Merrill Lynch Global Energy Mid and Small Cap Conference October 1, - - PowerPoint PPT Presentation

1

Merrill Lynch Global Energy Mid and Small Cap Conference

October 1, 2008

2

This presentation contains forward‐looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical facts, included in this presentation that address activities, events or developments that the Company expects, believes or anticipates will or may occur in the future are forward‐looking statements. Without limiting the generality of the foregoing, forward‐looking statements contained in this presentation specifically include the expectations

• f plans, strategies, objectives and anticipated financial and operating results of the Company, including as to the Company’s drilling program,

production, hedging activities, capital expenditure levels and other guidance included in this presentation. These statements are based on certain assumptions made by the Company based on management’s experience and perception of historical trends, current conditions, anticipated future developments and other factors believed to be appropriate. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Company, which may cause actual results to differ materially from those implied

• r expressed by the forward‐looking statements. These include risks relating to financial performance and results, prices and demand for oil and

natural gas, availability of drilling equipment and personnel, availability of sufficient capital to execute our business plan, difficulties integrating Henry Petroleum’s properties and employees into our Company, our ability to replace reserves and efficiently develop and exploit our current reserves and other important factors that could cause actual results to differ materially from those projected as described in the Company’s reports filed with the Securities and Exchange Commission(“SEC”). When considering our forward‐looking statements, you should keep in mind the risk factors and other cautionary statements found in the Company’s Annual Report on Form 10‐K for the year ended December 31, 2007. 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. In its filings with the Securities and Exchange Commission, Concho is permitted to disclose only proved reserves that it has demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions. Concho uses certain terms in this presentation, such as "unproved", or "potential" in relation to reserves that the SEC's guidelines strictly prohibit it from including in filings with the SEC. These estimates are subject to substantially greater risk of the Company not actually realizing

• them. Investors are urged to closely consider Concho's disclosure of its proved reserves, along with certain risks and uncertainties inherent in its

business, set forth in its filings with the SEC.

Forward Looking Statements

3

Ticker: Market Cap1: $2.6 billion Enterprise Value2: $3.3 billion Portfolio highlights

2Q ‘08 average daily production of 96 Mmcfe/d

June ‘08 pro forma average daily production of 134 Mmcfe/d3

782 Bcfe proved reserves (99% Permian)4

62% Oil 56% Proved developed

Over 4,200 identified opportunities

Company Overview

NM TX Map of operations

1Based on 9/22/08 closing price of $30.34 and 85M fully diluted shares

• utstanding

2 Long term Debt at 8/1/08 was $675M 3 Based on Concho’s and Henry’s June daily production 4 Concho’s mid‐year and Henry’s June reserves

New Mexico Shelf Properties Texas Permian Wolfberry Properties

4

Recent Highlights

Financial Highlights

• Revenues of $244.1 million in 1st half '08; 93% above 1st half '07 of $126.4 million
• Net cash provided by operating activities in 1st half '08 of $162.9 million, a 156% increase over 1st half '07
• EBITDAX1 in 1st half '08 of $173.8 million, a 97% increase over 1st half '07
• Increased '08 production guidance from 35‐37 Bcfe to 42‐43.5 Bcfe
• 1st half '08 production of 17.2 Bcfe, an 18% increase over 1st half '07

Henry Acquisition

• Closed acquisition of Henry Petroleum plus additional interests for approximately $588 million on July 31, 2008
• 100% of estimated proved reserves are located in the Permian Basin
• Immediately accretive to cash flow per share, recurring earnings per share, production and proved reserves per share
• Funded by borrowings under amended senior credit facility and the proceeds from common stock private placement
• Approximately $300 million available under senior credit facility at August 1, 2008

Increased ‘08 capital budget to $389 million

• Increased budget in Texas Permian by $43 million
• Added 6th rig on core Southeast New Mexico Shelf asset in July ‘08
• Increased budget in Southeast New Mexico Shelf by $28 million due to larger fracs and increased tubular costs
• Increased budget in Bakken Shale and Wolfcamp horizontal oil play to $29 million from $7 million due to early success in

the regions

1 See reconciliation in Appendix

5 1st Six Months 2008 Cash Margin1

Margin Analysis

• Strong price realizations due to 60/40
• il/gas mix and liquid content in gas

stream

• Favorable cost structure in core area

due to concentration of assets

• Stable differentials historically in the

Permian Basin

• Established infrastructure

1Sources: Company 10‐Qs

Cash Margin defined as: Revenue (ex. hedging) minus LOE, Severance Tax, and G&A Peers Include: DNR, RRC, SD, SWN, SM, EAC, WLL, XCO, and HK

$‐ $2.00 $4.00 $6.00 $8.00 $10.00 $12.00 $14.00

CXO Median

$12.39 $9.84 ($'s / Mcfe)

6

Concho Assets (Post Henry Acquisition)

Tatum Basin Delaware Basin Salt Basin Central Basin Platform Midland Basin

NM TX NM TX

Northwest Shelf Marfa Basin

Midland

New Mexico Shelf

61% of proved reserves Majority of

• pportunities < 7,000’

Texas Permian

34% of proved reserves Activities concentrated

in Wolfberry

Over 1,700

• pportunities

New Mexico Basin

4% of proved reserves Atoka, Morrow, Strawn 140 opportunities in

inventory 782 Bcfe proved reserves1

62% oil 56% proved developed

June ‘08 pro forma average daily production of 134 Mmcfe/d2 Over 4,200 opportunities

1,424 Yeso 1,408 Wolfberry 1,368 Other

1 Assumes Concho’s mid‐year 2008 and Henry’s June 2008 reserves 2 Pro forma June production for Henry acquisition

Concho Leasehold Henry Leasehold

7

Concho Leasehold SENM Shelf NM TX

Core asset from Chase acquisition Producing approximately 60% of Company’s total

production1

100,603 gross (49,306 net) acres Historic production from shallower zones including the

Grayburg, San Andres and Paddock (upper member of Yeso formation)

Initiated aggressive Blinebry drilling program in 2006

(lower member of Yeso formation)

• 52 wells drilled in 2006
• 98 wells drilled 2007
• 132 wells planned for 2008

Significant improvement in drilling times Recently added 6th rig drilling Blinebry / Paddock wells Majority of wells drilled through 2010 will be

combination Blinebry / Paddock wells

Additional opportunities include:

• Re‐stimulations on existing Paddock wells
• Deepening existing Paddock wells to the Blinebry
• Paddock waterflood
• Blinebry 10 acre down spacing
• Horizontal Wolfcamp oil play

Southeast New Mexico Shelf

1 June 2008 pro forma production

8

Concho Leasehold Acquired Wells + Other Producers 2008 Drilling Program 2008 Re‐fracs 2006/07 Drilling Program 2008 Deepenings

Southeast New Mexico Shelf

• Approximately $270 million (68% of 2008 capital budget) allocated to Shelf properties
• 132 drill wells
• 96 Paddock add pays
• 63 Paddock re‐stimulations
• 39 Blinebry deepenings
• Enhanced economics by combining Blinebry / Paddock intervals
• High liquid content ties approximately 80% of revenue stream on Blinebry/Paddock wells

to crude oil prices

• Paddock being developed on 10 acre spacing; Blinebry locations only identified based on

20 acre spacing

• Rapidly developing horizontal Wolfcamp oil play
• Approximately 14,000 acres
• Geographically close to our conventional shelf play
• Cimarex and Concho ‐ currently most active players

9

1 As of July 1, 2008

Total Proved 489 Bcfe Identified Unproved 400 Bcfe 51%

proved developed

70%

third party engineered

65%

Yeso opportunities

10 acre Blinebry Paddock Waterflood Horizontal Wolfcamp oil play Shallower zones waterflood

• ptimization / expansion

Quantify over next 2 to 3

years

Large Conventional Resource

Concho Leasehold Acquired Wells + Other Producers 2008 Drilling Program PUD Locations Unproved Locations 2006/07 Drilling Program

Southeast New Mexico Shelf

Total Proved1 Identified Unproved Additional Potential

10

Wolfberry PDP

• Core asset from Henry acquisition
• Substantially all operated
• Producing approximately 25% of company’s total production
• Over 500 Wolfberry wells drilled
• 8 Rigs currently drilling, executing a 9 year drilling schedule
• Identified unproved reserve potential of approximately 295 Bcfe

Texas Permian - Wolfberry

• Approximately 1,400 drilling

locations on 80 and 40 acre spacing

• Approximately 300

proved and 1,100 unproved

• 20 acre spacing

potential

CXO acreage

Spraberry Trend

11

Wolfberry Well Yeso Well

Initial Production: 90 BO/D + 230 MCF/D Final Decline Rate: 5% Gross EUR: 97 MBO + 321 MMCF Gross Capital Inv.: $1.7 million Ownership: 29% WI / 22% NRI IRR: 49% ($75.00 Oil, $7.50 Gas)1 65% ($100.00 Oil, $10.00 Gas) >100% ($125.00 Oil, $12.50 Gas) Initial Production: 145 BO/D + 346 MCF/D Final Decline Rate: 8% Gross EUR: 120 MBO + 365 MMCF Gross Capital Inv.: $1.6 million Ownership: 93% WI / 78% NRI IRR: >100% ($75.00 Oil, $7.50 Gas)1 >100% ($100.00 Oil, $10.00 Gas) >100% ($125.00 Oil, $12.50 Gas)

Wolfberry Yeso

Type Curve and Return Analysis

1 Assumes 15% reduced capital cost

12

• 1,408 Wolfberry
• 569 Blinebry / Paddock
• 373 Paddock stand–

alone

• 54 Blinebry stand-alone
• 229 Shallower than Yeso
• 109 Deeper than Yeso

360 Shallower than Yeso 289 Paddock re-stimulations 29 Yeso recompletions 70 Blinebry deepenings 21 Deeper than Yeso recompletions

Yeso Drilling

1Concho’s June 2008 identified inventory

Drilling and Recompletion Inventory

6 rigs running on S

• utheast New Mexico S

helf; each rig drilling an average of 2 wells per month 8 rigs running on Wolfberry acreage; average drilling time of 20 days per well

Drilling1 Recompletions1

13

Williston Basin - Bakken

Concho Leasehold NM TX

North Dakota

1As of 12/31/07

42,362 gross (11,069 net) acres1 50/50 partners in 8,000 net acres with Newfield in

Westberg area (McKenzie County) Prospective for the Bakken and Sanish/Three Forks formations Production from the most recently completed well averaged 710 Boepd over a 22‐hour period Expect to drill 5‐7 wells in the Westberg area in 2008; 2 rig drilling program planned through 2009

Expect to spend $15‐$18 million in 2008 with increased

activity level in 2009

14

Appendix

15

1 The index prices for the oil price swaps are based on NYMEX – West Texas Intermediate monthly average futures price. 2 The index price for the natural gas price collar is based on the Inside FERC‐El Paso Permian Basin first‐of‐the‐month spot price. 3 Amounts disclosed represent weighted average prices.

Hedging Schedule

(Hedges as of 8/1/08) Aggregate Remaining Volume Average Daily Hedge Volume Index Price (or floor / ceiling) Contract Period Cash flow hedges: Crude Oil (volumes in Bbls): Price swap 397,800 2,600 $67.50 (1) 08/1/08 - 12/31/08 Cash flow hedges dedesignated: Natural Gas (volumes in MMBtus): Price collar 2,065,500 13,500 $6.50 / $9.35 (2) 08/1/08 - 12/31/08 Derivatives not designated as cash flow hedges: Crude Oil (volumes in Bbls): Price swap 966,509 6,373 $92.94 (1) (3) 08/1/08 - 12/31/08 Costless collar 42,394 277 $55 / $72 (1) 08/1/08 - 12/31/08 Price swap 1,813,491 4,968 $87.16 (1) (3) Calendar 2009 Costless collar 768,000 2,104 $120 / $134.60 (1) Calendar 2009 Price swap 641,746 1,758 $93.26 (1) (3) Calendar 2010 Price swap 557,746 1,528 $104.91 (1) (3) Calendar 2011 Price swap 504,000 1,377 $127.80 (1) Calendar 2012 Natural Gas (volumes in MMBtus): Price swap 1,825,000 5,000 $8.44 (2) Calendar 2009

16

EBITDAX Reconciliation

($ thousands)

EBITDAX (as defined above) is presented herein, and reconciled to the generally accepted accounting principle (“GAAP”) measure of net income because of its wide acceptance by the investment community as a financial indicator of a company’s ability to internally fund exploration and development activities. We define EBITDAX as net income, plus (1) exploration and abandonments expense (2) depreciation & depletion expense (3) accretion expense (4) impairments of proved oil and gas properties (5) non‐cash stock‐based compensation expense (6) ineffective portion of cash flow hedges (7) interest expense, the amortization

• f related debt issuance costs and other financing costs, net of capitalized interest, and (9) federal and state income taxes, less other ancillary income including interest income, gathering income and rental
• income. EBITDAX is not a measure of net income or cash flow as determined by generally accepted accounting principles. Our EBITDAX measure provides additional information which may be used to better

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

2008 2007 2008 2007 Net Income (14,420) $ 5,925 $ 7,945 $ 10,548 $ Exploration and abandonments 723 5,864 3,464 6,305 Depreciation and depletion 22,010 17,609 43,294 37,033 Accretion of discount on asset retirement obligation 148 115 301 228 Impairment of proved oil and gas properties 53 2,085 69 3,198 Non-cash stock based compensation 1,730 1,128 3,029 1,953 Ineffective portion of cash flow hedges (356) (99) (920) 1,156 Unrealized loss on derivatives not designated as hedges 90,056

• 103,247
• Interest expense

3,885 10,074 9,500 20,749 Other, net (311) (208) (1,331) (473) Income tax expense (9,169) 3,988 5,199 7,363 EBITDAX 94,349 $ 46,481 $ 173,797 $ 88,060 $ June 30, Six Months Ended Three Months Ended June 30,

17

Wolfcamp shelf edge

Central Basin Platform A Eastern Shelf A’ Leonard shelf carbonates Wolfcamp shelf carbonates Spraberry turbidites (primary target) Wolfcamp debris flows (primary target) Wolfberry Fairway / Henry Petroleum Acreage

A A’

7,500’ 10,500’ 8,500’ 9,500’

Wolfberry Geologic Model

18

Drilling & recompletion projects by core area New Mexico Shelf 82% New Mexico Basin 3% Operated drilling and recompletion projects by category Proved 48% Unproved 52% Operated 96% Non‐operated 4% Total capital budget Drilling, recompletion and maintenance in core area 85% Exploration, Leasehold and G&G 15% Drilling & recompletion projects in core areas

Updated 2008 Capital Budget of $389 million

Texas 15%

19

2004 through 2007 illustrates growth through acquisitions

and drilling

Organic production growth driven by activity on core

southeast NM shelf asset 30% increase in 2007 vs. 2006 2Q '08 production mix is 62% oil, 38% gas

Initiated development program in 2006 on New Mexico

Shelf properties targeting Yeso formation Captured opportunity in Blinebry interval Drilled 98 wells and performed 96 recompletions in 2007 Large project inventory on New Mexico shelf and Wolfberry play

Added 6th rig to drilling program on Shelf assets in 3Q '08;

Operating 8 rigs on Wolfberry assets

Chase acquisition in 2006 and Henry acquisition in 2008

added significant proved reserves

Annual production Proved reserves

Reserve adds (Bcfe): Purchases

• Ext. & Disc.

2004 70 6 2005 2 35 2006 301 101 2007 1 128

Production & Reserve Growth

0.6 7 23 30 42 ‐ 43.5 10 20 30 40 50 2004 2005 2006 2007 2008 Est Bcfe

20

Combined Guidance

1 Includes results from Henry acquisition 2 Production Expense includes Lease Operating expenses and Ad Valorem

Concho 2008 Guidance Production: Natural gas equivalent (Bcfe) 42.0 - 43.5 Oil (MMbbl) 4.4 - 4.6 Natural Gas (Bcf) 15.5 - 16.1 Price Differencials to NYMEX: (excluding the effects of hedging) Oil (Bbl) (8 - 9%) Natural Gas (Bcf) 10 - 15% Operating costs and expenses: Production expenses ($/Mcfe) 2 $1.00 - $1.05 Production tax (% of oil and gas revenue) 9.00% G&A expense ($/Mcfe) $0.60 - $0.65 DD&A expense ($/Mcfe) $2.55 - $2.65 Capital expenditure ($ millions) $389