Exhibit 99.1

Barclays Capital 2009 CEO Energy/Power Conference September 9, 2009

Forward Looking Statements The foregoing contains forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934. The forward-looking statements are those that do not state historical facts and are inherently subject to risk and uncertainties. The forward-looking statements contained herein are based on current expectations and entail various risks and uncertainties that could cause actual results to differ materially from those projected in the forward-looking statements. Such risks and uncertainties include, among others, general economic, financial and business conditions, risks related to the level of activity for North American oil and gas, risks related to excess capacity in our industry, risks related to a shortage of skilled and qualified workers in our industry, risks associated with acquiring and integrating businesses and other factors discussed in the Company’s Annual Report on Form 10-K for the year ended December 31, 2008 under the caption Risk Factors. 1

CPX: The Resource Play Service Provider • Complementary completion and production services • Built around strong local leadership and basin expertise • Well positioned in most active North American unconventional resource play basins • Balanced and disciplined strategy • Well capitalized with ample liquidity 2

Completion & Production Services Wellbore 1) Cement (19 spreads) Preparation 6 2) Log/Perforate (105 E-Line Units) Stimulation 3) Hydraulic Fracturing: (237,000 HP) 4) Drill Out: (267 Well Service Rigs) Completion (57 Coiled Tubing Units) 5 4 5) Jet/Clean Out: (57 Coiled Tubing Units) 1 2 3 Production 6) Production Testing: (30 Units) Note: 1) Unit counts as of 6/30/09 3

Focused on Resource Plays Customers require: • Efficient service delivery and expertise (Execution) • Completion of tasks in a manufacturing Wellbore Field Development Drilling Preparation assembly-line like fashion CPX Focus • “Well factory” environment fComplementary services fCustomized solutions Stimulation fBasin expertise CPX Offers: Production Completion • Market leadership in key basins • Strong execution of services • Basin level expertise • Creative implementation of technology to accelerate production and enhance recovery 4

Market Leadership in Key Basins U.S. Coiled Tubing Unit Share^1,2 U.S. Well Servicing Rig Share³ BJ Services Other Key Other 9% Halliburton 32% 30% 40% 9% Schlumberger 9% Black Warrior Basic Nabors 9% 13% CT Services Cudd 16% 7% Complete 8% Complete 8% 9% Coiled Tubing Market Position by Basin Well Servicing Market Position by Basin Arkoma #1 #2 Mexico Barnett #1 #1 Piceance Green River #2 #2* Bakken East Texas #2 #2 Arkoma Barnett #4* Haynesville #3* #3 Bakken Notes: 1) Intervention and Coiled Tubing Association 2) Excludes Alaska 5 3) American Oil and Gas Reporter Well Service Rig Directory 12/1/08 4) * Tied with other competitors

Pressure Pumping Capabilities Barnett Shale – Best in Class Reliability and Performance Resource Play / Well Factory Environment • Frac fleets operating 18 hours/day, 5 days/week • On average¹: – 2.8 stages/day/fleet – 1.1 million lbs proppant/day/fleet (~5 rail cars/day) – Less than 0.4% down-time Bakken – Proven High-End Capabilities • Bakken Frac Job – 7.2 million gallons cross-linked gel – 3.9 million gallons linear gel – ~12 million pounds proppant • Multiple fluid system capabilities Note: 1) Specific fleets during Q2 2009 6

Coiled Tubing Capabilities Large Diameter and Extended Reach Large Diameter, High-Pressure Focus • Operate 7 out the estimated 30 units¹ in the U.S. that have strings greater than or equal to: – Two inches in diameter; and – 19,000 feet in length • Well positioned to capitalize on trend Simultaneous Operations toward increasing horizontal lengths High Pressure Equipment • Fleet is well equipped to pursue high pressure applications (Haynesville) Technologically Advanced • Real time data acquisition systems Note: 1) Management estimate 7

Bringing it All Together – Marcellus Shale Coiled Tubing Conveyed Perforation and Drill-Outs Coiled tubing conveyed perforation Coiled tubing frac plug drill-outs Equipment: – 2” x 14,500 ft x 0.156” String – Dual Fluid Pumps – 80 scfm N2 unit – 7-1/16” 5M or 4-1/16” 15M BOPs Marcellus Shale Frac 10 Stage Marcellus Frac – 2.3 MM gallons of fluid – 3.1 MM lbs of sand – 9,400 psi maximum pressure – 81 bpm maximum rate – 22,250 hhp, 115 bpm blender 8

Some of the Biggest Resource Play Focused E&P Companies are CPX’s Top Customers • No one customer represents more than 7% of revenue • Top 10 customers comprise approximately 45% of revenue Note: Statistics listed are for year ending December 31,2008 9

CPX is Well Positioned in the Most Active Resource Plays North America North America $238 M Million illion Q2 2009 Revenues Revenue By Region¹ North Texas (Barnett Shale) 33% Rockies (Bakken, Piceance, Uinta) 21% Mid Cont (Anadarko, Deep Woodford, 12% Bakken / Williston Granite Wash) Green River Uinta DJ Marcellus Piceance ArkLaTex (Haynesville) 6% Anadarko Arkoma Barnett / Ft. Worth Arkoma (Woodford, Fayetteville) 5% Haynesville Appalachia (Marcellus) <5% Note: 1) Second Quarter 2009 10

Major Emphasis For Most Active E&P Operators Higher initial production decline rate, but longer life Low geological risk – Location of gas is known – Significant drilling inventories 60,000 50,000 (MMcfd) 40,000 30,000 U.S. Lower 48 20,000 10,000 0 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009E Unconventional Conventional Offshore Source: EIA as of February 2009 11

Horizontal Completions Are Typically More Service Intensive Perforate, stimulate, drill-out and flow back multiple stages Horizontal drilling in unconventional resources estimated to require 6-7x more horsepower demand to stimulate a well as conventional resources¹ 59% 2,000 ² 1,600 30% 1,200 800 (# of U.S. Land Rigs) 400 0 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 YTD Horizontal & Directional Vertical Notes: 1) Citigroup Research 12 2) Baker Hughes Rig Count

Income Statement Summary Year Ending December 31, ¹ Six Months Ending 2004 2005 2006 2007 2008 06/30/08 06/30/09 Revenues $ 236,029 $ 629,578 $1,084,611 $1,494,179 $1,834,915 $ 853,448 $ 575,079 Margins 82,755 246,076 462,139 629,075 698,427 327,948 189,206 SG&A Expense² 37,930 99,431 152,226 192,974 198,200 95,454 87,472 Adjusted EBITDA³ 44,825 146,645 309,913 436,101 500,227 232,494 101,734 As a % of Revenue 19% 23% 29% 29% 27% 27% 18% Net Income from Continuing Operations⁴ 5,663 43,396 124,448 159,435 168,267 78,096 (26,168) Earnings Per Share:⁴ Basic $ 0.19 $ 0.93 $ 1.89 $ 2.21 $ 2.29 $ 1.07 $ (0.35) Diluted $ 0.19 $ 0.87 $ 1.84 $ 2.17 $ 2.26 $ 1.05 $ (0.35) Capital Expenditures 46,904 127,215 303,922 372,554 253,815 134,381 22,760 Notes: 1) Revised – See footnote 2 in CPX Form 10Q for period ending June 30, 2009 2) 2009 SG&A excludes loss from non-monetary asset exchange and asset/inventory write-down 13 3) See EBITDA reconciliation 4) Excludes impact from goodwill impairments

Comparative Performance 30.0% 29.2% 25.7% 25.9% 21.1% 24.1% 20.0% 13.0% 10.0% 13.1% 5.5% 0.0% Q3 Q4 Q1 Q2 (10.0%) (20.0%) (30.0%) CPX Change in Revenue Average Change in Revenue1 CPX EBITDA Margin Average EBITDA Margin1 Note: 1) Average of North American OFS Peers (OIS, KEG, BAS, RPC and SWSI) 14

Focus & Discipline Focus • Maximize cash flow without sacrificing: – Service quality – Future earnings power • Enhance core market positions Discipline • Year to date: – Cut net cash investing activities to $14.5MM from $223.6MM in the second half of 2008 – Reduced SG&A by 15% from the second half of 2008¹ – Generated $219.7MM in cash flow from operations – Reduced net debt by $200.7MM • Completed pay-down of revolving credit facility Note: 1) Excluding impact from non-monetary asset exchange, and fixed asset and inventory write-downs 15

Well Capitalized, Ample Liquidity Year Ending December 31, ¹ As of ($ 000s) 2006 2007 2008 6/30/09 Cash and cash equivalents $ 19,766 $ 13,034 $ 18,500 $ 22,033 Long-term debt Revolving credit 96,243 172,219 193,431 -8% Senior notes (due 2016) 650,000 650,000 650,000 650,000 Other 4,695 4,164 4,214 473 Total debt 750,938 826,383 847,645 650,473 Net debt 731,172 813,349 829,145 628,440 TTM Adjusted EBITDA 309,913 436,101 500,227 369,464 Net Debt / TTM Adjusted EBITDA^2,3 2.4x 1.9x 1.7x 1.7x • Primary revolver covenant = 3.0x Leverage Ratio² •$ 650 million senior notes — Interest only for 10 years (due 2016) •$ 400 million revolving credit facility (December 2011 maturity) Notes: 1) Revised – See footnote 2 in CPX Form 10Q for period ending June 30, 2009 2) See EBITDA reconciliation 16 3) For presentation purposes only - CPX’s credit facility leverage ratio = (gross debt + letters of credit)/TTM EBITDA

Activity May Have Bottomed in Q2 . . . 1,100 1,000 900 Count 800 700 U.S. Land Rig 600 (41%)* 500 400 (61%)** 300 1/6/2006 7/16/2006 1/23/2007 8/2/2007 2/9/2008 8/18/2008 2/25/2009 9/4/2009 Horizontal + Directional Vertical Notes: 1) Assumes Horizontal & Directional rig counts are a proxy for activity in resource plays and Vertical rig counts are a proxy for conventional activity 2) Data from Baker Hughes Rig Count as of 9/4/09 17 3) * Since peak on 11/7/08 of 1,037 Horizontal & Directional Wells 4) ** Since peak on 8/15/08 of 1,014 Vertical Wells

. . . But There Could be Another Step Down U.S. Natural Gas Storage 4,000 4,000 3,500 3,500 3,000 3,000 2,500 2,500 (Bcf) 2,000 2,000 1,500 5-Year Maximum (2004-2008) 1,500 Working Gas Stock 2008 1,000 1,000 Working Gas Stock 2009 2007 2008 500 500 2009 — - Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jun Jul Aug Sep Oct Nov Dec Note: 1) Source: Energy Information Administration 18

Change in U.S. Natural Gas Demand 1.00 0.50 — (0.50) Jul-08 Aug-08 Sep-08 Oct-08 Nov-08 Dec-08 Jan-09 Feb-09 Mar-09 Apr-09 May-09 Jun-09 Bcf/day (1.00) (1.50) (2.00) Average Feb ‘09 – June ‘09 (2.50) Industrial and Commercial (3.00) Consumption is down 2.74 Bcf/d (3.50) year over year Notes: 1) Year over year change in commercial and industrial natural gas consumption 19 2) Source: Energy Information Administration

Timing of Natural Gas Recovery? 70 2,400 2008 Avg Demand = 2,200 63.5 Bcf/Day 65 2009 & 2010 Avg Demand = 60.8 Bcf/Day? 2,000 60 1,800 55 1,600 Supply = Demand 1,400 50 in March 2010? 1,200 45 1,000 40 800 Sep-05 Nov-05 Jan-06 Mar-06 May-06 Jul-06 Sep-06 Nov-06 Jan-07 Mar-07 May-07 Jul-07 Sep-07 Nov-07 Jan-08 Mar-08 May-08 Jul-08 Sep-08 Nov-08 Jan-09 Mar-09 May-09 Jul-09 Sep-09 Nov-09 Jan-10 Mar-10 May-10 Jul-10 Sep-10 Nov-10 U.S. Dry Production Net Imports Total US Rig Count Notes: 1) Assumes production declines 0.5 Bcf/day each month and demand remains 2.74 Bcf/day below 2008 average 20 2) Sources: Energy Information Administration and Baker Hughes

Outlook Market appears to be stabilizing, but could see another step down Pockets of pricing pressure remain Near-term focus is to continue: – Prudently protecting and enhancing market positions – Focusing on execution at the field level – Adjusting cost structure with anticipated activity levels – Reducing capital expenditures and build cash Prepare to shift focus without taking eye off near-term challenges Anticipate market recovery 21

CPX: The Resource Play Provider Experienced Management Team with Proven Track Record Ex St Strategically Positioned as the Resource Play Service Provider Co Complementary Array of Completion and Production Services St Strong Local Leadership and Basin Expertise Innovative Approach to Technical and Operational Solutions In Co Conservative Capital Structure Ba Balanced and Disciplined Growth Strategy NYSE Stock Symbol: CPX Internet Address: www.completeproduction.com 22

Supplemental Financial Information

Income Statement ($ 000s) Year Ended December 31, Six Months Ended June 30, 1 2004 2005 2006 ¹ 2007 ¹ 2008 ¹ 2008 2009 Statement of Operations Data: Revenue: Completion and production services ... 190,267 502,517 860,508 1,238,050 1,541,709 715,493 483,967 Drilling Services ...... 37,584 115,771 194,517 212,272 234,104 110,503 60,100 Products sales ...... 8,178 11,290 29,586 40,857 59,102 27,452 31,012 Total ...... 236,029 629,578 1,084,611 1,491,179 1,834,915 853,448 575,079 Expenses: Service and product expenses ...... 153,274 383,502 622,472 862,104 1,136,488 525,500 385,973 Selling, general and administrative ... 37,930 99,431 152,226 192,974 198,200 95,454 94,911 Depreciation and amortization ...... 19,838 46,484 75,902 131,399 181,197 82,337 103,091 Impairment loss — - — 13,094 272,006 — -Operating income from continuing operations before interest, taxes, impairment charge and minority interest...... 24,987 100,161 234,011 291,608 47,024 150,157 (8,896) Write-off of deferred financing fees ...... — 3,315 170 — - — -Interest expense ...... 7,471 24,460 40,645 61,328 59,729 30,200 28,357 Interest income ...... — - (1,387) (325) (301) (157) (30) Taxes ...... 7,148 28,606 70,184 84,833 72,305 42,018 (11,055) Income (loss) from contining operations before minority interest ...... 10,368 43,780 124,399 145,772 (84,709) 78,096 (26,168) Minority interest ...... 4,705 384 (49) (569) — - -Income (loss) from continuing operations ...... 5,663 43,396 124,448 146,341 (84,709) 78,096 (26,168) Income (loss) from discontinued operations ... 8,221 10,466 14,050 11,443 (4,859) (4,706) -Net income (loss) ...... $ 13,884 $ 53,862 $ 138,498 $ 157,784 $ (89,568) $ 73,390 $ (26,168) Note: 1) Revised – See footnote 2 in CPX Form 10Q for period ending June 30, 2009 24

Other Financial Data Year Ended December 31, Six Months Ending 1 1 1 1 ($ 000s) 2004 2005 2006 2007 2008 6/30/08 6/30/09 Other Financial Data: Adjusted EBITDA ...... $ 44,825 $ 146,645 $ 309,913 $ 436,101 $ 500,227 $ 232,494 $ 101,734 Cash flows from operating activities ...... 34,622 76,427 187,635 338,472 350,409 180,003 219,726 Cash flows from financing activities ...... 157,630 112,139 471,376 66,643 27,990 (25,362) (201,362) Cash flows from investing activities.................. (186,776) (188,358) (650,863) (409,189) (374,098) (150,475) (14,542) Capital Expenditures: Acquisitions, net of cash acquired ... 139,362 67,689 369,606 50,406 180,154 71,862 -Property, plant and equipment........................ 46,904 127,215 303,922 372,554 253,815 134,381 22,760 Balance Sheet Data: Cash and cash equivalents ...... $ 11,547 $ 11,405 $ 19,766 $ 13,034 $ 18,500 $ 17,129 $ 22,033 Net property, plant and equipment.................. 227,406 371,337 752,648 1,013,539 1,166,686 1,108,197 1,073,410 Goodwill 139,322 280,961 541,313 549,130 341,592 569,569 341,512 Total assets ... 515,153 937,653 1,739,198 2,050,557 1,987,353 2,123,774 1,737,750 Long-term debts, excluding current portion.......... 169,178 509,981 750,311 825,985 843,842 788,150 650,170 Total stockholders’ equity ... 172,080 250,761 734,633 925,955 860,711 1,021,121 843,623 Note: 1) Revised – See footnote 2 in CPX Form 10Q for period ending June 30, 2009 25

EBITDA Reconciliation Year Ended December 31, Six Months Ending ($ 000s) 2004 2005 20061 20071 20081 6/30/081 6/30/09 Revenue ... $ 236,029 $ 629,578 $ 1,084,611 $ 1,491,179 $ 1,834,915 $ 853,448 $ 575,079 Net income (loss) ... 13,884 53,862 138,498 157,784 (89,568) 73,390 (26,168) Plus: interest expense, net ... 7,471 24,460 39,258 61,003 59,428 30,043 28,327 Plus: tax expense ...... 7,148 28,606 70,184 84,833 72,305 42,018 (11,055) Plus: depreciation and amortization............... 19,838 46,484 75,902 131,399 181,197 82,337 103,091 Plus: minority interest ...... 4,705 384 (49) (569) — - -Plus: impairment charge ...... — - — 13,094 272,006 — -Plus: loss on non-monetary asset exchange.. ... — - — - - — 4,868 Plus: loss on fixed asset and inventory writedown.. — - — - — - 2,671 Plus: write-off of deferred financing fees — 3,314 170 — - — -Minus: income from discontinued — - — - — - -operations (net of tax expense)............... 8,221 10,465 14,050 11,443 (4,859) (4,706) — Adjusted EBITDA ...... $ 44,825 $ 146,645 $ 309,913 $ 436,101 $ 500,227 $ 232,494 $ 101,734 Note: 1) Revised – See footnote 2 in CPX Form 10Q for period ending June 30, 2009 26