Financial Statements

December 31, 2015, 2014 and 2013

approximately $2.7 million, $4.0  million and $3.4  million, respectively.

Derivative instruments. The Company recognizes its derivative instruments, other than any commodity derivative contracts that are designated as normal purchase and normal sale, as either assets or liabilities measured at fair value. The Company netted the fair value of derivative instruments by counterparty in the accompanying consolidated balance sheets where the right of offset exists. The Company did not have any derivatives designated as fair value or cash flow hedges during the years ended December 31, 2015, 2014 or 2013. The Company may also enter into physical delivery contracts to effectively provide commodity price hedges. Because these contracts are not expected to be net cash settled, they are considered to be normal sales contracts and not derivatives. Therefore, these contracts are not recorded in the Company’s consolidated financial statements.

Asset retirement obligations. The Company records the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. Subsequently, the asset retirement cost included in the carrying amount of the related asset is allocated to expense through depletion of the asset. Changes in the liability due to passage of time are generally recognized as an increase in the carrying amount of the liability and as corresponding accretion expense. Based on certain factors including commodity prices and costs, the Company may revise its previous estimates related to the liability, which would also increase or decrease the associated oil and gas property asset.

Treasury stock. Treasury stock purchases are recorded at cost.

Revenue recognition. Oil and natural gas revenues are recorded at the time of physical transfer of such products to the purchaser, which for the Company is primarily at the wellhead. The Company follows the sales method of accounting for oil and natural gas sales, recognizing revenues based on the Company’s actual proceeds from the oil and natural gas sold to purchasers.

Oil and natural gas imbalances.Oil and natural gas imbalances are generated on properties for which two or more owners have the right to take production “in-kind” and, in doing so, take more or less than their respective entitled percentage. Imbalances are tracked by well, but the Company does not record any receivable from or payable to the other owners unless the imbalance has reached a level at which it exceeds the remaining reserves in the respective well. If reserves are insufficient to offset the imbalance and the Company is in an overtake position, a liability is recorded for the amount of shortfall in reserves valued at a contract price or the market price in effect at the time the imbalance is generated. If the Company is in an undertake position, a receivable is recorded for an amount that is reasonably expected to be received, not to exceed the current market value of such imbalance. The Company had no significant imbalances at December 31, 2015 or 2014.

General and administrative expense. The Company receives fees for the operation of jointly-owned oil and natural gas properties and records such reimbursements as reductions of general and administrative expense. Such fees totaled approximately $24.3 million, $23.2  million and $18.5  million for the years ended December 31, 2015, 2014 and 2013, respectively.

Stock-based compensation.For stock-based compensation awards granted, stock-based compensation expense is being recognized in the Company’s financial statements on an accelerated basis over the awards’ vesting periods based on their fair values on the dates of grant. The stock-based compensation awards generally vest over a period ranging from one to five years. The Company utilizes (i) the Black-Scholes option pricing model to measure the fair value of stock options, (ii) the average of the grant date’s high and low stock prices for the fair value of restricted stock and (iii) the Monte Carlo simulation method for the fair value of performance unit awards.

Income taxes. In November 2015, the FASB issued ASU No. 2015-17, “Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes,” which requires that all deferred tax assets and liabilities, along with any related valuation allowance, be classified as noncurrent on the balance sheet. The Company early adopted the ASU retrospectively for the interim period ended December 31, 2015, which resulted in its current deferred income tax liability of $162.6 million at December 31, 2014 to be reclassified as a noncurrent deferred income tax liability in the Company’s consolidated balance

F-11

Concho Resources Inc.

Notes to Consolidated Financial Statements

December 31, 2015, 2014 and 2013

sheet. The provisions of the ASU were adopted primarily to simplify the required reporting for subsequent registration filings. The Company previously classified deferred income tax liabilities and assets separately to current and noncurrent.

The Company recognizes deferred tax assets and liabilities for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rate is recognized in income in the period that includes the enactment date. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized.

The Company evaluates uncertain tax positions for recognition and measurement in the consolidated financial statements. To recognize a tax position, the Company determines whether it is more likely than not that the tax positions will be sustained upon examination, including resolution of any related appeals or litigation, based on the technical merits of the position. A tax position that meets the more likely than not threshold is measured to determine the amount of benefit to be recognized in the consolidated financial statements. The amount of tax benefit recognized with respect to any tax position is measured as the largest amount of benefit that is greater than 50 percent likely of being realized upon settlement. The Company had no material uncertain tax positions that required recognition in the consolidated financial statements at December 31, 2015 and 2014. Any interest or penalties would be recognized as a component of income tax expense.

Recent accounting pronouncements.In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606),” which outlines a new, single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. This new revenue recognition model provides a five-step analysis in determining when and how revenue is recognized. The new model will require revenue recognition to depict the transfer of promised goods or services to customers in an amount that reflects the consideration a company expects to receive in exchange for those goods or services.

In August 2015, the FASB issued ASU No. 2015-14, “Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date,” which deferred the effective date of ASU 2014-09 by one year. That new standard is now effective for annual reporting periods beginning after December 15, 2017. An entity can apply ASU 2014-09 using either a full retrospective method, meaning the standard is applied to all of the periods presented, or a modified retrospective method, meaning the cumulative effect of initially applying the standard is recognized in the most current period presented in the financial statements. The Company is evaluating the impact that this new guidance will have on its consolidated financial statements.

F-12

Concho Resources Inc.

Notes to Consolidated Financial Statements

December 31, 2015, 2014 and 2013

Note 3. Exploratory well costs

The Company capitalizes exploratory well costs until a determination is made that the well has either found proved reserves or that it is impaired. The capitalized exploratory well costs are carried in unproved oil and natural gas properties. See Unaudited Supplementary Data for the proved and unproved components of oil and natural gas properties. If the exploratory well is determined to be impaired, the well costs are charged to exploration and abandonments expense in the consolidated statements of operations. 

The following table reflects the Company’s net capitalized exploratory well activity during each of the years ended December 31, 2015, 2014 and 2013:

		Years Ended December 31,
(in thousands)		2015		2014		2013
Beginning capitalized exploratory well costs		$	241,657	$	144,504	$	118,806
	Additions to exploratory well costs pending the determination of proved reserves		102,846		234,057		130,967
	Reclassifications due to determination of proved reserves		(227,746)		(99,657)		(94,114)
	Exploratory well costs charged to expense		(559)		(37,247)		(11,155)
Ending capitalized exploratory well costs		$	116,198	$	241,657	$	144,504

The following table provides an aging at December 31, 2015 and 2014 of capitalized exploratory well costs based on the date drilling was completed:

			December 31,
(dollars in thousands)			2015		2014
Capitalized exploratory well costs that have been capitalized for a period of one year or less		$	98,764	$	232,346
Capitalized exploratory well costs that have been capitalized for a period greater than one year			17,434		9,311
	Total capitalized exploratory well costs	$	116,198	$	241,657
Number of projects with exploratory well costs that have been capitalized for a period greater
	than one year		8		7

Delaware Basin projects. At December 31, 2015, the Company had approximately $7.2 million of suspended well costs greater than one year recorded for two wells that were initially drilled to monitor nearby wells and are additionally being used to determine the productivity potential of additional zones. At December 31, 2015, the Company also had approximately $5.7 million of suspended well costs greater than one year recorded for a well spud in late 2014 that is testing multiple zones and is expected to be completed in the first half of 2016. All three wells completed drilling in 2014.

Projects operated by others. At December 31, 2015, the Company had approximately $4.5 million of suspended well costs greater than one year recorded for five wells that are operated by others and waiting on completion. Two of these wells, with suspended well costs totaling approximately $3.0 million, completed drilling in 2012 and are expected to be completed in 2016. The remaining three wells completed drilling in 2014 and are waiting on completion.

F-13

Concho Resources Inc.

Notes to Consolidated Financial Statements

December 31, 2015, 2014 and 2013

Note 4. Acquisition and divestiture

Clayton Williams Acreage Exchange. In December 2015, the Company completed a nonmonetary acreage exchange with Clayton Williams Energy, Inc. that consolidated acres into a concentrated, operated position in the southern Delaware Basin. The Company recognized a loss on disposition of assets of approximately $50.0 million related to the acreage exchange based on the fair value of the assets surrendered, which is presented in loss on disposition of assets, net, in the consolidated statement of operations for the year ended December 31, 2015.

Note 5. Asset retirement obligations

The Company’s asset retirement obligations represent the estimated present value of the estimated cash flows the Company will incur to plug, abandon and remediate its producing properties at the end of their productive lives, in accordance with applicable state laws. Market risk premiums associated with asset retirement obligations are estimated to represent a component of the Company’s credit-adjusted risk-free rate that is utilized in the calculations of asset retirement obligations.

The Company’s asset retirement obligation transactions during the years ended December 31, 2015, 2014 and 2013 are summarized in the table below:

		Years Ended December 31,
(in thousands)			2015		2014		2013
Asset retirement obligations, beginning of period		$	119,881	$	101,593	$	86,261
	Liabilities incurred from new wells		4,052		5,324		6,338
	Liabilities assumed in acquisitions		2,434		4,065		593
	Accretion expense		7,600		7,072		6,047
	Liabilities settled upon plugging and abandoning wells		(2,736)		(2,926)		(3,447)
	Revision of estimates (a)		(11,286)		4,753		5,801
Asset retirement obligations, end of period		$	119,945	$	119,881	$	101,593
(a)	The downward revision to the Company’s asset retirement obligation estimates for the year ended December 31, 2015 is primarily due to a reduction in the future estimated abandonment costs.

Note 6. Incentive plans

Defined contribution plan. The Company sponsors a 401(k) defined contribution plan for the benefit of substantially all employees. During the years ended December 31, 2015, 2014 and 2013, the Company matched 100 percent of employee contributions, not to exceed 10 percent of the employee’s annual salary. The Company’s contributions to the plan for the years ended December 31, 2015, 2014 and 2013 were approximately $9.5 million, $8.1 million and $6.6 million, respectively, of which a portion was recoverable from other working interest owners.

F-14

Concho Resources Inc.

Notes to Consolidated Financial Statements

December 31, 2015, 2014 and 2013

Stock incentive plan. The Company’s 2015 Stock Incentive Plan (the “Plan”) provides for granting stock options, restricted stock awards and performance awards to directors, officers and employees of the Company. A total of 10.5 million shares of common stock have been authorized for issuance under the Plan. At December 31, 2015, the Company had 2.9 million shares of common stock available for future grant.

Restricted stock awards. All restricted shares are legally issued and outstanding. If an employee terminates employment prior to the restriction lapse date, the awarded shares are forfeited and cancelled and are no longer considered issued and outstanding. A summary of the Company’s restricted stock award activity for the year ended December 31, 2015 is presented below:

				Weighted
				Average
			Number of	Grant Date
			Restricted	Fair Value
			Shares	Per Share
Restricted stock:
	Outstanding at December 31, 2014		1,091,309		$	106.33
		Shares granted	452,436		$	109.76
		Shares cancelled / forfeited	(33,124)		$	111.08
		Lapse of restrictions	(310,974)		$	96.15
	Outstanding at December 31, 2015		1,199,647		$	110.14

F-15

Concho Resources Inc.

Notes to Consolidated Financial Statements

December 31, 2015, 2014 and 2013

For restricted stock awards granted, stock-based compensation expense is being recognized in the Company’s financial statements on an accelerated basis over the awards’ vesting periods based on their fair values on the dates of grant. The restricted stock-based compensation awards generally vest over a period ranging from one to five years. The Company utilizes the average of the grant date’s high and low stock prices for the fair value of restricted stock.

The following table summarizes information about stock-based compensation for the Company’s restricted stock awards activity under the Plan for years ended December 31, 2015, 2014 and 2013:

		Years Ended December 31,
(in thousands)			2015		2014		2013
Fair value for awards granted during the period (a)		$	49,659	$	57,940	$	44,947
Fair value for awards vested during the period		$	35,700	$	59,226	$	21,496
Stock-based compensation expense from restricted stock		$	43,185	$	36,585	$	30,984
Income tax benefit related to restricted stock		$	16,049	$	13,672	$	11,650
(a)	The weighted average grant date fair value per share amounts were $109.76, $129.12 and $88.19 for the years ended December 31, 2015, 2014 and 2013, respectively. The year ended December 31, 2013 includes the effects of $1 million due to modifications of certain stock-based awards.

Stock option awards.  A summary of the Company’s stock option award activity under the Plan for the years ended December 31, 2015, 2014 and 2013 is presented below:

			Years Ended December 31,
			2015			2014			2013
					Weighted			Weighted			Weighted
					Average			Average			Average
			Number of		Exercise	Number of		Exercise	Number of		Exercise
			Options		Price	Options		Price	Options		Price
Stock options:
	Outstanding at beginning of period		47,713	$	17.49	255,537	$	21.50	429,879	$	20.28
		Options exercised	(4,812)	$	12.00	(207,824)	$	22.42	(174,342)	$	18.48
	Outstanding at end of period		42,901	$	18.10	47,713	$	17.49	255,537	$	21.50
	Vested and exercisable at end of period		42,901	$	18.10	47,713	$	17.49	255,537	$	21.50

The intrinsic value of options exercised during 2015, 2014 and 2013 was approximately $0.4 million, $23.2 million and $13.2 million, respectively, based on the difference between the market price at the exercise date and the option exercise price.

F-16

Concho Resources Inc.

Notes to Consolidated Financial Statements

December 31, 2015, 2014 and 2013

The following table summarizes information about the Company’s vested and exercisable stock options outstanding at December 31, 2015:

December 31, 2015
			Weighted				Intrinsic
			Average		Weighted		Value
	Range of		Remaining		Average		of
	Exercise	Number	Contractual		Exercise		Options
	Prices	Vested	Life		Price		(in thousands)
Vested and exercisable options:
	$12.00 - $12.85	15,824	1.54  years	$	12.81		1,267
	$20.40 - $22.77	27,077	2.98  years	$	21.20		1,940
		42,901	2.45  years	$	18.10	$	3,207

The following table shows the deductions in current taxable income related to stock options exercised for the years ended December 31, 2015, 2014 and 2013:

		Years Ended December 31,
(in thousands)				2015		2014		2013
	Deductions in current taxable income related to stock options exercised		$	415	$	23,208	$	13,193

Performance unit awards. During the years ended December 31, 2015, 2014 and 2013, the Company awarded performance units to its officers under the Plan. The number of shares of common stock that will ultimately be issued will be determined by a combination of (i) comparing the Company’s total shareholder return relative to the total shareholder return of a predetermined group of peer companies at the end of the performance period and (ii) the Company’s absolute total shareholder return at the end of the performance period. The performance period is 36 months. The grant date fair value was determined using the Monte Carlo simulation method and is being expensed ratably over the performance period. Expected volatilities utilized in the model were estimated using a historical period consistent with the remaining performance period of approximately three years. The risk-free interest rate was based on the United States Treasury rate for a term commensurate with the expected life of the grant.

The Company used the following assumptions to estimate the fair value of performance unit awards granted during the years ended December 31, 2015, 2014 and 2013:

	Years Ended December 31,
	2015	2014	2013
Risk-free interest rate	1.07%	0.76%	0.37%
Range of volatilities	26.1% - 43.0%	29.2% - 42.2%	31.5% - 45.1%

F-17

Concho Resources Inc.

Notes to Consolidated Financial Statements

December 31, 2015, 2014 and 2013

The following table summarizes the performance unit activity for the year ended December 31, 2015:

			Number of		Grant Date
			Units		Fair Value
Performance units:
	Outstanding at December 31, 2014		250,314	$	127.07
		Units granted (a)	176,330	$	156.86
		Units vested (b)	(110,889)	$	111.40
	Outstanding at December 31, 2015		315,755	$	149.21
(a)	Reflects the amount of performance units granted. The actual payout of shares will be between zero and 300 percent of the performance units granted depending on the Company’s performance at the end of the performance period.
(b)	On December 31, 2015, the performance period ended for these performance units. Each unit converted into 1.625 shares representing 180,199 shares of common stock issued on January 4, 2016.

The following table summarizes information about stock-based compensation expense for performance units for the years ended December 31, 2015, 2014 and 2013:

	Years Ended December 31,
(in thousands)		2015		2014		2013
Fair value for awards granted during the period	$	27,659	$	19,455	$	12,352
Stock-based compensation expense from performance units	$	19,888	$	10,545	$	4,080
Income tax benefit related to performance units	$	7,391	$	3,941	$	1,560

Future stock-based compensation expense. The following table reflects the future stock-based compensation expense to be recorded for all the stock-based compensation awards that were outstanding at December 31, 2015:

			Restricted		Performance
(in thousands)			Stock		Units		Total
2016		$	31,992	$	15,734	$	47,726
2017			18,189		9,219		27,408
2018			6,466		-		6,466
2019			286		-		286
2020			4		-		4
	Total	$	56,937	$	24,953	$	81,890

F-18

Concho Resources Inc.

Notes to Consolidated Financial Statements

December 31, 2015, 2014 and 2013

Note 7. Disclosures about fair value measurements

The Company uses a valuation framework based upon inputs that market participants use in pricing an asset or liability, which are classified into two categories: observable inputs and unobservable inputs. Observable inputs represent market data obtained from independent sources, whereas unobservable inputs reflect a company’s own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. These two types of inputs are further prioritized into the following fair value input hierarchy:

Level 1:     Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. The Company considers active markets to be those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2:     Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes those derivative instruments that the Company values using observable market data. Substantially all of these inputs are observable in the marketplace throughout the full term of the derivative instrument, can be derived from observable data, or supported by observable levels at which transactions are executed in the marketplace. Level 2 instruments primarily include non-exchange traded derivatives such as over-the-counter commodity price swaps, basis swaps, collars and floors, investments and interest rate swaps. The Company’s valuation models are primarily industry-standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value, (iii) current market and contractual prices for the underlying instruments and (iv) volatility factors, as well as other relevant economic measures.

Level 3:     Measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources (i.e., supported by little or no market activity). The Company’s valuation models are primarily industry-standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value, (iii) volatility factors and (iv) current market and contractual prices for the underlying instruments, as well as other relevant economic measures.

F-19

Concho Resources Inc.

Notes to Consolidated Financial Statements

December 31, 2015, 2014 and 2013

Financial Assets and Liabilities Measured at Fair Value

The following table presents the carrying amounts and fair values of the Company’s financial instruments at December 31, 2015 and 2014:

		December 31, 2015				December 31, 2014
		Carrying		Fair		Carrying		Fair
(in thousands)		Value		Value		Value		Value
Assets:
	Derivative instruments	$	819,536	$	819,536	$	752,700	$	752,700
Liabilities:
	Credit facility	$	-	$	-	$	139,500	$	131,068
	$600 million 7.0% senior notes due 2021 (a)	$	592,414	$	595,500	$	591,213	$	625,500
	$600 million 6.5% senior notes due 2022 (a)	$	591,549	$	579,000	$	590,454	$	628,500
	$600 million 5.5% senior notes due 2022 (a)	$	592,899	$	553,500	$	592,061	$	598,500
	$1,550 million 5.5% senior notes due 2023 (a)	$	1,555,326	$	1,453,005	$	1,555,909	$	1,573,875
(a)	The carrying value includes associated deferred loan costs and any (discount) premium. See Note 2 for additional information regarding the Company’s retrospective adoption of ASU No. 2015-03.

Cash and cash equivalents, accounts receivable, other current assets, accountspayable, interest payable and other current liabilities. The carrying amounts approximate fair value due to the short maturity of these instruments.

Credit facility.  The fair value of the Company’s credit facility is estimated by discounting the principal and interest payments at the Company’s credit-adjusted discount rate at the reporting date, which utilizes inputs that are Level 2 measurements in the fair value hierarchy.

Senior notes. The fair values of the Company’s senior notes are based on quoted market prices. The debt securities are not actively traded and, therefore, are classified as Level 2 in the fair value hierarchy.

F-20

Concho Resources Inc.

Notes to Consolidated Financial Statements

December 31, 2015, 2014 and 2013

Derivative instruments. The fair value of the Company’s derivative instruments is estimated by management considering various factors, including closing exchange and over-the-counter quotations and the time value of the underlying commitments. Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. The following tables summarize (i) the valuation of each of the Company’s financial instruments by required fair value hierarchy levels and (ii) the gross fair value by the appropriate balance sheet classification,even when the derivative instruments are subject to netting arrangements and qualify for net presentation in the Company’s consolidated balance sheets at December 31, 2015 and 2014. The Company nets the fair value of derivative instruments by counterparty in the Company’s consolidated balance sheets.

December 31, 2015
				Fair Value Measurements Using												Net
				Quoted Prices										Gross		Fair Value
				in Active				Significant						Amounts		Presented
				Markets for				Other		Significant				Offset in the		in the
				Identical				Observable		Unobservable				Consolidated		Consolidated
				Assets				Inputs		Inputs		Total		Balance		Balance
(in thousands)				(Level 1)				(Level 2)		(Level 3)		Fair Value		Sheet		Sheet
	Assets
		Current:
			Commodity derivatives		$	-	$	684,029	$	-	$	684,029	$	(31,531)	$	652,498
		Noncurrent:
			Commodity derivatives			-		175,267		-		175,267		(8,229)		167,038
	Liabilities
		Current:
			Commodity derivatives			-		(31,531)		-		(31,531)		31,531		-
		Noncurrent:
			Commodity derivatives			-		(8,229)		-		(8,229)		8,229		-
	Net derivative instruments				$	-	$	819,536	$	-	$	819,536	$	-	$	819,536

F-21

Concho Resources Inc.

Notes to Consolidated Financial Statements

December 31, 2015, 2014 and 2013

December 31, 2014
				Fair Value Measurements Using												Net
				Quoted Prices										Gross		Fair Value
				in Active				Significant						Amounts		Presented
				Markets for				Other		Significant				Offset in the		in the
				Identical				Observable		Unobservable				Consolidated		Consolidated
				Assets				Inputs		Inputs		Total		Balance		Balance
(in thousands)				(Level 1)				(Level 2)		(Level 3)		Fair Value		Sheet		Sheet
	Assets
		Current:
			Commodity derivatives		$	-	$	501,717	$	-	$	501,717	$	(11,366)	$	490,351
		Noncurrent:
			Commodity derivatives			-		262,349		-		262,349		-		262,349
	Liabilities
		Current:
			Commodity derivatives			-		(11,366)		-		(11,366)		11,366		-
		Noncurrent:
			Commodity derivatives			-		-		-		-		-		-
	Net derivative instruments				$	-	$	752,700	$	-	$	752,700	$	-	$	752,700

Concentrations of credit risk. At December 31, 2015, the Company’s primary concentration of credit risks are the risk of collecting accounts receivable and the risk of counterparties’ failure to perform under derivative obligations. See Note 12 for information regarding the Company’s major customers and derivative counterparties.

The Company has entered into International Swap Dealers Association Master Agreements (“ISDA Agreements”) with each of its derivative counterparties. The terms of the ISDA Agreements provide the Company and the counterparties with rights of set-off upon the occurrence of defined acts of default by either the Company or a counterparty to a derivative, whereby the party not in default may set off all derivative liabilities owed to the defaulting party against all derivative asset receivables from the defaulting party. See Note 8 for additional information regarding the Company’s derivative activities.

F-22

Concho Resources Inc.

Notes to Consolidated Financial Statements

December 31, 2015, 2014 and 2013

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

Certain assets and liabilities are reported at fair value on a nonrecurring basis in the Company’s consolidated balance sheets. The following methods and assumptions were used to estimate the fair values: 

Impairments of long-lived assets – The Company periodically reviews their long-lived assets to be held and used, including proved oil and natural gas properties and their integrated assets, whenever events or circumstances indicate that the carrying value of those assets may not be recoverable, for instance when there are declines in commodity prices or well performance. The Company reviews its oil and natural gas properties by depletion base or by individual well for those wells not constituting part of a depletion base. An impairment loss is indicated if the sum of the expected undiscounted future net cash flows is less than the carrying amount of the assets. If the estimated undiscounted future net cash flows are less than the carrying amount of the Company’s assets, it recognizes an impairment loss for the amount by which the carrying amount of the asset exceeds the estimated fair value of the asset.

The Company calculates the expected undiscounted future net cash flows of its long-lived assets and its integrated assets using management’s assumptions and expectations of (i) commodity prices, which are based on the New York Mercantile Exchange (“NYMEX”) strip, (ii) pricing adjustments for differentials, (iii) production costs, (iv) capital expenditures, (v) production volumes, (vi) proved reserves and risk-adjusted probable and possible reserves, and (vii) other sources of income and expenses from integrated assets.

The Company calculates the estimated fair values of its long-lived assets and their integrated assets using a discounted future cash flow model. Fair value assumptions associated with the calculation of discounted future net cash flows include (i) market estimates of commodity prices, (ii) pricing adjustments for differentials, (iii) production costs, (iv) capital expenditures, (v) production volumes, (vi) estimated proved reserves and risk-adjusted probable and possible reserves, (vii) prevailing market rates of income and expenses from integrated assets and (viii) discount rate. The Company discounts the future net cash flows using a market-based weighted average cost of capital rate determined appropriate at the time. These are classified as Level 3 fair value assumptions.

As a result of the carrying amount of certain of the Company’s long-lived assets being less than their expected undiscounted future net cash flows, the Company recognized a non-cash charge against earnings for the amount by which the carrying amount exceeded the estimated fair value of the assets. The following table reports the carrying amount, estimated fair value and impairment expense of long-lived assets for the indicated periods:

				Estimated
		Carrying		Fair Value		Impairment
(in thousands)		Amount		(Level 3)		Expense
December 2015	$	104,982	$	52,041	$	52,941
September 2015	$	18,023	$	10,435	$	7,588
December 2014	$	677,021	$	245,346	$	431,675
September 2014	$	26,790	$	11,314	$	15,476
June 2013	$	84,140	$	18,765	$	65,375

It is reasonably possible that the estimate of undiscounted future net cash flows may change in the future resulting in the need to impair carrying values. The primary factors that may affect estimates of future net cash flows are (i) commodity prices, (ii) increases or decreases in production and capital costs, (iii) future reserve adjustments, both positive and negative, to proved reserves and appropriate risk-adjusted probable and possible reserves, (iv) results of future drilling activities and (v) changes in income and expenses from integrated assets.

F-23

Concho Resources Inc.

Notes to Consolidated Financial Statements

December 31, 2015, 2014 and 2013

Based on the factors above as of December 31, 2015, the Company determined that undiscounted future cash flows attributable to certain depletion groups indicated that the carrying amounts were expected to be recovered; however, they may be at risk for impairment if management’s estimates of future cash flows further decline.

Note 8. Derivative financial instruments

The Company uses derivative financial instruments to manage its exposure to commodity price fluctuations. Commodity derivative instruments are used to (i) reduce the effect of the volatility of price changes on the oil and natural gas the Company produces and sells, (ii) support the Company’s capital budget and expenditure plans and (iii) support the economics associated with acquisitions. The Company does not enter into derivative financial instruments for speculative or trading purposes. The Company may also enter into physical delivery contracts to effectively provide commodity price hedges. Because these physical delivery contracts are not expected to be net cash settled, they are considered to be normal sales contracts and not derivatives. Therefore, these contracts are not recorded in the Company’s consolidated financial statements.

The Company does not designate its derivative instruments to qualify for hedge accounting. Accordingly, the Company reflects changes in the fair value of its derivative instruments in its statements of operations as they occur.

The following table summarizes the gains (losses) reported in earnings related to the commodity derivative instruments for the years ended December 31, 2015, 2014 and 2013:

			Years Ended December 31,
(in thousands)				2015		2014		2013
Gain (loss) on derivatives:
	Oil derivatives		$	675,303	$	869,421	$	(133,890)
	Natural gas derivatives			24,449		21,496		10,238
		Total	$	699,752	$	890,917	$	(123,652)
The following table represents the Company’s cash receipts from (payments on) derivatives for the years ended December 31, 2015, 2014 and 2013:
			Years Ended December 31,
(in thousands)				2015		2014		2013
Cash receipts from (payments on) derivatives:
	Oil derivatives		$	597,297	$	76,335	$	(41,616)
	Natural gas derivatives			35,619		(4,352)		9,275
		Total	$	632,916	$	71,983	$	(32,341)

F-24

Concho Resources Inc.

Notes to Consolidated Financial Statements

December 31, 2015, 2014 and 2013

Commodity derivative contracts at December 31, 2015. The following table sets forth the Company’s outstanding derivative contracts at December 31, 2015. When aggregating multiple contracts, the weighted average contract price is disclosed. All of the Company’s derivative contracts at December 31, 2015 are expected to settle by December 31, 2017.

				First		Second		Third		Fourth
				Quarter		Quarter		Quarter		Quarter		Total
Oil Swaps: (a)
	2016:
		Volume (Bbl)		6,722,000		5,985,000		5,460,000		5,054,000		23,221,000
		Price per Bbl	$	71.99	$	73.38	$	74.21	$	59.38	$	70.13
	2017:
		Volume (Bbl)		4,354,000		4,118,000		2,655,000		2,655,000		13,782,000
		Price per Bbl	$	61.59	$	62.03	$	55.23	$	55.23	$	59.27
Oil Basis Swaps: (b)
	2016:
		Volume (Bbl)		6,035,000		5,732,000		5,520,000		5,060,000		22,347,000
		Price per Bbl	$	(1.49)	$	(1.50)	$	(1.46)	$	(1.48)	$	(1.48)
	2017:
		Volume (Bbl)		3,780,000		3,822,000		1,012,000		1,012,000		9,626,000
		Price per Bbl	$	(1.32)	$	(1.32)	$	(0.54)	$	(0.54)	$	(1.16)
Natural Gas Swaps: (c)
	2016:
		Volume (MMBtu)		7,280,000		7,280,000		7,360,000		7,360,000		29,280,000
		Price per MMBtu	$	3.02	$	3.02	$	3.02	$	3.02	$	3.02
(a) The index prices for the oil price swaps are based on the NYMEX – West Texas Intermediate (“WTI”) monthly average futures price.
(b) The basis differential price is between Midland – WTI and Cushing – WTI.
(c) The index prices for the natural gas price swaps are based on the NYMEX – Henry Hub last trading day futures price.

F-25

Concho Resources Inc.

Notes to Consolidated Financial Statements

December 31, 2015, 2014 and 2013

Derivative counterparties.  The Company uses credit and other financial criteria to evaluate the creditworthiness of counterparties to its derivative instruments. The Company believes that all of its derivative counterparties are currently acceptable credit risks. Other than provided by the Company’s revolving credit facility, the Company is not required to provide credit support or collateral to any counterparties under its derivative contracts, nor are they required to provide credit support to the Company. See additional information in Note 12.

Note 9. Debt 

The Company’s debt consisted of the following at December 31, 2015 and 2014:

				December 31,
(in thousands)				2015		2014
Credit facility			$	-	$	139,500
7.0% unsecured senior notes due 2021				600,000		600,000
6.5% unsecured senior notes due 2022				600,000		600,000
5.5% unsecured senior notes due 2022				600,000		600,000
5.5% unsecured senior notes due 2023				1,550,000		1,550,000
Unamortized original issue premium				25,073		27,820
Deferred loan costs, net				(42,885)		(48,183)
	Less: current portion			-		-
		Total long-term debt	$	3,332,188	$	3,469,137

Credit facility. The Company’s credit facility, as amended and restated (the “Credit Facility”), has a maturity date of May 9, 2019. In April 2015, the Company amended its credit agreement to remove the current ratio financial covenant. The Company’s borrowing base is $3.25 billion until the next scheduled borrowing base redetermination in May 2016. At December 31, 2015, commitments from the Company’s bank group totaled $2.5 billion. Between scheduled borrowing base redeterminations, the Company and the lenders (requiring a 66 2/3 percent vote), may each request one special redetermination.

Advances on the Credit Facility bear interest, at the Company’s option, based on (i) the prime rate of JPMorgan Chase Bank (“JPM Prime Rate”) (3.50 percent at December 31, 2015) or (ii) a Eurodollar rate (substantially equal to the LIBOR). At December 31, 2015, the interest rates of Eurodollar rate advances and JPM Prime Rate advances varied, with interest margins ranging from 125 to 225 basis points and 25 to 125 basis points per annum, respectively, depending on the balance outstanding on the Credit Facility. During the years ended December 31, 2015, 2014 and 2013, the Company incurred commitment fees on the unused portion of the available commitments of $7.0 million, $7.7 million and $8.3 million, respectively. Under the current Credit Facility, commitment fees range from 30 to 37.5 basis points per annum. The Company had approximately $2.5 billion of unused commitments under its credit facility at December 31, 2015.

The Company’s obligations under the Credit Facility are secured by a first lien on substantially all of its oil and natural gas properties. At December 31, 2015, all of the Company’s subsidiaries are guarantors and have had their equity pledged to secure borrowings under the Credit Facility.

The Credit Facility contains various restrictive covenants and compliance requirements which include:

·maintenance of a quarterly ratio of total debt to consolidated earnings before interest expense, income taxes, depletion, depreciation, and amortization, exploration expense and other noncash income and expenses to be no greater than 4.25 to 1.0;

·limits on the incurrence of certain indebtedness and certain types of liens;

F-26

Concho Resources Inc.

Notes to Consolidated Financial Statements

December 31, 2015, 2014 and 2013

·restrictions as to mergers, combinations and dispositions of assets; and

·limits on the payment of cash dividends.

The Company recorded a loss on extinguishment of debt related to the Credit Facility of approximately $4.3 million for the year ended December 31, 2014. This amount includes the proportional amount of unamortized deferred loan costs associated with banks with lesser commitments in the amended credit facility syndicate.

Senior notes. Interest on the Company’s senior notes is paid in arrears semi-annually. The senior notes are fully and unconditionally guaranteed on a senior unsecured basis by all subsidiaries of the Company, subject to customary release provisions as described in Note 16.

On June 3, 2013, the Company received tenders and consents from the holders of approximately $225.6 million in aggregate principal amount, or approximately 75.2 percent, of its outstanding 8.625% senior notes due 2017 (the “8.625% Notes”) in connection with a cash tender offer for any and all of the 8.625% Notes at a price of 106.922 percent of the unpaid principal amount.

On June 21, 2013, the Company redeemed the remaining outstanding 8.625% Notes not purchased in the tender offer at a redemption price of 106.516 percent of the unpaid principal amount plus accrued and unpaid interest through June 20, 2013.

The Company recorded a loss on extinguishment of debt related to the tender offer and redemption of its 8.625% Notes of approximately $28.6 million for the year ended December 31, 2013. This amount includes approximately $20.4 million associated with the premium paid for the tender offer and redemption of the notes, approximately $5.5 million of unamortized deferred loan costs and approximately $2.7 million of unamortized discount.

On June 4, 2013, the Company completed the issuance of an additional $850 million in principal amount of its 5.5% senior notes due 2023 (the “Offering”) at 103.75 percent of par (resulting in a 4.884% yield) for net proceeds of approximately $867.8 million. The Company used a portion of the net proceeds from the Offering to fund the tender offer and redemption of the 8.625% Notes and to pay down amounts outstanding on the Credit Facility.

At December 31, 2015, the Company was in compliance with the covenants under all of its debt instruments.

Principal maturities of long-term debt.Principal maturities of long-term debt outstanding at December 31, 2015 were as follows:

(in thousands)
2016		$	-
2017			-
2018			-
2019			-
2020			-
Thereafter			3,350,000
	Total	$	3,350,000

F-27

Concho Resources Inc.

Notes to Consolidated Financial Statements

December 31, 2015, 2014 and 2013

Interest expense.  The following amounts have been incurred and charged to interest expense for the years ended December 31, 2015, 2014 and 2013:

		Years Ended December 31,
(in thousands)			2015		2014		2013
Cash payments for interest		$	211,443	$	211,342	$	200,961
Amortization of original issue discount (premium)			(2,747)		(2,599)		(1,248)
Amortization of deferred loan origination costs			9,971		10,937		13,172
Accretion expense			1,795		-		-
Net changes in accruals			(165)		(737)		5,696
	Interest costs incurred		220,297		218,943		218,581
Less: capitalized interest			(4,913)		(2,282)		-
	Total interest expense	$	215,384	$	216,661	$	218,581

Note 10. Commitments and contingencies

Severance agreements.The Company has entered into severance and change in control agreements with all of its officers. The current annual salaries for the Company’s officers covered under such agreements total approximately $8.5 million.

Indemnifications.  The Company has agreed to indemnify its directors and officers with respect to claims and damages arising from certain acts or omissions taken in such capacity.

Legal actions.  The Company is a party to proceedings and claims incidental to its business. While many of these matters involve inherent uncertainty, the Company believes that the amount of the liability, if any, ultimately incurred with respect to any such proceedings or claims will not have a material adverse effect on the Company’s consolidated financial position as a whole or on its liquidity, capital resources or future results of operations. The Company will continue to evaluate proceedings and claims involving the Company on a regular basis and will establish and adjust any reserves as appropriate to reflect its assessment of the then current status of the matters.

Severance tax, royalty and joint interest audits.  The Company is subject to routine severance, royalty and joint interest audits from regulatory bodies and non-operators and makes accruals as necessary for estimated exposure when deemed probable and estimable. Additionally, the Company is subject to various possible contingencies that arise primarily from interpretations affecting the oil and natural gas industry. Such contingencies include differing interpretations as to the prices at which oil and natural gas sales may be made, the prices at which royalty owners may be paid for production from their leases, allowable costs under joint interest arrangements and other matters. At December 31, 2015 and 2014, the Company had $13.4 million and $12.3 million, respectively, accrued for estimated exposure. Although the Company believes that it has estimated its exposure with respect to the various laws and regulations, administrative rulings and interpretations thereof, adjustments could be required as new interpretations and regulations are issued. 

F-28

Concho Resources Inc.

Notes to Consolidated Financial Statements

December 31, 2015, 2014 and 2013

Commitments. The Company periodically enters into contractual arrangements under which the Company is committed to expend funds. These contractual arrangements relate to purchase agreements the Company has entered into including daywork drilling contracts, water commitment agreements, throughput volume delivery commitments, power commitments and maintenance commitments. The following table summarizes the Company’s commitments at December 31, 2015:

(in thousands)
2016		$	51,710
2017			21,256
2018			21,148
2019			13,196
2020			7,335
Thereafter			45,451
	Total	$	160,096

Operating leases. The Company leases vehicles, equipment and office facilities under non-cancellable operating leases. Lease payments associated with these operating leases for the years ended December 31, 2015, 2014 and 2013 were approximately $8.0 million, $7.2 million and $5.7 million, respectively.

Future minimum lease commitments under non-cancellable operating leases at December 31, 2015 were as follows:

(in thousands)
2016		$	7,941
2017			7,877
2018			7,087
2019			5,651
2020			4,738
Thereafter			5,091
	Total	$	38,385

Note 11. Income taxes

The Company uses an asset and liability approach for financial accounting and reporting for income taxes. The Company’s objectives of accounting for income taxes are to recognize (i) the amount of taxes payable or refundable for the current year and (ii) deferred tax liabilities and assets for the future tax consequences of events that have been recognized in its financial statements or tax returns. The Company and its subsidiaries file a federal corporate income tax return on a consolidated basis. The tax returns and the amount of taxable income or loss are subject to examination by federal and state taxing authorities. At December 31, 2015 the Company had current income taxes receivable of approximately $37.3 million and current income taxes payable of approximately $1.0 million. At December 31, 2014 the Company had current income taxes receivable of approximately $32.9 million and current income taxes payable of approximately $1.1 million.

The Company continually assesses both positive and negative evidence to determine whether it is more likely than not that deferred tax assets can be realized prior to their expiration. Management monitors company-specific, oil and natural gas industry and worldwide economic factors and assesses the likelihood that the Company’s net operating loss carryforwards (“NOLs”), if any, and other deferred tax attributes in the United States, state, and local tax jurisdictions will be utilized prior to their expiration. At December 31, 2015 and 2014, the Company had no valuation allowances related to its deferred tax assets.

F-29

Concho Resources Inc.

Notes to Consolidated Financial Statements

December 31, 2015, 2014 and 2013

At December 31, 2015, the Company did not have any significant uncertain tax positions requiring recognition in the financial statements. The tax years 2012 through 2015 remain subject to examination by the major tax jurisdictions.

Income tax provision.  The Company’s income tax provision and amounts separately allocated were attributable to the following items for the years ended December 31, 2015, 2014 and 2013:

		Years Ended December 31,
(in thousands)			2015		2014		2013
Income from continuing operations		$	31,371	$	317,785	$	118,237
Income from discontinued operations			-		-		7,518
Changes in stockholders’ equity:
	Excess tax benefits related to stock-based compensation		(2,150)		(16,480)		(6,147)
		$	29,221	$	301,305	$	119,608

The Company’s income tax provision attributable to income from continuing operations consisted of the following for the years ended December 31, 2015, 2014 and 2013:

					Years Ended December 31,
(in thousands)						2015		2014		2013
Current:
	U.S. federal				$	127	$	16,621	$	12,504
	U.S. state and local					1,622		4,997		3,306
		Total current income tax provision				1,749		21,618		15,810
Deferred:
	U.S. federal					40,364		278,615		119,985
	U.S. state and local					(10,742)		17,552		(17,558)
		Total deferred income tax provision				29,622		296,167		102,427
			Total income tax provision attributable to income from
				continuing operations	$	31,371	$	317,785	$	118,237

F-30

Concho Resources Inc.

Notes to Consolidated Financial Statements

December 31, 2015, 2014 and 2013

The reconciliation between the income tax expense computed by multiplying pre-tax income from continuing operations by the United States federal statutory rate and the reported amounts of income tax expense from continuing operations is as follows:

		Years Ended December 31,
(in thousands)			2015		2014		2013
Income at U.S. federal statutory rate		$	34,045	$	299,586	$	125,006
State income taxes (net of federal tax effect)			3,071		22,826		12,505
Revisions of previous estimates			(631)		738		1,400
Change in estimated effective statutory state income tax			(9,026)		(7,945)		(21,876)
Nondeductible expense & other			3,912		2,580		1,202
	Income tax expense	$	31,371	$	317,785	$	118,237
Effective tax rate			32.3%		37.1%		33.1%

The Company monitors changes in enacted tax rates for the jurisdictions in which it operates. The Company monitors its state tax apportionment footprint and makes updates for changes in its projected activity, including changes in budgets and drilling plans. During 2013, the state of New Mexico passed legislation to phase in a tax rate reduction over the next five years. In June of 2015, the State of Texas enacted legislation to reduce its rate. Based upon the Company’s projected future activity for the states in which it conducts business, the timing for when it anticipates its deferred tax items to become taxable and enacted tax rates at such time deferred items become taxable, the Company has revised its estimated state rate and recorded an additional deferred tax benefit of $9.0 million, $7.9 million and $21.9 million during 2015, 2014 and 2013, respectively.

The Company’s effective tax rate decreased in 2015 as compared to 2014. The primary reason for the decrease is lower income, which caused a more pronounced impact for each reconciling item, as compared with 2014. In particular, the reduction in our blended state rate caused a 9.3% reduction, partially offset by other reconciling and non-deductible items for a net rate reduction of 4.8% over 2014.

The Company’s income tax provision attributable to income from discontinued operations consisted of the following for the year ended December 31, 2013:

				Year Ended
(in thousands)				December 31, 2013
Current:
	U.S. federal			$	144
	U.S. state and local				25
		Total current income tax provision			169
Deferred:
	U.S. federal				6,397
	U.S. state and local				952
		Total deferred income tax provision			7,349
			Total income tax provision attributable to income from discontinued operations	$	7,518

F-31

Concho Resources Inc.

Notes to Consolidated Financial Statements

December 31, 2015, 2014 and 2013

The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities were as follows:

				December 31,
(in thousands)				2015			2014
Deferred tax assets:
	Stock-based compensation			$	36,738	$	24,810
	Asset retirement obligation				44,573		44,802
	Other				29,574		28,925
			Total deferred tax assets		110,885		98,537
Deferred tax liabilities:
	Oil and natural gas properties, principally due to differences in basis and
		depreciation and the deduction of intangible drilling costs for tax purposes			(1,420,275)		(1,401,313)
	Intangible assets - operating rights				(9,548)		(10,148)
	Derivative instruments				(304,550)		(281,303)
	Other				(6,885)		(6,524)
			Total deferred tax liability		(1,741,258)		(1,699,288)
			Net deferred tax liability	$	(1,630,373)	$	(1,600,751)

Note 12. Major customers and derivative counterparties

Sales to major customers. The Company’s share of oil and natural gas production is sold to various purchasers. The Company is of the opinion that the loss of any one purchaser would not have a material adverse effect on the ability of the Company to sell its oil and natural gas production.

The following purchasers individually accounted for 10 percent or more of the consolidated oil and natural gas revenues during the years ended December 31, 2015, 2014 and 2013:

	Years Ended December 31,
	2015	2014	2013
Holly Frontier Refining and Marketing, LLC	25%	17%	30%
Enterprise Crude Oil LLC	12%	12%	13%
Plains Marketing and Transportation, Inc.	11%	6%	4%
Western Refining Company LP	5%	12%	1%

At December 31, 2015, the Company had receivables from Holly Frontier Refining and Marketing, LLC, Enterprise Crude Oil LLC, Plains Marketing & Transportation Inc. and Western Refining Company LP of $31.7 million, $10.4 million $11.6 million and $3.9 million, respectively, which are reflected in accounts receivable — oil and natural gasin the accompanying consolidated balance sheets.

Derivative counterparties. The Company uses credit and other financial criteria to evaluate the creditworthiness of counterparties to its derivative instruments. The Company’s Credit Facility requires that the senior unsecured debt ratings of the Company’s derivative counterparties be (i) not less than either A- by Standard & Poor’s Rating Group rating system or A3 by Moody’s Investors Service, Inc. rating system or (ii) a lender or related affiliate under the Company’s Credit Facility. At December 31, 2015 and 2014, the counterparties with whom the Company had outstanding derivative contracts met or exceeded these criteria. Although the Company does not obtain collateral or otherwise secure the fair value of its derivative instruments, management believes the associated credit risk is mitigated by the Company’s credit risk policies and

F-32

Concho Resources Inc.

Notes to Consolidated Financial Statements

December 31, 2015, 2014 and 2013

procedures and by the criteria of the Company’s Credit Facility.

At December 31, 2015, the Company had a net asset position of $819.5 million as a result of outstanding derivative contracts which are reflected in the accompanying consolidated balance sheets. The Company assessed this balance for concentration risk and noted balances of approximately $121.8  million, $100.5  million, $90.3  million and $74.7  million with Barclays Bank PLC,J.P. Morgan Chase Bank, Wells Fargo Bank, N.A. and KeyBank National Association, respectively.

Note 13. Related party transactions

The following table summarizes charges incurred with and payments made to related parties and reported in the Company’s consolidated statements of operations for the periods presented:

	Years Ended December 31,
(in thousands)		2015		2014		2013
Amounts paid to a partnership in which a director has an ownership interest (a)	$	5,745	$	15,181	$	7,255
Amounts paid to a director and certain officers of the Company (b)	$	593	$	383	$	43
Amounts paid under consulting agreement with Steven L. Beal (c)	$	-	$	-	$	865
Amounts received from a director and certain officers of the Company (d)	$	237	$	169	$	84

(a)   Amounts include royalties on certain properties and lease bonus payments paid to a partnership in which a director of the Company is the general partner and owns a 3.5 percent partnership interest.

(b)   Amounts include revenue interests, overriding royalty interests and net profits interests in properties owned by the Company made to a director and certain officers (or affiliated entities). Amounts also include payments for an acreage acquisition and lease bonuses to an affiliated entity of an officer.

(c)   On June 30, 2009, Steven L. Beal, the Company’s then-president and chief operating officer, retired from such positions. On June 9, 2009, the Company entered into a consulting agreement (the “Consulting Agreement”) with Mr. Beal, under which Mr. Beal began serving as a consultant to the Company on July 1, 2009. During the term of the consulting relationship, Mr. Beal received a consulting fee of $20,000 per month and a monthly reimbursement for his medical and dental coverage costs. In August 2013, the Company and Mr. Beal mutually terminated the Consulting Agreement in exchange for the payment to Mr. Beal of $720,000, which termination and payment were approved by the disinterested members of the Company’s Board of Directors.

(d)   Amounts include payments to the Company as a result of activity on oil and natural gas properties in which a director and certain officers (or affiliated entities) have an interest.

____________________________________________________________________________________________________

At December 31, 2014, the Company had a $76,000 receivable from an officer (or affiliated entities) related to certain properties it operates.

In June 2013, in connection with the tender offer for the 8.625% Notes, certain directors and officers received an aggregate amount of approximately $1.3 million for the 8.625% Notes they owned. The tender offer was approved by the disinterested members of the Company’s Board of Directors.

F-33

Concho Resources Inc.

Notes to Consolidated Financial Statements

December 31, 2015, 2014 and 2013

Note 14. Net income per share

The Company uses the two-class method of calculating net income per share because certain of the Company’s unvested share-based awards qualify as participating securities. Participating securities participate in income proportionate to the weighted average number of outstanding common shares, but are not assumed to participate in the Company’s net losses because they are not contractually obligated to do so. Accordingly, allocations of earnings to participating securities are included in the Company’s calculations of basic and diluted earnings per share from continuing operations, discontinued operations and net income attributable to common stockholders.

The following tables reconcile the Company’s income from continuing operations, income from discontinued operations and net income attributable to common stockholders to the basic and diluted earnings used to determine the Company’s income per share amounts for the years ended December 31, 2015, 2014 and 2013, respectively, under the two-class method:

		Years Ended December 31,
(in thousands, except per share amounts)		2015		2014
Income as reported		$	65,900	$	538,175
Participating basic earnings			(635)		(5,961)
	Basic income attributable to common stockholders		65,265		532,214
Reallocation of participating earnings			2		16
	Diluted income attributable to common stockholders	$	65,267	$	532,230
Income per common share:
	Basic	$	0.54	$	4.89
	Diluted	$	0.54	$	4.88

			Year Ended
			December 31, 2013
		Continuing		Discontinued
(in thousands, except per share amounts)		Operations		Operations		Total
Income as reported		$	238,922	$	12,081	$	251,003
Participating basic earnings			(2,610)		(132)		(2,742)
	Basic income attributable to common stockholders		236,312		11,949		248,261
Reallocation of participating earnings			4		-		4
	Diluted income attributable to common stockholders	$	236,316	$	11,949	$	248,265
Income per common share:
	Basic	$	2.28	$	0.11	$	2.39
	Diluted	$	2.28	$	0.11	$	2.39

F-34

Concho Resources Inc.

Notes to Consolidated Financial Statements

December 31, 2015, 2014 and 2013

The following table is a reconciliation of the basic weighted average common shares outstanding to diluted weighted average common shares outstanding for the years ended December 31, 2015, 2014 and 2013:

		Years Ended December 31,
(in thousands)		2015	2014	2013
Weighted average common shares outstanding:
	Basic	119,926	108,844	103,744
	Dilutive common stock options	25	83	165
	Dilutive performance units	422	205	4
	Diluted	120,373	109,132	103,913

The following table is a summary of the performance units, which were not included in the computation of diluted net income per share, as inclusion of these items would be antidilutive:

		Years Ended December 31,
(in thousands)		2015	2014	2013
Number of antidilutive common shares:
	Antidilutive performance units	-	-	83

Note 15. Other current liabilities

The following table provides the components of the Company’s other current liabilities at December 31, 2015 and 2014:

				December 31,
(in thousands)				2015		2014
Other current liabilities:
	Accrued production costs		$	70,876	$	70,786
	Payroll related matters			29,411		34,349
	Accrued interest			68,925		69,264
	Asset retirement obligations			8,626		9,146
	Other			7,072		11,763
		Other current liabilities	$	184,910	$	195,308

F-35

Concho Resources Inc.

Notes to Consolidated Financial Statements

December 31, 2015, 2014 and 2013

Note 16.  Subsidiary guarantors

All of the Company’s 100 percent owned subsidiaries have fully and unconditionally guaranteed the Company’s senior notes. The indentures governing the Company’s senior notes provide that the guarantees of its subsidiary guarantors will be releasedin certain customary circumstances including (i) in connection with any sale, exchange or other disposition, whether by merger, consolidation or otherwise, of the capital stock of that guarantor to a person that is not the Company or a restricted subsidiary of the Company, such that, after giving effect to such transaction, such guarantor would no longer constitute a subsidiary of the Company, (ii) in connection with any sale, exchange or other disposition (other than a lease) of all or substantially all of the assets of that guarantor to a person that is not the Company or a restricted subsidiary of the Company, (iii) upon the merger of a guarantor into the Company or any other guarantor or the liquidation or dissolution of a guarantor, (iv) if the Company designates any restricted subsidiary that is a guarantor to be an unrestricted subsidiary in accordance with the indenture, (v) upon legal defeasance or satisfaction and discharge of the indenture and (vi) upon written notice of such release or discharge by the Company to the trustee following the release or discharge of all guarantees by such guarantor of any indebtedness that resulted in the creation of such guarantee, except a discharge or release by or as a result of payment under such guarantee.

See Note 9 for a summary of the Company’s senior notes. In accordance with practices accepted by the United States Securities and Exchange Commission (“SEC”), the Company has prepared condensed consolidating financial statements in order to quantify the assets, results of operations and cash flows of such subsidiaries as subsidiary guarantors.

The following condensed consolidating balance sheets at December 31, 2015 and 2014, condensed consolidating statements of operations and condensed consolidating statements of cash flows for the years ended December 31, 2015, 2014 and 2013, present financial information for Concho Resources Inc. as the parent on a stand-alone basis (carrying any investments in subsidiaries under the equity method), financial information for the subsidiary guarantors on a stand-alone basis and the consolidation and elimination entries necessary to arrive at the information for the Company on a consolidated basis. All current and deferred income taxes are recorded on Concho Resources Inc., as the subsidiaries are flow-through entities for income tax purposes. The subsidiary guarantors are not restricted from making distributions to the Company.

F-36

Concho Resources Inc.

Notes to Consolidated Financial Statements

December 31, 2015, 2014 and 2013

Condensed Consolidating Balance Sheet
December 31, 2015
			Parent		Subsidiary		Consolidating
(in thousands)			Issuer		Guarantors		Entries		Total
ASSETS
Accounts receivable - related parties		$	8,502,099	$	1,162,297	$	(9,664,396)	$	-
Other current assets			753,716		560,834		-		1,314,550
Oil and natural gas properties, net			-		10,798,497		-		10,798,497
Property and equipment, net			-		178,450		-		178,450
Investment in subsidiaries			3,698,485		-		(3,698,485)		-
Other long-term assets			182,623		167,756		-		350,379
	Total assets	$	13,136,923	$	12,867,834	$	(13,362,881)	$	12,641,876
LIABILITIES AND EQUITY
Accounts payable - related parties		$	1,162,297	$	8,502,099	$	(9,664,396)	$	-
Other current liabilities			69,514		526,906		-		596,420
Long-term debt			3,332,188		-		-		3,332,188
Other long-term liabilities			1,630,373		140,344		-		1,770,717
Equity			6,942,551		3,698,485		(3,698,485)		6,942,551
	Total liabilities and equity	$	13,136,923	$	12,867,834	$	(13,362,881)	$	12,641,876

Condensed Consolidating Balance Sheet
December 31, 2014
			Parent		Subsidiary		Consolidating
(in thousands)			Issuer		Guarantors		Entries		Total
ASSETS
Accounts receivable - related parties		$	6,670,744	$	1,201,950	$	(7,872,694)	$	-
Other current assets			569,545		618,851		-		1,188,396
Oil and natural gas properties, net			-		10,076,878		-		10,076,878
Property and equipment, net			-		129,136		-		129,136
Investment in subsidiaries			4,085,045		-		(4,085,045)		-
Other long-term assets			282,609		74,761		-		357,370
	Total assets	$	11,607,943	$	12,101,576	$	(11,957,739)	$	11,751,780
LIABILITIES AND EQUITY
Accounts payable - related parties		$	1,201,950	$	6,670,744	$	(7,872,694)	$	-
Other current liabilities			55,318		1,209,309		-		1,264,627
Long-term debt			3,469,137		-		-		3,469,137
Other long-term liabilities			1,600,750		136,478		-		1,737,228
Equity			5,280,788		4,085,045		(4,085,045)		5,280,788
	Total liabilities and equity	$	11,607,943	$	12,101,576	$	(11,957,739)	$	11,751,780

F-37

Concho Resources Inc.

Notes to Consolidated Financial Statements

December 31, 2015, 2014 and 2013

Condensed Consolidating Statement of Operations
For the Year Ended December 31, 2015
			Parent		Subsidiary		Consolidating
(in thousands)			Issuer		Guarantors		Entries		Total
Total operating revenues		$	-	$	1,803,573	$	-	$	1,803,573
Total operating costs and expenses			697,247		(2,119,817)		-		(1,422,570)
	Income (loss) from operations		697,247		(316,244)		-		381,003
Interest expense			(213,416)		(1,968)		-		(215,384)
Other, net			(386,560)		(68,348)		386,560		(68,348)
	Income (loss) before income taxes		97,271		(386,560)		386,560		97,271
Income tax expense			(31,371)		-		-		(31,371)
	Net income (loss)	$	65,900	$	(386,560)	$	386,560	$	65,900

Condensed Consolidating Statement of Operations
For the Year Ended December 31, 2014
		Parent		Subsidiary		Consolidating
(in thousands)		Issuer		Guarantors		Entries		Total
Total operating revenues		$	-	$	2,660,147	$	-	$	2,660,147
Total operating costs and expenses			888,632		(2,459,034)		-		(1,570,402)
	Income from operations		888,632		201,113		-		1,089,745
Interest expense			(216,661)		-		-		(216,661)
Loss on extinguishment of debt			(4,316)		-		-		(4,316)
Other, net			188,305		(12,809)		(188,304)		(12,808)
	Income before income taxes		855,960		188,304		(188,304)		855,960
Income tax expense			(317,785)		-		-		(317,785)
	Net income	$	538,175	$	188,304	$	(188,304)	$	538,175

Condensed Consolidating Statement of Operations
For the Year Ended December 31, 2013
			Parent		Subsidiary		Consolidating
(in thousands)			Issuer		Guarantors		Entries		Total
Total operating revenues		$	-	$	2,319,919	$	-	$	2,319,919
Total operating costs and expenses			(125,924)		(1,576,558)		-		(1,702,482)
	Income (loss) from operations		(125,924)		743,361		-		617,437
Interest expense			(218,581)		-		-		(218,581)
Loss on extinguishment of debt			(28,616)		-		-		(28,616)
Other, net			749,878		(13,136)		(749,823)		(13,081)
	Income before income taxes		376,757		730,225		(749,823)		357,159
Income tax expense			(118,237)		-		-		(118,237)
	Income from continuing operations		258,520		730,225		(749,823)		238,922
Income (loss) from discontinued operations, net of tax			(7,517)		19,598		-		12,081
	Net income	$	251,003	$	749,823	$	(749,823)	$	251,003

F-38

Concho Resources Inc.

Notes to Consolidated Financial Statements

December 31, 2015, 2014 and 2013

Condensed Consolidating Statement of Cash Flows
For the Year Ended December 31, 2015
			Parent Issuer		Subsidiary Guarantors		Consolidating Entries
(in thousands)									Total
Net cash flows provided by (used in) operating activities		$	(2,026,206)	$	2,923,711	$	-	$	897,505
Net cash flows provided by (used in) investing activities			632,916		(2,602,641)		-		(1,969,725)
Net cash flows provided by (used in) financing activities			1,393,290		(92,541)		-		1,300,749
	Net increase in cash and cash equivalents		-		228,529		-		228,529
	Cash and cash equivalents at beginning of period		-		21		-		21
	Cash and cash equivalents at end of period	$	-	$	228,550	$	-	$	228,550

Condensed Consolidating Statement of Cash Flows
For the Year Ended December 31, 2014
			Parent		Subsidiary		Consolidating
(in thousands)			Issuer		Guarantors		Entries		Total
Net cash flows provided by (used in) operating activities		$	(888,369)	$	2,562,156	$	-	$	1,673,787
Net cash flows provided by (used in) investing activities			71,983		(2,617,979)		-		(2,545,996)
Net cash flows provided by financing activities			816,386		55,823		-		872,209
	Net increase (decrease) in cash and cash equivalents		-		-		-		-
	Cash and cash equivalents at beginning of period		-		21		-		21
	Cash and cash equivalents at end of period	$	-	$	21	$	-	$	21

Condensed Consolidating Statement of Cash Flows
For the Year Ended December 31, 2013
			Parent		Subsidiary		Consolidating
(in thousands)			Issuer		Guarantors		Entries		Total
Net cash flows provided by (used in) operating activities		$	(487,131)	$	1,849,151	$	-	$	1,362,020
Net cash flows used in investing activities			(32,341)		(1,864,453)		-		(1,896,794)
Net cash flows provided by financing activities			519,472		12,443		-		531,915
	Net decrease in cash and cash equivalents		-		(2,859)		-		(2,859)
	Cash and cash equivalents at beginning of period		-		2,880		-		2,880
	Cash and cash equivalents at end of period	$	-	$	21	$	-	$	21

F-39

Concho Resources Inc.

Notes to Consolidated Financial Statements

December 31, 2015, 2014 and 2013

Note 17.  Subsequent events

Asset acquisition. In January 2016, the Company entered into an asset purchase agreement to acquire 80 percent of the seller’s interest in certain oil and natural gas properties and related assets in the southern Delaware Basin. As consideration for the acquisition, the Company agreed to issue to the seller approximately 2.2 million shares of common stock, $150.0 million in cash and $40.0 million to carry a portion of the seller’s future development costs in these properties. The acquisition is expected to close during the first quarter of 2016, subject to customary closing conditions.

Asset divestiture. In January 2016, the Company entered into an agreement to sell certain assets in the northern Delaware Basin for cash proceeds of approximately $290.0 million. The sale is expected to close during the first quarter of 2016, subject to customary closing conditions.

New commodity derivative contracts.After December 31, 2015, the Company entered into the following additional oil price swaps and oil basis swaps to hedge additional amounts of the Company’s estimated future production:

				First		Second		Third		Fourth
				Quarter		Quarter		Quarter		Quarter		Total
Oil Swaps: (a)
	2017:
		Volume (Bbl)		180,000		180,000		750,000		750,000		1,860,000
		Price per Bbl	$	42.55	$	42.55	$	43.63	$	43.63	$	43.42
Oil Basis Swaps: (b)
	2016:
		Volume (Bbl)		120,000		182,000		-		-		302,000
		Price per Bbl	$	(0.25)	$	(0.25)	$	-	$	-	$	(0.25)
	2017:
		Volume (Bbl)		360,000		242,000		2,024,000		2,024,000		4,650,000
		Price per Bbl	$	(0.41)	$	(0.38)	$	(0.38)	$	(0.38)	$	(0.38)
(a)		The index prices for the oil price swaps are based on the NYMEX – WTI monthly average futures price.
(b)		The basis differential price is between Midland – WTI and Cushing – WTI.

F-40

Concho Resources Inc.

Unaudited Supplementary Data

December 31, 2015, 2014 and 2013

Capitalized costs

			December 31,
(in thousands)			2015		2014
Oil and natural gas properties:
	Proved		$	14,940,259	$	12,795,970
	Unproved			906,048		1,071,861
	Less: accumulated depletion			(5,047,810)		(3,790,953)
		Net capitalized costs for oil and natural gas properties	$	10,798,497	$	10,076,878

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

			Years Ended December 31,
(in thousands)			2015		2014		2013
Property acquisition costs:
	Proved		$	57,190	$	99,362	$	11,499
	Unproved			206,214		292,363		85,538
Exploration				1,122,587		1,615,238		1,029,793
Development				709,088		937,491		738,430
	Total costs incurred for oil and natural gas properties		$	2,095,079	$	2,944,454	$	1,865,260
(a)	The costs incurred for oil and natural gas producing activities includes the following amounts of asset retirement obligations:
			Years Ended December 31,
	(in thousands)		2015		2014		2013
	Exploration costs		$	1,820	$	2,589	$	2,672
	Development costs			(9,084)		7,488		9,467
		Total asset retirement obligations (b)	$	(7,264)	$	10,077	$	12,139
	(b)	The downward revision to the Company’s asset retirement estimates for the year ended December 31, 2015 is primarily due to a reduction in the future estimated abandonment costs.

F-41

Concho Resources Inc.

Unaudited Supplementary Data

December 31, 2015, 2014 and 2013

Reserve Quantity Information

The following information represents estimates of the Company’s proved reserves as of December 31, 2015. The pricing that was used for estimates of the Company’s reserves as of December 31, 2015 was based on the SEC pricing of $46.79per Bbl West Texas Intermediate posted oil price and $2.59per MMBtu Henry Hub spot natural gas price. See table below.

Subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years of the date of booking. This rule limited, and may continue to limit, the Company’s potential to record additional proved undeveloped reserves as it pursues its drilling program, particularly as it develops its significant acreage in the Permian Basin of Southeast New Mexico and West Texas. Moreover, the Company may be required to write down its proved undeveloped reserves if it does not drill on those reserves with the required five-year timeframe. The Company does not have any proved undeveloped reserves which have remained undeveloped for five years or more.

The Company’s proved oil and natural gas reserves are all located in the United States, primarily in the Permian Basin of Southeast New Mexico and West Texas. All of the estimates of the proved reserves at December 31, 2015, 2014 and 2013 are based on reports prepared by Cawley, Gillespie & Associates, Inc. and Netherland, Sewell & Associates, Inc., independent petroleum engineers. Proved reserves were estimated in accordance with the guidelines established by the SEC and the FASB.

The following table summarizes the prices utilized in the reserve estimates for 2015, 2014 and 2013. Commodity prices utilized for the reserve estimates prior to adjustments for location, grade and quality are as follows:

		December 31,
		2015		2014		2013
Prices utilized in the reserve estimates before adjustments:
	Oil per Bbl	$	46.79	$	91.48	$	93.42
	Natural gas per MMBtu	$	2.59	$	4.35	$	3.67

Oil and natural gas reserve quantity estimates are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. The accuracy of such estimates is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of subsequent drilling, testing and production may cause either upward or downward revision of previous estimates. Further, the volumes considered to be commercially recoverable fluctuate with changes in prices and operating costs. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of currently producing oil and natural gas properties. Accordingly, these estimates are expected to change as additional information becomes available in the future.

F-42

Concho Resources Inc.

Unaudited Supplementary Data

December 31, 2015, 2014 and 2013

The following table provides a rollforward of the total proved reserves for the years ended December 31, 2015, 2014 and 2013, as well as proved developed and proved undeveloped reserves at the beginning and end of each respective year. Oil and condensate volumes are expressed in MBbls and natural gas volumes are expressed in MMcf.

		2015			2014			2013
		Oil and Condensate (MBbls)	Natural Gas (MMcf)	Total (MBoe)	Oil and Condensate (MBbls)	Natural Gas (MMcf)	Total (MBoe)	Oil and Condensate (MBbls)	Natural Gas (MMcf)	Total (MBoe)
Total Proved Reserves:
	Balance, January 1	370,347	1,601,015	637,183	307,382	1,173,240	502,921	273,508	1,042,079	447,188
	Purchases of minerals-in-place	7,083	27,722	11,703	2,543	18,970	5,705	889	4,016	1,558
	Sales of minerals-in-place	(944)	(2,610)	(1,379)	-	-	-	-	-	-
	Extensions and discoveries	97,208	359,161	157,068	115,389	400,329	182,111	72,025	199,886	105,339
	Revisions of previous estimates	(71,453)	(344,238)	(128,826)	(28,648)	95,812	(12,679)	(17,914)	2,313	(17,529)
	Production	(34,457)	(106,987)	(52,288)	(26,319)	(87,336)	(40,875)	(21,126)	(75,054)	(33,635)
	Balance, December 31	367,784	1,534,063	623,461	370,347	1,601,015	637,183	307,382	1,173,240	502,921
Proved Developed Reserves:
	January 1	211,446	992,567	376,874	179,520	742,417	303,255	160,936	665,419	271,839
	December 31	203,880	926,629	358,318	211,446	992,567	376,874	179,520	742,417	303,255
Proved Undeveloped Reserves:
	January 1	158,901	608,448	260,309	127,862	430,823	199,666	112,572	376,660	175,349
	December 31	163,904	607,434	265,143	158,901	608,448	260,309	127,862	430,823	199,666

Purchases and sales of minerals-in-place.The Company’s purchases of minerals-in-place are composed of approximately 11.7 MMBoe from various acquisitions throughout the year and 1.4 MMBoe from various divestitures throughout the year.

Extensions and discoveries. Extensions and discoveries of approximately 157.1 MMBoe are primarily the result of the Company’s continued success from its extension and infill horizontal drilling programs in its core operating areas. There were approximately 54.8 MMBoe of proved developed reserves that were directly added through the Company’s drilling activity last year. Based upon this activity, approximately 102.3 MMBoe of new proved undeveloped locations were added, of which the vast majority are one offset location from an existing producing well.

Revisions of previous estimates. Revisions of previous estimates are comprised of (i) 112.2 MMBoe of negative price revisions, (ii) 10.9 MMBoe of negative revisions due to proved undeveloped reserves reclassified to unproved reserves because they are no longer expected to be developed within the five years of their initial recording required by SEC rules and (iii) 5.7 MMBoe net negative revision resulting from technical and performance evaluations.

Standardized Measure of Discounted Future Net Cash Flows

The standardized measure of discounted future net cash flows is computed by applying the 12-month unweighted average of the first-day-of-the-month pricing for oil and natural gas (with consideration of price changes only to the extent provided by contractual arrangements) to the estimated future production of proved oil and natural gas reserves less estimated future expenditures (based on year-end costs) to be incurred in developing and producing the proved reserves, discounted using a rate of 10 percent per year to reflect the estimated timing of the future cash flows. Future income taxes are calculated by comparing undiscounted future cash flows to the tax basis of oil and natural gas properties plus available carryforwards and credits and applying the current tax rates to the difference.

Discounted future cash flow estimates like those shown below are not intended to represent estimates of the fair value of oil and natural gas properties. Estimates of fair value would also consider probable and possible reserves, anticipated future oil and natural gas prices, interest rates, changes in development and production costs and risks associated with future production. Because of these and other considerations, any estimate of fair value is necessarily subjective and imprecise.

F-43

Concho Resources Inc.

Unaudited Supplementary Data

December 31, 2015, 2014 and 2013

The following table provides the standardized measure of discounted future net cash flows at December 31, 2015, 2014 and 2013:

		December 31,
(in thousands)		2015		2014		2013
Oil and gas producing activities:
	Future cash inflows	$	20,133,330	$	42,162,518	$	34,428,001
	Future production costs		(7,667,091)		(11,878,549)		(10,180,985)
	Future development and abandonment costs (a)		(3,357,362)		(4,665,495)		(3,808,507)
	Future income tax expense		(1,119,143)		(7,565,280)		(6,304,087)
	Future net cash flows		7,989,734		18,053,194		14,134,422
	10% annual discount factor		(4,250,249)		(10,030,367)		(7,889,987)
	Standardized measure of discounted future net cash flows	$	3,739,485	$	8,022,827	$	6,244,435
(a)	Includes $196.5 million, $203.9 million and $173.5 million of undiscounted asset retirement cash outflow estimated at December 31, 2015, 2014 and 2013, respectively, using current estimates of future abandonment costs less salvage values. See Note 5 for corresponding information regarding the Company’s discounted asset retirement obligations.

Changes in Standardized Measure of Discounted Future Net Cash Flows

The following table provides a rollforward of the standardized measure of discounted future net cash flows for the years ended December 31, 2015, 2014 and 2013:

		Years Ended December 31,
(in thousands)		2015		2014		2013
Oil and natural gas producing activities:
	Purchases of minerals-in-place	$	73,676	$	102,032	$	19,331
	Sales of minerals-in-place		(4,991)		-		-
	Extensions and discoveries		1,021,693		3,353,339		2,036,404
	Development costs incurred during the period		464,697		561,198		441,998
	Net changes in prices and production costs		(7,892,682)		(645,947)		(344,763)
	Oil and natural gas sales, net of production costs		(1,262,214)		(2,121,773)		(1,864,483)
	Changes in future development costs		987,800		310,326		155,489
	Revisions of previous quantity estimates		(1,125,226)		(250,401)		(363,615)
	Accretion of discount		1,064,504		906,661		833,226
	Changes in production rates, timing and other		(448,804)		139,885		(211,099)
	Change in present value of future net revenues		(7,121,547)		2,355,320		702,488
	Net change in present value of future income taxes		2,838,205		(576,928)		(246,126)
			(4,283,342)		1,778,392		456,362
Balance, beginning of year			8,022,827		6,244,435		5,788,073
Balance, end of year		$	3,739,485	$	8,022,827	$	6,244,435

F-44

Concho Resources Inc.

Unaudited Supplementary Data

December 31, 2015, 2014 and 2013

Selected Quarterly Financial Results

The following table provides selected quarterly financial results for the years ended December 31, 2015 and 2014:

			Quarter
(in thousands, except per share data)			First		Second		Third		Fourth
Year ended December 31, 2015:
	Total operating revenues		$	413,522	$	537,425	$	463,474	$	389,152
	Operating costs and expenses (excluding gains (losses)
		on derivatives)		(459,290)		(522,057)		(551,876)		(589,099)
	Gains (losses) on derivatives			115,340		(147,399)		413,130		318,681
	Income (loss) from operations		$	69,572	$	(132,031)	$	324,728	$	118,734
	Net income (loss)		$	7,512	$	(120,483)	$	179,659	$	(788)
	Net income (loss) per common share - Basic		$	0.07	$	(1.02)	$	1.49	$	(0.01)
	Net income (loss) per common share - Diluted		$	0.06	$	(1.02)	$	1.49	$	(0.01)
Year ended December 31, 2014:
	Total operating revenues		$	660,959	$	704,702	$	700,263	$	594,223
	Operating costs and expenses (excluding gains (losses)
		on derivatives)		(423,112)		(451,934)		(484,480)		(1,101,793)
	Gains (losses) on derivatives			(35,615)		(164,707)		326,229		765,010
	Income from operations		$	202,232	$	88,061	$	542,012	$	257,440
	Net income		$	91,307	$	11,769	$	305,203	$	129,896
	Net income per common share - Basic		$	0.87	$	0.11	$	2.70	$	1.15
	Net income per common share - Diluted		$	0.87	$	0.11	$	2.69	$	1.15

F-45

Index of Exhibits

Exhibit

NumberDescription

3.1                            Restated Certificate of Incorporation (filed as Exhibit 3.1 to the Company’s Current Report on Form 8-K on August 8, 2007, and incorporated herein by reference).

3.2                            Second Amended and Restated Bylaws of Concho Resources Inc., as amended November 7, 2012 (filed as Exhibit 3.1 to the Company’s Current Report on Form 8-K on November 8, 2012, and incorporated herein by reference).

4.1                            Specimen Common Stock Certificate (filed as Exhibit 4.1 to the Company’s Annual Report on Form 10-K on February 22, 2013, and incorporated herein by reference).

4.2                            Indenture, dated September 18, 2009, between Concho Resources Inc., the subsidiary guarantors named therein, and Wells Fargo Bank, National Association, as trustee (filed as Exhibit 4.1 to the Company’s Current Report on Form 8-K on September 22, 2009, and incorporated herein by reference).

4.3                            First Supplemental Indenture, dated September 18, 2009, between Concho Resources Inc., the subsidiary guarantors named therein, and Wells Fargo Bank, National Association, as trustee (filed as Exhibit 4.2 to the Company’s Current Report on Form 8-K on September 22, 2009, and incorporated herein by reference).

4.4                            Second Supplemental Indenture, dated November 3, 2010, between Concho Resources Inc., the subsidiary guarantors named therein, and Wells Fargo Bank, National Association, as trustee (filed as Exhibit 4.4 to the Post-Effective Amendment to the Company’s Registration Statement on Form S-3 on December 7, 2010, and incorporated herein by reference).

4.5                            Third Supplemental Indenture, dated December 14, 2010, between Concho Resources Inc., the subsidiary guarantors named therein, and Wells Fargo Bank, National Association, as trustee (filed as Exhibit 4.1 to the Company’s Current Report on Form 8-K on December 14, 2010, and incorporated herein by reference).

4.6                            Fourth Supplemental Indenture, dated May 23, 2011, between Concho Resources Inc., the subsidiary guarantors named therein, and Wells Fargo Bank, National Association, as trustee (filed as Exhibit 4.1 to the Company’s Current Report on Form 8-K on May 23, 2011, and incorporated herein by reference).

4.7                            Fifth Supplemental Indenture, dated December 12, 2011, between Concho Resources Inc., the subsidiary guarantors named therein, and Wells Fargo Bank, National Association, as trustee (filed as Exhibit 4.7 to the Company’s Annual Report on Form 10-K on February 24, 2012, and incorporated herein by reference).

4.8                            Sixth Supplemental Indenture, dated March 12, 2012, between Concho Resources Inc., the subsidiary guarantors named therein, and Wells Fargo Bank, National Association, as trustee (filed as Exhibit 4.1 to the Company’s Current Report on Form 8-K on March 12, 2012, and incorporated herein by reference).

4.9                            Seventh Supplemental Indenture, dated August 17, 2012, between Concho Resources Inc., the subsidiary guarantors named therein, and Wells Fargo Bank, National Association, as trustee (filed as Exhibit 4.1 to the Company’s Current Report on Form 8-K on August 17, 2012, and incorporated herein by reference).

4.10                          Eighth Supplemental Indenture, dated June 3, 2013, between Concho Resources Inc., the subsidiary guarantors named therein, and Wells Fargo Bank, National Association, as trustee (filed as Exhibit 4.1 to the Company’s Current Report on Form 8-K on June 6, 2013, and incorporated herein by reference).

Index of Exhibits

Exhibit

NumberDescription

4.11                          Form of 7.0% Senior Notes due 2021 (included in Exhibit 4.1 to the Company’s Current Report on Form 8-K on December 14, 2010, and incorporated herein by reference).

4.12                          Form of 6.5% Senior Notes due 2022 (included in Exhibit 4.1 to the Company’s Current Report on Form 8-K on May 23, 2011, and incorporated herein by reference).

4.13                          Form of 5.5% Senior Notes due 2022 (included in Exhibit 4.2 to the Company’s Current Report on Form 8-K on March 12, 2012, and incorporated herein by reference).

4.14                          Form of 5.5% Senior Notes due 2023 (included in Exhibit 4.1 to the Company’s Current Report on Form 8-K on August 17, 2012, and incorporated herein by reference).

10.1            **         Form of Performance Unit Award Agreement (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on January 4, 2013, and incorporated herein by reference).

10.2            **         Concho Resources Inc. 2015 Stock Incentive Plan (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on June 5, 2015, and incorporated herein by reference).

10.3            **         Form of Nonstatutory Stock Option Agreement (filed as Exhibit 10.16 to the Company’s Annual Report on Form 10-K on March 28, 2008, and incorporated herein by reference).

10.4            **         Form of Restricted Stock Agreement (for officers) (filed as Exhibit 10.11 to the Company’s Annual Report on Form 10-K on February 22, 2013, and incorporated herein by reference).

10.5            **         Form of Restricted Stock Agreement (for non-employee directors) (filed as Exhibit 10.18 to the Company’s Annual Report on Form 10-K on March 28, 2008, and incorporated herein by reference).

10.6            **         Employment Agreement dated December 19, 2008, between Concho Resources Inc. and Timothy A. Leach (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on December 19, 2008, and incorporated herein by reference).

10.7            **         Employment Agreement dated December 19, 2008, between Concho Resources Inc. and E. Joseph Wright (filed as Exhibit 10.3 to the Company’s Current Report on Form 8-K on December 19, 2008, and incorporated herein by reference).

10.8            **         Employment Agreement dated December 19, 2008, between Concho Resources Inc. and Darin G. Holderness (filed as Exhibit 10.4 to the Company’s Current Report on Form 8-K on December 19, 2008, and incorporated herein by reference).

10.9            **         Employment Agreement dated December 19, 2008, between Concho Resources Inc. and Matthew G. Hyde (filed as Exhibit 10.6 to the Company’s Current Report on Form 8-K on December 19, 2008, and incorporated herein by reference).

10.10          **         Employment Agreement dated November 5, 2009, between Concho Resources Inc. and C. William Giraud (filed as Exhibit 10.18 to the Company’s Annual Report on Form 10-K on February 26, 2010, and incorporated herein by reference).

10.11          **         Employment Agreement dated March 19, 2014, between Concho Resources Inc. and Jack F. Harper (filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K on March 24, 2014, and incorporated herein by reference).

Index of Exhibits

Exhibit

NumberDescription

10.12          **         Form of First Amendment to Employment Agreement between Concho Resources Inc. and each of Messrs. Leach, Giraud, Holderness, Hyde and Wright (filed as Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q on May 6, 2011, and incorporated herein by reference).

10.13          **         Form of Indemnification Agreement between Concho Resources Inc. and each of the officers and directors thereof (filed as Exhibit 10.23 to the Company’s Registration Statement on Form S-1 on April 24, 2007, and incorporated herein by reference).

10.14          **         Indemnification Agreement, dated February 27, 2008, by and between Concho Resources, Inc. and William H. Easter III (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on March 4, 2008, and incorporated herein by reference).

10.15          **         Indemnification Agreement, dated May 21, 2008, by and between Concho Resources, Inc. and Matthew G. Hyde (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on May 28, 2008, and incorporated herein by reference).

10.16          **         Indemnification Agreement, dated August 25, 2008, by and between Concho Resources, Inc. and Darin G. Holderness (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on August 29, 2008, and incorporated herein by reference).

10.17          **         Indemnification Agreement, dated November 5, 2009, by and between Concho Resources, Inc. and Mark B. Puckett (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on November 12, 2009, and incorporated herein by reference).

10.18          **         Indemnification Agreement, dated November 5, 2009, by and between Concho Resources, Inc. and C. William Giraud (filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K on November 12, 2009, and incorporated herein by reference).

10.19          **         Form of Director and Officer Indemnification Agreement between Concho Resources Inc. and each of Messrs. Surma and Harper (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on March 24, 2014, and incorporated herein by reference).

10.20          **         Indemnification Agreement, dated January 10, 2012, between Concho Resources Inc. and Gary A. Merriman (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on January 12, 2012, and incorporated herein by reference).

10.21                        Second Amended and Restated Credit Agreement, dated as of May 9, 2014, among Concho Resources Inc., the lenders party thereto and JPMorgan Chase Bank, N.A., as Administrative Agent (filed as Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q on May 12, 2014, and incorporated herein by reference).

10.22                        First Amendment to Second Amended and Restated Credit Agreement, dated as of April 8, 2015, among Concho Resources Inc., the lenders party thereto and JPMorgan Chase Bank, N.A., as Administrative Agent (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on April 9, 2015, and incorporated herein by reference).

10.23                        Registration Rights Agreement, dated February 27, 2006, among Concho Resources Inc. and the other signatories thereto (filed as Exhibit 10.12 to the Company’s Registration Statement on Form S-1 on April 24, 2007, and incorporated herein by reference).

Index of Exhibits

Exhibit

NumberDescription

12.1            (a)         Ratio of Earnings to Fixed Charges and Ratio of Earnings to Fixed Charges and Preferred Stock Dividends.

21.1            (a)         Subsidiaries of Concho Resources Inc.

23.1            (a)         Consent of Grant Thornton LLP.

23.2            (a)         Consent of Netherland, Sewell & Associates, Inc.

23.3            (a)         Consent of Cawley, Gillespie & Associates, Inc.

31.1            (a)         Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2            (a)         Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1            (b)         Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2            (b)         Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

99.1            (a)         Netherland, Sewell & Associates, Inc. Reserve Report.

99.2            (a)         Cawley, Gillespie & Associates, Inc. Reserve Report.

101.INS     (a)         XBRL Instance Document.

101.SCH   (a)         XBRL Schema Document.

101.CAL   (a)         XBRL Calculation Linkbase Document.

101.DEF    (a)         XBRL Definition Linkbase Document.

101.LAB   (a)         XBRL Labels Linkbase Document.

101.PRE    (a)         XBRL Presentation Linkbase Document.

(a)  Filed herewith.

(b)  Furnished herewith.

**   Management contract or compensatory plan or agreement

EX-12

 

EXHIBIT 12.1

Ratio of Earnings to Fixed Charges and

Ratio of Earnings to Fixed Charges and Preferred Stock Dividends

			Years Ended December 31,
(in thousands, except ratios)			2015		2014		2013		2012		2011
	Income from continuing operations before income taxes		$	97,271	$	855,960	$	357,159	$	659,271	$	681,334
	Interest expense			215,384		216,661		218,581		182,705		118,360
	Rental expense attributable to interest			2,650		2,406		1,906		1,553		1,193
		Earnings	$	315,305	$	1,075,027	$	577,646	$	843,529	$	800,887
	Interest expense		$	215,384	$	216,661	$	218,581	$	182,705	$	118,360
	Capitalized interest			4,913		2,282		-		-		73
	Rental expense attributable to interest			2,650		2,406		1,906		1,553		1,193
	Preferred stock dividends			-		-		-		-		-
		Fixed charges and preferred stock dividends	$	222,947	$	221,349	$	220,487	$	184,258	$	119,626
	Ratio of earnings to fixed charges (a)			1.41		4.86		2.62		4.58		6.69
	Ratio of earnings to fixed charges and preferred stock dividends (b)			1.41		4.86		2.62		4.58		6.69

(a)The ratio has been computed by dividing earnings by fixed charges. For purposes of computing the ratio:

•earnings include income from continuing operations before income taxes, adjusted for interest expense and the portion of rental expense deemed to be representative of the interest component of rental expense; and

•fixed charges consist of interest expense, capitalized interest and the portion of rental expense deemed to be representative of the interest component of rental expense.

(b)The ratio has been computed by dividing earnings by fixed charges and preferred stock dividends. For purposes of computing the ratio:

•earnings include income from continuing operations before income taxes, adjusted for interest expense and the portion of rental expense deemed to be representative of the interest component of rental expense; and

•fixed charges and preferred stock dividends consist of interest expense, capitalized interest, the portion of rental expense deemed to be representative of the interest component of rental expense and preferred stock dividends.

___________________________________________________________________________________________

EX-21

 

EXHIBIT 21.1

Subsidiaries of the Company

At December 31, 2015

State or Jurisdiction of Organization	Subsidiaries	Ownership %
Delaware	COG Operating LLC	100%
Delaware	Concho Oil & Gas LLC	100%
Texas	Quail Ranch LLC	100%
Texas	COG Realty LLC	100%
Texas	COG Holdings LLC	100%
Texas	Delaware River SWD LLC	100%
Texas	COG Production LLC	100%
Texas	COG Acreage LP	100%

EX-23

 

EXHIBIT 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We have issued our reports dated February 25, 2016, with respect to the consolidated financial statements and internal control over financial reporting included in the Annual Report of Concho Resources Inc. on Form 10-K for the year ended December 31, 2015.  We hereby consent to the incorporation by reference of said reports in the Registration Statements of Concho Resources Inc. on Forms S-8 (File No. 333-145791, effective August 30, 2007, File No. 333-182046, effective June 11, 2012 and File No. 333-204765, effective June 5, 2015) and Form S-3 (File No. 333-206172, effective August 6, 2015).

/s/ GRANT THORNTON LLP

Tulsa, Oklahoma

February 25, 2016

EX-23

 

EXHIBIT 23.2

 

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS

We hereby consent to (i) the use of the name Netherland, Sewell & Associates, Inc., the reference to our reserves report for Concho Resources Inc. (the “Company”) dated January 22, 2016, and the use of information contained therein in the Company’s annual report on Form 10-K to be filed on or about February 25, 2016, and (ii) inclusion of our summary report dated January 22, 2016, included in the Form 10-K to be filed on or about February 25, 2016, as Exhibit 99.1.

We hereby further consent to the incorporation by reference in the Registration Statements on (i) Form S-8 (file no. 333-145791, effective August 30, 2007), (ii) Form S-8 (file no. 333-182046, effective June 11, 2012), (iii) Form S-8 (file no. 333-204765, effective June 5, 2015), and (iv) Form S-3 (file no. 333-206172, effective August 6, 2015) of such information.

NETHERLAND, SEWELL & ASSOCIATES, INC.
By:	/s/ C.H. (Scott) Rees III
	C.H. (Scott) Rees III, P.E.
	Chairman and Chief Executive Officer

Dallas, Texas

February 25, 2016

EX-23

 

EXHIBIT 23.3

 

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS

Cawley, Gillespie & Associates, Inc., hereby consents to (i) the use of the oil and gas reserve information in the Concho Resources Inc. Securities and Exchange Commission Form 10-K for the year ending December 31, 2015 and in the Concho Resources Inc. annual report for the year ending December 31, 2015, based on the reserve report dated January 20, 2016, prepared by Cawley, Gillespie & Associates, Inc. and (ii) inclusion of our summary report dated January 20, 2016 included in the Form 10-K to be filed on or about February 25, 2016 as Exhibit 99.2.

We hereby further consent to the incorporation by reference in the Registration Statements on (i) Form S-8 (file no. 333-145791, effective August 30, 2007), (ii) Form S-8 (file no. 333-182046, effective June 11, 2012), (iii) Form S-8 (file no. 333-204765, effective June 5, 2015) and (iv) Form S-3 (file no. 333-206172, effective August 6, 2015) of such information.

CAWLEY, GILLESPIE & ASSOCIATES, INC.

                                                                                                J. Zane Meekins, P.E.

                                                                                                Executive Vice President

Fort Worth, Texas

February 25, 2016

EX-31

 

EXHIBIT 31.1

CERTIFICATIONS

I, Timothy A. Leach, certify that:

1.I have reviewed this annual report of Concho Resources Inc. (the “registrant”);

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

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

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

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

(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

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

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

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

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

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

Date:	February 25, 2016	/s/  Timothy A. Leach
		Timothy A. Leach
		Director, Chairman of the Board of Directors, Chief Executive Officer
		and President (Principal Executive Officer)

EX-31

 

EXHIBIT 31.2

CERTIFICATIONS

I, Darin G. Holderness, certify that:

1.I have reviewed this annual report of Concho Resources Inc. (the “registrant”);

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

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

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

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

(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

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

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

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

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

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

Date:	February 25, 2016	/s/  Darin G. Holderness
		Darin G. Holderness
		Senior Vice President, Chief Financial Officer and Treasurer
		(Principal Financial Officer)

EX-32

 

                        EXHIBIT 32.1

Certification of Chief Executive Officer of Concho Resources Inc.

(Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002)

In connection with the annual report of Concho Resources Inc. (the “Company”), as filed with the Securities and Exchange Commission on the date hereof (the “Report”), Timothy A. Leach, Chief Executive Officer of the Company, hereby certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to his knowledge:

(1)the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

(2)the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date:	February 25, 2016	/s/  Timothy A. Leach
		Timothy A. Leach
		Director, Chairman of the Board of Directors, Chief Executive Officer
		and President (Principal Executive Officer)

EX-32

 

EXHIBIT 32.2

Certification of Chief Financial Officer of Concho Resources Inc.

(Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002)

In connection with the annual report of Concho Resources Inc. (the “Company”), as filed with the Securities and Exchange Commission on the date hereof (the “Report”), Darin G. Holderness, Chief Financial Officer of the Company, hereby certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to his knowledge:

(1)the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

(2)the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date:	February 25, 2016	/s/  Darin G. Holderness
		Darin G. Holderness
		Senior Vice President, Chief Financial Officer and Treasurer
		(Principal Financial Officer)

EX-99

 

EXHIBIT 99.1

January 22, 2016

Mr. J. Steve Guthrie

Concho Resources Inc.

One Concho Center

600 West Illinois Avenue

Midland, Texas 79701

Dear Mr. Guthrie:

In accordance with your request, we have estimated the proved reserves and future revenue, as of December 31, 2015, to the Concho Resources Inc. (Concho) interest in certain oil and gas properties located in Texas.  We completed our evaluation on or about the date of this letter.  It is our understanding that the proved reserves estimated in this report constitute approximately 28 percent of all proved reserves owned by Concho.  The estimates in this report have been prepared in accordance with the definitions and regulations of the U.S. Securities and Exchange Commission (SEC) and, with the exception of the exclusion of future income taxes, conform to the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas.  Definitions are presented immediately following this letter.  This report has been prepared for Concho's use in filing with the SEC; in our opinion the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for such purpose.

We estimate the net reserves and future net revenue to the Concho interest in these properties, as of December 31, 2015, to be:

	Net Reserves		Future Net Revenue (M$)
	Oil	Gas		Present Worth
Category	(MBBL)	(MMCF)	Total	at 10%
Proved Developed Producing	60,364.8	208,659.2	1,797,710.4	1,039,271.0
Proved Developed Non-Producing	1,721.7	4,819.9	40,955.0	5,090.4
Proved Undeveloped	53,798.9	127,668.2	1,071,539.2	216,336.9
Total Proved	115,885.5	341,147.3	2,910,204.8	1,260,698.5

Totals may not add because of rounding.

The oil volumes shown include crude oil and condensate.  Oil volumes are expressed in thousands of barrels (MBBL); a barrel is equivalent to 42 United States gallons.  Gas volumes are expressed in millions of cubic feet (MMCF) at standard temperature and pressure bases.

The estimates shown in this report are for proved reserves.  As requested, probable and possible reserves that exist for these properties have not been included.  This report does not include any value that could be attributed to interests in undeveloped acreage beyond those tracts for which undeveloped reserves have been estimated.  Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production status.  The estimates of reserves and future revenue included herein have not been adjusted for risk.

Gross revenue is Concho's share of the gross (100 percent) revenue from the properties prior to any deductions.  Future net revenue is after deductions for Concho's share of production taxes, ad valorem taxes, capital costs, and operating expenses but before consideration of any income taxes.  The future net revenue has been discounted at an annual rate of 10 percent to determine its present worth, which is shown to indicate the effect of time on the value of money.  Future net revenue presented in this report, whether discounted or undiscounted, should not be construed as being the fair market value of the properties.

Prices used in this report are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period January through December 2015.  For oil volumes, the average West Texas Intermediate posted price of $46.79 per barrel is adjusted by field for quality, transportation fees, and market differentials.  For gas volumes, the average Henry Hub spot price of $2.587 per MMBTU is adjusted by field for energy content, transportation fees, and market differentials.  All prices are held constant throughout the lives of the properties.  The average adjusted product prices weighted by production over the remaining lives of the properties are $43.21 per barrel of oil and $2.995 per MCF of gas. 

Operating costs used in this report are based on operating expense records of Concho.  For the nonoperated properties, these costs include the per-well overhead expenses allowed under joint operating agreements along with estimates of costs to be incurred at and below the district and field levels.  As requested, operating costs for the operated properties are limited to direct lease- and field-level costs and $4.39 per well per month, which is Concho's estimate of the portion of its headquarters general and administrative overhead expenses necessary to operate the properties.  Operating costs have been divided into per-well costs and per-unit-of-production costs and are not escalated for inflation. 

Capital costs used in this report were provided by Concho and are based on authorizations for expenditure and actual costs from recent activity.  Capital costs are included as required for workovers, new development wells, and production equipment.  Based on our understanding of future development plans, a review of the records provided to us, and our knowledge of similar properties, we regard these estimated capital costs to be reasonable.  Capital costs are not escalated for inflation.   As requested, our estimates do not include any salvage value for the lease and well equipment or the cost of abandoning the properties.

For the purposes of this report, we did not perform any field inspection of the properties, nor did we examine the mechanical operation or condition of the wells and facilities.  We have not investigated possible environmental liability related to the properties; therefore, our estimates do not include any costs due to such possible liability. 

We have made no investigation of potential volume and value imbalances resulting from overdelivery or underdelivery to the Concho interest.  Therefore, our estimates of reserves and future revenue do not include adjustments for the settlement of any such imbalances; our projections are based on Concho receiving its net revenue interest share of estimated future gross production.

The reserves shown in this report are estimates only and should not be construed as exact quantities.  Proved reserves are those quantities of oil and gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be economically producible; probable and possible reserves are those additional reserves which are sequentially less certain to be recovered than proved reserves.  Estimates of reserves may increase or decrease as a result of market conditions, future operations, changes in regulations, or actual reservoir performance.  In addition to the primary economic assumptions discussed herein, our estimates are based on certain assumptions including, but not limited to, that the properties will be developed consistent with current development plans as provided to us by Concho, that the properties will be operated in a prudent manner, that no governmental regulations or controls will be put in place that would impact the ability of the interest owner to recover the reserves, and that our projections of future production will

prove consistent with actual performance.  If the reserves are recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts.  Because of governmental policies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred in recovering such reserves may vary from assumptions made while preparing this report. 

For the purposes of this report, we used technical and economic data including, but not limited to, well logs, geologic maps, well test data, production data, historical price and cost information, and property ownership interests.  The reserves in this report have been estimated using deterministic methods; these estimates have been prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE Standards).  We used standard engineering and geoscience methods, or a combination of methods, including performance analysis and analogy, that we considered to be appropriate and necessary to categorize and estimate reserves in accordance with SEC definitions and regulations.  A substantial portion of these reserves are for undeveloped locations; such reserves are based on analogy to properties with similar geologic and reservoir characteristics.  As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, our conclusions necessarily represent only informed professional judgment. 

The data used in our estimates were obtained from Concho, public data sources, and the nonconfidential files of Netherland, Sewell & Associates, Inc. (NSAI) and were accepted as accurate.  Supporting work data are on file in our office.  We have not examined the titles to the properties or independently confirmed the actual degree or type of interest owned.  The technical person primarily responsible for preparing the estimates presented herein meets the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the SPE Standards.  Michael B. Begland, a Licensed Professional Engineer in the State of Texas, has been practicing consulting petroleum engineering at NSAI since 1993 and has over 7 years of prior industry experience.  We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these properties nor are we employed on a contingent basis.

                                                                                    Sincerely,

                                                                                    NETHERLAND, SEWELL & ASSOCIATES, INC.

                                                                                    Texas Registered Engineering Firm F-2699

                                                                                           /s/ C.H. (Scott) Rees III

                                                                                    By:                                                                  

                                                                                           C.H. (Scott) Rees III, P.E.

                                                                                           Chairman and Chief Executive Officer

                                                                                           /s/ Michael B. Begland

                                                                                    By:                                                                  

                                                                                           Michael B. Begland, P.E. 104898

                                                                                           Vice President

                                                                                    Date Signed:  January 22, 2016

Please be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates, Inc. (NSAI) as a convenience to our clients.  The digital document is intended to be substantively the same as the original signed document maintained by NSAI.  The digital document is subject to the parameters, limitations, and conditions stated in the original document.  In the event of any differences between the digital document and the original document, the original document shall control and supersede the digital document.

MBB:KWC

DEFINITIONS OF OIL AND GAS RESERVES Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

The following definitions are set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Section 210.4‑10(a).  Also included is supplemental information from (1) the 2007 Petroleum Resources Management System approved by the Society of Petroleum Engineers, (2) the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas, and (3) the SEC's Compliance and Disclosure Interpretations.

(1) Acquisition of properties.  Costs incurred to purchase, lease or otherwise acquire a property, including costs of lease bonuses and options to purchase or lease properties, the portion of costs applicable to minerals when land including mineral rights is purchased in fee, brokers' fees, recording fees, legal costs, and other costs incurred in acquiring properties.

(2) Analogous reservoir.  Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery.  When used to support proved reserves, an "analogous reservoir" refers to a reservoir that shares the following characteristics with the reservoir of interest:

(i)   Same geological formation (but not necessarily in pressure communication with the reservoir of interest);

(ii)   Same environment of deposition;

(iii)  Similar geological structure; and

(iv)  Same drive mechanism.

Instruction to paragraph (a)(2): Reservoir properties must, in the aggregate, be no more favorable in the analog than in the reservoir of interest.

(3) Bitumen.  Bitumen, sometimes referred to as natural bitumen, is petroleum in a solid or semi-solid state in natural deposits with a viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis.  In its natural state it usually contains sulfur, metals, and other non-hydrocarbons.

(4) Condensate.  Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

(5) Deterministic estimate.  The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.

(6) Developed oil and gas reserves.  Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i)   Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii)   Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Supplemental definitions from the 2007 Petroleum Resources Management System:

Developed Producing Reserves – Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate.  Improved recovery reserves are considered producing only after the improved recovery project is in operation.

Developed Non-Producing Reserves – Developed Non-Producing Reserves include shut-in and behind-pipe Reserves.  Shut-in Reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not yet started producing, (2) wells which were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons.  Behind-pipe Reserves are expected to be recovered from zones in existing wells which will require additional completion work or future recompletion prior to start of production.  In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well. 

(7) Development costs.  Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas.  More specifically, development costs, including depreciation and

Definitions – Page 4 of 8

DEFINITIONS OF OIL AND GAS RESERVES Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:

(i)   Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves.

(ii)   Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly.

(iii)  Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems.

(iv)  Provide improved recovery systems.

(8) Development project.  A development project is the means by which petroleum resources are brought to the status of economically producible.  As examples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.

(9) Development well.  A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

(10) Economically producible.  The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation.  The value of the products that generate revenue shall be determined at the terminal point of oil and gas producing activities as defined in paragraph (a)(16) of this section.

(11) Estimated ultimate recovery (EUR).  Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.

(12) Exploration costs.  Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells.  Exploration costs may be incurred both before acquiring the related property (sometimes referred to in part as prospecting costs) and after acquiring the property.  Principal types of exploration costs, which include depreciation and applicable operating costs of support equipment and facilities and other costs of exploration activities, are:

(i)   Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews, and others conducting those studies.  Collectively, these are sometimes referred to as geological and geophysical or "G&G" costs.

(ii)   Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title defense, and the maintenance of land and lease records.

(iii)  Dry hole contributions and bottom hole contributions.

(iv)  Costs of drilling and equipping exploratory wells.

(v)  Costs of drilling exploratory-type stratigraphic test wells.

(13) Exploratory well.  An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir.  Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well as those items are defined in this section.

(14) Extension well.  An extension well is a well drilled to extend the limits of a known reservoir.

(15) Field.  An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.  There may be two or more reservoirs in a field which are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or by both.  Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field.  The

Definitions – Page 5 of 8

DEFINITIONS OF OIL AND GAS RESERVES Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

geological terms "structural feature" and "stratigraphic condition" are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.

(16) Oil and gas producing activities.

(i)   Oil and gas producing activities include:

(A)  The search for crude oil, including condensate and natural gas liquids, or natural gas ("oil and gas") in their natural states and original locations;

(B)  The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas from such properties;

(C)  The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including the acquisition, construction, installation, and maintenance of field gathering and storage systems, such as:

(1)  Lifting the oil and gas to the surface; and

(2)  Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and

(D)  Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction.

Instruction 1 to paragraph (a)(16)(i): The oil and gas production function shall be regarded as ending at a "terminal point", which is the outlet valve on the lease or field storage tank.  If unusual physical or operational circumstances exist, it may be appropriate to regard the terminal point for the production function as:

a.   The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery, or a marine terminal; and

b.   In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to a purchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, a refinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas.

Instruction 2 to paragraph (a)(16)(i): For purposes of this paragraph (a)(16), the term saleable hydrocarbons means hydrocarbons that are saleable in the state in which the hydrocarbons are delivered.

(ii)   Oil and gas producing activities do not include:

(A)  Transporting, refining, or marketing oil and gas;

(B)  Processing of produced oil, gas, or natural resources that can be upgraded into synthetic oil or gas by a registrant that does not have the legal right to produce or a revenue interest in such production;

(C)  Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and gas can be extracted; or

(D)  Production of geothermal steam.

(17) Possible reserves.  Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

(i)   When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves.  When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.

(ii)   Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain.  Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.

Definitions – Page 6 of 8

DEFINITIONS OF OIL AND GAS RESERVES Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(iii)  Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.

(iv)  The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.

(v)  Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir.  Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.

(vi)  Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology.  Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.

(18) Probable reserves.  Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

(i)   When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves.  When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

(ii)   Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion.  Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.

(iii)  Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

(iv)  See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.

(19) Probabilistic estimate.  The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrence.

(20) Production costs.

(i)   Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities.  They become part of the cost of oil and gas produced.  Examples of production costs (sometimes called lifting costs) are:

(A)  Costs of labor to operate the wells and related equipment and facilities.

(B)  Repairs and maintenance.

(C)  Materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities.

(D)  Property taxes and insurance applicable to proved properties and wells and related equipment and facilities.

(E)  Severance taxes.

Definitions – Page 7 of 8

DEFINITIONS OF OIL AND GAS RESERVES Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(ii)   Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation, refining, and marketing activities.  To the extent that the support equipment and facilities are used in oil and gas producing activities, their depreciation and applicable operating costs become exploration, development or production costs, as appropriate.  Depreciation, depletion, and amortization of capitalized acquisition, exploration, and development costs are not production costs but also become part of the cost of oil and gas produced along with production (lifting) costs identified above.

(21) Proved area.  The part of a property to which proved reserves have been specifically attributed.

(22) Proved oil and gas reserves.  Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation.  The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i)   The area of the reservoir considered as proved includes:  

(A)  The area identified by drilling and limited by fluid contacts, if any, and

(B)  Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(ii)   In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii)  Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv)  Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A)  Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

(B)  The project has been approved for development by all necessary parties and entities, including governmental entities.

(v)  Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined.  The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

(23) Proved properties.  Properties with proved reserves.

(24) Reasonable certainty.  If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered.  If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate.  A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.

Definitions – Page 8 of 8

DEFINITIONS OF OIL AND GAS RESERVES Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(25) Reliable technology.  Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

(26) Reserves.  Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.  In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible.  Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

Excerpted from the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas:

932-235-50-30  A standardized measure of discounted future net cash flows relating to an entity's interests in both of the following shall be disclosed as of the end of the year:

    a.   Proved oil and gas reserves (see paragraphs 932-235-50-3 through 50-11B)

    b.   Oil and gas subject to purchase under long-term supply, purchase, or similar agreements and contracts in which the entity participates in the operation of the properties on which the oil or gas is located or otherwise serves as the producer of those reserves (see paragraph 932-235-50-7).

The standardized measure of discounted future net cash flows relating to those two types of interests in reserves may be combined for reporting purposes. 

932-235-50-31  All of the following information shall be disclosed in the aggregate and for each geographic area for which reserve quantities are disclosed in accordance with paragraphs 932-235-50-3 through 50-11B:

    a.   Future cash inflows.  These shall be computed by applying prices used in estimating the entity's proved oil and gas reserves to the year-end quantities of those reserves.  Future price changes shall be considered only to the extent provided by contractual arrangements in existence at year-end.

    b.   Future development and production costs.  These costs shall be computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions.  If estimated development expenditures are significant, they shall be presented separately from estimated production costs.

    c.   Future income tax expenses.  These expenses shall be computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pretax net cash flows relating to the entity's proved oil and gas reserves, less the tax basis of the properties involved.  The future income tax expenses shall give effect to tax deductions and tax credits and allowances relating to the entity's proved oil and gas reserves.

    d.   Future net cash flows.  These amounts are the result of subtracting future development and production costs and future income tax expenses from future cash inflows.

    e.   Discount.  This amount shall be derived from using a discount rate of 10 percent a year to reflect the timing of the future net cash flows relating to proved oil and gas reserves.

    f.    Standardized measure of discounted future net cash flows.  This amount is the future net cash flows less the computed discount. 

(27) Reservoir.   A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

(28) Resources.   Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations.  A portion of the resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable.  Resources include both discovered and undiscovered accumulations.

Definitions – Page 9 of 8

DEFINITIONS OF OIL AND GAS RESERVES Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(29) Service well.  A well drilled or completed for the purpose of supporting production in an existing field.  Specific purposes of service wells include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion.

(30) Stratigraphic test well.  A stratigraphic test well is a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition.  Such wells customarily are drilled without the intent of being completed for hydrocarbon production.  The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration.  Stratigraphic tests are classified as "exploratory type" if not drilled in a known area or "development type" if drilled in a known area.

(31) Undeveloped oil and gas reserves.  Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(i)   Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii)   Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

From the SEC's Compliance and Disclosure Interpretations (October 26, 2009):

Although several types of projects — such as constructing offshore platforms and development in urban areas, remote locations or environmentally sensitive locations — by their nature customarily take a longer time to develop and therefore often do justify longer time periods, this determination must always take into consideration all of the facts and circumstances. No particular type of project per se justifies a longer time period, and any extension beyond five years should be the exception, and not the rule.

Factors that a company should consider in determining whether or not circumstances justify recognizing reserves even though development may extend past five years include, but are not limited to, the following:

Ÿ    The company's level of ongoing significant development activities in the area to be developed (for example, drilling only the minimum number of wells necessary to maintain the lease generally would not constitute significant development activities);

Ÿ    The company's historical record at completing development of comparable long-term projects;

Ÿ    The amount of time in which the company has maintained the leases, or booked the reserves, without significant development activities;

Ÿ    The extent to which the company has followed a previously adopted development plan (for example, if a company has changed its development plan several times without taking significant steps to implement any of those plans, recognizing proved undeveloped reserves typically would not be appropriate); and

Ÿ    The extent to which delays in development are caused by external factors related to the physical operating environment (for example, restrictions on development on Federal lands, but not obtaining government permits), rather than by internal factors (for example, shifting resources to develop properties with higher priority).

(iii)  Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

(32) Unproved properties.  Properties with no proved reserves.

Definitions – Page 10 of 8

EX-99

 

EXHIBIT 99.2

 

January 20, 2016

Mr. J. Steve Guthrie

Senior Vice President of

  Business Operations & Engineering

Concho Resources Inc.

One Concho Center 

600 West Illinois Avenue

Midland, Texas 79701

                                                                                                  Re:    Evaluation Summary – SEC Pricing

                                                                                                            Concho Resources Inc. Interests

                                                                                                            Various States

                                                                                                            Proved Reserves

As of December 31, 2015                                           

Dear Mr. Guthrie:

                As requested, we are submitting our estimates of proved reserves and our forecasts of the resulting economics attributable to the above captioned interests as of December 31, 2015.  We completed our evaluation on January 20, 2016.  It is our understanding that the proved reserves estimated in this report constitute approximately 72 percent of all proved reserves owned by Concho Resources Inc.

                This report has been prepared for Concho Resources Inc.'s use in filing with the SEC; in our opinion the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for such purpose.    Composite reserve estimates and economic forecasts are summarized below:

			Proved	Proved
		Total	Developed	Developed	Proved
		Proved	Producing	Non-Producing	Undeveloped
Net Reserves
Oil/Condensate	- Mbbl	251,898.8	128,009.0	13,784.6	110,105.2
Gas	- MMcf	1,192,915.0	668,183.3	44,965.8	479,766.3
Operating Income (BFIT)	- M$	6,395,180.0	3,875,583.0	412,394.5	2,107,202.3
Discounted at 10%	- M$	3,048,872.5	2,347,716.0	96,954.0	604,200.6

                In accordance with the Securities and Exchange Commission guidelines, the operating income (BFIT) has been discounted at an annual rate of 10% to determine its “present worth”.  The discounted value, “present worth”, shown above should not be construed to represent an estimate of the fair market value by Cawley, Gillespie & Associates, Inc.

                The annual average Henry Hub spot market gas price of $2.587 per MMBtu and the annual average Plains WTI posted oil price of $46.79 per barrel were used.  In accordance with the Securities and Exchange Commission guidelines, these prices are determined as an unweighted arithmetic average of the first-day-of-the-month price for each month of 2015.  The oil and gas prices were held constant and were adjusted for gravity, heating value, quality, transportation and marketing.  The adjusted volume-weighted average product prices over the life of the properties are $43.64 per barrel of oil and $2.608 per Mcf of  gas.

                Operating costs were based on operating expense records of Concho Resources.  For non-operated properties, these costs include the overhead expenses allowed under existing joint operating agreements.  Drilling and completion costs were based on estimates provided by Concho Resources and reviewed by Cawley, Gillespie & Associates.  As per the Securities and Exchange Commission guidelines, neither expenses nor investments were escalated.  The cost of plugging and the salvage value of equipment have not been considered.

                The proved reserve classifications conform to criteria of the Securities and Exchange Commission.  We used a combination of methods, including production performance analysis, analogy and volumetric analysis, we considered to be appropriate and necessary to categorize and estimate reserves in accordance with SEC definitions and regulations.  The reserves and economics are predicated on the regulatory agency classifications, rules, policies, laws, taxes and royalties in effect on the effective date except as noted herein.  The possible effects of changes in legislation or other Federal or State restrictive actions have not been considered.  All reserve estimates represent our best judgment based on data available at the time of preparation and assumptions as to future economic and regulatory conditions.  It should be realized that the reserves actually recovered, the revenue derived therefrom and the actual cost incurred could be more or less than the estimated amounts.

                The reserve estimates were based on interpretations of factual data furnished by Concho Resources.  Ownership interests were supplied by Concho Resources and were accepted as furnished.  To some extent, information from public records has been used to check and/or supplement these data.  The basic engineering and geological data were utilized subject to third party reservations and qualifications.  Nothing has come to our attention, however, that would cause us to believe that we are not justified in relying on such data.  An on-site inspection of these properties has not been made nor have the wells been tested by Cawley, Gillespie & Associates, Inc.

                Cawley, Gillespie & Associates, Inc. is independent with respect to Concho Resources Inc. as provided in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserve Information promulgated by the Society of Petroleum Engineers.  Neither Cawley, Gillespie & Associates, Inc. nor any of its employees has any interest in the subject properties.  Neither the employment to make this study nor the compensation is contingent on the results of our work or the future production rates for the subject properties.

                Our work-papers and related data are available for inspection and review by authorized parties.

                                                                                                  Respectfully submitted,

 

CAWLEY, GILLESPIE & ASSOCIATES, INC.

                                                                                                  Texas Registered Engineering Firm F-693

XML

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2015	Feb. 22, 2016
Document Documentand Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2015
Document Fiscal Year Focus	2015
Document Fiscal Period Focus	FY
Trading Symbol	CXO
Entity Registrant Name	CONCHO RESOURCES INC
Entity Central Index Key	0001358071
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Common Stock, Shares Outstanding		129,357,977
Entity Public Float	$ 14,274,370,137

XML

Consolidated Balance Sheets - USD ($)	Dec. 31, 2015	Dec. 31, 2014
Current assets:
Cash and cash equivalents	$ 228,550,000	$ 21,000
Accounts receivable, net of allowance for doubtful accounts:
Oil and natural gas	203,972,000	250,600,000
Joint operations and other	190,608,000	409,665,000
Derivative instruments	652,498,000	490,351,000
Prepaid costs and other	38,922,000	37,759,000
Total current assets	1,314,550,000	1,188,396,000
Property and equipment:
Oil and natural gas properties, successful efforts method	15,846,307,000	13,867,831,000
Accumulated depletion and depreciation	(5,047,810,000)	(3,790,953,000)
Total oil and natural gas properties, net	10,798,497,000	10,076,878,000
Other property and equipment, net	178,450,000	129,136,000
Total property and equipment, net	10,976,947,000	10,206,014,000
Deferred loan costs, net	15,585,000	20,260,000
Intangible asset - operating rights, net	25,693,000	27,154,000
Inventory	19,118,000	14,435,000
Noncurrent derivative instruments	167,038,000	262,349,000
Other assets	122,945,000	33,172,000
Total assets	12,641,876,000	11,751,780,000
Accounts payable:
Trade	13,200,000	20,380,000
Related parties	0	0
Bank overdrafts	0	92,541,000
Revenue payable	169,787,000	238,098,000
Accrued and prepaid drilling costs	228,523,000	718,300,000
Other current liabilities	184,910,000	195,308,000
Total current liabilities	596,420,000	1,264,627,000
Long-term debt	3,332,188,000	3,469,137,000
Deferred income taxes	1,630,373,000	1,600,751,000
Asset retirement obligations and other long-term liabilities	$ 140,344,000	$ 136,477,000
Commitments and contingencies (Note 10)
Stockholders' equity:
Common stock, $0.001 par value; 300,000,000 authorized; 129,444,042 and 113,264,918 shares issued at December 31, 2015 and 2014, respectively	$ 129,000	$ 113,000
Additional paid-in capital	4,628,390,000	3,027,412,000
Retained earnings	2,345,641,000	2,279,741,000
Treasury stock, at cost; 306,061 and 260,124 shares at December 31, 2015 and 2014, respectively	(31,609,000)	(26,478,000)
Total stockholders' equity	6,942,551,000	5,280,788,000
Total liabilities and stockholders' equity	$ 12,641,876,000	$ 11,751,780,000

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Consolidated Balance Sheets (Parenthetical) - $ / shares	Dec. 31, 2015	Dec. 31, 2014
Statement of Financial Position [Abstract]
Common stock, par value	$ 0.001	$ 0.001
Common stock, shares authorized	300,000,000	300,000,000
Common stock, shares issued	129,444,042	113,264,918
Treasury shares	306,061	260,124

XML

Consolidated Statements of Operations - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Operating revenues:
Oil sales	$ 1,539,917	$ 2,189,072	$ 1,938,433
Natural gas sales	263,656	471,075	381,486
Total operating revenues	1,803,573	2,660,147	2,319,919
Operating costs and expenses:
Oil and natural gas production	541,359	538,374	455,436
Exploration and abandonments	58,847	284,821	109,549
Depreciation, depletion and amortization	1,223,253	979,740	772,608
Accretion of discount on asset retirement obligations	7,600	7,072	6,047
Impairments of long-lived assets	60,529	447,151	65,375
General and administrative (including non-cash stock-based compensation of $63,073, $47,130 and $35,078 for the years ended December 31, 2015, 2014 and 2013, respectively)	230,734	204,161	169,815
(Gain) loss on derivatives	(699,752)	(890,917)	123,652
Total operating costs and expenses	1,422,570	1,570,402	1,702,482
Income from operations	381,003	1,089,745	617,437
Other income (expense):
Interest expense	(215,384)	(216,661)	(218,581)
Loss on extinguishment of debt	0	(4,316)	(28,616)
Loss on disposition of assets, net	(53,789)	(9,308)	(1,268)
Other, net	(14,559)	(3,500)	(11,813)
Total other expense	(283,732)	(233,785)	(260,278)
Income from continuing operations before income taxes	97,271	855,960	357,159
Income tax expense	(31,371)	(317,785)	(118,237)
Income from continuing operations	65,900	538,175	238,922
Income from discontinued operations, net of tax	0	0	12,081
Net income	$ 65,900	$ 538,175	$ 251,003
Basic earnings per share:
Income from continuing operations	$ 0.54	$ 4.89	$ 2.28
Income from discontinued operations, net of tax	0	0	0.11
Net income	0.54	4.89	2.39
Diluted earnings per share:
Income from continuing operations	0.54	4.88	2.28
Income from discontinued operations, net of tax	0	0	0.11
Net income	$ 0.54	$ 4.88	$ 2.39

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Consolidated Statements of Operations (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Statement [Abstract]
Non-cash stock-based compensation	$ 63,073	$ 47,130	$ 35,078

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Consolidated Statement of Stockholders Equity - USD ($) $ in Thousands	Total	Common Stock [Member]	Additional Paid In Capital [Member]	Retained Earnings [Member]	Treasury Stock [Member]
BALANCE at Dec. 31, 2012	$ 3,466,196	$ 105	$ 1,982,714	$ 1,490,563	$ (7,186)
BALANCE, Shares at Dec. 31, 2012		104,668,000			87,000
Net income	251,003	$ 0	0	251,003	$ 0
Stock options exercised	$ 3,223	$ 0	3,223	0	$ 0
Stock options exercised, shares	174,342	174,000			0
Grants of restricted stock, shares	499
Cancellation of restricted stock, shares		(118,000)			0
Stock-based compensation	$ 35,078	$ 0	35,078	0	$ 0
Excess tax benefits related to stock-based compensation	6,147	0	6,147	0	0
Purchase of treasury stock	(3,698)	$ 0	0	0	$ (3,698)
Purchase of treasury stock, shares		0			40,000
BALANCE at Dec. 31, 2013	3,757,949		2,027,162	1,741,566	$ (10,884)
BALANCE, Shares at Dec. 31, 2013		105,223,000			127,000
Net income	538,175	$ 0	0	538,175	$ 0
Issuance of common stock (Shares)		7,475,000
Issuance of common stock	931,989	$ 7	931,982
Stock options exercised	$ 4,659	$ 1	4,658	0	$ 0
Stock options exercised, shares	207,824	208,000			0
Grants of restricted stock, shares	448
Cancellation of restricted stock, shares		(89,000)			0
Stock-based compensation	$ 47,130	$ 0	47,130	0	$ 0
Excess tax benefits related to stock-based compensation	16,480	0	16,480	0	0
Purchase of treasury stock	(15,594)	$ 0	0	0	$ (15,594)
Purchase of treasury stock, shares		0			133,000
BALANCE at Dec. 31, 2014	5,280,788	$ 113	3,027,412	2,279,741	$ (26,478)
BALANCE, Shares at Dec. 31, 2014		113,265,000			260,000
Net income	65,900	$ 0	0	65,900	$ 0
Issuance of common stock (Shares)		15,755,000
Issuance of common stock	1,535,712	$ 16	1,535,696
Stock options exercised	$ 59	$ 0	59	0	$ 0
Stock options exercised, shares	4,812	5,000			0
Grants of restricted stock, shares	452,436
Cancellation of restricted stock, shares		(33,000)			0
Stock-based compensation	$ 63,073	$ 0	63,073	0	$ 0
Excess tax benefits related to stock-based compensation	2,150	0	2,150	0	0
Purchase of treasury stock	(5,131)	$ 0	0	0	$ (5,131)
Purchase of treasury stock, shares		0			46,000
BALANCE at Dec. 31, 2015	$ 6,942,551	$ 129	$ 4,628,390	$ 2,345,641	$ (31,609)
BALANCE, Shares at Dec. 31, 2015		129,444,000			306,000

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Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$ 65,900	$ 538,175	$ 251,003
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	1,223,253	979,740	772,608
Accretion of discount on asset retirement obligations	7,600	7,072	6,047
Impairments of long-lived assets	60,529	447,151	65,375
Exploration and abandonments, including dry holes	43,737	265,064	80,714
Non-cash stock-based compensation expense	63,073	47,130	35,078
Deferred income taxes	29,622	296,167	102,427
Loss on disposition of assets and other	53,789	9,308	1,268
(Gain) loss on derivatives	(699,752)	(890,917)	123,652
Discontinued operations	0	0	(12,250)
Other non-cash items	14,639	18,379	19,720
Changes in operating assets and liabilities, net of acquisitions and dispositions:
Accounts receivable	117,716	(104,988)	(40,009)
Prepaid costs and other	(3,726)	(23,628)	4,945
Inventory	(5,154)	2,441	509
Accounts payable	(17,689)	1,566	(18,469)
Revenue payable	(68,311)	60,481	28,593
Other current liabilities	12,279	20,646	(59,191)
Net cash provided by operating activities	897,505	1,673,787	1,362,020
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures on oil and natural gas properties	(2,443,704)	(2,554,914)	(1,850,992)
Additions to property, equipment and other assets	(67,699)	(34,320)	(28,678)
Proceeds from the disposition of assets	104	1,305	15,217
Contributions to equity method investments	(91,342)	(30,050)	0
Settlements received from (paid on) derivatives	632,916	71,983	(32,341)
Net cash used in investing activities	(1,969,725)	(2,545,996)	(1,896,794)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of debt	1,490,900	2,081,000	3,257,575
Payments of debt	(1,630,400)	(2,191,500)	(2,729,700)
Exercise of stock options	59	4,659	3,223
Excess tax benefit from stock-based compensation	2,150	16,480	6,147
Net proceeds from issuance of common stock	1,535,712	931,989	0
Payments for loan costs	0	(10,648)	(14,075)
Purchase of treasury stock	(5,131)	(15,594)	(3,698)
Increase (decrease) in bank overdrafts	(92,541)	55,823	12,443
Net cash provided by financing activities	1,300,749	872,209	531,915
Net increase (decrease) in cash and cash equivalents	228,529	0	(2,859)
Cash and cash equivalents at beginning of period	21	21	2,880
Cash and cash equivalents at end of period	228,550	21	21
SUPPLEMENTAL CASH FLOWS:
Cash paid for interest	211,443	211,342	200,961
Cash paid for income taxes	$ 3,950	$ 27,844	$ 21,376

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Organization and nature of operations

12 Months Ended

Dec. 31, 2015

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Organization and nature of operations

Note 1. Organization and nature of operations

Concho Resources Inc. (the “Company”) is a Delaware corporation formed on February 22, 2006. The Company’s principal business is the acquisition, development and exploration of oil and natural gas properties primarily located in the Permian Basinof Southeast New Mexico and West Texas.

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Summary of significant accounting policies

12 Months Ended

Dec. 31, 2015

Accounting Policies [Abstract]

Summary of significant accounting policies

Note 2. Summary of significant accounting policies

Principles of consolidation. The consolidated financial statements of the Company include the accounts of the Company and its 100 percent owned subsidiaries. The Company consolidates the financial statements of these entities. All material intercompany balances and transactions have been eliminated.

Retrospective adjustments and reclassifications. Certain reclassifications have been made to the 2014 amounts in order to conform to the 2015 presentation and for the retrospective application resulting from the early adoption of Accounting Standards Update (“ASU”) No. 2015-03 and 2015-17. The retrospective application of ASU 2015-03 resulted in $48.2 million of net deferred loan costs directly related to the Company’s senior notes being reclassified from a noncurrent asset to a direct deduction from thecarrying amount of the related senior notesat December 31, 2014. The retrospective application of ASU 2015-17 resulted in the current deferred income tax liability of $162.6 million at December 31, 2014 to be reclassified as a noncurrent deferred income tax liability in the Company’s consolidated balance sheet.

Other certain prior period amounts have been reclassified to conform to the 2015 presentation. These reclassifications had no impact on the balance sheet, net income (loss) or cash flows.

Discontinued operations. In December 2012, the Company closed the sale of certain of its non-core assets for cash consideration of approximately $503.1 million, which resulted in a pre-tax gain of approximately $0.9 million. As a result of post-closing adjustments during the year ended December 31,2013, the Company made a positive adjustment to gain (loss) on disposition of assets of approximately $19.6 million, before income tax expense of approximately $7.5 million. The Company recognized income from discontinued operations, net of tax of $12.1 million for the year ended December 31,2013.

Use of estimates in the preparation of financial statements. Preparation of financial statements in conformity with generally accepted accounting principles in the United States of America (“U.S. GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from these estimates. Depletion of oil and natural gas properties is determined using estimates of proved oil and natural gas reserves. There are numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. Similarly, evaluations for impairment of proved and unproved oil and natural gas properties are subject to numerous uncertainties including, among others, estimates of future recoverable reserves, commodity price outlooks and prevailing market rates of other sources of income and costs. Other significant estimates include, but are not limited to, asset retirement obligations, fair value of derivative financial instruments, fair value of business combinations,fair value of nonmonetary exchanges, fair value of stock-based compensation and income taxes.

Cash equivalents. The Company considers all cash on hand, depository accounts held by banks, money market accounts and investments with an original maturity of three months or less to be cash equivalents. The Company’s cash and cash equivalents are held in financial institutions in amounts that exceed the insurance limits of the Federal Deposit Insurance Corporation. However, management believes that the Company’s counterparty risks are minimal based on the reputation and history of the institutions selected.

Accounts receivable. The Company sells oil and natural gas to various customers and participates with other parties in the drilling, completion and operation of oil and natural gas wells. Joint interest and oil and natural gas sales receivables related to these operations are generally unsecured. The Company determines joint interest operations accounts receivable allowances based on management’s assessment of the creditworthiness of the joint interest owners and the Company’s ability to realize the receivables through netting of anticipated future production revenues. Receivables are considered past due if full payment is not received by the contractual due date. Past due accounts are generally written off against the allowance for doubtful accounts only after all collection attempts have been exhausted. The Company had an allowance for doubtful accounts of approximately $1.2million and $0.7million at December 31,2015 and December 31,2014, respectively.

Inventory. Inventory consists primarily of tubular goods, water and other oilfield equipment that the Company plans to utilize in its ongoing exploration and development activities and is carried at the lower of cost or market value, on a weighted average cost basis.

Deferred loan costs.Deferred loan costs are stated at cost, net of amortization, which is computed using the effective interest method and straight-line methods. For the interim period ended December 31, 2015, the Company early adopted ASU No. 2015-03, “Interest-Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs,” which requires net deferred loan costs directly related to the Company’s senior notes to be classified as a direct deduction from the carrying amount of the related senior notes. The Company retrospectively adopted the ASU and reclassified $48.2million at December 31, 2014from a noncurrent asset to a deduction from long-term debt. The deferred loan costs related to the Company’s credit facility remain classified as a noncurrent asset due to the revolving nature of that facility. The provisions of the ASU were adopted primarily to simplify the required reporting for subsequent registration filings. The Company had deferred loan costs related to its senior notes of $42.9million and $48.2million, net of accumulated amortization of $18.7million and $13.4million, as a reduction of long-term debt at December 31, 2015 and December 31,2014, respectively.

The Company had deferred loan costs related to the credit facility of $15.6million and $20.3million, net of accumulated amortization of $51.0million and $46.3million, in noncurrent assets at December 31, 2015 and December 31,2014, respectively.

Oil and natural gas properties. The Company utilizes the successful efforts method of accounting for its oil and natural gas properties. Under this method all costs associated with productive wells and nonproductive development wells are capitalized, while nonproductive exploration costs are expensed. Capitalized acquisition costs relating to proved properties are depleted using the unit-of-production method based on proved reserves. The depletion of capitalized drilling and development costs and integrated assets is based on the unit-of-production method using proved developed reserves. During the years ended December 31, 2015, 2014 and 2013, the Company recognized depletion expensefrom continuing operations of $1,203.5 million, $960.9 million and $756.0 million, respectively.

The Company generally does not carry the costs of drilling an exploratory well as an asset in its consolidated balance sheets following the completion of drilling unless both of the following conditions are met:

• the well has found a sufficient quantity of reserves to justify its completion as a producing well; and
• the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project.

Due to the capital intensive nature and the geographical location of certain projects, it may take the Company longer than one year to evaluate the future potential of the exploration well and economics associated with making a determination on its commercial viability. In these instances, the project’s feasibility is not contingent upon price improvements or advances in technology, but rather the Company’s ongoing efforts and expenditures related to accurately predicting the hydrocarbon recoverability based on well information, gaining access to other companies’ production, transportation or processing facilities and/or getting partner approval to drill additional appraisal wells. These activities are ongoing and being pursued constantly. Consequently, the Company’s assessment of suspended exploratory well costs is continuous until a decision can be made that the well has found proved reserves or is noncommercial and is charged to exploration and abandonments expense. See Note 3 for additional information regarding the Company’s suspended exploratory well costs.

Proceeds from the sales of individual properties and the capitalized costs of individual properties sold or abandoned are credited and charged, respectively, to accumulated depletion. Generally, no gain or loss is recognized until the entire depletion base is sold. However, gain or loss is recognized from the sale of less than an entire depletion base if the disposition is significant enough to materially impact the depletion rate of the remaining properties in the depletion base. Ordinary maintenance and repair costs are expensed as incurred.

Costs of significant nonproducing properties, wells in the process of being drilled and completed and development projects are excluded from depletion until the related project is completed and proved developed reserves are established or, if unsuccessful, impairment is determined. The Company capitalizes interest, if debt is outstanding, on expenditures for significant development projects until such projects are ready for their intended use. During the years ended December 31, 2015 and 2014, the Company had capitalized interest of $0.7 million and $1.4 million, respectively. The Company did not capitalize interest during 2013.

The Company reviews its long-lived assets to be held and used, including proved oil and natural gas properties, whenever events or circumstances indicate that the carrying value of those assets may not be recoverable. An impairment loss is indicated if the sum of the expected future cash flows is less than the carrying amount of the assets. In this circumstance, the Company recognizes an impairment loss for the amount by which the carrying amount of the asset exceeds the estimated fair value of the asset. The Company reviews its oil and natural gas properties by depletion base or by individual well for those wells not constituting part of a depletion base. For each property determined to be impaired, an impairment loss equal to the difference between the carrying value of the properties and the estimated fair value (discounted future cash flows) of the properties and integrated assets would be recognized at that time. Estimating future cash flows involves the use of judgments, including estimation of the proved and risk-adjusted unproved oil and natural gas reserve quantities, timing of development and production, expected future commodity prices, capital expenditures and production costs and cash flows from integrated assets. The Company recognized impairment expense of $60.5 million, $447.2 million, and $65.4 million during the years ended December 31, 2015, 2014and 2013, respectively, related to its proved oil and natural gas properties.

Unproved oil and natural gas properties are each periodically assessed for impairment by considering future drilling plans, the results of exploration activities, commodity price outlooks, planned future sales or expiration of all or a portion of such projects. During the years ended December 31, 2015, 2014 and 2013, the Company recognized expense of $34.5million, $217.3 million and $49.8 million, respectively, related to abandoned prospects and expiring acreage, which is included in exploration andabandonments expensein the accompanying consolidated statements of operations.

Other property and equipment.  Other capital assets include buildings, transportation equipment, computer equipment and software, telecommunications equipment, leasehold improvements and furniture and fixtures. These items are recorded at cost, or fair value if acquired, and are depreciated using the straight-line method based on expected lives of the individual assets or group of assets ranging from two to 31 years.The Company had other capital assets of $178.5 million and $129.1 million, net of accumulated depreciation of $54.4 million and $52.5 million, at December 31, 2015 and December 31,2014, respectively. During the years ended December 31, 2015, 2014 and 2013, the Company recognized depreciation expense of $18.3 million, $17.3 million and $15.2 million, respectively.

Intangible assets. The Company has capitalized certain operating rights acquired in an acquisition. The gross operating rights, which have no residual value, are amortized over the estimated economic life of 25 years. Impairment will be assessed if indicators of potential impairment exist or when there is a material change in the remaining useful economic life. The following table reflects the gross and net intangible assets at December 31, 2015 and 2014, respectively:

			December 31,
(in thousands)			2015		2014
Gross intangible - operating rights		$	36,557	$	36,557
Accumulated amortization			(10,864)		(9,403)
	Net intangible - operating rights	$	25,693	$	27,154

The following table reflects amortization expense from continuing operations for the years ended December 31, 2015, 2014 and 2013:

	Years Ending December 31,
(in thousands)	2015		2014		2013
Amortization expense	$	1,461	$	1,461	$	1,461

The following table reflects the estimated aggregate amortization expense for each of the periods presented below at December 31,2015:

(in thousands)
2016		$	1,461
2017			1,461
2018			1,461
2019			1,461
2020			1,461
Thereafter			18,388
	Total	$	25,693

Equity method investments.The Company owns a 50 percent member interest in a midstream joint venture, Alpha Crude Connector, LLC (“ACC”), to construct a crude oil gathering and transportation system in the northern Delaware Basin. The Company has the option to purchase the member interest of the other investor in ACC. This purchase option becomes exercisable three months after the completion date of the pipeline and remains exercisable for a period of twelve months.The Company accounts for its investment in ACC under the equity method of accounting for investments in unconsolidated affiliates. The Company’s net investment in ACC wasapproximately $98.9 million and $29.5 million at December 31, 2015 and December 31, 2014, respectively, and was included in other assets in the Company’s consolidated balance sheet. The equity loss for the years ended December 31, 2015 and 2014 was approximately $4.1 million and $1.3 million, respectively, and was included in other expense in the Company’s consolidated statement of operations. During2015 and 2014,the Company recorded approximately $2.9 million and $0.7 million, respectively, of capitalized interest on its investment in ACC. ACC started partial operations in late 2015. The Company expects the system to be fully operational during 2016.

During 2015, the Company purchased a 25 percent member interest in an entity, which is constructing a crude oil gathering and transportation system in the southern Delaware Basin. The system is expected to be completed and operational during 2016. The Company accounts for its investment under the equity method of accounting for investments in unconsolidated affiliates. The Company’s net investment is approximately $20.8 million at December 31, 2015 and is included in other assets in the Company’s consolidated balance sheet.

Environmental. The Company is subject to extensive federal, state and local environmental laws and regulations. These laws, which are often changing, regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures of a noncapital nature are recorded when environmental assessment and/or remediation is probable and the costs can be reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash payments is fixed and readily determinable. At December 31, 2015 and 2014, the Company has accrued approximately $1.0million and $1.7 million, respectively, related to environmental liabilities. During the years ended December 31, 2015, 2014 and 2013, the Company recognized environmental charges of approximately $2.7million, $4.0 million and $3.4 million, respectively.

Derivative instruments. The Company recognizes its derivative instruments, other than any commodity derivative contracts that are designated as normal purchase and normal sale, as either assets or liabilities measured at fair value. The Company netted the fair value of derivative instruments by counterparty in the accompanying consolidated balance sheets where the right of offset exists. The Company did not have any derivatives designated as fair value or cash flow hedges during the years ended December 31, 2015, 2014 or 2013.The Company may also enter into physical delivery contracts to effectively provide commodity price hedges. Because these contracts are not expected to be net cash settled, they are considered to be normal sales contracts and not derivatives. Therefore, these contracts are not recorded in the Company’s consolidated financial statements.

Asset retirement obligations. The Company records the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. Subsequently, the asset retirement cost included in the carrying amount of the related asset is allocated to expense through depletion of the asset. Changes in the liability due to passage of time are generally recognized as an increase in the carrying amount of the liability and as corresponding accretion expense. Based on certain factors including commodity prices and costs, the Company may revise its previous estimates related to the liability, which would also increase or decrease the associated oil and gas property asset.

Treasury stock. Treasury stock purchases are recorded at cost.

Revenue recognition. Oil and natural gas revenues are recorded at the time of physical transfer of such products to the purchaser, which for the Company is primarily at the wellhead. The Company follows the sales method of accounting for oil and natural gas sales, recognizing revenues based on the Company’s actual proceeds from the oil and natural gas sold to purchasers.

Oil and natural gas imbalances.Oil and natural gas imbalances are generated on properties for which two or more owners have the right to take production “in-kind” and, in doing so, take more or less than their respective entitled percentage. Imbalances are tracked by well, but the Company does not record any receivable from or payable to the other owners unless the imbalance has reached a level at which it exceeds the remaining reserves in the respective well. If reserves are insufficient to offset the imbalance and the Company is in an overtake position, a liability is recorded for the amount of shortfall in reserves valued at a contract price or the market price in effect at the time the imbalance is generated. If the Company is in an undertake position, a receivable is recorded for an amount that is reasonably expected to be received, not to exceed the current market value of such imbalance. The Company had no significant imbalances at December 31, 2015 or 2014.

General and administrative expense. The Company receives fees for the operation of jointly-owned oil and natural gas properties and records such reimbursements as reductions of general and administrative expense. Such fees totaled approximately $24.3million, $23.2 million and $18.5 million for the years ended December 31, 2015, 2014 and 2013, respectively.

Stock-based compensation.For stock-based compensation awards granted, stock-based compensation expense is being recognized in the Company’s financial statements on anaccelerated basis over the awards’ vesting periods based on their fair values on the dates of grant. The stock-based compensation awards generally vest over a period ranging from one to five years. The Company utilizes (i) the Black-Scholes option pricing model to measure the fair value of stock options, (ii) the average of the grant date’s high and low stock prices for the fair value of restricted stock and (iii) the Monte Carlo simulation method for the fair value of performance unit awards.

Income taxes.In November 2015, the FASB issued ASU No. 2015-17, “Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes,” which requires that all deferred tax assets and liabilities, along with any related valuation allowance, be classified as noncurrent on the balance sheet. The Company early adopted the ASU retrospectively for the interim period ended December 31, 2015, which resulted in its current deferred income tax liability of $162.6 million at December 31, 2014 to be reclassified as a noncurrent deferred income tax liability in the Company’s consolidated balance sheet. The provisions of the ASU were adopted primarily to simplify the required reporting for subsequent registration filings. The Company previously classified deferred income tax liabilities and assets separately to current and noncurrent.

The Company recognizes deferred tax assets and liabilities for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rate is recognized in income in the period that includes the enactment date. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized.

The Company evaluates uncertain tax positions for recognition and measurement in the consolidated financial statements. To recognize a tax position, the Company determines whether it is more likely than not that the tax positions will be sustained upon examination, including resolution of any related appeals or litigation, based on the technical merits of the position. A tax position that meets the more likely than not threshold is measured to determine the amount of benefit to be recognized in the consolidated financial statements. The amount of tax benefit recognized with respect to any tax position is measured as the largest amount of benefit that is greater than 50 percent likely of being realized upon settlement. The Company had no material uncertain tax positions that required recognition in the consolidated financial statements at December 31, 2015 and 2014. Any interest or penalties would be recognized as a component of income tax expense.

Recent accounting pronouncements.In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606),” which outlines a new, single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. This new revenue recognition model provides a five-step analysis in determining when and how revenue is recognized. The new model will require revenue recognition to depict the transfer of promised goods or services to customers in an amount that reflects the consideration a company expects to receive in exchange for those goods or services.

In August 2015, the FASB issued ASU No. 2015-14, “Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date,” which deferred the effective date of ASU 2014-09 by one year. That new standard is now effective for annual reporting periods beginning after December 15, 2017. An entity can apply ASU 2014-09 using either a full retrospective method, meaning the standard is applied to all of the periods presented, or a modified retrospective method, meaning the cumulative effect of initially applying the standard is recognized in the most current period presented in the financial statements. The Company is evaluating the impact that this new guidance will have on its consolidated financial statements.

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Exploratory well costs

12 Months Ended

Dec. 31, 2015

Disclosure Exploratory Well Costs Capitalized Exploratory Well Activity [Abstract]

Exploratory well costs

Note 3.Exploratory well costs

The Company capitalizes exploratory well costs until a determination is made that the well has either found proved reserves or that it is impaired. The capitalized exploratory well costs are carried in unproved oil and natural gas properties. See Unaudited Supplementary Data for the proved and unproved components of oil and natural gas properties. If the exploratory well is determined to be impaired, the well costs are charged to exploration and abandonments expense in the consolidated statements of operations. 

The following table reflects the Company’s net capitalized exploratory well activity during each of the years ended December 31,2015, 2014 and 2013:

		Years Ended December 31,
(in thousands)		2015		2014		2013
Beginning capitalized exploratory well costs		$	241,657	$	144,504	$	118,806
	Additions to exploratory well costs pending the determination of proved reserves		102,846		234,057		130,967
	Reclassifications due to determination of proved reserves		(227,746)		(99,657)		(94,114)
	Exploratory well costs charged to expense		(559)		(37,247)		(11,155)
Ending capitalized exploratory well costs		$	116,198	$	241,657	$	144,504

The following table provides an aging at December 31,2015 and 2014 of capitalized exploratory well costs based on the date drilling was completed:

			December 31,
(dollars in thousands)			2015		2014
Capitalized exploratory well costs that have been capitalized for a period of one year or less		$	98,764	$	232,346
Capitalized exploratory well costs that have been capitalized for a period greater than one year			17,434		9,311
	Total capitalized exploratory well costs	$	116,198	$	241,657
Number of projects with exploratory well costs that have been capitalized for a period greater
	than one year		8		7

Delaware Basin projects. At December 31, 2015, the Company had approximately $7.2millionof suspended well costs greater than one year recorded for two wells that were initially drilled to monitor nearby wells and areadditionally being used to determine the productivity potential of additional zones. At December 31, 2015, the Company also had approximately $5.7millionof suspended well costs greater than one year recorded for a well spud in late 2014 that is testing multiple zones and is expected to be completed in the first half of 2016. All three wells completed drilling in 2014.

Projects operated by others. At December 31, 2015, the Company had approximately $4.5millionof suspended well costs greater than one year recorded for five wells that are operated by others and waiting on completion.

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Acquisitions and business combinations

12 Months Ended

Dec. 31, 2015

Business Combinations [Abstract]

Acquisitions and business combinations

Note 4. Acquisition and divestiture

Clayton Williams Acreage Exchange. In December 2015, the Company completed a nonmonetary acreage exchange with Clayton Williams Energy, Inc. that consolidated acres into a concentrated, operated position in the southern Delaware Basin. The Company recognized a loss on disposition of assets of approximately $50.0 million related to the acreage exchange based on the fair value of the assets surrendered, which is presented in loss on disposition of assets, net, in the consolidated statement of operations for the year ended December 31, 2015.

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Asset retirement obligations

12 Months Ended

Dec. 31, 2015

Asset Retirement Obligation Disclosure [Abstract]

Asset retirement obligations

Note 5. Asset retirement obligations

The Company’s asset retirement obligations represent the estimated present value of the estimated cash flows the Company will incur to plug, abandon and remediate its producing properties at the end of their productive lives, in accordance with applicable state laws. Market risk premiums associated with asset retirement obligations are estimated to represent a component of the Company’s credit-adjusted risk-free rate that is utilized in the calculations of asset retirement obligations.

The Company’s asset retirement obligation transactions during the years ended December 31, 2015, 2014 and 2013are summarized in the table below:

		Years Ended December 31,
(in thousands)			2015		2014		2013
Asset retirement obligations, beginning of period		$	119,881	$	101,593	$	86,261
	Liabilities incurred from new wells		4,052		5,324		6,338
	Liabilities assumed in acquisitions		2,434		4,065		593
	Accretion expense		7,600		7,072		6,047
	Liabilities settled upon plugging and abandoning wells		(2,736)		(2,926)		(3,447)
	Revision of estimates (a)		(11,286)		4,753		5,801
Asset retirement obligations, end of period		$	119,945	$	119,881	$	101,593
(a)	The downward revision to the Company’s asset retirement obligation estimates for the year ended December 31, 2015 is primarily due to a reduction in the future estimated abandonment costs.

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Incentive plans

12 Months Ended

Dec. 31, 2015

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Incentive plans

Note 6. Incentive plans

Defined contribution plan. The Company sponsors a 401(k) defined contribution plan for the benefit of substantially all employees. During the years ended December 31,2015,2014 and 2013, the Company matched 100 percent of employee contributions, not to exceed 10 percent of the employee’s annual salary. The Company’s contributions to the plan for the years ended December 31,2015,2014 and 2013 were approximately $9.5 million, $8.1 million and $6.6 million, respectively, of which a portion was recoverable from other working interest owners.

Stock incentive plan. The Company’s 2015 Stock Incentive Plan (the “Plan”) provides for granting stock options, restricted stock awards and performance awards to directors, officers and employees of the Company. A total of 10.5 million shares of common stock have been authorized for issuance under the Plan. At December 31, 2015, the Company had 2.9 million shares of common stockavailable for future grant.

Restricted stock awards.All restricted shares are legally issued and outstanding. If an employee terminates employment prior to the restriction lapse date, the awarded shares are forfeited and cancelled and are no longer considered issued and outstanding. A summary of the Company’s restricted stock award activity for the yearended December 31,2015is presented below:

				Weighted
				Average
			Number of	Grant Date
			Restricted	Fair Value
			Shares	Per Share
Restricted stock:
	Outstanding at December 31, 2014		1,091,309		$	106.33
		Shares granted	452,436		$	109.76
		Shares cancelled / forfeited	(33,124)		$	111.08
		Lapse of restrictions	(310,974)		$	96.15
	Outstanding at December 31, 2015		1,199,647		$	110.14

For restricted stock awards granted, stock-based compensation expense is being recognized in the Company’s financial statements on anaccelerated basis over the awards’ vesting periods based on their fair values on the dates of grant. The restricted stock-based compensation awards generally vest over a period ranging from one to five years. The Company utilizes the average of the grant date’s high and low stock prices for the fair value of restricted stock.

The following table summarizes information about stock-based compensation for the Company’s restricted stock awards activity under the Plan for years ended December 31, 2015, 2014 and 2013:

		Years Ended December 31,
(in thousands)			2015		2014		2013
Fair value for awards granted during the period (a)		$	49,659	$	57,940	$	44,947
Fair value for awards vested during the period		$	35,700	$	59,226	$	21,496
Stock-based compensation expense from restricted stock		$	43,185	$	36,585	$	30,984
Income tax benefit related to restricted stock		$	16,049	$	13,672	$	11,650
(a)	The weighted average grant date fair value per share amounts were $109.76, $129.12 and $88.19 for the years ended December 31, 2015, 2014 and 2013, respectively. The year ended December 31, 2013 includes the effects of $1 million due to modifications of certain stock-based awards.

Stock option awards.  A summary of the Company’s stock option award activity under the Plan for the years ended December 31,2015, 2014 and 2013is presented below:

			Years Ended December 31,
			2015			2014			2013
					Weighted			Weighted			Weighted
					Average			Average			Average
			Number of		Exercise	Number of		Exercise	Number of		Exercise
			Options		Price	Options		Price	Options		Price
Stock options:
	Outstanding at beginning of period		47,713	$	17.49	255,537	$	21.50	429,879	$	20.28
		Options exercised	(4,812)	$	12.00	(207,824)	$	22.42	(174,342)	$	18.48
	Outstanding at end of period		42,901	$	18.10	47,713	$	17.49	255,537	$	21.50
	Vested and exercisable at end of period		42,901	$	18.10	47,713	$	17.49	255,537	$	21.50

The intrinsic value of options exercised during 2015, 2014 and 2013 was approximately $0.4 million, $23.2million and $13.2 million, respectively, based on the difference between the market price at the exercise date and the option exercise price.

The following table summarizes information about the Company’s vested and exercisablestock options outstanding at December 31,2015:

December 31, 2015
			Weighted				Intrinsic
			Average		Weighted		Value
	Range of		Remaining		Average		of
	Exercise	Number	Contractual		Exercise		Options
	Prices	Vested	Life		Price		(in thousands)
Vested and exercisable options:
	$12.00 - $12.85	15,824	1.54 years	$	12.81		1,267
	$20.40 - $22.77	27,077	2.98 years	$	21.20		1,940
		42,901	2.45 years	$	18.10	$	3,207

The following table shows the deductions in current taxable income related to stock options exercised for the years ended December 31,2015, 2014 and 2013:

		Years Ended December 31,
(in thousands)				2015		2014		2013
	Deductions in current taxable income related to stock options exercised		$	415	$	23,208	$	13,193

Performance unit awards. During the years ended December 31,2015, 2014 and 2013, the Company awarded performance units to its officers under the Plan. The number of shares of common stock that will ultimately be issued will be determined by a combination of (i) comparing the Company’s total shareholder return relative to the total shareholder return of a predetermined group of peer companies at the end of the performance period and (ii) the Company’s absolute total shareholder return at the end of the performance period. The performance period is 36 months. The grant date fair value was determined using the Monte Carlo simulation method and is being expensed ratably over the performance period. Expected volatilities utilized in the model were estimated using a historical period consistent with the remaining performance period of approximately three years. The risk-free interest rate was based on the United States Treasury rate for a term commensurate with the expected life of the grant.

The Company used the following assumptions to estimate the fair value of performance unit awards granted during the years ended December 31,2015, 2014 and 2013:

	Years Ended December 31,
	2015	2014	2013
Risk-free interest rate	1.07%	0.76%	0.37%
Range of volatilities	26.1% - 43.0%	29.2% - 42.2%	31.5% - 45.1%

The following table summarizes the performance unit activity for the year ended December 31,2015:

			Number of		Grant Date
			Units		Fair Value
Performance units:
	Outstanding at December 31, 2014		250,314	$	127.07
		Units granted (a)	176,330	$	156.86
		Units vested (b)	(110,889)	$	111.40
	Outstanding at December 31, 2015		315,755	$	149.21
(a)	Reflects the amount of performance units granted. The actual payout of shares will be between zero and 300 percent of the performance units granted depending on the Company’s performance at the end of the performance period.
(b)	On December 31, 2015, the performance period ended for these performance units. Each unit converted into 1.625 shares representing 180,199 shares of common stock issued on January 4, 2016.

The following table summarizes information about stock-based compensation expense for performance units for the years ended December 31,2015, 2014 and 2013:

	Years Ended December 31,
(in thousands)		2015		2014		2013
Fair value for awards granted during the period	$	27,659	$	19,455	$	12,352
Stock-based compensation expense from performance units	$	19,888	$	10,545	$	4,080
Income tax benefit related to performance units	$	7,391	$	3,941	$	1,560

Future stock-based compensation expense. The following table reflects the future stock-based compensation expense to be recorded for all the stock-based compensation awards that were outstanding at December 31,2015:

			Restricted		Performance
(in thousands)			Stock		Units		Total
2016		$	31,992	$	15,734	$	47,726
2017			18,189		9,219		27,408
2018			6,466		-		6,466
2019			286		-		286
2020			4		-		4
	Total	$	56,937	$	24,953	$	81,890

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Disclosures about fair value of financial instruments

12 Months Ended

Dec. 31, 2015

Fair Value Disclosures [Abstract]

Disclosures about fair value of financial instruments

Note 7. Disclosures about fair value measurements

The Company uses a valuation framework based upon inputs that market participants use in pricing an asset or liability, which are classified into two categories: observable inputs and unobservable inputs. Observable inputs represent market data obtained from independent sources, whereas unobservable inputs reflect a company’s own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. These two types of inputs are further prioritized into the following fair value input hierarchy:

Level 1:Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. The Company considers active markets to be those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2:Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes those derivative instruments that the Company values using observable market data. Substantially all of these inputs are observable in the marketplace throughout the full term of the derivative instrument, can be derived from observable data, or supported by observable levels at which transactions are executed in the marketplace. Level 2 instruments primarily include non-exchange traded derivatives such as over-the-counter commodity price swaps, basis swaps, collars and floors, investments and interest rate swaps. The Company’s valuation models are primarily industry-standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value, (iii) current market and contractual prices for the underlying instruments and (iv) volatility factors, as well as other relevant economic measures.

Level 3:Measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources (i.e., supported by little or no market activity). The Company’s valuation models are primarily industry-standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value, (iii) volatility factors and (iv) current market and contractual prices for the underlying instruments, as well as other relevant economic measures.

Financial Assets and Liabilities Measured at Fair Value

The following table presents the carrying amounts and fair values of the Company’s financial instruments at December 31,2015 and 2014:

		December 31, 2015				December 31, 2014
		Carrying		Fair		Carrying		Fair
(in thousands)		Value		Value		Value		Value
Assets:
	Derivative instruments	$	819,536	$	819,536	$	752,700	$	752,700
Liabilities:
	Credit facility	$	-	$	-	$	139,500	$	131,068
	$600 million 7.0% senior notes due 2021 (a)	$	592,414	$	595,500	$	591,213	$	625,500
	$600 million 6.5% senior notes due 2022 (a)	$	591,549	$	579,000	$	590,454	$	628,500
	$600 million 5.5% senior notes due 2022 (a)	$	592,899	$	553,500	$	592,061	$	598,500
	$1,550 million 5.5% senior notes due 2023 (a)	$	1,555,326	$	1,453,005	$	1,555,909	$	1,573,875
(a)	The carrying value includes associated deferred loan costs and any (discount) premium. See Note 2 for additional information regarding the Company’s retrospective adoption of ASU No. 2015-03.

Cash and cash equivalents, accounts receivable, other current assets, accountspayable, interest payable and other current liabilities. The carrying amounts approximate fair value due to the short maturity of these instruments.

Credit facility.  The fair value of the Company’s credit facility is estimated by discounting the principal and interest payments at the Company’s credit-adjusted discount rate at the reporting date, which utilizes inputs that are Level 2 measurements in the fair value hierarchy.

Senior notes. The fair values of the Company’s senior notes are based on quoted market prices. The debt securities are not actively traded and, therefore, are classified as Level 2 in the fair value hierarchy.

Derivative instruments. The fair value of the Company’s derivative instruments is estimated by management considering various factors, including closing exchange and over-the-counter quotations and the time value of the underlying commitments. Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. The following tables summarize (i) the valuation of each of the Company’s financial instruments by required fair value hierarchy levels and (ii) the gross fair value by the appropriate balance sheet classification,even when the derivative instruments are subject to netting arrangements and qualify for net presentation in the Company’s consolidated balance sheets at December 31,2015 and 2014. The Company nets the fair value of derivative instruments by counterparty in the Company’s consolidated balance sheets.

December 31, 2015
				Fair Value Measurements Using												Net
				Quoted Prices										Gross		Fair Value
				in Active				Significant						Amounts		Presented
				Markets for				Other		Significant				Offset in the		in the
				Identical				Observable		Unobservable				Consolidated		Consolidated
				Assets				Inputs		Inputs		Total		Balance		Balance
(in thousands)				(Level 1)				(Level 2)		(Level 3)		Fair Value		Sheet		Sheet
	Assets
		Current:
			Commodity derivatives		$	-	$	684,029	$	-	$	684,029	$	(31,531)	$	652,498
		Noncurrent:
			Commodity derivatives			-		175,267		-		175,267		(8,229)		167,038
	Liabilities
		Current:
			Commodity derivatives			-		(31,531)		-		(31,531)		31,531		-
		Noncurrent:
			Commodity derivatives			-		(8,229)		-		(8,229)		8,229		-
	Net derivative instruments				$	-	$	819,536	$	-	$	819,536	$	-	$	819,536

December 31, 2014
				Fair Value Measurements Using												Net
				Quoted Prices										Gross		Fair Value
				in Active				Significant						Amounts		Presented
				Markets for				Other		Significant				Offset in the		in the
				Identical				Observable		Unobservable				Consolidated		Consolidated
				Assets				Inputs		Inputs		Total		Balance		Balance
(in thousands)				(Level 1)				(Level 2)		(Level 3)		Fair Value		Sheet		Sheet
	Assets
		Current:
			Commodity derivatives		$	-	$	501,717	$	-	$	501,717	$	(11,366)	$	490,351
		Noncurrent:
			Commodity derivatives			-		262,349		-		262,349		-		262,349
	Liabilities
		Current:
			Commodity derivatives			-		(11,366)		-		(11,366)		11,366		-
		Noncurrent:
			Commodity derivatives			-		-		-		-		-		-
	Net derivative instruments				$	-	$	752,700	$	-	$	752,700	$	-	$	752,700

Concentrations of credit risk. At December 31, 2015, the Company’s primary concentration of credit risks are the risk of collecting accounts receivable and the risk of counterparties’ failure to perform under derivative obligations. See Note 12 for information regarding the Company’s major customers and derivative counterparties.

The Company has entered into International Swap Dealers Association Master Agreements (“ISDA Agreements”) with each of its derivative counterparties. The terms of the ISDA Agreements provide the Company and the counterparties with rights of set-off upon the occurrence of defined acts of default by either the Company or a counterparty to a derivative, whereby the party not in default may set off all derivative liabilities owed to the defaulting party against all derivative asset receivables from the defaulting party. See Note 8 for additional information regarding the Company’s derivative activities.

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

Certain assets and liabilities are reported at fair value on a nonrecurring basis in the Company’s consolidated balance sheets. The following methods and assumptions were used to estimate the fair values: 

Impairments of long-lived assets – The Company periodically reviewstheir long-lived assets to be held and used, including proved oil and natural gas properties and their integrated assets, whenever events or circumstances indicate that the carrying value of those assets may not be recoverable, for instance when there are declines in commodity prices or well performance. The Company reviewsits oil and natural gas properties by depletion base or by individual well for those wells not constituting part of a depletion base. An impairment loss is indicated if the sum of the expected undiscounted future net cash flows is less than the carrying amount of the assets. If the estimated undiscounted future net cash flows are less than the carrying amount of the Company’s assets, it recognizes an impairment loss for the amount by which the carrying amount of the asset exceeds the estimated fair value of the asset.

The Company calculates the expected undiscounted future net cash flows of its long-lived assets and its integrated assets using management’s assumptions and expectations of (i) commodity prices, which are based on the New York Mercantile Exchange (“NYMEX”) strip, (ii) pricing adjustments for differentials, (iii) production costs, (iv) capital expenditures, (v) production volumes, (vi) proved reserves and risk-adjusted probable and possible reserves, and (vii) other sources of income and expenses from integrated assets.

The Company calculates the estimated fair values of its long-lived assets and their integrated assets using a discounted future cash flow model. Fair value assumptions associated with the calculation of discounted future net cash flows include (i) market estimates of commodity prices, (ii) pricing adjustments for differentials, (iii) production costs, (iv) capital expenditures, (v) production volumes, (vi) estimated proved reserves and risk-adjusted probable and possible reserves, (vii) prevailing market rates of income and expenses from integrated assets and (viii) discount rate. The Company discounts the future net cash flows using a market-based weighted average cost of capital rate determined appropriate at the time. These are classified as Level 3 fair value assumptions.

As a result of the carrying amount of certain of the Company’s long-lived assets being less than their expected undiscounted future net cash flows, the Company recognized a non-cash charge against earnings for the amount by which the carrying amount exceeded the estimated fair value of the assets.The following table reports the carrying amount, estimated fair value and impairment expense of long-lived assets for the indicated periods:

				Estimated
		Carrying		Fair Value		Impairment
(in thousands)		Amount		(Level 3)		Expense
December 2015	$	104,982	$	52,041	$	52,941
September 2015	$	18,023	$	10,435	$	7,588
December 2014	$	677,021	$	245,346	$	431,675
September 2014	$	26,790	$	11,314	$	15,476
June 2013	$	84,140	$	18,765	$	65,375

It is reasonably possible that the estimate of undiscounted future net cash flows may change in the future resulting in the need to impair carrying values. The primary factors that may affect estimates of future net cash flows are (i) commodity prices, (ii) increases or decreases in production and capital costs, (iii) future reserve adjustments, both positive and negative, to proved reserves and appropriate risk-adjusted probable and possible reserves, (iv) results of future drilling activities and (v) changes in income and expenses from integrated assets.

Based on the factors above as of December 31, 2015, the Company determined that undiscounted future cash flows attributable to certain depletion groups indicated that the carrying amountswere expected to be recovered; however, they may be at risk for impairment if management’s estimates of future cash flows further decline.

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Derivative financial instruments

12 Months Ended

Dec. 31, 2015

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative financial instruments

Note 8. Derivative financial instruments

The Company uses derivative financial instruments to manage its exposure to commodity price fluctuations. Commodity derivative instruments are used to (i) reduce the effect of the volatility of price changes on the oil and natural gas the Company produces and sells, (ii) support the Company’s capital budget and expenditure plans and (iii) support the economics associated with acquisitions. The Company does not enter into derivative financial instruments for speculative or trading purposes. The Company may also enter into physical delivery contracts to effectively provide commodity price hedges. Because these physical delivery contracts are not expected to be net cash settled, they are considered to be normal sales contracts and not derivatives. Therefore, these contracts are not recorded in the Company’s consolidated financial statements.

The Company does not designate its derivative instruments to qualify for hedge accounting. Accordingly, the Company reflects changes in the fair value of its derivative instruments in its statements of operations as they occur.

The following table summarizes the gains(losses) reported in earnings related to the commodity derivative instruments for the years ended December 31,2015, 2014 and 2013:

			Years Ended December 31,
(in thousands)				2015		2014		2013
Gain (loss) on derivatives:
	Oil derivatives		$	675,303	$	869,421	$	(133,890)
	Natural gas derivatives			24,449		21,496		10,238
		Total	$	699,752	$	890,917	$	(123,652)
The following table represents the Company’s cash receipts from (payments on) derivatives for the years ended December 31, 2015, 2014 and 2013:
			Years Ended December 31,
(in thousands)				2015		2014		2013
Cash receipts from (payments on) derivatives:
	Oil derivatives		$	597,297	$	76,335	$	(41,616)
	Natural gas derivatives			35,619		(4,352)		9,275
		Total	$	632,916	$	71,983	$	(32,341)

Commodity derivative contracts at December 31,2015. The following table sets forth the Company’s outstanding derivative contracts at December 31,2015. When aggregating multiple contracts, the weighted average contract price is disclosed.All of the Company’s derivative contracts at December 31, 2015 are expected to settle by December 31, 2017.

				First		Second		Third		Fourth
				Quarter		Quarter		Quarter		Quarter		Total
Oil Swaps: (a)
	2016:
		Volume (Bbl)		6,722,000		5,985,000		5,460,000		5,054,000		23,221,000
		Price per Bbl	$	71.99	$	73.38	$	74.21	$	59.38	$	70.13
	2017:
		Volume (Bbl)		4,354,000		4,118,000		2,655,000		2,655,000		13,782,000
		Price per Bbl	$	61.59	$	62.03	$	55.23	$	55.23	$	59.27
Oil Basis Swaps: (b)
	2016:
		Volume (Bbl)		6,035,000		5,732,000		5,520,000		5,060,000		22,347,000
		Price per Bbl	$	(1.49)	$	(1.50)	$	(1.46)	$	(1.48)	$	(1.48)
	2017:
		Volume (Bbl)		3,780,000		3,822,000		1,012,000		1,012,000		9,626,000
		Price per Bbl	$	(1.32)	$	(1.32)	$	(0.54)	$	(0.54)	$	(1.16)
Natural Gas Swaps: (c)
	2016:
		Volume (MMBtu)		7,280,000		7,280,000		7,360,000		7,360,000		29,280,000
		Price per MMBtu	$	3.02	$	3.02	$	3.02	$	3.02	$	3.02
(a) The index prices for the oil price swaps are based on the NYMEX – West Texas Intermediate (“WTI”) monthly average futures price.
(b) The basis differential price is between Midland – WTI and Cushing – WTI.
(c) The index prices for the natural gas price swaps are based on the NYMEX – Henry Hub last trading day futures price.

Derivative counterparties. The Company uses credit and other financial criteria to evaluate the creditworthiness of counterparties to its derivative instruments. The Company believes that all of its derivative counterparties are currently acceptable credit risks. Other than provided by the Company’s revolving credit facility, the Company is not required to provide credit support or collateral to any counterparties under its derivative contracts, nor are they required to provide credit support to the Company. See additional information in Note 12.

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Debt

12 Months Ended

Dec. 31, 2015

Debt Disclosure [Abstract]

Debt

Note 9. Debt

The Company’s debt consisted of the following at December 31, 2015 and 2014:

				December 31,
(in thousands)				2015		2014
Credit facility			$	-	$	139,500
7.0% unsecured senior notes due 2021				600,000		600,000
6.5% unsecured senior notes due 2022				600,000		600,000
5.5% unsecured senior notes due 2022				600,000		600,000
5.5% unsecured senior notes due 2023				1,550,000		1,550,000
Unamortized original issue premium				25,073		27,820
Deferred loan costs, net				(42,885)		(48,183)
	Less: current portion			-		-
		Total long-term debt	$	3,332,188	$	3,469,137

Credit facility. The Company’s credit facility, as amended and restated (the “Credit Facility”), has a maturity date of May 9, 2019. In April 2015, the Company amended its credit agreement to remove the current ratio financial covenant.The Company’s borrowing base is $3.25 billion until the next scheduled borrowing base redetermination in May 2016. At December 31,2015, commitments from the Company’s bank group totaled $2.5 billion. Between scheduled borrowing base redeterminations, the Company and the lenders (requiring a 66 2/3 percent vote), may each request one special redetermination.

Advances on the Credit Facility bear interest, at the Company’s option, based on (i) the prime rate of JPMorgan Chase Bank (“JPM Prime Rate”) (3.50 percent at December 31,2015) or (ii) a Eurodollar rate (substantially equal to the LIBOR). At December 31,2015, the interest rates of Eurodollar rate advances and JPM Prime Rate advances varied, with interest margins ranging from 125 to 225 basis points and 25 to 125 basis points per annum, respectively, depending on the balance outstanding on the Credit Facility. During the years ended December 31,2015,2014and 2013, the Company incurred commitment fees on the unused portion of the available commitments of $7.0 million, $7.7 million and $8.3 million, respectively. Under the current Credit Facility, commitment fees range from 30 to 37.5 basis points per annum. The Company had approximately $2.5 billion of unused commitments under its credit facility at December 31,2015.

The Company’s obligations under the Credit Facility are secured by a first lien on substantially all of its oil and natural gas properties. At December 31, 2015, all of the Company’s subsidiaries are guarantors and have had their equity pledged to secure borrowings under the Credit Facility.

The Credit Facility contains various restrictive covenants and compliance requirements which include:

• maintenance of a quarterly ratio of total debt to consolidated earnings before interest expense, income taxes, depletion, depreciation, and amortization, exploration expense and other noncash income and expenses to be no greater than 4.25 to 1.0;
• limits on the incurrence of certain indebtedness and certain types of liens;
• restrictions as to mergers, combinations and dispositions of assets; and
• limits on the payment of cash dividends.

The Company recorded a loss on extinguishment of debt related to the Credit Facility of approximately $4.3 million for the year endedDecember 31,2014. This amount includes the proportional amount of unamortized deferred loan costs associated with banks with lesser commitments in the amended credit facility syndicate.

Senior notes. Interest on the Company’s senior notes is paid in arrears semi-annually. The senior notes are fully and unconditionally guaranteed on a senior unsecured basis by all subsidiaries of the Company, subject to customary release provisions as described in Note 16.

On June 3, 2013, the Company received tenders and consents from the holders of approximately $225.6 million in aggregate principal amount, or approximately 75.2 percent, of its outstanding 8.625% senior notes due 2017 (the “8.625% Notes”) in connection with a cash tender offer for any and all of the 8.625% Notes at a price of 106.922 percent of the unpaid principal amount.

On June 21, 2013, the Company redeemed the remaining outstanding 8.625% Notes not purchased in the tender offer at a redemption price of 106.516 percent of the unpaid principal amount plus accrued and unpaid interest through June 20, 2013.

The Company recorded a loss on extinguishment of debt related to the tender offer and redemption of its 8.625% Notes of approximately $28.6 million for the year endedDecember 31,2013. This amount includes approximately $20.4 million associated with the premium paid for the tender offer and redemption of the notes, approximately $5.5 million of unamortized deferred loan costs and approximately $2.7 million of unamortized discount.

On June 4, 2013, the Company completed the issuance of an additional $850 million in principal amount of its 5.5% senior notes due 2023 (the “Offering”) at 103.75 percent of par (resulting in a 4.884% yield) for net proceeds of approximately $867.8 million. The Company used a portion of the net proceeds from the Offering to fund the tender offer and redemption of the 8.625% Notes and to pay down amounts outstanding on the Credit Facility.

At December 31,2015, the Company was in compliance with the covenants under all of its debt instruments.

Principal maturities of long-term debt.Principal maturities of long-term debt outstanding at December 31,2015were as follows:

(in thousands)
2016		$	-
2017			-
2018			-
2019			-
2020			-
Thereafter			3,350,000
	Total	$	3,350,000

Interest expense.The following amounts have been incurred and charged to interest expense for the years ended December 31,2015, 2014 and 2013:

		Years Ended December 31,
(in thousands)			2015		2014		2013
Cash payments for interest		$	211,443	$	211,342	$	200,961
Amortization of original issue discount (premium)			(2,747)		(2,599)		(1,248)
Amortization of deferred loan origination costs			9,971		10,937		13,172
Accretion expense			1,795		-		-
Net changes in accruals			(165)		(737)		5,696
	Interest costs incurred		220,297		218,943		218,581
Less: capitalized interest			(4,913)		(2,282)		-
	Total interest expense	$	215,384	$	216,661	$	218,581

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Commitments and contingencies

12 Months Ended

Dec. 31, 2015

Commitments and Contingencies Disclosure [Abstract]

Commitments and contingencies

Note 10. Commitments and contingencies

Severance agreements.The Company has entered into severance and change in control agreements with all of its officers. The current annual salaries for the Company’s officers covered under such agreements total approximately $8.5million.

Indemnifications.The Company has agreed to indemnify its directors and officers with respect to claims and damages arising from certain acts or omissions taken in such capacity.

Legal actions. The Company is a party to proceedings and claims incidental to its business. While many of these matters involve inherent uncertainty, the Company believes that the amount of the liability, if any, ultimately incurred with respect to any such proceedings or claims will not have a material adverse effect on the Company’s consolidated financial position as a whole or on its liquidity, capital resources or future results of operations. The Company will continue to evaluate proceedings and claims involving the Company on a regular basis and will establish and adjust any reserves as appropriate to reflect its assessment of the then current status of the matters.

Severance tax, royalty and joint interest audits. The Company is subject to routine severance, royalty and joint interest audits from regulatory bodies and non-operators and makes accruals as necessary for estimated exposure when deemed probable and estimable. Additionally, the Company is subject to various possible contingencies that arise primarily from interpretations affecting the oil and natural gas industry. Such contingencies include differing interpretations as to the prices at which oil and natural gas sales may be made, the prices at which royalty owners may be paid for production from their leases, allowable costs under joint interest arrangements and other matters. At December 31, 2015 and 2014, the Company had $13.4 million and $12.3 million, respectively, accrued for estimated exposure. Although the Company believes that it hasestimated its exposure with respect to the various laws and regulations, administrative rulings and interpretations thereof, adjustments could be required as new interpretations and regulations are issued. 

Commitments.The Company periodically enters into contractual arrangements under which the Company is committed to expend funds. These contractual arrangements relate to purchase agreements the Company has entered into including daywork drilling contracts, water commitment agreements, throughput volume delivery commitments, power commitments and maintenance commitments.The following table summarizes the Company’s commitments at December 31,2015:

(in thousands)
2016		$	51,710
2017			21,256
2018			21,148
2019			13,196
2020			7,335
Thereafter			45,451
	Total	$	160,096

Operating leases.The Company leases vehicles, equipment and office facilities under non-cancellable operating leases. Lease payments associated with these operating leases for the years ended December 31, 2015, 2014 and 2013 were approximately $8.0 million, $7.2 million and $5.7 million, respectively.

Future minimum lease commitments under non-cancellable operating leases at December 31,2015were as follows:

(in thousands)
2016		$	7,941
2017			7,877
2018			7,087
2019			5,651
2020			4,738
Thereafter			5,091
	Total	$	38,385

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Income taxes

12 Months Ended

Dec. 31, 2015

Income Tax Disclosure [Abstract]

Income taxes

Note 11. Income taxes

The Company uses an asset and liability approach for financial accounting and reporting for income taxes. The Company’s objectives of accounting for income taxes are to recognize (i) the amount of taxes payable or refundable for the current year and (ii) deferred tax liabilities and assets for the future tax consequences of events that have been recognized in its financial statements or tax returns. The Company and its subsidiaries file a federal corporate income tax return on a consolidated basis. The tax returns and the amount of taxable income or loss are subject to examination by federal and state taxing authorities. At December 31,2015 the Company had current income taxes receivable of approximately $37.3 million and current income taxes payable of approximately $1.0 million.At December 31,2014 the Company had current income taxes receivable of approximately $32.9 million and current income taxes payable of approximately $1.1 million.

The Company continually assesses both positive and negative evidence to determine whether it is more likely than not that deferred tax assets can be realized prior to their expiration. Management monitors company-specific, oil and natural gas industry and worldwide economic factors and assesses the likelihood that the Company’s net operating loss carryforwards (“NOLs”), if any, and other deferred tax attributes in the United States, state, and local tax jurisdictions will be utilized prior to their expiration. At December 31,2015 and 2014, the Company had no valuation allowances related to its deferred tax assets.

At December 31,2015, the Company did not have any significant uncertain tax positions requiring recognition in the financial statements. The tax years 2012 through 2015 remain subject to examination by the major tax jurisdictions.

Income tax provision. The Company’s income tax provision and amounts separately allocated were attributable to the following items for the years ended December 31,2015, 2014 and 2013:

		Years Ended December 31,
(in thousands)			2015		2014		2013
Income from continuing operations		$	31,371	$	317,785	$	118,237
Income from discontinued operations			-		-		7,518
Changes in stockholders’ equity:
	Excess tax benefits related to stock-based compensation		(2,150)		(16,480)		(6,147)
		$	29,221	$	301,305	$	119,608

The Company’s income tax provision attributable to income from continuing operations consisted of the following for the years ended December 31,2015, 2014 and 2013:

					Years Ended December 31,
(in thousands)						2015		2014		2013
Current:
	U.S. federal				$	127	$	16,621	$	12,504
	U.S. state and local					1,622		4,997		3,306
		Total current income tax provision				1,749		21,618		15,810
Deferred:
	U.S. federal					40,364		278,615		119,985
	U.S. state and local					(10,742)		17,552		(17,558)
		Total deferred income tax provision				29,622		296,167		102,427
			Total income tax provision attributable to income from
				continuing operations	$	31,371	$	317,785	$	118,237

The reconciliation between the income tax expense computed by multiplying pre-tax income from continuing operations by the United States federal statutory rate and the reported amounts of income tax expense from continuing operations is as follows:

		Years Ended December 31,
(in thousands)			2015		2014		2013
Income at U.S. federal statutory rate		$	34,045	$	299,586	$	125,006
State income taxes (net of federal tax effect)			3,071		22,826		12,505
Revisions of previous estimates			(631)		738		1,400
Change in estimated effective statutory state income tax			(9,026)		(7,945)		(21,876)
Nondeductible expense & other			3,912		2,580		1,202
	Income tax expense	$	31,371	$	317,785	$	118,237
Effective tax rate			32.3%		37.1%		33.1%

The Company monitors changes in enacted tax rates for the jurisdictions in which it operates. The Company monitors its state tax apportionment footprint and makes updates for changes in its projected activity, including changes in budgets and drilling plans. During 2013, the state of New Mexico passed legislation to phase in a tax rate reduction over the next five years. In June of 2015, the State of Texas enacted legislation to reduce its rate. Based upon the Company’s projected future activity for the states in which it conducts business, the timing for when it anticipates its deferred tax items to become taxable and enacted tax rates at such time deferred items become taxable, the Company has revised its estimated state rate and recorded an additional deferred tax benefit of $9.0 million, $7.9 million and $21.9 million during 2015, 2014 and 2013, respectively.

The Company’s effective tax rate decreased in 2015 as compared to 2014. The primary reason for the decrease is lower income, which caused a more pronounced impact for each reconciling item, as compared with 2014. In particular, the reduction in our blended state rate caused a 9.3% reduction, partially offset by other reconciling and non-deductible items for a net rate reduction of 4.8% over 2014.

The Company’s income tax provision attributable to income from discontinued operations consisted of the following for the year ended December 31, 2013:

				Year Ended
(in thousands)				December 31, 2013
Current:
	U.S. federal			$	144
	U.S. state and local				25
		Total current income tax provision			169
Deferred:
	U.S. federal				6,397
	U.S. state and local				952
		Total deferred income tax provision			7,349
			Total income tax provision attributable to income from discontinued operations	$	7,518

The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities were as follows:

				December 31,
(in thousands)				2015			2014
Deferred tax assets:
	Stock-based compensation			$	36,738	$	24,810
	Asset retirement obligation				44,573		44,802
	Other				29,574		28,925
			Total deferred tax assets		110,885		98,537
Deferred tax liabilities:
	Oil and natural gas properties, principally due to differences in basis and
		depreciation and the deduction of intangible drilling costs for tax purposes			(1,420,275)		(1,401,313)
	Intangible assets - operating rights				(9,548)		(10,148)
	Derivative instruments				(304,550)		(281,303)
	Other				(6,885)		(6,524)
			Total deferred tax liability		(1,741,258)		(1,699,288)
			Net deferred tax liability	$	(1,630,373)	$	(1,600,751)

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Major customers and derivative counterparties

12 Months Ended

Dec. 31, 2015

Major Customer Disclosure [Abstract]

Major Customers and Derivative Counterparties [Text Block]

Note 12. Major customers and derivative counterparties

Sales to major customers. The Company’s share of oil and natural gas production is sold to various purchasers. The Company is of the opinion that the loss of any one purchaser would not have a material adverse effect on the ability of the Company to sell its oil and natural gas production.

The following purchasers individually accounted for 10 percent or more of the consolidated oil and natural gas revenuesduring the years ended December 31, 2015, 2014 and 2013:

	Years Ended December 31,
	2015	2014	2013
Holly Frontier Refining and Marketing, LLC	25%	17%	30%
Enterprise Crude Oil LLC	12%	12%	13%
Plains Marketing and Transportation, Inc.	11%	6%	4%
Western Refining Company LP	5%	12%	1%

At December 31, 2015, the Company had receivables from Holly Frontier Refining and Marketing, LLC, Enterprise Crude Oil LLC, Plains Marketing & Transportation Inc. and Western Refining Company LP of $31.7 million, $10.4million $11.6million and $3.9million, respectively, which are reflected in accounts receivable — oil and natural gasin the accompanying consolidated balance sheets.

Derivative counterparties. The Company uses credit and other financial criteria to evaluate the creditworthiness of counterparties to its derivative instruments. The Company’s Credit Facility requires that the senior unsecured debt ratings of the Company’s derivative counterparties be (i) not less than either A- by Standard & Poor’s Rating Group rating system or A3 by Moody’s Investors Service, Inc. rating system or (ii) a lender or related affiliate under the Company’s Credit Facility. At December 31, 2015 and 2014, the counterparties with whom the Company had outstanding derivative contracts met or exceeded these criteria. Although the Company does not obtain collateral or otherwise secure the fair value of its derivative instruments, management believes the associated credit risk is mitigated by the Company’s credit risk policies and procedures and by the criteria of the Company’s Credit Facility.

At December 31, 2015, the Company had a net asset position of $819.5 million as a result of outstanding derivative contracts which are reflected in the accompanying consolidated balance sheets. The Company assessed this balance for concentration risk and noted balances of approximately $121.8 million, $100.5 million, $90.3 million and $74.7 million with Barclays Bank PLC,J.P. Morgan Chase Bank, Wells Fargo Bank, N.A. and KeyBank National Association, respectively.

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Related party transactions

12 Months Ended

Dec. 31, 2015

Related Party Transactions [Abstract]

Related party transactions

Note 13. Related party transactions

The following table summarizes charges incurred with and payments made to related parties and reported in the Company’s consolidated statements of operations for the periods presented:

	Years Ended December 31,
(in thousands)		2015		2014		2013
Amounts paid to a partnership in which a director has an ownership interest (a)	$	5,745	$	15,181	$	7,255
Amounts paid to a director and certain officers of the Company (b)	$	593	$	383	$	43
Amounts paid under consulting agreement with Steven L. Beal (c)	$	-	$	-	$	865
Amounts received from a director and certain officers of the Company (d)	$	237	$	169	$	84

(a)Amounts include royalties on certain properties and lease bonus payments paid to a partnership in which a director of the Company is the general partner and owns a 3.5 percent partnership interest.

(b) Amounts include revenue interests, overriding royalty interests and net profits interests in properties owned by the Company made to a director and certain officers (or affiliated entities). Amounts also include payments for an acreage acquisition and lease bonuses to an affiliated entity of an officer.

(c)On June 30, 2009, Steven L. Beal, the Company’s then-president and chief operating officer, retired from such positions. On June 9, 2009, the Company entered into a consulting agreement (the “Consulting Agreement”) with Mr. Beal, under which Mr. Beal began serving as a consultant to the Company on July 1, 2009. During the term of the consulting relationship, Mr. Beal received a consulting fee of $20,000 per month and a monthly reimbursement for his medical and dental coverage costs. In August 2013, the Company and Mr. Beal mutually terminated the Consulting Agreement in exchange for the payment to Mr. Beal of $720,000, which termination and payment were approved by the disinterested members of the Company’s Board of Directors.

(d) Amounts include payments to the Company as a result of activity on oil and natural gas properties in which a director and certain officers (or affiliated entities) have an interest.

At December 31, 2014, the Company had a $76,000 receivable from an officer (or affiliated entities) related to certain properties it operates.

In June 2013, in connection with the tender offer for the 8.625% Notes, certain directors and officers received an aggregate amount of approximately $1.3 million for the 8.625% Notes they owned.The tender offer was approved by the disinterested members of the Company’s Board of Directors.

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Net income per share

12 Months Ended

Dec. 31, 2015

Earnings Per Share, Basic and Diluted, Other Disclosures [Abstract]

Net income per share

Note 14. Net income per share

The Company uses the two-class method of calculating net income per share because certain of the Company’s unvested share-based awards qualify as participating securities. Participating securities participate in income proportionate to the weighted average number of outstanding common shares, but are not assumed to participate in the Company’s net losses because they are not contractually obligated to do so. Accordingly, allocations of earnings to participating securities are included in the Company’s calculations of basic and diluted earnings per share from continuing operations, discontinued operations and net incomeattributable to common stockholders.

The following tables reconcile the Company’s incomefrom continuing operations,income from discontinued operations and net income attributable to common stockholders to the basic and diluted earnings used to determine the Company’s income per share amounts for the years ended December 31, 2015, 2014 and 2013, respectively, under the two-class method:

		Years Ended December 31,
(in thousands, except per share amounts)		2015		2014
Income as reported		$	65,900	$	538,175
Participating basic earnings			(635)		(5,961)
	Basic income attributable to common stockholders		65,265		532,214
Reallocation of participating earnings			2		16
	Diluted income attributable to common stockholders	$	65,267	$	532,230
Income per common share:
	Basic	$	0.54	$	4.89
	Diluted	$	0.54	$	4.88

			Year Ended
			December 31, 2013
		Continuing		Discontinued
(in thousands, except per share amounts)		Operations		Operations		Total
Income as reported		$	238,922	$	12,081	$	251,003
Participating basic earnings			(2,610)		(132)		(2,742)
	Basic income attributable to common stockholders		236,312		11,949		248,261
Reallocation of participating earnings			4		-		4
	Diluted income attributable to common stockholders	$	236,316	$	11,949	$	248,265
Income per common share:
	Basic	$	2.28	$	0.11	$	2.39
	Diluted	$	2.28	$	0.11	$	2.39

The following table is a reconciliation of the basic weighted average common shares outstanding to diluted weighted average common shares outstanding for the years ended December 31, 2015, 2014 and 2013:

		Years Ended December 31,
(in thousands)		2015	2014	2013
Weighted average common shares outstanding:
	Basic	119,926	108,844	103,744
	Dilutive common stock options	25	83	165
	Dilutive performance units	422	205	4
	Diluted	120,373	109,132	103,913

The following table is a summary of the performance units, which were not included in the computation of diluted net income per share, as inclusion of these items would be antidilutive:

		Years Ended December 31,
(in thousands)		2015	2014	2013
Number of antidilutive common shares:
	Antidilutive performance units	-	-	83

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Other current liabilities

12 Months Ended

Dec. 31, 2015

Other Liabilities Disclosure [Abstract]

Other current liabilities

Note 15. Other current liabilities

The following table provides the components of the Company’s other current liabilities at December 31, 2015 and 2014:

				December 31,
(in thousands)				2015		2014
Other current liabilities:
	Accrued production costs		$	70,876	$	70,786
	Payroll related matters			29,411		34,349
	Accrued interest			68,925		69,264
	Asset retirement obligations			8,626		9,146
	Other			7,072		11,763
		Other current liabilities	$	184,910	$	195,308

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Subsidiary guarantors

12 Months Ended

Dec. 31, 2015

Guarantees [Abstract]

Subsidiary guarantors

Note 16. Subsidiary guarantors

All of the Company’s 100 percent owned subsidiaries have fully and unconditionally guaranteed the Company’s senior notes. The indentures governing the Company’s senior notes provide that the guarantees of its subsidiary guarantors will be released in certain customary circumstances including (i) in connection with any sale, exchange or other disposition, whether by merger, consolidation or otherwise, of the capital stock of that guarantor to a person that is not the Company or a restricted subsidiary of the Company, such that, after giving effect to such transaction, such guarantor would no longer constitute a subsidiary of the Company, (ii) in connection with any sale, exchange or other disposition (other than a lease) of all or substantially all of the assets of that guarantor to a person that is not the Company or a restricted subsidiary of the Company, (iii) upon the merger of a guarantor into the Company or any other guarantor or the liquidation or dissolution of a guarantor, (iv) if the Company designates any restricted subsidiary that is a guarantor to be an unrestricted subsidiary in accordance with the indenture, (v) upon legal defeasance or satisfaction and discharge of the indenture and (vi) upon written notice of such release or discharge by the Company to the trustee following the release or discharge of all guarantees by such guarantor of any indebtedness that resulted in the creation of such guarantee, except a discharge or release by or as a result of payment under such guarantee.

See Note 9 for a summary of the Company’s senior notes. In accordance with practices accepted by the United States Securities and Exchange Commission(“SEC”), the Company has prepared condensed consolidating financial statements in order to quantify the assets, results of operations and cash flows of such subsidiaries as subsidiary guarantors.

The following condensed consolidating balance sheets at December 31, 2015 and 2014, condensed consolidating statements of operations and condensed consolidating statements of cash flows for the years ended December 31, 2015, 2014 and 2013, present financial information for Concho Resources Inc. as the parent on a stand-alone basis (carrying any investments in subsidiaries under the equity method), financial information for the subsidiary guarantors on a stand-alone basis and the consolidation and elimination entries necessary to arrive at the information for the Company on a consolidated basis. All current and deferred income taxes are recorded on Concho Resources Inc., as the subsidiaries are flow-through entities for income tax purposes. The subsidiary guarantors are not restricted from making distributions to the Company.

Condensed Consolidating Balance Sheet
December 31, 2015
			Parent		Subsidiary		Consolidating
(in thousands)			Issuer		Guarantors		Entries		Total
ASSETS
Accounts receivable - related parties		$	8,502,099	$	1,162,297	$	(9,664,396)	$	-
Other current assets			753,716		560,834		-		1,314,550
Oil and natural gas properties, net			-		10,798,497		-		10,798,497
Property and equipment, net			-		178,450		-		178,450
Investment in subsidiaries			3,698,485		-		(3,698,485)		-
Other long-term assets			182,623		167,756		-		350,379
	Total assets	$	13,136,923	$	12,867,834	$	(13,362,881)	$	12,641,876
LIABILITIES AND EQUITY
Accounts payable - related parties		$	1,162,297	$	8,502,099	$	(9,664,396)	$	-
Other current liabilities			69,514		526,906		-		596,420
Long-term debt			3,332,188		-		-		3,332,188
Other long-term liabilities			1,630,373		140,344		-		1,770,717
Equity			6,942,551		3,698,485		(3,698,485)		6,942,551
	Total liabilities and equity	$	13,136,923	$	12,867,834	$	(13,362,881)	$	12,641,876

Condensed Consolidating Balance Sheet
December 31, 2014
			Parent		Subsidiary		Consolidating
(in thousands)			Issuer		Guarantors		Entries		Total
ASSETS
Accounts receivable - related parties		$	6,670,744	$	1,201,950	$	(7,872,694)	$	-
Other current assets			569,545		618,851		-		1,188,396
Oil and natural gas properties, net			-		10,076,878		-		10,076,878
Property and equipment, net			-		129,136		-		129,136
Investment in subsidiaries			4,085,045		-		(4,085,045)		-
Other long-term assets			282,609		74,761		-		357,370
	Total assets	$	11,607,943	$	12,101,576	$	(11,957,739)	$	11,751,780
LIABILITIES AND EQUITY
Accounts payable - related parties		$	1,201,950	$	6,670,744	$	(7,872,694)	$	-
Other current liabilities			55,318		1,209,309		-		1,264,627
Long-term debt			3,469,137		-		-		3,469,137
Other long-term liabilities			1,600,750		136,478		-		1,737,228
Equity			5,280,788		4,085,045		(4,085,045)		5,280,788
	Total liabilities and equity	$	11,607,943	$	12,101,576	$	(11,957,739)	$	11,751,780

Condensed Consolidating Statement of Operations
For the Year Ended December 31, 2015
			Parent		Subsidiary		Consolidating
(in thousands)			Issuer		Guarantors		Entries		Total
Total operating revenues		$	-	$	1,803,573	$	-	$	1,803,573
Total operating costs and expenses			697,247		(2,119,817)		-		(1,422,570)
	Income (loss) from operations		697,247		(316,244)		-		381,003
Interest expense			(213,416)		(1,968)		-		(215,384)
Other, net			(386,560)		(68,348)		386,560		(68,348)
	Income (loss) before income taxes		97,271		(386,560)		386,560		97,271
Income tax expense			(31,371)		-		-		(31,371)
	Net income (loss)	$	65,900	$	(386,560)	$	386,560	$	65,900

Condensed Consolidating Statement of Operations
For the Year Ended December 31, 2014
		Parent		Subsidiary		Consolidating
(in thousands)		Issuer		Guarantors		Entries		Total
Total operating revenues		$	-	$	2,660,147	$	-	$	2,660,147
Total operating costs and expenses			888,632		(2,459,034)		-		(1,570,402)
	Income from operations		888,632		201,113		-		1,089,745
Interest expense			(216,661)		-		-		(216,661)
Loss on extinguishment of debt			(4,316)		-		-		(4,316)
Other, net			188,305		(12,809)		(188,304)		(12,808)
	Income before income taxes		855,960		188,304		(188,304)		855,960
Income tax expense			(317,785)		-		-		(317,785)
	Net income	$	538,175	$	188,304	$	(188,304)	$	538,175

Condensed Consolidating Statement of Operations
For the Year Ended December 31, 2013
			Parent		Subsidiary		Consolidating
(in thousands)			Issuer		Guarantors		Entries		Total
Total operating revenues		$	-	$	2,319,919	$	-	$	2,319,919
Total operating costs and expenses			(125,924)		(1,576,558)		-		(1,702,482)
	Income (loss) from operations		(125,924)		743,361		-		617,437
Interest expense			(218,581)		-		-		(218,581)
Loss on extinguishment of debt			(28,616)		-		-		(28,616)
Other, net			749,878		(13,136)		(749,823)		(13,081)
	Income before income taxes		376,757		730,225		(749,823)		357,159
Income tax expense			(118,237)		-		-		(118,237)
	Income from continuing operations		258,520		730,225		(749,823)		238,922
Income (loss) from discontinued operations, net of tax			(7,517)		19,598		-		12,081
	Net income	$	251,003	$	749,823	$	(749,823)	$	251,003

Condensed Consolidating Statement of Cash Flows
For the Year Ended December 31, 2015
			Parent Issuer		Subsidiary Guarantors		Consolidating Entries
(in thousands)									Total
Net cash flows provided by (used in) operating activities		$	(2,026,206)	$	2,923,711	$	-	$	897,505
Net cash flows provided by (used in) investing activities			632,916		(2,602,641)		-		(1,969,725)
Net cash flows provided by (used in) financing activities			1,393,290		(92,541)		-		1,300,749
	Net increase in cash and cash equivalents		-		228,529		-		228,529
	Cash and cash equivalents at beginning of period		-		21		-		21
	Cash and cash equivalents at end of period	$	-	$	228,550	$	-	$	228,550

Condensed Consolidating Statement of Cash Flows
For the Year Ended December 31, 2014
			Parent		Subsidiary		Consolidating
(in thousands)			Issuer		Guarantors		Entries		Total
Net cash flows provided by (used in) operating activities		$	(888,369)	$	2,562,156	$	-	$	1,673,787
Net cash flows provided by (used in) investing activities			71,983		(2,617,979)		-		(2,545,996)
Net cash flows provided by financing activities			816,386		55,823		-		872,209
	Net increase (decrease) in cash and cash equivalents		-		-		-		-
	Cash and cash equivalents at beginning of period		-		21		-		21
	Cash and cash equivalents at end of period	$	-	$	21	$	-	$	21

Condensed Consolidating Statement of Cash Flows
For the Year Ended December 31, 2013
			Parent		Subsidiary		Consolidating
(in thousands)			Issuer		Guarantors		Entries		Total
Net cash flows provided by (used in) operating activities		$	(487,131)	$	1,849,151	$	-	$	1,362,020
Net cash flows used in investing activities			(32,341)		(1,864,453)		-		(1,896,794)
Net cash flows provided by financing activities			519,472		12,443		-		531,915
	Net decrease in cash and cash equivalents		-		(2,859)		-		(2,859)
	Cash and cash equivalents at beginning of period		-		2,880		-		2,880
	Cash and cash equivalents at end of period	$	-	$	21	$	-	$	21

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Subsequent events

12 Months Ended

Dec. 31, 2015

Subsequent Events [Abstract]

Subsequent events

Note 17. Subsequentevents

Asset acquisition. In January 2016, the Company entered into an asset purchase agreement to acquire 80 percent of the seller’s interest in certain oil and natural gas properties and related assets in the southern Delaware Basin. As consideration for the acquisition, the Company agreed to issue to the seller approximately 2.2 million shares of common stock, $150.0 million in cash and $40.0 million to carry a portion of the seller’s future development costs in these properties. The acquisition is expected to close during the first quarter of 2016, subject to customary closing conditions.

Asset divestiture. In January 2016, the Company entered into an agreement to sell certain assets in the northern Delaware Basin for cash proceeds of approximately $290.0 million. The sale is expected to close during the first quarter of 2016,subject to customary closing conditions.

New commodity derivative contracts.After December 31, 2015, the Company entered into the following additional oil price swaps and oil basis swaps to hedge additional amounts of the Company’s estimated future production:

				First		Second		Third		Fourth
				Quarter		Quarter		Quarter		Quarter		Total
Oil Swaps: (a)
	2017:
		Volume (Bbl)		180,000		180,000		750,000		750,000		1,860,000
		Price per Bbl	$	42.55	$	42.55	$	43.63	$	43.63	$	43.42
Oil Basis Swaps: (b)
	2016:
		Volume (Bbl)		120,000		182,000		-		-		302,000
		Price per Bbl	$	(0.25)	$	(0.25)	$	-	$	-	$	(0.25)
	2017:
		Volume (Bbl)		360,000		242,000		2,024,000		2,024,000		4,650,000
		Price per Bbl	$	(0.41)	$	(0.38)	$	(0.38)	$	(0.38)	$	(0.38)
(a)		The index prices for the oil price swaps are based on the NYMEX – WTI monthly average futures price.
(b)		The basis differential price is between Midland – WTI and Cushing – WTI.

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Summary of significant accounting policies (Policies)

12 Months Ended

Dec. 31, 2015

Accounting Policies [Abstract]

Principles of consolidation

Principles of consolidation. The consolidated financial statements of the Company include the accounts of the Company and its 100 percent owned subsidiaries. The Company consolidates the financial statements of these entities. All material intercompany balances and transactions have been eliminated.

Reclassification

Retrospective adjustments and reclassifications. Certain reclassifications have been made to the 2014 amounts in order to conform to the 2015 presentation and for the retrospective application resulting from the early adoption of Accounting Standards Update (“ASU”) No. 2015-03 and 2015-17. The retrospective application of ASU 2015-03 resulted in $48.2 million of net deferred loan costs directly related to the Company’s senior notes being reclassified from a noncurrent asset to a direct deduction from thecarrying amount of the related senior notesat December 31, 2014. The retrospective application of ASU 2015-17 resulted in the current deferred income tax liability of $162.6 million at December 31, 2014 to be reclassified as a noncurrent deferred income tax liability in the Company’s consolidated balance sheet.

Other certain prior period amounts have been reclassified to conform to the 2015 presentation. These reclassifications had no impact on the balance sheet, net income (loss) or cash flows.

Discontinued operations

Discontinued operations. In December 2012, the Company closed the sale of certain of its non-core assets for cash consideration of approximately $503.1 million, which resulted in a pre-tax gain of approximately $0.9 million. As a result of post-closing adjustments during the year ended December 31,2013, the Company made a positive adjustment to gain (loss) on disposition of assets of approximately $19.6 million, before income tax expense of approximately $7.5 million. The Company recognized income from discontinued operations, net of tax of $12.1 million for the year ended December 31,2013.

Use of estimates in the preparation of financial statements

Use of estimates in the preparation of financial statements. Preparation of financial statements in conformity with generally accepted accounting principles in the United States of America (“U.S. GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from these estimates. Depletion of oil and natural gas properties is determined using estimates of proved oil and natural gas reserves. There are numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. Similarly, evaluations for impairment of proved and unproved oil and natural gas properties are subject to numerous uncertainties including, among others, estimates of future recoverable reserves, commodity price outlooks and prevailing market rates of other sources of income and costs. Other significant estimates include, but are not limited to, asset retirement obligations, fair value of derivative financial instruments, fair value of business combinations,fair value of nonmonetary exchanges, fair value of stock-based compensation and income taxes.

Cash equivalents

Cash equivalents. The Company considers all cash on hand, depository accounts held by banks, money market accounts and investments with an original maturity of three months or less to be cash equivalents. The Company’s cash and cash equivalents are held in financial institutions in amounts that exceed the insurance limits of the Federal Deposit Insurance Corporation. However, management believes that the Company’s counterparty risks are minimal based on the reputation and history of the institutions selected.

Accounts receivable

Accounts receivable. The Company sells oil and natural gas to various customers and participates with other parties in the drilling, completion and operation of oil and natural gas wells. Joint interest and oil and natural gas sales receivables related to these operations are generally unsecured. The Company determines joint interest operations accounts receivable allowances based on management’s assessment of the creditworthiness of the joint interest owners and the Company’s ability to realize the receivables through netting of anticipated future production revenues. Receivables are considered past due if full payment is not received by the contractual due date. Past due accounts are generally written off against the allowance for doubtful accounts only after all collection attempts have been exhausted. The Company had an allowance for doubtful accounts of approximately $1.2million and $0.7million at December 31,2015 and December 31,2014, respectively.

Inventory

Inventory. Inventory consists primarily of tubular goods, water and other oilfield equipment that the Company plans to utilize in its ongoing exploration and development activities and is carried at the lower of cost or market value, on a weighted average cost basis.

Deferred loan costs.

Deferred loan costs.Deferred loan costs are stated at cost, net of amortization, which is computed using the effective interest method and straight-line methods. For the interim period ended December 31, 2015, the Company early adopted ASU No. 2015-03, “Interest-Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs,” which requires net deferred loan costs directly related to the Company’s senior notes to be classified as a direct deduction from the carrying amount of the related senior notes. The Company retrospectively adopted the ASU and reclassified $48.2million at December 31, 2014from a noncurrent asset to a deduction from long-term debt. The deferred loan costs related to the Company’s credit facility remain classified as a noncurrent asset due to the revolving nature of that facility. The provisions of the ASU were adopted primarily to simplify the required reporting for subsequent registration filings. The Company had deferred loan costs related to its senior notes of $42.9million and $48.2million, net of accumulated amortization of $18.7million and $13.4million, as a reduction of long-term debt at December 31, 2015 and December 31,2014, respectively.

The Company had deferred loan costs related to the credit facility of $15.6million and $20.3million, net of accumulated amortization of $51.0million and $46.3million, in noncurrent assets at December 31, 2015 and December 31,2014, respectively.

Oil and natural gas properties

Oil and natural gas properties. The Company utilizes the successful efforts method of accounting for its oil and natural gas properties. Under this method all costs associated with productive wells and nonproductive development wells are capitalized, while nonproductive exploration costs are expensed. Capitalized acquisition costs relating to proved properties are depleted using the unit-of-production method based on proved reserves. The depletion of capitalized drilling and development costs and integrated assets is based on the unit-of-production method using proved developed reserves. During the years ended December 31, 2015, 2014 and 2013, the Company recognized depletion expensefrom continuing operations of $1,203.5 million, $960.9 million and $756.0 million, respectively.

The Company generally does not carry the costs of drilling an exploratory well as an asset in its consolidated balance sheets following the completion of drilling unless both of the following conditions are met:

• the well has found a sufficient quantity of reserves to justify its completion as a producing well; and
• the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project.

Due to the capital intensive nature and the geographical location of certain projects, it may take the Company longer than one year to evaluate the future potential of the exploration well and economics associated with making a determination on its commercial viability. In these instances, the project’s feasibility is not contingent upon price improvements or advances in technology, but rather the Company’s ongoing efforts and expenditures related to accurately predicting the hydrocarbon recoverability based on well information, gaining access to other companies’ production, transportation or processing facilities and/or getting partner approval to drill additional appraisal wells. These activities are ongoing and being pursued constantly. Consequently, the Company’s assessment of suspended exploratory well costs is continuous until a decision can be made that the well has found proved reserves or is noncommercial and is charged to exploration and abandonments expense. See Note 3 for additional information regarding the Company’s suspended exploratory well costs.

Proceeds from the sales of individual properties and the capitalized costs of individual properties sold or abandoned are credited and charged, respectively, to accumulated depletion. Generally, no gain or loss is recognized until the entire depletion base is sold. However, gain or loss is recognized from the sale of less than an entire depletion base if the disposition is significant enough to materially impact the depletion rate of the remaining properties in the depletion base. Ordinary maintenance and repair costs are expensed as incurred.

Costs of significant nonproducing properties, wells in the process of being drilled and completed and development projects are excluded from depletion until the related project is completed and proved developed reserves are established or, if unsuccessful, impairment is determined. The Company capitalizes interest, if debt is outstanding, on expenditures for significant development projects until such projects are ready for their intended use. During the years ended December 31, 2015 and 2014, the Company had capitalized interest of $0.7 million and $1.4 million, respectively. The Company did not capitalize interest during 2013.

The Company reviews its long-lived assets to be held and used, including proved oil and natural gas properties, whenever events or circumstances indicate that the carrying value of those assets may not be recoverable. An impairment loss is indicated if the sum of the expected future cash flows is less than the carrying amount of the assets. In this circumstance, the Company recognizes an impairment loss for the amount by which the carrying amount of the asset exceeds the estimated fair value of the asset. The Company reviews its oil and natural gas properties by depletion base or by individual well for those wells not constituting part of a depletion base. For each property determined to be impaired, an impairment loss equal to the difference between the carrying value of the properties and the estimated fair value (discounted future cash flows) of the properties and integrated assets would be recognized at that time. Estimating future cash flows involves the use of judgments, including estimation of the proved and risk-adjusted unproved oil and natural gas reserve quantities, timing of development and production, expected future commodity prices, capital expenditures and production costs and cash flows from integrated assets. The Company recognized impairment expense of $60.5 million, $447.2 million, and $65.4 million during the years ended December 31, 2015, 2014and 2013, respectively, related to its proved oil and natural gas properties.

Unproved oil and natural gas properties are each periodically assessed for impairment by considering future drilling plans, the results of exploration activities, commodity price outlooks, planned future sales or expiration of all or a portion of such projects. During the years ended December 31, 2015, 2014 and 2013, the Company recognized expense of $34.5million, $217.3 million and $49.8 million, respectively, related to abandoned prospects and expiring acreage, which is included in exploration andabandonments expensein the accompanying consolidated statements of operations.

Other property and equipment

Other property and equipment.  Other capital assets include buildings, transportation equipment, computer equipment and software, telecommunications equipment, leasehold improvements and furniture and fixtures. These items are recorded at cost, or fair value if acquired, and are depreciated using the straight-line method based on expected lives of the individual assets or group of assets ranging from two to 31 years.The Company had other capital assets of $178.5 million and $129.1 million, net of accumulated depreciation of $54.4 million and $52.5 million, at December 31, 2015 and December 31,2014, respectively. During the years ended December 31, 2015, 2014 and 2013, the Company recognized depreciation expense of $18.3 million, $17.3 million and $15.2 million, respectively.

Intangible assets.

Intangible assets. The Company has capitalized certain operating rights acquired in an acquisition. The gross operating rights, which have no residual value, are amortized over the estimated economic life of 25 years. Impairment will be assessed if indicators of potential impairment exist or when there is a material change in the remaining useful economic life. The following table reflects the gross and net intangible assets at December 31, 2015 and 2014, respectively:

			December 31,
(in thousands)			2015		2014
Gross intangible - operating rights		$	36,557	$	36,557
Accumulated amortization			(10,864)		(9,403)
	Net intangible - operating rights	$	25,693	$	27,154

The following table reflects amortization expense from continuing operations for the years ended December 31, 2015, 2014 and 2013:

	Years Ending December 31,
(in thousands)	2015		2014		2013
Amortization expense	$	1,461	$	1,461	$	1,461

The following table reflects the estimated aggregate amortization expense for each of the periods presented below at December 31,2015:

(in thousands)
2016		$	1,461
2017			1,461
2018			1,461
2019			1,461
2020			1,461
Thereafter			18,388
	Total	$	25,693

Equity method investment

Equity method investments.The Company owns a 50 percent member interest in a midstream joint venture, Alpha Crude Connector, LLC (“ACC”), to construct a crude oil gathering and transportation system in the northern Delaware Basin. The Company has the option to purchase the member interest of the other investor in ACC. This purchase option becomes exercisable three months after the completion date of the pipeline and remains exercisable for a period of twelve months.The Company accounts for its investment in ACC under the equity method of accounting for investments in unconsolidated affiliates. The Company’s net investment in ACC wasapproximately $98.9 million and $29.5 million at December 31, 2015 and December 31, 2014, respectively, and was included in other assets in the Company’s consolidated balance sheet. The equity loss for the years ended December 31, 2015 and 2014 was approximately $4.1 million and $1.3 million, respectively, and was included in other expense in the Company’s consolidated statement of operations. During2015 and 2014,the Company recorded approximately $2.9 million and $0.7 million, respectively, of capitalized interest on its investment in ACC.

Environmental

Environmental. The Company is subject to extensive federal, state and local environmental laws and regulations. These laws, which are often changing, regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures of a noncapital nature are recorded when environmental assessment and/or remediation is probable and the costs can be reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash payments is fixed and readily determinable. At December 31, 2015 and 2014, the Company has accrued approximately $1.0million and $1.7 million, respectively, related to environmental liabilities. During the years ended December 31, 2015, 2014 and 2013, the Company recognized environmental charges of approximately $2.7million, $4.0 million and $3.4 million, respectively.

Derivative instruments

Derivative instruments. The Company recognizes its derivative instruments, other than any commodity derivative contracts that are designated as normal purchase and normal sale, as either assets or liabilities measured at fair value. The Company netted the fair value of derivative instruments by counterparty in the accompanying consolidated balance sheets where the right of offset exists. The Company did not have any derivatives designated as fair value or cash flow hedges during the years ended December 31, 2015, 2014 or 2013.The Company may also enter into physical delivery contracts to effectively provide commodity price hedges. Because these contracts are not expected to be net cash settled, they are considered to be normal sales contracts and not derivatives. Therefore, these contracts are not recorded in the Company’s consolidated financial statements.

Asset retirement obligations

Asset retirement obligations. The Company records the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. Subsequently, the asset retirement cost included in the carrying amount of the related asset is allocated to expense through depletion of the asset. Changes in the liability due to passage of time are generally recognized as an increase in the carrying amount of the liability and as corresponding accretion expense. Based on certain factors including commodity prices and costs, the Company may revise its previous estimates related to the liability, which would also increase or decrease the associated oil and gas property asset.

Treasury stock

Treasury stock. Treasury stock purchases are recorded at cost.

Revenue recognition

Revenue recognition. Oil and natural gas revenues are recorded at the time of physical transfer of such products to the purchaser, which for the Company is primarily at the wellhead. The Company follows the sales method of accounting for oil and natural gas sales, recognizing revenues based on the Company’s actual proceeds from the oil and natural gas sold to purchasers.

Oil and natural gas imbalances

Oil and natural gas imbalances.Oil and natural gas imbalances are generated on properties for which two or more owners have the right to take production “in-kind” and, in doing so, take more or less than their respective entitled percentage. Imbalances are tracked by well, but the Company does not record any receivable from or payable to the other owners unless the imbalance has reached a level at which it exceeds the remaining reserves in the respective well. If reserves are insufficient to offset the imbalance and the Company is in an overtake position, a liability is recorded for the amount of shortfall in reserves valued at a contract price or the market price in effect at the time the imbalance is generated. If the Company is in an undertake position, a receivable is recorded for an amount that is reasonably expected to be received, not to exceed the current market value of such imbalance. The Company had no significant imbalances at December 31, 2015 or 2014.

General and administrative expense.

General and administrative expense. The Company receives fees for the operation of jointly-owned oil and natural gas properties and records such reimbursements as reductions of general and administrative expense. Such fees totaled approximately $24.3million, $23.2 million and $18.5 million for the years ended December 31, 2015, 2014 and 2013, respectively.

Stock-based compensation

Stock-based compensation.For stock-based compensation awards granted, stock-based compensation expense is being recognized in the Company’s financial statements on anaccelerated basis over the awards’ vesting periods based on their fair values on the dates of grant. The stock-based compensation awards generally vest over a period ranging from one to five years. The Company utilizes (i) the Black-Scholes option pricing model to measure the fair value of stock options, (ii) the average of the grant date’s high and low stock prices for the fair value of restricted stock and (iii) the Monte Carlo simulation method for the fair value of performance unit awards.

Income taxes

Income taxes.In November 2015, the FASB issued ASU No. 2015-17, “Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes,” which requires that all deferred tax assets and liabilities, along with any related valuation allowance, be classified as noncurrent on the balance sheet. The Company early adopted the ASU retrospectively for the interim period ended December 31, 2015, which resulted in its current deferred income tax liability of $162.6 million at December 31, 2014 to be reclassified as a noncurrent deferred income tax liability in the Company’s consolidated balance sheet. The provisions of the ASU were adopted primarily to simplify the required reporting for subsequent registration filings. The Company previously classified deferred income tax liabilities and assets separately to current and noncurrent.

The Company recognizes deferred tax assets and liabilities for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rate is recognized in income in the period that includes the enactment date. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized.

Income taxes uncertainties

The Company evaluates uncertain tax positions for recognition and measurement in the consolidated financial statements. To recognize a tax position, the Company determines whether it is more likely than not that the tax positions will be sustained upon examination, including resolution of any related appeals or litigation, based on the technical merits of the position. A tax position that meets the more likely than not threshold is measured to determine the amount of benefit to be recognized in the consolidated financial statements. The amount of tax benefit recognized with respect to any tax position is measured as the largest amount of benefit that is greater than 50 percent likely of being realized upon settlement. The Company had no material uncertain tax positions that required recognition in the consolidated financial statements at December 31, 2015 and 2014. Any interest or penalties would be recognized as a component of income tax expense.

Recent accounting pronouncements

Recent accounting pronouncements.In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606),” which outlines a new, single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. This new revenue recognition model provides a five-step analysis in determining when and how revenue is recognized. The new model will require revenue recognition to depict the transfer of promised goods or services to customers in an amount that reflects the consideration a company expects to receive in exchange for those goods or services.

In August 2015, the FASB issued ASU No. 2015-14, “Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date,” which deferred the effective date of ASU 2014-09 by one year. That new standard is now effective for annual reporting periods beginning after December 15, 2017. An entity can apply ASU 2014-09 using either a full retrospective method, meaning the standard is applied to all of the periods presented, or a modified retrospective method, meaning the cumulative effect of initially applying the standard is recognized in the most current period presented in the financial statements. The Company is evaluating the impact that this new guidance will have on its consolidated financial statements.

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Summary of significant accounting policies (Tables)

12 Months Ended

Dec. 31, 2015

Accounting Policies [Abstract]

Schedule of Finite-Lived Intangible Assets [Table Text Block]

The following table reflects the gross and net intangible assets at December 31, 2015 and 2014, respectively:

			December 31,
(in thousands)			2015		2014
Gross intangible - operating rights		$	36,557	$	36,557
Accumulated amortization			(10,864)		(9,403)
	Net intangible - operating rights	$	25,693	$	27,154

Schedule Of Amortization Expense [Table Text Block]

The following table reflects amortization expense from continuing operations for the years ended December 31, 2015, 2014 and 2013:

	Years Ending December 31,
(in thousands)	2015		2014		2013
Amortization expense	$	1,461	$	1,461	$	1,461

Schedule of Finite-Lived Intangible Assets, Future Amortization Expense [Table Text Block]

The following table reflects the estimated aggregate amortization expense for each of the periods presented below at December 31,2015:

(in thousands)
2016		$	1,461
2017			1,461
2018			1,461
2019			1,461
2020			1,461
Thereafter			18,388
	Total	$	25,693

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Exploratory well costs (Tables)

12 Months Ended

Dec. 31, 2015

Disclosure Exploratory Well Costs Capitalized Exploratory Well Activity [Abstract]

Company's capitalized exploratory well activity

The following table reflects the Company’s net capitalized exploratory well activity during each of the years ended December 31,2015, 2014 and 2013:

		Years Ended December 31,
(in thousands)		2015		2014		2013
Beginning capitalized exploratory well costs		$	241,657	$	144,504	$	118,806
	Additions to exploratory well costs pending the determination of proved reserves		102,846		234,057		130,967
	Reclassifications due to determination of proved reserves		(227,746)		(99,657)		(94,114)
	Exploratory well costs charged to expense		(559)		(37,247)		(11,155)
Ending capitalized exploratory well costs		$	116,198	$	241,657	$	144,504

Aging of capitalized exploratory well costs based on the date drilling was completed

The following table provides an aging at December 31,2015 and 2014 of capitalized exploratory well costs based on the date drilling was completed:

			December 31,
(dollars in thousands)			2015		2014
Capitalized exploratory well costs that have been capitalized for a period of one year or less		$	98,764	$	232,346
Capitalized exploratory well costs that have been capitalized for a period greater than one year			17,434		9,311
	Total capitalized exploratory well costs	$	116,198	$	241,657
Number of projects with exploratory well costs that have been capitalized for a period greater
	than one year		8		7

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Asset retirement obligations (Tables)

12 Months Ended

Dec. 31, 2015

Asset Retirement Obligation Disclosure [Abstract]

Asset retirement obligations

The Company’s asset retirement obligation transactions during the years ended December 31, 2015, 2014 and 2013are summarized in the table below:

		Years Ended December 31,
(in thousands)			2015		2014		2013
Asset retirement obligations, beginning of period		$	119,881	$	101,593	$	86,261
	Liabilities incurred from new wells		4,052		5,324		6,338
	Liabilities assumed in acquisitions		2,434		4,065		593
	Accretion expense		7,600		7,072		6,047
	Liabilities settled upon plugging and abandoning wells		(2,736)		(2,926)		(3,447)
	Revision of estimates (a)		(11,286)		4,753		5,801
Asset retirement obligations, end of period		$	119,945	$	119,881	$	101,593
(a)	The downward revision to the Company’s asset retirement obligation estimates for the year ended December 31, 2015 is primarily due to a reduction in the future estimated abandonment costs.

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Incentive plans (Tables)

12 Months Ended

Dec. 31, 2015

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Summary of the Company's restricted stock awards activity

A summary of the Company’s restricted stock award activity for the yearended December 31,2015is presented below:

				Weighted
				Average
			Number of	Grant Date
			Restricted	Fair Value
			Shares	Per Share
Restricted stock:
	Outstanding at December 31, 2014		1,091,309		$	106.33
		Shares granted	452,436		$	109.76
		Shares cancelled / forfeited	(33,124)		$	111.08
		Lapse of restrictions	(310,974)		$	96.15
	Outstanding at December 31, 2015		1,199,647		$	110.14

Summarizes information about stock-based compensation for the Company's restricted stock awards activity under the Plan

The following table summarizes information about stock-based compensation for the Company’s restricted stock awards activity under the Plan for years ended December 31, 2015, 2014 and 2013:

		Years Ended December 31,
(in thousands)			2015		2014		2013
Fair value for awards granted during the period (a)		$	49,659	$	57,940	$	44,947
Fair value for awards vested during the period		$	35,700	$	59,226	$	21,496
Stock-based compensation expense from restricted stock		$	43,185	$	36,585	$	30,984
Income tax benefit related to restricted stock		$	16,049	$	13,672	$	11,650
(a)	The weighted average grant date fair value per share amounts were $109.76, $129.12 and $88.19 for the years ended December 31, 2015, 2014 and 2013, respectively. The year ended December 31, 2013 includes the effects of $1 million due to modifications of certain stock-based awards.

Summary of the Company's stock option awards activity under the Plan

Stock option awards.  A summary of the Company’s stock option award activity under the Plan for the years ended December 31,2015, 2014 and 2013is presented below:

			Years Ended December 31,
			2015			2014			2013
					Weighted			Weighted			Weighted
					Average			Average			Average
			Number of		Exercise	Number of		Exercise	Number of		Exercise
			Options		Price	Options		Price	Options		Price
Stock options:
	Outstanding at beginning of period		47,713	$	17.49	255,537	$	21.50	429,879	$	20.28
		Options exercised	(4,812)	$	12.00	(207,824)	$	22.42	(174,342)	$	18.48
	Outstanding at end of period		42,901	$	18.10	47,713	$	17.49	255,537	$	21.50
	Vested and exercisable at end of period		42,901	$	18.10	47,713	$	17.49	255,537	$	21.50

Summarizes information about the Company's vested and exercisable stock options outstanding

The following table summarizes information about the Company’s vested and exercisablestock options outstanding at December 31,2015:

December 31, 2015
			Weighted				Intrinsic
			Average		Weighted		Value
	Range of		Remaining		Average		of
	Exercise	Number	Contractual		Exercise		Options
	Prices	Vested	Life		Price		(in thousands)
Vested and exercisable options:
	$12.00 - $12.85	15,824	1.54 years	$	12.81		1,267
	$20.40 - $22.77	27,077	2.98 years	$	21.20		1,940
		42,901	2.45 years	$	18.10	$	3,207

Summarizes information about stock-based compensation for stock options

The following table shows the deductions in current taxable income related to stock options exercised for the years ended December 31,2015, 2014 and 2013:

		Years Ended December 31,
(in thousands)				2015		2014		2013
	Deductions in current taxable income related to stock options exercised		$	415	$	23,208	$	13,193

Summarizes the assumptions to estimate the fair value of performance units granted

The Company used the following assumptions to estimate the fair value of performance unit awards granted during the years ended December 31,2015, 2014 and 2013:

Summary of the Company's performance unit activity

The following table summarizes the performance unit activity for the year ended December 31,2015:

			Number of		Grant Date
			Units		Fair Value
Performance units:
	Outstanding at December 31, 2014		250,314	$	127.07
		Units granted (a)	176,330	$	156.86
		Units vested (b)	(110,889)	$	111.40
	Outstanding at December 31, 2015		315,755	$	149.21
(a)	Reflects the amount of performance units granted. The actual payout of shares will be between zero and 300 percent of the performance units granted depending on the Company’s performance at the end of the performance period.
(b)	On December 31, 2015, the performance period ended for these performance units. Each unit converted into 1.625 shares representing 180,199 shares of common stock issued on January 4, 2016.

Summarizes information about stock-based compensation for the Company's performance unit awards activity under the Plan

The following table summarizes information about stock-based compensation expense for performance units for the years ended December 31,2015, 2014 and 2013:

	Years Ended December 31,
(in thousands)		2015		2014		2013
Fair value for awards granted during the period	$	27,659	$	19,455	$	12,352
Stock-based compensation expense from performance units	$	19,888	$	10,545	$	4,080
Income tax benefit related to performance units	$	7,391	$	3,941	$	1,560

Future stock-based compensation expense to be recorded for all the stock-based compensation awards that were outstanding

Future stock-based compensation expense. The following table reflects the future stock-based compensation expense to be recorded for all the stock-based compensation awards that were outstanding at December 31,2015:

			Restricted		Performance
(in thousands)			Stock		Units		Total
2016		$	31,992	$	15,734	$	47,726
2017			18,189		9,219		27,408
2018			6,466		-		6,466
2019			286		-		286
2020			4		-		4
	Total	$	56,937	$	24,953	$	81,890

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Disclosures about fair value of financial instruments (Tables)

12 Months Ended

Dec. 31, 2015

Fair Value Disclosures [Abstract]

Carrying amounts and fair values of the Company's financial instruments

The following table presents the carrying amounts and fair values of the Company’s financial instruments at December 31,2015 and 2014:

		December 31, 2015				December 31, 2014
		Carrying		Fair		Carrying		Fair
(in thousands)		Value		Value		Value		Value
Assets:
	Derivative instruments	$	819,536	$	819,536	$	752,700	$	752,700
Liabilities:
	Credit facility	$	-	$	-	$	139,500	$	131,068
	$600 million 7.0% senior notes due 2021 (a)	$	592,414	$	595,500	$	591,213	$	625,500
	$600 million 6.5% senior notes due 2022 (a)	$	591,549	$	579,000	$	590,454	$	628,500
	$600 million 5.5% senior notes due 2022 (a)	$	592,899	$	553,500	$	592,061	$	598,500
	$1,550 million 5.5% senior notes due 2023 (a)	$	1,555,326	$	1,453,005	$	1,555,909	$	1,573,875
(a)	The carrying value includes associated deferred loan costs and any (discount) premium. See Note 2 for additional information regarding the Company’s retrospective adoption of ASU No. 2015-03.

Net basis derivative fair values as reported in the consolidated balance sheets

The following tables summarize (i) the valuation of each of the Company’s financial instruments by required fair value hierarchy levels and (ii) the gross fair value by the appropriate balance sheet classification,even when the derivative instruments are subject to netting arrangements and qualify for net presentation in the Company’s consolidated balance sheets at December 31,2015 and 2014. The Company nets the fair value of derivative instruments by counterparty in the Company’s consolidated balance sheets.

December 31, 2015
				Fair Value Measurements Using												Net
				Quoted Prices										Gross		Fair Value
				in Active				Significant						Amounts		Presented
				Markets for				Other		Significant				Offset in the		in the
				Identical				Observable		Unobservable				Consolidated		Consolidated
				Assets				Inputs		Inputs		Total		Balance		Balance
(in thousands)				(Level 1)				(Level 2)		(Level 3)		Fair Value		Sheet		Sheet
	Assets
		Current:
			Commodity derivatives		$	-	$	684,029	$	-	$	684,029	$	(31,531)	$	652,498
		Noncurrent:
			Commodity derivatives			-		175,267		-		175,267		(8,229)		167,038
	Liabilities
		Current:
			Commodity derivatives			-		(31,531)		-		(31,531)		31,531		-
		Noncurrent:
			Commodity derivatives			-		(8,229)		-		(8,229)		8,229		-
	Net derivative instruments				$	-	$	819,536	$	-	$	819,536	$	-	$	819,536

December 31, 2014
				Fair Value Measurements Using												Net
				Quoted Prices										Gross		Fair Value
				in Active				Significant						Amounts		Presented
				Markets for				Other		Significant				Offset in the		in the
				Identical				Observable		Unobservable				Consolidated		Consolidated
				Assets				Inputs		Inputs		Total		Balance		Balance
(in thousands)				(Level 1)				(Level 2)		(Level 3)		Fair Value		Sheet		Sheet
	Assets
		Current:
			Commodity derivatives		$	-	$	501,717	$	-	$	501,717	$	(11,366)	$	490,351
		Noncurrent:
			Commodity derivatives			-		262,349		-		262,349		-		262,349
	Liabilities
		Current:
			Commodity derivatives			-		(11,366)		-		(11,366)		11,366		-
		Noncurrent:
			Commodity derivatives			-		-		-		-		-		-
	Net derivative instruments				$	-	$	752,700	$	-	$	752,700	$	-	$	752,700

Carrying amounts, estimated fair values and impairment expense of long-lived assets

The following table reports the carrying amount, estimated fair value and impairment expense of long-lived assets for the indicated periods:

				Estimated
		Carrying		Fair Value		Impairment
(in thousands)		Amount		(Level 3)		Expense
December 2015	$	104,982	$	52,041	$	52,941
September 2015	$	18,023	$	10,435	$	7,588
December 2014	$	677,021	$	245,346	$	431,675
September 2014	$	26,790	$	11,314	$	15,476
June 2013	$	84,140	$	18,765	$	65,375

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Derivative financial instruments (Tables)

12 Months Ended

Dec. 31, 2015

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Summarizes the gains and losses reported in earnings related to the commodity and interest rate derivative instruments

The following table summarizes the gains(losses) reported in earnings related to the commodity derivative instruments for the years ended December 31,2015, 2014 and 2013:

			Years Ended December 31,
(in thousands)				2015		2014		2013
Gain (loss) on derivatives:
	Oil derivatives		$	675,303	$	869,421	$	(133,890)
	Natural gas derivatives			24,449		21,496		10,238
		Total	$	699,752	$	890,917	$	(123,652)
The following table represents the Company’s cash receipts from (payments on) derivatives for the years ended December 31, 2015, 2014 and 2013:
			Years Ended December 31,
(in thousands)				2015		2014		2013
Cash receipts from (payments on) derivatives:
	Oil derivatives		$	597,297	$	76,335	$	(41,616)
	Natural gas derivatives			35,619		(4,352)		9,275
		Total	$	632,916	$	71,983	$	(32,341)

Company's outstanding derivative contracts

Commodity derivative contracts at December 31,2015. The following table sets forth the Company’s outstanding derivative contracts at December 31,2015. When aggregating multiple contracts, the weighted average contract price is disclosed.All of the Company’s derivative contracts at December 31, 2015 are expected to settle by December 31, 2017.

				First		Second		Third		Fourth
				Quarter		Quarter		Quarter		Quarter		Total
Oil Swaps: (a)
	2016:
		Volume (Bbl)		6,722,000		5,985,000		5,460,000		5,054,000		23,221,000
		Price per Bbl	$	71.99	$	73.38	$	74.21	$	59.38	$	70.13
	2017:
		Volume (Bbl)		4,354,000		4,118,000		2,655,000		2,655,000		13,782,000
		Price per Bbl	$	61.59	$	62.03	$	55.23	$	55.23	$	59.27
Oil Basis Swaps: (b)
	2016:
		Volume (Bbl)		6,035,000		5,732,000		5,520,000		5,060,000		22,347,000
		Price per Bbl	$	(1.49)	$	(1.50)	$	(1.46)	$	(1.48)	$	(1.48)
	2017:
		Volume (Bbl)		3,780,000		3,822,000		1,012,000		1,012,000		9,626,000
		Price per Bbl	$	(1.32)	$	(1.32)	$	(0.54)	$	(0.54)	$	(1.16)
Natural Gas Swaps: (c)
	2016:
		Volume (MMBtu)		7,280,000		7,280,000		7,360,000		7,360,000		29,280,000
		Price per MMBtu	$	3.02	$	3.02	$	3.02	$	3.02	$	3.02
(a) The index prices for the oil price swaps are based on the NYMEX – West Texas Intermediate (“WTI”) monthly average futures price.
(b) The basis differential price is between Midland – WTI and Cushing – WTI.
(c) The index prices for the natural gas price swaps are based on the NYMEX – Henry Hub last trading day futures price.

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Debt (Tables)

12 Months Ended

Dec. 31, 2015

Debt Disclosure [Abstract]

Company's debt

Note 9. Debt

The Company’s debt consisted of the following at December 31, 2015 and 2014:

				December 31,
(in thousands)				2015		2014
Credit facility			$	-	$	139,500
7.0% unsecured senior notes due 2021				600,000		600,000
6.5% unsecured senior notes due 2022				600,000		600,000
5.5% unsecured senior notes due 2022				600,000		600,000
5.5% unsecured senior notes due 2023				1,550,000		1,550,000
Unamortized original issue premium				25,073		27,820
Deferred loan costs, net				(42,885)		(48,183)
	Less: current portion			-		-
		Total long-term debt	$	3,332,188	$	3,469,137

Principal maturities of debt

Principal maturities of long-term debt outstanding at December 31,2015were as follows:

(in thousands)
2016		$	-
2017			-
2018			-
2019			-
2020			-
Thereafter			3,350,000
	Total	$	3,350,000

Interest expense

The following amounts have been incurred and charged to interest expense for the years ended December 31,2015, 2014 and 2013:

		Years Ended December 31,
(in thousands)			2015		2014		2013
Cash payments for interest		$	211,443	$	211,342	$	200,961
Amortization of original issue discount (premium)			(2,747)		(2,599)		(1,248)
Amortization of deferred loan origination costs			9,971		10,937		13,172
Accretion expense			1,795		-		-
Net changes in accruals			(165)		(737)		5,696
	Interest costs incurred		220,297		218,943		218,581
Less: capitalized interest			(4,913)		(2,282)		-
	Total interest expense	$	215,384	$	216,661	$	218,581

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Commitments and contingencies (Tables)

12 Months Ended

Dec. 31, 2015

Commitments and Contingencies Disclosure [Abstract]

Summary of the Company's future commitments

The following table summarizes the Company’s commitments at December 31,2015:

(in thousands)
2016		$	51,710
2017			21,256
2018			21,148
2019			13,196
2020			7,335
Thereafter			45,451
	Total	$	160,096

Future minimum lease commitments under non-cancellable operating leases

Future minimum lease commitments under non-cancellable operating leases at December 31,2015were as follows:

(in thousands)
2016		$	7,941
2017			7,877
2018			7,087
2019			5,651
2020			4,738
Thereafter			5,091
	Total	$	38,385

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Income taxes (Tables)

12 Months Ended

Dec. 31, 2015

Income Tax Disclosure [Abstract]

The Company's income tax provision

The Company’s income tax provision and amounts separately allocated were attributable to the following items for the years ended December 31,2015, 2014 and 2013:

		Years Ended December 31,
(in thousands)			2015		2014		2013
Income from continuing operations		$	31,371	$	317,785	$	118,237
Income from discontinued operations			-		-		7,518
Changes in stockholders’ equity:
	Excess tax benefits related to stock-based compensation		(2,150)		(16,480)		(6,147)
		$	29,221	$	301,305	$	119,608

Company's income tax provision attributable to income from continuing operations

The Company’s income tax provision attributable to income from continuing operations consisted of the following for the years ended December 31,2015, 2014 and 2013:

					Years Ended December 31,
(in thousands)						2015		2014		2013
Current:
	U.S. federal				$	127	$	16,621	$	12,504
	U.S. state and local					1,622		4,997		3,306
		Total current income tax provision				1,749		21,618		15,810
Deferred:
	U.S. federal					40,364		278,615		119,985
	U.S. state and local					(10,742)		17,552		(17,558)
		Total deferred income tax provision				29,622		296,167		102,427
			Total income tax provision attributable to income from
				continuing operations	$	31,371	$	317,785	$	118,237

reconciliation between the income tax expense computed by multiplying pretax income from continuing operations

The reconciliation between the income tax expense computed by multiplying pre-tax income from continuing operations by the United States federal statutory rate and the reported amounts of income tax expense from continuing operations is as follows:

		Years Ended December 31,
(in thousands)			2015		2014		2013
Income at U.S. federal statutory rate		$	34,045	$	299,586	$	125,006
State income taxes (net of federal tax effect)			3,071		22,826		12,505
Revisions of previous estimates			(631)		738		1,400
Change in estimated effective statutory state income tax			(9,026)		(7,945)		(21,876)
Nondeductible expense & other			3,912		2,580		1,202
	Income tax expense	$	31,371	$	317,785	$	118,237
Effective tax rate			32.3%		37.1%		33.1%

Company's income tax provision attributable to income from discontinued operations

The Company’s income tax provision attributable to income from discontinued operations consisted of the following for the year ended December 31, 2013:

				Year Ended
(in thousands)				December 31, 2013
Current:
	U.S. federal			$	144
	U.S. state and local				25
		Total current income tax provision			169
Deferred:
	U.S. federal				6,397
	U.S. state and local				952
		Total deferred income tax provision			7,349
			Total income tax provision attributable to income from discontinued operations	$	7,518

Schedule of Deferred Tax Assets and Liabilities [Table Text Block]

The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities were as follows:

				December 31,
(in thousands)				2015			2014
Deferred tax assets:
	Stock-based compensation			$	36,738	$	24,810
	Asset retirement obligation				44,573		44,802
	Other				29,574		28,925
			Total deferred tax assets		110,885		98,537
Deferred tax liabilities:
	Oil and natural gas properties, principally due to differences in basis and
		depreciation and the deduction of intangible drilling costs for tax purposes			(1,420,275)		(1,401,313)
	Intangible assets - operating rights				(9,548)		(10,148)
	Derivative instruments				(304,550)		(281,303)
	Other				(6,885)		(6,524)
			Total deferred tax liability		(1,741,258)		(1,699,288)
			Net deferred tax liability	$	(1,630,373)	$	(1,600,751)

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Major customers and derivative counterparties (Tables)

12 Months Ended

Dec. 31, 2015

Major Customer Disclosure [Abstract]

Schedule of Revenue by Major Customers by Reporting Segments [Table Text Block]

The following purchasers individually accounted for 10 percent or more of the consolidated oil and natural gas revenuesduring the years ended December 31, 2015, 2014 and 2013:

	Years Ended December 31,
	2015	2014	2013
Holly Frontier Refining and Marketing, LLC	25%	17%	30%
Enterprise Crude Oil LLC	12%	12%	13%
Plains Marketing and Transportation, Inc.	11%	6%	4%
Western Refining Company LP	5%	12%	1%

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Related party transactions (Tables)

12 Months Ended

Dec. 31, 2015

Related Party Transactions [Abstract]

Summary of charges incurred with and payments made to and received from the Company's related parties and reported in the consolidated statements of operations

The following table summarizes charges incurred with and payments made to related parties and reported in the Company’s consolidated statements of operations for the periods presented:

	Years Ended December 31,
(in thousands)		2015		2014		2013
Amounts paid to a partnership in which a director has an ownership interest (a)	$	5,745	$	15,181	$	7,255
Amounts paid to a director and certain officers of the Company (b)	$	593	$	383	$	43
Amounts paid under consulting agreement with Steven L. Beal (c)	$	-	$	-	$	865
Amounts received from a director and certain officers of the Company (d)	$	237	$	169	$	84

(a)Amounts include royalties on certain properties and lease bonus payments paid to a partnership in which a director of the Company is the general partner and owns a 3.5 percent partnership interest.

(b) Amounts include revenue interests, overriding royalty interests and net profits interests in properties owned by the Company made to a director and certain officers (or affiliated entities). Amounts also include payments for an acreage acquisition and lease bonuses to an affiliated entity of an officer.

(c)On June 30, 2009, Steven L. Beal, the Company’s then-president and chief operating officer, retired from such positions. On June 9, 2009, the Company entered into a consulting agreement (the “Consulting Agreement”) with Mr. Beal, under which Mr. Beal began serving as a consultant to the Company on July 1, 2009. During the term of the consulting relationship, Mr. Beal received a consulting fee of $20,000 per month and a monthly reimbursement for his medical and dental coverage costs. In August 2013, the Company and Mr. Beal mutually terminated the Consulting Agreement in exchange for the payment to Mr. Beal of $720,000, which termination and payment were approved by the disinterested members of the Company’s Board of Directors.

(d) Amounts include payments to the Company as a result of activity on oil and natural gas properties in which a director and certain officers (or affiliated entities) have an interest.

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Net income per share (Tables)

12 Months Ended

Dec. 31, 2015

Earnings Per Share, Basic and Diluted, Other Disclosures [Abstract]

Reconciliation of earnings attributable to common shares, basic and diluted

The following tables reconcile the Company’s incomefrom continuing operations,income from discontinued operations and net income attributable to common stockholders to the basic and diluted earnings used to determine the Company’s income per share amounts for the years ended December 31, 2015, 2014 and 2013, respectively, under the two-class method:

		Years Ended December 31,
(in thousands, except per share amounts)		2015		2014
Income as reported		$	65,900	$	538,175
Participating basic earnings			(635)		(5,961)
	Basic income attributable to common stockholders		65,265		532,214
Reallocation of participating earnings			2		16
	Diluted income attributable to common stockholders	$	65,267	$	532,230
Income per common share:
	Basic	$	0.54	$	4.89
	Diluted	$	0.54	$	4.88

			Year Ended
			December 31, 2013
		Continuing		Discontinued
(in thousands, except per share amounts)		Operations		Operations		Total
Income as reported		$	238,922	$	12,081	$	251,003
Participating basic earnings			(2,610)		(132)		(2,742)
	Basic income attributable to common stockholders		236,312		11,949		248,261
Reallocation of participating earnings			4		-		4
	Diluted income attributable to common stockholders	$	236,316	$	11,949	$	248,265
Income per common share:
	Basic	$	2.28	$	0.11	$	2.39
	Diluted	$	2.28	$	0.11	$	2.39

reconciliation of the basic weighted average common shares outstanding to diluted weighted average common shares outstanding

The following table is a reconciliation of the basic weighted average common shares outstanding to diluted weighted average common shares outstanding for the years ended December 31, 2015, 2014 and 2013:

		Years Ended December 31,
(in thousands)		2015	2014	2013
Weighted average common shares outstanding:
	Basic	119,926	108,844	103,744
	Dilutive common stock options	25	83	165
	Dilutive performance units	422	205	4
	Diluted	120,373	109,132	103,913

summary of the performance units that were not included in the computation of diluted net income per share

The following table is a summary of the performance units, which were not included in the computation of diluted net income per share, as inclusion of these items would be antidilutive:

		Years Ended December 31,
(in thousands)		2015	2014	2013
Number of antidilutive common shares:
	Antidilutive performance units	-	-	83

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Other current liabilities (Tables)

12 Months Ended

Dec. 31, 2015

Other Liabilities Disclosure [Abstract]

components of the Company's other current liabilities

The following table provides the components of the Company’s other current liabilities at December 31, 2015 and 2014:

				December 31,
(in thousands)				2015		2014
Other current liabilities:
	Accrued production costs		$	70,876	$	70,786
	Payroll related matters			29,411		34,349
	Accrued interest			68,925		69,264
	Asset retirement obligations			8,626		9,146
	Other			7,072		11,763
		Other current liabilities	$	184,910	$	195,308

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Subsidiary guarantors (Tables)

12 Months Ended

Dec. 31, 2015

Guarantees [Abstract]

Condensed Consolidating Balance Sheet

The following condensed consolidating balance sheets at December 31, 2015 and 2014, condensed consolidating statements of operations and condensed consolidating statements of cash flows for the years ended December 31, 2015, 2014 and 2013, present financial information for Concho Resources Inc. as the parent on a stand-alone basis (carrying any investments in subsidiaries under the equity method), financial information for the subsidiary guarantors on a stand-alone basis and the consolidation and elimination entries necessary to arrive at the information for the Company on a consolidated basis. All current and deferred income taxes are recorded on Concho Resources Inc., as the subsidiaries are flow-through entities for income tax purposes. The subsidiary guarantors are not restricted from making distributions to the Company.

Condensed Consolidating Balance Sheet
December 31, 2015
			Parent		Subsidiary		Consolidating
(in thousands)			Issuer		Guarantors		Entries		Total
ASSETS
Accounts receivable - related parties		$	8,502,099	$	1,162,297	$	(9,664,396)	$	-
Other current assets			753,716		560,834		-		1,314,550
Oil and natural gas properties, net			-		10,798,497		-		10,798,497
Property and equipment, net			-		178,450		-		178,450
Investment in subsidiaries			3,698,485		-		(3,698,485)		-
Other long-term assets			182,623		167,756		-		350,379
	Total assets	$	13,136,923	$	12,867,834	$	(13,362,881)	$	12,641,876
LIABILITIES AND EQUITY
Accounts payable - related parties		$	1,162,297	$	8,502,099	$	(9,664,396)	$	-
Other current liabilities			69,514		526,906		-		596,420
Long-term debt			3,332,188		-		-		3,332,188
Other long-term liabilities			1,630,373		140,344		-		1,770,717
Equity			6,942,551		3,698,485		(3,698,485)		6,942,551
	Total liabilities and equity	$	13,136,923	$	12,867,834	$	(13,362,881)	$	12,641,876

Condensed Consolidating Balance Sheet
December 31, 2014
			Parent		Subsidiary		Consolidating
(in thousands)			Issuer		Guarantors		Entries		Total
ASSETS
Accounts receivable - related parties		$	6,670,744	$	1,201,950	$	(7,872,694)	$	-
Other current assets			569,545		618,851		-		1,188,396
Oil and natural gas properties, net			-		10,076,878		-		10,076,878
Property and equipment, net			-		129,136		-		129,136
Investment in subsidiaries			4,085,045		-		(4,085,045)		-
Other long-term assets			282,609		74,761		-		357,370
	Total assets	$	11,607,943	$	12,101,576	$	(11,957,739)	$	11,751,780
LIABILITIES AND EQUITY
Accounts payable - related parties		$	1,201,950	$	6,670,744	$	(7,872,694)	$	-
Other current liabilities			55,318		1,209,309		-		1,264,627
Long-term debt			3,469,137		-		-		3,469,137
Other long-term liabilities			1,600,750		136,478		-		1,737,228
Equity			5,280,788		4,085,045		(4,085,045)		5,280,788
	Total liabilities and equity	$	11,607,943	$	12,101,576	$	(11,957,739)	$	11,751,780

Condensed Consolidating Statement of Operations

The following condensed consolidating balance sheets at December 31, 2015 and 2014, condensed consolidating statements of operations and condensed consolidating statements of cash flows for the years ended December 31, 2015, 2014 and 2013, present financial information for Concho Resources Inc. as the parent on a stand-alone basis (carrying any investments in subsidiaries under the equity method), financial information for the subsidiary guarantors on a stand-alone basis and the consolidation and elimination entries necessary to arrive at the information for the Company on a consolidated basis. All current and deferred income taxes are recorded on Concho Resources Inc., as the subsidiaries are flow-through entities for income tax purposes. The subsidiary guarantors are not restricted from making distributions to the Company.

Condensed Consolidating Statement of Operations
For the Year Ended December 31, 2015
			Parent		Subsidiary		Consolidating
(in thousands)			Issuer		Guarantors		Entries		Total
Total operating revenues		$	-	$	1,803,573	$	-	$	1,803,573
Total operating costs and expenses			697,247		(2,119,817)		-		(1,422,570)
	Income (loss) from operations		697,247		(316,244)		-		381,003
Interest expense			(213,416)		(1,968)		-		(215,384)
Other, net			(386,560)		(68,348)		386,560		(68,348)
	Income (loss) before income taxes		97,271		(386,560)		386,560		97,271
Income tax expense			(31,371)		-		-		(31,371)
	Net income (loss)	$	65,900	$	(386,560)	$	386,560	$	65,900

Condensed Consolidating Statement of Operations
For the Year Ended December 31, 2014
		Parent		Subsidiary		Consolidating
(in thousands)		Issuer		Guarantors		Entries		Total
Total operating revenues		$	-	$	2,660,147	$	-	$	2,660,147
Total operating costs and expenses			888,632		(2,459,034)		-		(1,570,402)
	Income from operations		888,632		201,113		-		1,089,745
Interest expense			(216,661)		-		-		(216,661)
Loss on extinguishment of debt			(4,316)		-		-		(4,316)
Other, net			188,305		(12,809)		(188,304)		(12,808)
	Income before income taxes		855,960		188,304		(188,304)		855,960
Income tax expense			(317,785)		-		-		(317,785)
	Net income	$	538,175	$	188,304	$	(188,304)	$	538,175

Condensed Consolidating Statement of Operations
For the Year Ended December 31, 2013
			Parent		Subsidiary		Consolidating
(in thousands)			Issuer		Guarantors		Entries		Total
Total operating revenues		$	-	$	2,319,919	$	-	$	2,319,919
Total operating costs and expenses			(125,924)		(1,576,558)		-		(1,702,482)
	Income (loss) from operations		(125,924)		743,361		-		617,437
Interest expense			(218,581)		-		-		(218,581)
Loss on extinguishment of debt			(28,616)		-		-		(28,616)
Other, net			749,878		(13,136)		(749,823)		(13,081)
	Income before income taxes		376,757		730,225		(749,823)		357,159
Income tax expense			(118,237)		-		-		(118,237)
	Income from continuing operations		258,520		730,225		(749,823)		238,922
Income (loss) from discontinued operations, net of tax			(7,517)		19,598		-		12,081
	Net income	$	251,003	$	749,823	$	(749,823)	$	251,003

Condensed Consolidating Statement of Cash Flows

The following condensed consolidating balance sheets at December 31, 2015 and 2014, condensed consolidating statements of operations and condensed consolidating statements of cash flows for the years ended December 31, 2015, 2014 and 2013, present financial information for Concho Resources Inc. as the parent on a stand-alone basis (carrying any investments in subsidiaries under the equity method), financial information for the subsidiary guarantors on a stand-alone basis and the consolidation and elimination entries necessary to arrive at the information for the Company on a consolidated basis. All current and deferred income taxes are recorded on Concho Resources Inc., as the subsidiaries are flow-through entities for income tax purposes. The subsidiary guarantors are not restricted from making distributions to the Company.

Condensed Consolidating Statement of Cash Flows
For the Year Ended December 31, 2015
			Parent Issuer		Subsidiary Guarantors		Consolidating Entries
(in thousands)									Total
Net cash flows provided by (used in) operating activities		$	(2,026,206)	$	2,923,711	$	-	$	897,505
Net cash flows provided by (used in) investing activities			632,916		(2,602,641)		-		(1,969,725)
Net cash flows provided by (used in) financing activities			1,393,290		(92,541)		-		1,300,749
	Net increase in cash and cash equivalents		-		228,529		-		228,529
	Cash and cash equivalents at beginning of period		-		21		-		21
	Cash and cash equivalents at end of period	$	-	$	228,550	$	-	$	228,550

Condensed Consolidating Statement of Cash Flows
For the Year Ended December 31, 2014
			Parent		Subsidiary		Consolidating
(in thousands)			Issuer		Guarantors		Entries		Total
Net cash flows provided by (used in) operating activities		$	(888,369)	$	2,562,156	$	-	$	1,673,787
Net cash flows provided by (used in) investing activities			71,983		(2,617,979)		-		(2,545,996)
Net cash flows provided by financing activities			816,386		55,823		-		872,209
	Net increase (decrease) in cash and cash equivalents		-		-		-		-
	Cash and cash equivalents at beginning of period		-		21		-		21
	Cash and cash equivalents at end of period	$	-	$	21	$	-	$	21

Condensed Consolidating Statement of Cash Flows
For the Year Ended December 31, 2013
			Parent		Subsidiary		Consolidating
(in thousands)			Issuer		Guarantors		Entries		Total
Net cash flows provided by (used in) operating activities		$	(487,131)	$	1,849,151	$	-	$	1,362,020
Net cash flows used in investing activities			(32,341)		(1,864,453)		-		(1,896,794)
Net cash flows provided by financing activities			519,472		12,443		-		531,915
	Net decrease in cash and cash equivalents		-		(2,859)		-		(2,859)
	Cash and cash equivalents at beginning of period		-		2,880		-		2,880
	Cash and cash equivalents at end of period	$	-	$	21	$	-	$	21

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Subsequent events (Tables)

12 Months Ended

Dec. 31, 2015

Subsequent Events [Abstract]

New commodity derivative contracts

After December 31, 2015, the Company entered into the following additional oil price swaps and oil basis swaps to hedge additional amounts of the Company’s estimated future production:

				First		Second		Third		Fourth
				Quarter		Quarter		Quarter		Quarter		Total
Oil Swaps: (a)
	2017:
		Volume (Bbl)		180,000		180,000		750,000		750,000		1,860,000
		Price per Bbl	$	42.55	$	42.55	$	43.63	$	43.63	$	43.42
Oil Basis Swaps: (b)
	2016:
		Volume (Bbl)		120,000		182,000		-		-		302,000
		Price per Bbl	$	(0.25)	$	(0.25)	$	-	$	-	$	(0.25)
	2017:
		Volume (Bbl)		360,000		242,000		2,024,000		2,024,000		4,650,000
		Price per Bbl	$	(0.41)	$	(0.38)	$	(0.38)	$	(0.38)	$	(0.38)
(a)		The index prices for the oil price swaps are based on the NYMEX – WTI monthly average futures price.
(b)		The basis differential price is between Midland – WTI and Cushing – WTI.

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Summary Of Significant Accounting Policies (Narrative) (Detail) - USD ($) $ in Thousands	3 Months Ended					12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2013	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Disclosure Summary Of Significant Accounting Policies Narrative [Abstract]
Deferred loan costs, net	$ 42,885		$ 48,183			$ 42,885	$ 48,183
Current deferred income tax liability			162,600				162,600
Allowance for Doubtful Accounts Receivable	1,200		700			1,200	700
Accumulated amortization of reclassified deferred loan costs						18,700	13,400
Deferred loan costs	15,585		20,260			15,585	20,260
Accumulated amortization						$ 51,000	46,300
Estimated economic life of gross operating rights in years						25 years
Depletion expense from continuing and discontuned operations						$ 1,203,500	960,900	$ 756,000
Impairment Of Oil And Gas Properties	52,941	$ 7,588	431,675	$ 15,476	$ 65,375	60,500	447,200	65,400
Impairment of Leasehold						34,500	217,300	49,800
Other property and equipment, net	178,450		129,136			178,450	129,136
Other property and equipment, accumulated depreciation	54,400		52,500			54,400	52,500
Depreciation expense on other property and equipment						18,300	17,300	15,200
Environmental liability accrued	1,000		1,700			1,000	1,700
Environmental libility expensed						2,700	4,000	3,400
Fees related to operation of jointly owned oil and natural gas properties						24,300	23,200	18,500
Interest costs capitalized on oil and gas properties						$ 700	1,400	$ 0
Disposal Date						Jan. 01, 2016		Dec. 15, 2012
Net Proceeds								$ 503,100
Pre-tax gain on sale of assets of discontinued operations								900
Gain on Sale of Assets								19,600
Discontinued Operation Tax Effect Of Discontinued Operation								7,500
Income from discontinued operations, net of tax						$ 0	0	$ 12,081
Alpha Crude Connector [Member]
Equity Method Investments [Line Items]
Income (loss) from equity method investments						(4,100)	(1,300)
Interest costs capitalized on equity method investment						2,900	700
Total equity method investment	$ 98,900		$ 29,500			$ 98,900	$ 29,500
Equity method investment ownership percentage	50.00%					50.00%
Other [Member]
Equity Method Investments [Line Items]
Total equity method investment	$ 20,800					$ 20,800
Equity method investment ownership percentage	25.00%					25.00%

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Summary Of Significant Accounting Policies (Gross And Net Intangible Assets) (Detail) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Disclosure Summary Of Significant Accounting Policies Gross And Net Intangible Assets [Abstract]
Gross intangible - operating rights	$ 36,557	$ 36,557
Accumulated amortization	(10,864)	(9,403)
Net intangible - operating rights	$ 25,693	$ 27,154

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Summary Of Significant Accounting Policies (Amortization Expense) (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Disclosure Summary Of Significant Accounting Policies Amortization Expense [Abstract]
Amortization expense	$ 1,461	$ 1,461	$ 1,461

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Summary Of Significant Accounting Policies (Estimated Future Aggregate Amortization Expense) (Detail) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Disclosure Summary Of Significant Accounting Policies Estimated Future Aggregate Amortization Expense [Abstract]
2016	$ 1,461
2017	1,461
2018	1,461
2019	1,461
2020	1,461
Thereafter	18,388
Net intangible - operating rights	$ 25,693	$ 27,154

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Exploratory Well Costs (Capitalized Exploratory Well Activity) (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Disclosure Exploratory Well Costs Capitalized Exploratory Well Activity [Abstract]
Beginning capitalized exploratory well costs	$ 241,657	$ 144,504	$ 118,806
Additions to exploratory well costs pending the determination of proved reserves	102,846	234,057	130,967
Reclassifications due to determination of proved reserves	(227,746)	(99,657)	(94,114)
Exploratory well costs charged to expense	(559)	(37,247)	(11,155)
Ending capitalized exploratory well costs	$ 116,198	$ 241,657	$ 144,504

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Exploratory Well Costs (Aging Of Capitalized Exploratory Well Costs Based On The Date Of Drilling) (Detail) $ in Thousands	Dec. 31, 2015 USD ($) Number	Dec. 31, 2014 USD ($) Number	Dec. 31, 2013 USD ($)	Dec. 31, 2012 USD ($)
Disclosure Exploratory Well Costs Aging Of Capitalized Exploratory Well Costs Based On The Date Of Drilling [Abstract]
Capitalized exploratory well costs that have been capitalized for a period of one year or less	$ 98,764	$ 232,346
Capitalized exploratory well costs that have been capitalized for a period greater than one year	17,434	9,311
Total capitalized exploratory well costs	$ 116,198	$ 241,657	$ 144,504	$ 118,806
Projects that have Exploratory Well Costs that have been Capitalized for Period Greater than One Year, Number of Projects | Number	8	7

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Exploratory Well Costs (Narrative) (Detail) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Oil And Gas In Process Activities [Line Items]
Capitalized Exploratory Well Costs That Have Been Capitalized For Period Greater Than One Year	$ 17,434	$ 9,311
Delaware Basin Area [Member]
Oil And Gas In Process Activities [Line Items]
Capitalized Exploratory Well Costs That Have Been Capitalized For Period Greater Than One Year	7,200
Delaware Basin Area - Other Project [Member]
Oil And Gas In Process Activities [Line Items]
Capitalized Exploratory Well Costs That Have Been Capitalized For Period Greater Than One Year	5,700
OBO Projects [Member]
Oil And Gas In Process Activities [Line Items]
Capitalized Exploratory Well Costs That Have Been Capitalized For Period Greater Than One Year	4,500
OBO Projects - Projects Drilled in 2012 [Member]
Oil And Gas In Process Activities [Line Items]
Capitalized Exploratory Well Costs That Have Been Capitalized For Period Greater Than One Year	$ 3,000

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Acquisitions And Business Combinations (Narrative) (Detail)	12 Months Ended
	Dec. 31, 2015 USD ($)
Clayton Williams [Member]
Business Acquisition [Line Items]
Gain (loss) on disposition of assets	$ (50,000,000)

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Asset Retirement Obligations (Schedule Of Asset Retirement Obligation Transactions) (Detail) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Disclosure Asset Retirement Obligations Schedule Of Asset Retirement Obligation Transactions [Abstract]
Asset retirement obligations, beginning of period		$ 119,881	$ 101,593	$ 86,261
Liabilities incurred from new wells		4,052	5,324	6,338
Liabilities assumed in acquisitions		2,434	4,065	593
Accretion expense for continuing operations		7,600	7,072	6,047
Liabilities settled upon plugging and abandoning wells		(2,736)	(2,926)	(3,447)
Revision of estimates	[1]	(11,286)	4,753	5,801
Asset retirement obligations, end of period		$ 119,945	$ 119,881	$ 101,593

[1] The downward revision to the Company’s asset retirement obligation estimates for the year ended December 31, 2015 is primarily due to a reduction in the future estimated abandonment costs.

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Incentive Plans (Narrative) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Defined Benefit Plans And Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined contribution plan, employers contribution	$ 9.5	$ 8.1	$ 6.6
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercises in Period, Total Intrinsic Value	$ 0.4	$ 23.2	$ 13.2
Performance unit awards vesting period	3 years
Approved and authorized awards	10,500,000
Awards available for future grant	2,900,000
Plan 401 k [Member]
Defined Benefit Plans And Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined contribution plan employer's contribution match percentage	100.00%
Defined contribution plan, employee contribution	10.00%

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Incentive Plans (Summary Of Stock Incentive Plan) (Detail) - shares	Dec. 31, 2015	Dec. 31, 2014
Disclosure Incentive Plans Summary Of Stock Incentive Plan [Abstract]
Treasury shares	306,061	260,124

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Incentive Plans (Schedule Of Restricted Stock Awards Activity) (Detail) - $ / shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Disclosure Incentive Plans Schedule Of Restricted Stock Awards Activity [Abstract]
Outstanding at beginning of period	1,091,309
Shares granted	452,436	448	499
Shares cancelled / forfeited	(33,124)
Lapse of restrictions	(310,974)
Outstanding at end of period	1,199,647	1,091,309
Weighted Average Grant Date Fair Value, Outstanding at beginning of year	$ 106.33
Shares Granted - Weighted Average Grant Date Fair Value Per Share	109.76	$ 129.12	$ 88.19
Shares cancelled / forfeited - Weighted Average Grant Date Fair Value per share	111.08
Lapse of Restrictions - Weighted Average Grant Date Fair Value per share	96.15
Weighted Average Grant Date Fair Value, Outstanding at end of year	$ 110.14	$ 106.33

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Incentive Plans (Summary Information For Stock-Based Compensation For Restricted Stock Awards) (Detail) - USD ($)		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Shares Granted - Weighted Average Grant Date Fair Value Per Share		$ 109.76	$ 129.12	$ 88.19
Restricted Stock [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Fair value for awards granted during the period	[1]	$ 49,659,000	$ 57,940,000	$ 44,947,000
Fair value for awards vested during the period		35,700,000	59,226,000	21,496,000
Stock-based compensation expense from restricted stock		43,185,000	36,585,000	30,984,000
Income tax benefit related to restricted stock		$ 16,049,000	$ 13,672,000	$ 11,650,000

[1] The weighted average grant date fair value per share amounts were $109.76, $129.12 and $88.19 for the years ended December 31, 2015, 2014 and 2013, respectively. The year ended December 31, 2013 includes the effects of $1 million due to modifications of certain stock-based awards.

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Incentive Plans (Schedule Of Stock Option Awards Activity) (Detail) - $ / shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Disclosure Incentive Plans Schedule Of Stock Option Awards Activity [Abstract]
Outstanding at beginning of period (Shares)	47,713	255,537	429,879
Options exercised (Shares)	(4,812)	(207,824)	(174,342)
Outstanding at end of period (Shares)	42,901	47,713	255,537
Vested and exercisable at end of period (Shares)	42,901
Outstanding at beginning of period	$ 17.49	$ 21.5	$ 20.28
Options exercised	12	22.42	18.48
Outstanding at end of period	18.1	17.49	21.5
Vested and exercisable at end of period - weighted average exercise price	$ 18.1	$ 17.49	$ 21.5

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Incentive Plans (Summary Information For Vested And Exercisable Stock Options Outstanding) (Detail) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]
Vested and exercisable at end of period (Shares)	42,901
Weighted Average Remaining Contractual Life, Vested and exercisable options, years	2 years 5 months
Vested and exercisable at end of period - weighted average exercise price	$ 18.1	$ 17.49	$ 21.5
Intrinsic Value, Vested and exercisable options	$ 3,207
Range Three [Member]
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]
Exercise price, Lower range	$ 12
Exercise price, Upper range	$ 12.85
Vested and exercisable at end of period (Shares)	15,824
Weighted Average Remaining Contractual Life, Vested and exercisable options, years	1 year 6 months
Vested and exercisable at end of period - weighted average exercise price	$ 12.81
Intrinsic Value, Vested and exercisable options	$ 1,267
Range Four [Member]
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]
Exercise price, Lower range	$ 20.4
Exercise price, Upper range	$ 22.77
Vested and exercisable at end of period (Shares)	27,077
Weighted Average Remaining Contractual Life, Vested and exercisable options, years	2 years 12 months
Vested and exercisable at end of period - weighted average exercise price	$ 21.2
Intrinsic Value, Vested and exercisable options	$ 1,940

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Incentive Plans (Summary Information For Stock-Based Compensation For Stock Options) (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Stock Options [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Deductions in current taxable income related to stock options exercised	$ 415	$ 23,208	$ 13,193

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Incentive Plans (Summary Of Assumptions To Estimate Fair Value of Performance Unit Awards) (Detail)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Disclosure Incentive Plans Schedule Of Performance Unit Awards Fair Value Assumptions [Abstract]
Risk-free interest rate	1.07%	0.76%	0.37%
Volatility assumption - minimum	26.10%	29.20%	31.50%
Volatility assumption - maximum	43.00%	42.20%	45.10%

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Incentive Plans (Schedule Of Performance Unit Awards Activity) (Detail)	12 Months Ended
	Dec. 31, 2015 $ / shares shares
Disclosure Incentive Plans Schedule Of Performance Unit Awards Activity [Abstract]
Performance units outstanding at beginning of period (Shares)	250,314
Units granted	176,330	[1]
Units vested	110,889	[2]
Performance units outstanding at end of period (Shares)	315,755
Weighted Average Grant Date Fair Value, Outstanding at beginning of year | $ / shares	$ 127.07
Shares Granted - Grant Date Fair Value - Performance Units | $ / shares	156.86	[1]
Shares Vested - Grant Date Fair Value - Performance Units | $ / shares	111.4	[2]
Weighted Average Grant Date Fair Value, Outstanding at end of year | $ / shares	$ 149.21
Performance Percentage Of Actual Payout Minimum	0.00%
Performance Percentage Of Actual Payout Maximum	300.00%
Number Of Shares Earned For Each Vested Award	180,199

[1] Reflects the amount of performance units granted. The actual payout of shares will be between zero and 300 percent of the performance units granted depending on the Company’s performance at the end of the performance period.

[2] On December 31, 2015, the performance period ended for these performance units. Each unit converted into 1.625 shares representing 180,199 shares of common stock issued on January 4, 2016.

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Incentive Plans (Summary Information For Stock-Based Compensation For Performance Units) (Detail) - Performance Shares [Member] - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Fair value for awards granted during the period	$ 27,659	$ 19,455	$ 12,352
Stock-based compensation expense from performance units	19,888	10,545	4,080
Income tax benefit related to performance units	$ 7,391	$ 3,941	$ 1,560

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Incentive Plans (Summary For Future Stock-Based Compensation Expense) (Detail) $ in Thousands	Dec. 31, 2015 USD ($)
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
2016	$ 47,726
2017	27,408
2018	6,466
2019	286
2020	4
Total	81,890
Restricted Stock [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
2016	31,992
2017	18,189
2018	6,466
2019	286
2020	4
Total	56,937
Performance Shares [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
2016	15,734
2017	9,219
2018	0
2019	0
2020	0
Total	$ 24,953

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Disclosures About Fair Value Of Financial Instruments (Carrying Amounts And Fair Values Of The Company's Financial Instruments) (Detail) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Credit facility	$ 0	$ 139,500
Seven Point Zero Percent Unsecured Senior Notes [Member]
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Unsecured senior notes	600,000	600,000
Six Point Five Percent Unsecured Senior Notes [Member]
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Unsecured senior notes	600,000	600,000
Five Point Five Percent Unsecured Senior Notes [Member]
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Unsecured senior notes	600,000	600,000
Five Point Five Percent Unsecured Senior Notes Due Twenty Twenty Three [Member]
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Unsecured senior notes	1,550,000	1,550,000
Carrying Reported Amount Fair Value Disclosure [Member]
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Derivative instruments, Assets	819,536	752,700
Credit facility	0	139,500
Carrying Reported Amount Fair Value Disclosure [Member] | Seven Point Zero Percent Unsecured Senior Notes [Member]
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Unsecured senior notes	592,414	591,213
Carrying Reported Amount Fair Value Disclosure [Member] | Six Point Five Percent Unsecured Senior Notes [Member]
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Unsecured senior notes	591,549	590,454
Carrying Reported Amount Fair Value Disclosure [Member] | Five Point Five Percent Unsecured Senior Notes [Member]
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Unsecured senior notes	592,899	592,061
Carrying Reported Amount Fair Value Disclosure [Member] | Five Point Five Percent Unsecured Senior Notes Due Twenty Twenty Three [Member]
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Unsecured senior notes	1,555,326	1,555,909
Portion At Fair Value Fair Value Disclosure [Member]
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Derivative instruments, Assets	819,536	752,700
Credit facility	0	131,068
Portion At Fair Value Fair Value Disclosure [Member] | Seven Point Zero Percent Unsecured Senior Notes [Member]
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Unsecured senior notes	595,500	625,500
Portion At Fair Value Fair Value Disclosure [Member] | Six Point Five Percent Unsecured Senior Notes [Member]
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Unsecured senior notes	579,000	628,500
Portion At Fair Value Fair Value Disclosure [Member] | Five Point Five Percent Unsecured Senior Notes [Member]
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Unsecured senior notes	553,500	598,500
Portion At Fair Value Fair Value Disclosure [Member] | Five Point Five Percent Unsecured Senior Notes Due Twenty Twenty Three [Member]
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Unsecured senior notes	$ 1,453,005	$ 1,573,875

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Disclosures About Fair Value Measurements (Company's Assets And Liabilities Measured At Fair Value On A Recurring Basis) (Detail) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Fair Value Of Derivatives Disclosure Information [Line Items]
Current derivative contracts, assets	$ 652,498	$ 490,351
Noncurrent derivative contracts, assets	167,038	262,349
Net financial assets (liabilities)	819,536	752,700
Estimate Of Fair Value Fair Value Disclosure [Member]
Fair Value Of Derivatives Disclosure Information [Line Items]
Current derivative contracts, assets	684,029	501,717
Noncurrent derivative contracts, assets	175,267	262,349
Current derivative contracts, liabilities	(31,531)	(11,366)
Noncurrent derivative contracts, liabilities	(8,229)	0
Net financial assets (liabilities)	819,536	752,700
Gross Amounts Offset in Consolidated Balance Sheet [Member]
Fair Value Of Derivatives Disclosure Information [Line Items]
Current derivative contracts, assets	(31,531)	(11,366)
Noncurrent derivative contracts, assets	(8,229)	0
Current derivative contracts, liabilities	31,531	11,366
Noncurrent derivative contracts, liabilities	8,229	0
Net financial assets (liabilities)	0	0
Fair Value Inputs Level 1 [Member]
Fair Value Of Derivatives Disclosure Information [Line Items]
Current derivative contracts, assets	0	0
Noncurrent derivative contracts, assets	0	0
Current derivative contracts, liabilities	0	0
Noncurrent derivative contracts, liabilities	0	0
Net financial assets (liabilities)	0	0
Fair Value Inputs Level 2 [Member]
Fair Value Of Derivatives Disclosure Information [Line Items]
Current derivative contracts, assets	684,029	501,717
Noncurrent derivative contracts, assets	175,267	262,349
Current derivative contracts, liabilities	(31,531)	(11,366)
Noncurrent derivative contracts, liabilities	(8,229)	0
Net financial assets (liabilities)	819,536	752,700
Fair Value Inputs Level 3 [Member]
Fair Value Of Derivatives Disclosure Information [Line Items]
Current derivative contracts, assets	0	0
Noncurrent derivative contracts, assets	0	0
Current derivative contracts, liabilities	0	0
Noncurrent derivative contracts, liabilities	0	0
Net financial assets (liabilities)	$ 0	$ 0

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Disclosures About Fair Value Of Financial Instruments (Carrying Amounts, Estimated Fair Values And Impairment Expense Of Long-Lived Assets For Continuing And Discontinued Operations) (Detail) - USD ($) $ in Thousands	3 Months Ended					12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2013	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Disclosure Disclosures About Fair Value Of Financial Instruments Carrying Amounts Estimated Fair Values And Impairment Expense Of Long Lived Assets For Continuing And Discontinued Operations [Abstract]
Carrying Amount	$ 104,982	$ 18,023	$ 677,021	$ 26,790	$ 84,140
Estimated Fair Value	52,041	10,435	245,346	11,314	18,765
Impairment Expense	$ 52,941	$ 7,588	$ 431,675	$ 15,476	$ 65,375	$ 60,500	$ 447,200	$ 65,400

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Derivative Financial Instruments (Gains And Losses Reported In Earnings Related To The Commodity And Interest Rate Derivative Instruments) (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Derivative Financial Instruments Gains And Losses Reported In Earnings Related To Commodity And Interest Rate Derivative Instruments [Line Items]
Settlements received from (paid on) derivatives	$ 632,916	$ 71,983	$ (32,341)
Mark-to-market gain (loss)	699,752	890,917	(123,652)
Oil Commodity Derivative [Member]
Derivative Financial Instruments Gains And Losses Reported In Earnings Related To Commodity And Interest Rate Derivative Instruments [Line Items]
Settlements received from (paid on) derivatives	597,297	76,335	(41,616)
Mark-to-market gain (loss)	675,303	869,421	(133,890)
Natural Gas Commodity Derivative [Member]
Derivative Financial Instruments Gains And Losses Reported In Earnings Related To Commodity And Interest Rate Derivative Instruments [Line Items]
Settlements received from (paid on) derivatives	35,619	(4,352)	9,275
Mark-to-market gain (loss)	$ 24,449	$ 21,496	$ 10,238

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Derivative Financial Instruments (Outstanding Commodity Derivative Contracts) (Detail)		3 Months Ended				12 Months Ended
		Dec. 31, 2016 MMBTU bbl $ / bbl $ / MMBTU	Sep. 30, 2016 MMBTU bbl $ / bbl $ / MMBTU	Jun. 30, 2016 MMBTU bbl $ / bbl $ / MMBTU	Mar. 31, 2016 MMBTU bbl $ / bbl $ / MMBTU	Dec. 31, 2016 MMBTU bbl $ / bbl $ / MMBTU
Oil Swaps [Member]
Derivative [Line Items]
Volume (Bbl/MMBtu) - Current Year | bbl	[1]	5,054,000	5,460,000	5,985,000	6,722,000	23,221,000
Price per Bbl/MMBtu - Current Year | $ / bbl	[1]	59.38	74.21	73.38	71.99	70.13
Volume (Bbl/MMBtu) - Year One | bbl	[1]	2,655,000	2,655,000	4,118,000	4,354,000	13,782,000
Price per Bbl/MMBtu - Year One | $ / bbl	[1]	55.23	55.23	62.03	61.59	59.27
Oil Basis Swaps [Member]
Derivative [Line Items]
Volume (Bbl/MMBtu) - Current Year | bbl	[2]	5,060,000	5,520,000	5,732,000	6,035,000	22,347,000
Price per Bbl/MMBtu - Current Year | $ / bbl	[2]	(1.48)	(1.46)	(1.5)	(1.49)	(1.48)
Volume (Bbl/MMBtu) - Year One | bbl	[2]	1,012,000	1,012,000	3,822,000	3,780,000	9,626,000
Price per Bbl/MMBtu - Year One | $ / bbl	[2]	(0.54)	(0.54)	(1.32)	(1.32)	(1.16)
Natural Gas Swap [Member]
Derivative [Line Items]
Volume (Bbl/MMBtu) - Current Year | MMBTU	[3]	7,360,000	7,360,000	7,280,000	7,280,000	29,280,000
Price per Bbl/MMBtu - Current Year | $ / MMBTU	[3]	3.02	3.02	3.02	3.02	3.02

[1] The index prices for the oil price swaps are based on the NYMEX – West Texas Intermediate (“WTI”) monthly average futures price.the NYMEX – West Texas Intermediate monthly average futures price.

[2] The basis differential price is between Midland – WTI and Cushing – WTI.

[3] The index prices for the natural gas price swaps are based on the NYMEX – Henry Hub last trading day futures price.

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Debt (Summary Of Long-Term Debt) (Detail) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
Credit facility	$ 0	$ 139,500
Unamortized original issue premium	25,073	27,820
Deferred loan costs, net	(42,885)	(48,183)
Less: current portion	0	0
Total long-term debt	3,332,188	3,469,137
8.625% senior notes due 2017
Debt Instrument [Line Items]
Deferred loan costs, net	(5,500)
7.0% unsecured senior notes due 2021
Debt Instrument [Line Items]
Unsecured senior notes	600,000	600,000
6.5% unsecured senior notes due 2022
Debt Instrument [Line Items]
Unsecured senior notes	600,000	600,000
5.5% unsecured senior notes due 2022
Debt Instrument [Line Items]
Unsecured senior notes	600,000	600,000
5.5% unsecured senior notes due 2023
Debt Instrument [Line Items]
Unsecured senior notes	$ 1,550,000	$ 1,550,000

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Debt (Narrative) (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Debt Disclosure [Line Items]
Line of credit maturity date	May 09, 2019
Aggregate lender commitments	$ 2,500,000
Aggregate maximum borrowing base	3,250,000
Unused lender commitments	$ 2,500,000
Line of credit interest rate	3.50%
Debt Related Commitment Fees	$ 7,000	$ 7,700	$ 8,300
Loss on extinguishment of debt	0	(4,316)	$ (28,616)
Unamortized Debt Issuance Expense	$ 42,885	$ 48,183
Minimum [Member]
Debt Disclosure [Line Items]
Commitment fees on unused portion of available commitment	0.30%
Maximum [Member]
Debt Disclosure [Line Items]
Commitment fees on unused portion of available commitment	0.375%
Prime Rate [Member] | Minimum [Member]
Debt Disclosure [Line Items]
Line Of Credit Facility Interest Rate At Period End	0.25%
Prime Rate [Member] | Maximum [Member]
Debt Disclosure [Line Items]
Line Of Credit Facility Interest Rate At Period End	1.25%
Eurodollar Future [Member] | Minimum [Member]
Debt Disclosure [Line Items]
Line Of Credit Facility Interest Rate At Period End	1.25%
Eurodollar Future [Member] | Maximum [Member]
Debt Disclosure [Line Items]
Line Of Credit Facility Interest Rate At Period End	2.25%
8.625% senior notes due 2017
Debt Disclosure [Line Items]
Interest rate	8.625%
Debt Instrument Maturity Year	2017
Debt Instrument, Repurchased Face Amount	$ 225,600
Percentage Of Notes Tendered	75.20%
Price Of Tender And Consent	106.922%
Price Of Remaining Notes Tendered	106.516%
Premium Paid For Tender Offer	$ 20,400
Unamortized Debt Issuance Expense	5,500
Debt Instrument, Unamortized Discount	2,700
5.5% unsecured senior notes due 2023
Debt Disclosure [Line Items]
Debt instrument amount issued	$ 850,000
Interest rate	5.50%
Debt instrument percent of par value issued	103.75%
Debt Instrument Maturity Year	2023
Resulting Yield	4.884%
Proceeds from Debt, Net of Issuance Costs	$ 867,800

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Debt (Principal Maturities Of Debt) (Detail) $ in Thousands	Dec. 31, 2015 USD ($)
Disclosure Debt Principal Maturities Of Debt [Abstract]
2016	$ 0
2017	0
2018	0
2019	0
2020	0
Thereafter	3,350,000
Total	$ 3,350,000

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Debt (Summary Of Interest Expense) (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Disclosure Debt Summary Of Interest Expense [Abstract]
Cash payments for interest	$ (211,443)	$ (211,342)	$ (200,961)
Amortization of original issue discount (premium)	(2,747)	(2,599)	(1,248)
Amortization of deferred loan origination costs	9,971	10,937	13,172
Accretion expense	1,795	0	0
Net changes in accruals	(165)	(737)	5,696
Interest costs incurred	220,297	218,943	218,581
Less: capitalized interest	(4,913)	(2,282)	0
Total interest expense	$ 215,384	$ 216,661	$ 218,581

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Commitments And Contingencies (Narrative) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Commitments [Line Items]
Annual officers' salaries	$ 8.5
Operating leases, lease payments	8.0	$ 7.2	$ 5.7
Accrued Exposure	$ 13.4	$ 12.3

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Commitments And Contingencies (Future Commitments) (Detail) $ in Thousands	Dec. 31, 2015 USD ($)
Disclosure Commitments And Contingencies Future Commitments [Abstract]
2016	$ 51,710
2017	21,256
2018	21,148
2019	13,196
2020	7,335
Thereafter	45,451
Total	$ 160,096

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Commitments And Contingencies (Future Minimum Lease Commitments Under Non-Cancellable Operating Leases) (Detail) $ in Thousands	Dec. 31, 2015 USD ($)
Disclosure Commitments And Contingencies Future Minimum Lease Commitments Under Non Cancellable Operating Leases [Abstract]
2016	$ 7,941
2017	7,877
2018	7,087
2019	5,651
2020	4,738
Thereafter	5,091
Total	$ 38,385

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Income Taxes (Narrative) (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Disclosure Income Taxes Narrative [Abstract]
Income taxes receivable, current	$ 37,300	$ 32,900
Income taxes payable, current	1,000	1,100
Change in estimated effective statutory state income tax	$ (9,026)	$ (7,945)	$ (21,876)
State Tax Rate Reduction	9.30%
Income Tax Rate Reduction	4.80%

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Income Taxes (Company's Income Tax Provision (Benefit)) (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Disclosure Income Taxes Companys Income Tax Provision Benefit [Abstract]
Income from continuing operations	$ 31,371	$ 317,785	$ 118,237
Income from discontinued operations	0	0	7,518
Excess tax benefits related to stock-based compensation	(2,150)	(16,480)	(6,147)
Income Tax Expense Benefit Net Of Excess Tax Benefits, Total	$ 29,221	$ 301,305	$ 119,608

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Income Taxes (Income Tax Provision (Benefit) Attributable To Income (Loss) From Continuing Operations) (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Disclosure Income Taxes Income Tax Provision Benefit Attributable To Income Loss From Continuing Operations [Abstract]
U.S. federal	$ 127	$ 16,621	$ 12,504
U.S. state and local	1,622	4,997	3,306
Total current income tax provision	1,749	21,618	15,810
U.S. federal	40,364	278,615	119,985
U.S. state and local	(10,742)	17,552	(17,558)
Total deferred income tax provision	29,622	296,167	102,427
Total income tax provision attributable to income from continuing operations	$ 31,371	$ 317,785	$ 118,237

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Income Taxes (Reconciliation Between The Income Tax Expense (Benefit) And The Reported Amounts Of Income Tax Expense) (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Disclosure Income Taxes Reconciliation Between The Income Tax Expense Benefit And The Reported Amounts Of Income Tax Expense [Abstract]
Income at U.S. federal statutory rate	$ 34,045	$ 299,586	$ 125,006
State income taxes (net of federal tax effect)	3,071	22,826	12,505
Revisions of previous estimates	(631)	738	1,400
Change in estimated effective statutory state income tax	(9,026)	(7,945)	(21,876)
Nondeductible expense & other	3,912	2,580	1,202
Total income tax provision attributable to income from continuing operations	$ 31,371	$ 317,785	$ 118,237
Effective tax rate	32.30%	37.10%	33.10%

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Income Taxes (Company's Income Tax Provision Attributable To Income From Discontinued Operations) (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Disclosure Income Taxes Companys Income Tax Provision Attributable To Income From Discontinued Operations [Abstract]
U.S. federal, current			$ 144
U.S. state and local, current			25
Total current income tax provision			169
U.S. federal, deferred			6,397
U.S. state and local, deferred			952
Total deferred income tax provision			7,349
Total income tax provision attributable to income from discontinued operations	$ 0	$ 0	$ 7,518

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Income Taxes (Deferred Tax Assets and Liabilities) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Components of Deferred Tax Assets and Liabilities [Abstract]
Stock Based Compensation	$ 36,738	$ 24,810
Asset retirement obligation	44,573	44,802
Other	29,574	28,925
Total Deferred tax assets	(110,885)	(98,537)
Oil and Gas Properties deduction of intangible drilling cost due to tax purpose	(1,420,275)	(1,401,313)
Intangible Assets - Operating rights	(9,548)	(10,148)
Derivative instruments	(304,550)	(281,303)
Other	(6,885)	(6,524)
Deferred Tax Liabilities, Gross	(1,741,258)	(1,699,288)
Net deferred tax liabilities	$ (1,630,373)	$ (1,600,751)

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Major Customers and Derivative Counterparties (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Holly Frontier Refining and Marketing LLC [Member]
Revenue, Major Customer [Line Items]
Entity Wide Receivables Major Customer	$ 31.7
Holly Frontier Refining and Marketing LLC [Member] | Revenue [Member]
Revenue, Major Customer [Line Items]
Major Customer Percentage	25.00%	17.00%	30.00%
Enterprise Crude Oil LLC [Member]
Revenue, Major Customer [Line Items]
Entity Wide Receivables Major Customer	$ 10.4
Enterprise Crude Oil LLC [Member] | Revenue [Member]
Revenue, Major Customer [Line Items]
Major Customer Percentage	12.00%	12.00%	13.00%
Western Refining Company LP [Member]
Revenue, Major Customer [Line Items]
Entity Wide Receivables Major Customer	$ 3.9
Western Refining Company LP [Member] | Revenue [Member]
Revenue, Major Customer [Line Items]
Major Customer Percentage	5.00%	12.00%	1.00%
Plains Marketing and Transportation Inc [Member]
Revenue, Major Customer [Line Items]
Entity Wide Receivables Major Customer	$ 11.6
Plains Marketing and Transportation Inc [Member] | Revenue [Member]
Revenue, Major Customer [Line Items]
Major Customer Percentage	11.00%	6.00%	4.00%

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Derivative Counterparties (Detail) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Derivative Counterparties Fair Value [Line Items]
Net financial assets (liabilities)	$ 819,536	$ 752,700
JP Morgan Chase Bank [Member]
Derivative Counterparties Fair Value [Line Items]
Credit Risk Derivative Assets at Fair Value	100,500
Wells Fargo Bank NA [Member]
Derivative Counterparties Fair Value [Line Items]
Credit Risk Derivative Assets at Fair Value	90,300
Barclays Bank PLC [Member]
Derivative Counterparties Fair Value [Line Items]
Credit Risk Derivative Assets at Fair Value	121,800
KeyBank National Association [Member]
Derivative Counterparties Fair Value [Line Items]
Credit Risk Derivative Assets at Fair Value	$ 74,700

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Related Party Transactions (Schedule Of Related Party Transactions) (Detail) - USD ($)		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Related Party Transaction [Line Items]
Ownership interest in partnership		3.50%
Partnership (Director Ownership Interest) [Member]
Related Party Transaction [Line Items]
Amounts paid	[1]	$ 5,745,000	$ 15,181,000	$ 7,255,000
Director And Certain Officers [Member]
Related Party Transaction [Line Items]
Amounts paid	[2]	593,000	383,000	43,000
Payments for Notes to Directors and Officers				1,300,000
Related party receivable from an officer (or affiliated entities)			76,000
Payments From Officers	[3]	237,000	169,000	84,000
Former President And Chief Operating Officer [Member]
Related Party Transaction [Line Items]
Amounts paid under consulting agreement with Steven L. Beal	[4]	$ 0	$ 0	865,000
Consulting fee per month				20,000
Payment To Mutually Terminate Consulting Agreement				$ 720,000

[1] Amounts include royalties on certain properties and lease bonus payments paid to a partnership in which a director of the Company is the general partner and owns a 3.5 percent partnership interest.

[2] Amounts include revenue interests, overriding royalty interests and net profits interests in properties owned by the Company made to a director and certain officers (or affiliated entities). Amounts also include payments for an acreage acquisition and lease bonuses to an affiliated entity of an office r.

[3] Amounts include p ayments to the Company as a result of activity on oil and natural gas properties in which a director and certain officers (or affiliated entities) have an interest.

[4] On June 30, 2009, Steven L. Beal, the Company’s then-president and chief operating officer, retired from such positions. On June 9, 2009, the Company entered into a consulting agreement (the “ Consulting Agreement ”) with Mr. Beal, under which Mr. Be al began serving as a consultant to the Company on July 1, 2009. During the term of the consulting relationship, Mr. Beal received a consulting fee of $20,000 per month and a monthly reimbursement for his medical and dental coverage costs. In August 2013, the Company and Mr. Beal mutually terminated the Consulting Agreement in exchange for the payment to Mr. Beal of $720,000, which termination and payment were approved by the disinterested members of the Company’s Board of Directors.

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Net Income Per Share (Reconciliation Of Earnings Attributable To Common Shares Basic And Diluted) (Detail) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Earnings Per Share, Basic and Diluted, by Common Class, Including Two Class Method [Line Items]
Income as reported	$ 65,900	$ 538,175	$ 251,003
Participating basic earnings	(635)	(5,961)	(2,742)
Basic income attributable to common stockholders	65,265	532,214	248,261
Reallocation of participating earnings	2	16	4
Diluted income attributable to common stockholders	$ 65,267	$ 532,230	$ 248,265
Basic	$ 0.54	$ 4.89	$ 2.39
Diluted	$ 0.54	$ 4.88	$ 2.39
Segment, Continuing Operations [Member]
Earnings Per Share, Basic and Diluted, by Common Class, Including Two Class Method [Line Items]
Income as reported			$ 238,922
Participating basic earnings			(2,610)
Basic income attributable to common stockholders			236,312
Reallocation of participating earnings			4
Diluted income attributable to common stockholders			$ 236,316
Basic			$ 2.28
Diluted			$ 2.28
Segment, Discontinued Operations [Member]
Earnings Per Share, Basic and Diluted, by Common Class, Including Two Class Method [Line Items]
Income as reported			$ 12,081
Participating basic earnings			(132)
Basic income attributable to common stockholders			11,949
Reallocation of participating earnings			0
Diluted income attributable to common stockholders			$ 11,949
Basic			$ 0.11
Diluted			$ 0.11

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Net Income Per Share (Reconciliation Of The Weighted Average Common Shares Outstanding) (Detail) - shares shares in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Reconciliation Of Basic Weighted Average Common Shares Outstanding To Diluted Weighted Average Common Shares Outstanding [Line Items]
Basic	119,926	108,844	103,744
Diluted	120,373	109,132	103,913
Stock Options [Member]
Reconciliation Of Basic Weighted Average Common Shares Outstanding To Diluted Weighted Average Common Shares Outstanding [Line Items]
Dilutive shares	25	83	165
Performance Unit [Member]
Reconciliation Of Basic Weighted Average Common Shares Outstanding To Diluted Weighted Average Common Shares Outstanding [Line Items]
Dilutive shares	422	205	4

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Net Income Per Share (Summary Of The Common Stock Options And Restricted Stock) (Detail) - shares shares in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Performance Unit [Member]
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Antidilutive common shares	0	0	83

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Other Current Liabilities (Schedule Of Other Current Liabilities) (Detail) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Other Liabilities Disclosure [Abstract]
Accrued production costs	$ 70,876	$ 70,786
Payroll related matters	29,411	34,349
Accrued interest	68,925	69,264
Asset retirement obligations	8,626	9,146
Other	7,072	11,763
Other current liabilities	$ 184,910	$ 195,308

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Subsidiary Guarantors (Condensed Consolidating Balance Sheet) (Detail) - USD ($)	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
ASSETS
Accounts receivable - related parties	$ 0	$ 0
Other current assets	1,314,550,000	1,188,396,000
Oil and natural gas properties, net	10,798,497,000	10,076,878,000
Property and equipment, net	178,450,000	129,136,000
Investment in subsidiaries	0	0
Other long-term assets	350,379,000	357,370,000
Total assets	12,641,876,000	11,751,780,000
LIABILITIES AND EQUITY
Accounts payable - related parties	0	0
Other current liabilities	596,420,000	1,264,627,000
Long-term debt	3,332,188,000	3,469,137,000
Other long-term liabilities	1,770,717,000	1,737,228,000
Equity	6,942,551,000	5,280,788,000	$ 3,757,949,000	$ 3,466,196,000
Total liabilities and stockholders' equity	12,641,876,000	11,751,780,000
Consolidation Eliminations [Member]
ASSETS
Accounts receivable - related parties	(9,664,396,000)	(7,872,694,000)
Other current assets	0	0
Oil and natural gas properties, net	0	0
Property and equipment, net	0	0
Investment in subsidiaries	(3,698,485,000)	(4,085,045,000)
Other long-term assets	0	0
Total assets	(13,362,881,000)	(11,957,739,000)
LIABILITIES AND EQUITY
Accounts payable - related parties	(9,664,396,000)	(7,872,694,000)
Other current liabilities	0	0
Long-term debt	0	0
Other long-term liabilities	0	0
Equity	(3,698,485,000)	(4,085,045,000)
Total liabilities and stockholders' equity	(13,362,881,000)	(11,957,739,000)
Parent Company [Member]
ASSETS
Accounts receivable - related parties	8,502,099,000	6,670,744,000
Other current assets	753,716,000	569,545,000
Oil and natural gas properties, net	0	0
Property and equipment, net	0	0
Investment in subsidiaries	3,698,485,000	4,085,045,000
Other long-term assets	182,623,000	282,609,000
Total assets	13,136,923,000	11,607,943,000
LIABILITIES AND EQUITY
Accounts payable - related parties	1,162,297,000	1,201,950,000
Other current liabilities	69,514,000	55,318,000
Long-term debt	3,332,188,000	3,469,137,000
Other long-term liabilities	1,630,373,000	1,600,750,000
Equity	6,942,551,000	5,280,788,000
Total liabilities and stockholders' equity	13,136,923,000	11,607,943,000
Guarantor Subsidiaries [Member]
ASSETS
Accounts receivable - related parties	1,162,297,000	1,201,950,000
Other current assets	560,834,000	618,851,000
Oil and natural gas properties, net	10,798,497,000	10,076,878,000
Property and equipment, net	178,450,000	129,136,000
Investment in subsidiaries	0	0
Other long-term assets	167,756,000	74,761,000
Total assets	12,867,834,000	12,101,576,000
LIABILITIES AND EQUITY
Accounts payable - related parties	8,502,099,000	6,670,744,000
Other current liabilities	526,906,000	1,209,309,000
Long-term debt	0	0
Other long-term liabilities	140,344,000	136,478,000
Equity	3,698,485,000	4,085,045,000
Total liabilities and stockholders' equity	$ 12,867,834,000	$ 12,101,576,000

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Subsidiary Guarantors (Condensed Consolidating Statement Of Operations) (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Condensed Financial Statements Captions [Line Items]
Total operating revenues	$ 1,803,573,000	$ 2,660,147,000	$ 2,319,919,000
Total operating costs and expenses	1,422,570,000	1,570,402,000	1,702,482,000
Income (loss) from operations	381,003,000	1,089,745,000	617,437,000
Interest expense	(215,384,000)	(216,661,000)	(218,581,000)
Loss on extinguishment of debt	0	(4,316,000)	(28,616,000)
Other, net	(68,348,000)	(12,808,000)	(13,081,000)
Income from continuing operations before income taxes	97,271,000	855,960,000	357,159,000
Income tax expense	(31,371,000)	(317,785,000)	(118,237,000)
Income from continuing operations	65,900,000	538,175,000	238,922,000
Income from discontinued operations, net of tax			12,081,000
Net income	65,900,000	538,175,000	251,003,000
Consolidation Eliminations [Member]
Condensed Financial Statements Captions [Line Items]
Total operating revenues	0	0	0
Total operating costs and expenses	0	0	0
Income (loss) from operations	0	0	0
Interest expense	0	0	0
Loss on extinguishment of debt		0	0
Other, net	386,560,000	(188,304,000)	(749,823,000)
Income from continuing operations before income taxes	386,560,000	(188,304,000)	(749,823,000)
Income tax expense	0	0	0
Income from continuing operations			(749,823,000)
Income from discontinued operations, net of tax			0
Net income	386,560,000	(188,304,000)	(749,823,000)
Parent Company [Member]
Condensed Financial Statements Captions [Line Items]
Total operating revenues	0	0	0
Total operating costs and expenses	(697,247,000)	(888,632,000)	125,924,000
Income (loss) from operations	697,247,000	888,632,000	(125,924,000)
Interest expense	(213,416,000)	(216,661,000)	(218,581,000)
Loss on extinguishment of debt		(4,316,000)	(28,616,000)
Other, net	(386,560,000)	188,305,000	749,878,000
Income from continuing operations before income taxes	97,271,000	855,960,000	376,757,000
Income tax expense	(31,371,000)	(317,785,000)	(118,237,000)
Income from continuing operations			258,520,000
Income from discontinued operations, net of tax			(7,517,000)
Net income	65,900,000	538,175,000	251,003,000
Guarantor Subsidiaries [Member]
Condensed Financial Statements Captions [Line Items]
Total operating revenues	1,803,573,000	2,660,147,000	2,319,919,000
Total operating costs and expenses	2,119,817,000	2,459,034,000	1,576,558,000
Income (loss) from operations	(316,244,000)	201,113,000	743,361,000
Interest expense	(1,968,000)	0	0
Loss on extinguishment of debt		0	0
Other, net	(68,348,000)	(12,809,000)	(13,136,000)
Income from continuing operations before income taxes	(386,560,000)	188,304,000	730,225,000
Income tax expense	0	0	0
Income from continuing operations			730,225,000
Income from discontinued operations, net of tax			19,598,000
Net income	$ (386,560,000)	$ 188,304,000	$ 749,823,000

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Subsidiary Guarantors (Condensed Consolidating Statement Of Cash Flows) (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Condensed Financial Statements Captions [Line Items]
Net cash flows provided by (used in) operating activities	$ 897,505,000	$ 1,673,787,000	$ 1,362,020,000
Net cash flows provided by (used in) investing activities	(1,969,725,000)	(2,545,996,000)	(1,896,794,000)
Net cash flows provided by (used in) financing activities	1,300,749,000	872,209,000	531,915,000
Net increase (decrease) in cash and cash equivalents	228,529,000	0	(2,859,000)
Cash and cash equivalents at beginning of period	21,000	21,000	2,880,000
Cash and cash equivalents at end of period	228,550,000	21,000	21,000
Consolidation Eliminations [Member]
Condensed Financial Statements Captions [Line Items]
Net cash flows provided by (used in) operating activities	0	0	0
Net cash flows provided by (used in) investing activities	0	0	0
Net cash flows provided by (used in) financing activities	0	0	0
Net increase (decrease) in cash and cash equivalents	0	0	0
Cash and cash equivalents at beginning of period	0	0	0
Cash and cash equivalents at end of period	0	0	0
Parent Company [Member]
Condensed Financial Statements Captions [Line Items]
Net cash flows provided by (used in) operating activities	(2,026,206,000)	(888,369,000)	(487,131,000)
Net cash flows provided by (used in) investing activities	632,916,000	71,983,000	(32,341,000)
Net cash flows provided by (used in) financing activities	1,393,290,000	816,386,000	519,472,000
Net increase (decrease) in cash and cash equivalents	0	0	0
Cash and cash equivalents at beginning of period	0	0	0
Cash and cash equivalents at end of period	0	0	0
Guarantor Subsidiaries [Member]
Condensed Financial Statements Captions [Line Items]
Net cash flows provided by (used in) operating activities	2,923,711,000	2,562,156,000	1,849,151,000
Net cash flows provided by (used in) investing activities	(2,602,641,000)	(2,617,979,000)	(1,864,453,000)
Net cash flows provided by (used in) financing activities	(92,541,000)	55,823,000	12,443,000
Net increase (decrease) in cash and cash equivalents	228,529,000	0	(2,859,000)
Cash and cash equivalents at beginning of period	21,000	21,000	2,880,000
Cash and cash equivalents at end of period	$ 228,550,000	$ 21,000	$ 21,000

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Subsequent Events (Narrative) (Detail) - USD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2013
Subsequent Event [Line Items]
Acquisiton Agreement date	Jan. 01, 2016
Number of common stock issued	2.2
Payments To Acquire Oil And Gas Property	$ 150.0
Future Carry Amount	40.0
Proceeds From Sale Of Oil And Gas Property And Equipment	$ 290.0
Disposal Date	Jan. 01, 2016	Dec. 15, 2012

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Subsequent Events (New Commodity Derivative Contracts) (Detail) - Subsequent Event [Member]		3 Months Ended				12 Months Ended
		Dec. 31, 2016 bbl $ / bbl	Sep. 30, 2016 bbl $ / bbl	Jun. 30, 2016 bbl $ / bbl	Mar. 31, 2016 bbl $ / bbl	Dec. 31, 2016 bbl $ / bbl
Oil Swaps [Member]
Subsequent Event [Line Items]
Volume (Bbl/MMBtu) - Year One | bbl	[1]	750,000	750,000	180,000	180,000	1,860,000
Price per Bbl/MMBtu - Year One | $ / bbl	[1]	43.63	43.63	42.55	42.55	43.42
Oil Basis Swaps [Member]
Subsequent Event [Line Items]
Volume (Bbl/MMBtu) - Current Year | bbl	[2]	0	0	182,000	120,000	302,000
Price per Bbl/MMBtu - Current Year | $ / bbl	[2]	0	0	(0.25)	(0.25)	(0.25)
Volume (Bbl/MMBtu) - Year One | bbl	[2]	2,024,000	2,024,000	242,000	360,000	4,650,000
Price per Bbl/MMBtu - Year One | $ / bbl	[2]	(0.38)	(0.38)	(0.38)	(0.41)	(0.38)

[1] The index prices for the oil price swaps are based on the NYMEX – WTI monthly average futures price.

[2] The basis differential price is between Midland – WTI and Cushing – WTI.