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Concho Resources Inc. Reports 2014 Proved Reserves

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Concho Resources Inc. (NYSE:CXO) (the “Company” or “Concho”) today reported proved reserves for 2014.

Highlights

  • Concho increased proved reserves to a record 637 million Boe, up 134 million Boe, or 27%, over year-end 2013 proved reserves.
  • Strong results from the Company’s horizontal development program in 2014 more than doubled horizontal proved reserves and increased total resource potential to 3.7 billion Boe.
  • The Company achieved 428% reserve replacement at $14.02 per Boe drill-bit finding and development cost.
  • Full-year 2014 production increased 22% over 2013, to 40.9 million Boe. Crude oil production increased 25% year-over-year.

For an explanation of how we calculate and use the reserve replacement ratio and drill-bit finding and development cost, please see “Supplemental Non-GAAP Financial Measures” below.

Tim Leach, Chairman, Chief Executive Officer and President, commented, “Concho delivered outstanding reserves growth for 2014 at low finding costs and replaced 428% of production. We also delivered on our annual production target, achieving 22% year-over-year growth with crude oil production up 25%. These results demonstrate the strength of our technically-driven team, the benefits of operating one of the Permian’s largest and most efficient drilling programs and the realization of our ongoing efforts to optimize well performance. The technical enhancements we are applying across our Permian assets continue to expand our resource base, which is now approximately 3.7 billion Boe.”

2014 Proved Reserves

At December 31, 2014, the Company’s estimated proved reserves totaled 637 million barrels of oil equivalent (MMBoe), up 27% from year-end 2013. The Company’s proved reserves are approximately 58% crude oil and 42% natural gas. Proved developed reserves increased 24% year-over-year and represented 59% of total proved reserves. The present value of the Company’s proved reserves, discounted at 10% (“PV-10″), increased 26% to $11.4 billion at year-end 2014. For an explanation of how we calculate and use PV-10 (non-GAAP), please see “Supplemental Non-GAAP Financial Measures” below.

Concho’s robust drilling program and positive results from optimized drilling and completion techniques drove a 107% increase in the Company’s horizontal proved reserves over year-end 2013. The Company’s horizontal proved reserves accounted for 57% of total proved reserves as of December 31, 2014, reflecting Concho’s transition to large-scale horizontal development across its assets in the Permian Basin. During 2014, Concho started drilling or participated in 595 gross wells, of which 69% were horizontal. Proved horizontal reserves have increased by more than 25x since Concho initiated its horizontal development program in 2010.

The Delaware Basin continues to be Concho’s most significant area of capital investment and growth. The Company’s proved reserves in the Delaware Basin at year-end 2014 increased 77% over year-end 2013 and accounted for 38% of total proved reserves.

The table below summarizes changes in estimated proved reserves during the year ended December 31, 2014:

Estimated Proved
(MMBoe) Reserves
Balance – December 31, 2013 503
Extensions and discoveries 182
Revisions of previous estimates (13 )
Purchase of reserves-in-place 6
Production (41 )
Balance – December 31, 2014 637
Proved developed reserves
Balance – December 31, 2013 303
Balance – December 31, 2014 377

In 2014, Concho added 182 MMBoe of proved reserves as a result of its drilling and completion program in the Permian Basin. Negative revisions to previous estimates of 13 MMBoe were primarily due to the reclassification of approximately 36 MMBoe of proved undeveloped reserves attributable to vertical locations that the Company does not plan to drill within five years of their initial recording as required by SEC rules, partially offset by 23 MMBoe of net positive revisions, resulting from performance and technical evaluations.

Full-Year 2014 Production

Production for full-year 2014 totaled 40.9 MMBoe, or an average of 112.0 MBoepd, up 22% over 2013. Production for 2014 consisted of 26.3 MMBbls of crude oil and 87.3 Bcf of natural gas. Crude oil production increased 25% over 2013.

Costs Incurred

Costs incurred excluding acquisitions for 2014 were in-line with the Company’s annual capital budget of $2.6 billion. Costs incurred for property acquisitions were approximately $390 million for 2014. For a summary of costs incurred for the year ended December 31, 2014, see “Costs Incurred” below.

Drill-bit finding and development cost was $14.02 per Boe for 2014, compared to $16.79 per Boe for 2013. At December 31, 2014, the Company’s three-year average drill-bit finding and development cost was $15.40 per Boe. For an explanation of how we calculate and use drill-bit finding and development cost, please see “Supplemental Non-GAAP Financial Measures” below.

Concho Resources Inc.

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

Forward-Looking Statements and Cautionary Statements

The foregoing contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical fact, included in this press release that address activities, events or developments that the Company expects, believes or anticipates will or may occur in the future are forward-looking statements. Forward-looking statements contained in this press release specifically include statements, estimates and projections regarding the Company’s future financial position, operations, performance, business strategy, drilling program, capital expenditure budget, liquidity and capital resources, the timing and success of specific projects, outcomes and effects of litigation, claims and disputes, derivative activities and potential financing. The words “estimate,” “project,” “predict,” “believe,” “expect,” “anticipate,” “potential,” “could,” “may,” “foresee,” “plan,” “goal” or other similar expressions are intended to identify forward-looking statements, which generally are not historical in nature. However, the absence of these words does not mean that the statements are not forward-looking. These statements are based on certain assumptions and analyses made by the Company based on management’s experience, expectations and perception of historical trends, current conditions, anticipated future developments and other factors believed to be appropriate. Forward-looking statements are not guarantees of performance. Although the Company believes the expectations reflected in its forward-looking statements are reasonable and are based on reasonable assumptions, no assurance can be given that these assumptions are accurate or that any of these expectations will be achieved (in full or at all) or will prove to have been correct. Moreover, such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Company, which may cause actual results to differ materially from those implied or expressed by the forward-looking statements. These include the factors discussed or referenced in the “Risk Factors” section of the Company’s most recent Annual Report on Form 10-K; risks relating to declines in the prices the Company receives for its oil and natural gas; uncertainties about the estimated quantities of oil and natural gas reserves; drilling and operating risks, including risks related to properties where the Company does not serve as the operator and risks related to hydraulic fracturing activities; the adequacy of the Company’s capital resources and liquidity including, but not limited to, access to additional borrowing capacity under its 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; 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 the Company’s 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 the Company’s oil, natural gas liquids and natural gas and other processing and transportation considerations; shortages of oilfield equipment, services and qualified personnel and increases in costs for such equipment, services and personnel; potential financial losses or earnings reductions from the Company’s commodity price management program; risks and liabilities related to the integration of acquired properties or businesses; uncertainties about the Company’s ability to successfully execute its business and financial plans and strategies; uncertainties about the Company’s ability to replace reserves and economically develop its current reserves; general economic and business conditions, either internationally or domestically; competition in the oil and natural gas industry; uncertainty concerning the Company’s assumed or possible future results of operations; and other important factors that could cause actual results to differ materially from those projected.

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

We may use the terms “unproved reserves,” “resource potential,” “estimated ultimate recovery (‘EUR’)” per well and “upside potential” to describe estimates of potentially recoverable hydrocarbons that the U.S. Securities and Exchange Commission (“SEC”) rules prohibit from being included in filings with the SEC. These are based on analogy to the Company’s existing models applied to additional acres, additional zones and tighter spacing and are the Company’s internal estimates of hydrocarbon quantities that may be potentially discovered through exploratory drilling or recovered with additional drilling or recovery techniques. These quantities may not constitute “reserves” within the meaning of the Society of Petroleum Engineer’s Petroleum Resource Management System or SEC rules. EUR estimates, resource potential and drilling locations have not been fully risked by Company management and are inherently more speculative than proved reserves estimates. Actual locations drilled and quantities that may be ultimately recovered from the Company’s interests could differ substantially. There is no commitment by the Company to drill all of the drilling locations which have been attributed to these quantities. Factors affecting ultimate recovery include the scope of our ongoing drilling program, which will be directly affected by the availability of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, transportation constraints, regulatory approvals and other factors; and actual drilling results, including geological and mechanical factors affecting recovery rates. Estimates of unproved reserves, resource potential, per well EUR and upside potential may change significantly as development of the Company’s oil and natural gas assets provide additional data. Our production forecasts and expectations for future periods are dependent upon many assumptions, including estimates of production decline rates from existing wells and the undertaking and outcome of future drilling activity, which may be affected by significant commodity price declines or drilling cost increases.

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

Concho Resources Inc.
Costs Incurred
Unaudited

The table below provides the costs incurred for the periods indicated:

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

Three Months Ended Years Ended
December 31, December 31,
(in thousands) 2014 2013 2014 2013
Property acquisition costs:
Proved $ 39,003 $ 9,123 $ 99,362 $ 11,499
Unproved 184,378 26,706 292,363 85,538
Exploration 479,027 250,767 1,615,238 1,029,793
Development 327,711 145,424 937,491 738,430
Total costs incurred for oil and natural gas properties $ 1,030,119 $ 432,020 $ 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:

Three Months Ended Years Ended
December 31, December 31,
(in thousands) 2014 2013 2014 2013
Exploration costs $ 739 $ 583 $ 2,589 $ 2,672
Development costs 1,463 304 7,488 9,467
Total asset retirement obligations $ 2,202 $ 887 $ 10,077 $ 12,139

Supplemental Non-GAAP Financial Measures
(Unaudited)

Reserve Replacement

The Company uses the reserve replacement ratio as an indicator of the Company’s ability to replenish annual production volumes and grow its reserves, thereby providing some information on the sources of future production. It should be noted that the reserve replacement ratio is a statistical indicator that has limitations. The ratio is limited because it typically varies widely based on the extent and timing of discoveries and property acquisitions. Its predictive and comparative value is also limited for the same reasons. In addition, since the ratio does not embed the cost or timing of future production of new reserves, it cannot be used as a measure of value creation. The reserve replacement ratio of 428% was calculated by dividing net proved reserve additions of 175.1 MMBoe (the sum of extensions, discoveries, revisions and purchases) by production of 40.9 MMBoe.

Finding and Development Cost

Finding and development cost is a non-GAAP measure used to assist in an evaluation of how much it costs the Company, on a per Boe basis, to add proved reserves. Drill-bit finding and development costs are calculated by dividing the sum of exploration costs and development costs of $2.6 billion by total reserve extensions and discoveries of 182 MMBoe. This calculation does not include the future development costs required for the development of proved undeveloped reserves.

PV-10

The present value of our proved reserves, discounted at 10% (“PV-10″), was estimated at $11.4 billion at December 31, 2014, and was calculated based on the first-of-the-month, twelve-month average prices for crude oil and natural gas of $91.48 per Bbl of crude oil and $4.35 per MMBtu of natural gas.

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. The Company believes that the presentation of the PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to our estimated net 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 properties. Further, investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies. The Company uses this measure when assessing the potential return on investment related to our oil and natural gas properties. PV-10, however, is not a substitute for the standardized measure of discounted future net cash flows. The Company’s 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.

The following table provides a reconciliation of PV-10 to the standardized measure of discounted future net cash flows at December 31, 2014 and 2013, respectively:

December 31,
(in millions) 2014 2013
PV-10 $ 11,385 $ 9,030
Present value of future income taxes discounted at 10% (3,362 ) (2,786 )
Standardized measure of discounted future net cash flows $ 8,023 $ 6,244

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