Howard Weil 40th Annual Energy Conference March 27th, 2012

2 Forward-looking Statements This presentation contains various forward-looking statements and information that are based on management’s current expectations and assumptions about future events. Forward-looking statements are generally accompanied by words such as “estimate,” “project,” “predict,” “expect,” “anticipate,” “plan,” “intend,” “seek,” “will,” “should,” “goal” and other words that convey the uncertainty of future events and outcomes. Forward-looking information includes, among other matters, statements regarding the Company’s anticipated growth, quality of assets, rig utilization rate, capital spending by oil and gas companies, production rates, the Company's growth strategy, and the Company's international operations. Although the Company believes that the expectations and assumptions reflected in such forward-looking statements are reasonable, it can give no assurance that such expectations and assumptions will prove to have been correct. Such statements are subject to certain risks, uncertainties and assumptions, including, among others: general and regional economic conditions and industry trends; the continued strength of the contract land drilling industry in the geographic areas where the Company operates; decisions about onshore exploration and development projects to be made by oil and gas companies; the highly competitive nature of the contract land drilling business; the Company’s future financial performance, including availability, terms and deployment of capital; the continued availability of qualified personnel; changes in governmental regulations, including those relating to the environment; the political, economic and other uncertainties encountered in the Company's international operations and other risks, contingencies and uncertainties, most of which are difficult to predict and many of which are beyond our control. Should one or more of these risks, contingencies or uncertainties materialize, or should underlying assumptions prove incorrect, actual results may vary materially from those expected. Many of these factors have been discussed in more detail in the Company's annual report on Form 10- K for the fiscal year ended December 31, 2011. Unpredictable or unknown factors that the Company has not discussed in this presentation or in its filings with the Securities and Exchange Commission could also have material adverse effects on actual results of matters that are the subject of the forward-looking statements. All forward-looking statements speak only as the date on which they are made and the Company undertakes no duty to update or revise any forward-looking statements. We advise our shareholders to use caution and common sense when considering our forward-looking statements.

Overview Ticker Symbol: PDC Market Cap: $519.1 million (March 22, 2012) Stock price: $8.44 (March 22, 2012) Average 3-month daily trading volume: 762,362 shares Public float: Approximately 61.5 million shares Employees: 3,300 Headquarters: San Antonio, Texas Website: www.pioneerdrlg.com 3

Pioneer Drilling Company 4 64 Drilling Rigs in 8 Locations  Approximately 9th largest contract driller 94 Well Service Rigs operating in 12 Locations  Approximately 7th largest well service provider 108 Wireline Units in 24 Locations  91 cased hole  17 open hole 10 Coiled Tubing Units in 5 Locations  7 Onshore Units  3 Offshore Units

5 Leading Service Provider Across Well Life Cycle Diversified Business and Geography Mix TTM Dec 31, 2011 39% 61% Drilling Services Production Services Total Revenue: $716 million 45% 55% Drilling Services Production Services Total Margin: $259 million Colombia

Investment Considerations  Superior safety performance enhances equipment utilization and opens doors to new client relationships  Bifurcated land rig market providing improved opportunity for our high-end mechanical rigs  Majority of assets targeting oil-driven opportunities  Approximately 87% of our working drilling rigs and 79% of our production services assets are operating on wells that are targeting or producing oil and liquids-rich plays  Closed acquisition of Go-Coil, LLC on 12/31/11, which adds a complementary coiled tubing service to Pioneer’s Production Services Division  Continued organic growth opportunities in core businesses: land drilling, well services, coiled tubing and wireline  Signed multi-year term contracts for ten new-build drilling rigs for 2012 delivery  Added 15 550HP and 600HP well service rigs in 2011 with 13 more rigs planned for 2012  Added 21 wireline units in 2011 with 11 more units on order for 2012 delivery  Adding a minimum of three coiled tubing units for 2012 6

7 Well Services  Provides a wide range of well services to exploration and production companies  Existing well maintenance  Workover of existing wells  Completion of newly-drilled wells  Plugging and abandonment of wells at the end of their useful lives  One of the newest and most highly capable well service fleets in the industry  94 total units with all but one of the units 550 HP or greater  Awarded 1st place in Division IV of the 2011 Association of Energy Service Contractors (AESC) Annual Safety Awards  Established in the Bakken, Fayetteville, Haynesville and Eagle Ford shales

Well Services 8 Fleet Overview Well Service Locations 2007-2010 24% 2% Williston Bryan Palestine Longview El Campo Liberty Lafayette Laurel 2005-2006 2002-2004 Snyder  Capable of working at depths of 20,000’  Approximately 73% of the fleet working on oil and liquid-rich wells 54% Alice Kenedy Greenbrier 2011-2012 19% Fleet Age

Wireline 9  Majority of revenue derived from cased-hole operations that include perforating, logging, and pipe recovery  Significant growth in pump down operations due to demand for horizontal drilling  Fleet of 108 wireline units has an average age of approximately 6 years  Established in the Bakken, Eagle Ford, Niobrara, Mississippian, Haynesville, and Tuscaloosa Marine shales Fleet Overview Wireline Locations Williston Dickinson Cut Bank Billings Havre Tyler Bossier City Broussard Graham Roosevelt Pratt Liberal Hays Casper Ft. Morgan Brighton Wray Laredo Laurel Victoria Enid Houma Alice Houston

10 Coiled Tubing  Provides a broad range of production and completion services  Completion applications include frac plug drillouts, tubing conveyed perforating (TCP) and well cleanouts  All ten units were placed into service between 2009 and 2011  Established in the Eagle Ford, Haynesville, Granite Wash and Marcellus

Coiled Tubing 11 Fleet Profile Coiled Tubing Locations Danville Weatherford George West Maurice Arcadia  Standardized, new equipment (7 onshore units, 3 offshore units)  Servicing wells up to a total depth of 19,000’ with 2” coil  Six units utilize large-diameter 2” coiled tubing  Four units operate 1.25” – 1.50” coiled tubing

12 Drilling Services

3% 17% 58% 22% 45% 55% High Quality Drilling Fleet, Focused on Unconventional Plays 13 Historical Fleet Growth Drilling Locations Current Rig Fleet Mix Note: Rig counts for 2004, 2005 and 2006 represent fiscal years ended March 31, 2004, 2005 and 2006 while 2007, 2008 and 2009 represent fiscal years ended December 31, 2007, 2008 and 2009. (1) Figure reflects the retirement of seven rigs effective on September 30, 2011 . 15 rigs South Texas 6 rigs East Texas Electric Mechanical 750-900 HP 1,000-1,400 HP 1,500-2,000 HP 9 rigs North Dakota 18 rigs West Texas 4 rigs Utah 4 rigs Appalachia 8 rigs Colombia 40 52 61 66 70 71 71 64 2004 2005 2006 2007 2008 2009 2010 2011 (1) <750 HP

14 Drilling Facts  Pioneer Drilling Services was the safest among the 15 largest land contract drillers in the United States for 2011 as reported through the IADC  Pioneer received an award from Ecopetrol as having the top two performing rigs in Colombia in 2011  Strong contract backlog in land drilling segment  80% of working rigs backed by term contracts  Through 2017, Spears & Associates estimates that over 50% of wells to be drilled in the United States will be vertical or directional with depths of 10,000 – 11,000 ft., ideal for our high-end mechanical rigs.  Approximately 70% of our drilling rigs are working for large and mega-cap E&P operators

0% 20% 40% 60% 80% 100% Pioneer Helmerich & Payne Patterson-UTI Nabors Precision (U.S.) 15 Strong Utilization Through the Cycles Source: Helmerich & Payne, Patterson-UTI, & Precision Drilling data consists of U.S. domestic utilization rates derived from Form 10-K, Form 10-Q reports, & press releases. Nabors utilization rates obtained from public documents and industry analysts. Helmerich & Payne Q3 2010 only estimated based on analyst reports. Pioneer Drilling utilization rates include Colombian operations beginning Q3 2007. (1) PDC utilization as of Feb 21, 2011; figure reflects the retirement of seven rigs effective on September 30, 2011.  Averaged approximately 81% utilization through cycles since 2001, comparing favorably to peers  Current utilization of 88%(1) Comparable Utilization Rates

16 Modern, Efficient Drilling Fleet  36 rigs with top drives (56% of fleet)  16 walking/skidding systems on rigs  36 pairs of 1,300/1,600 HP mud pumps  77% of rigs have iron roughnecks  45% of rigs are electric  84% of rigs have rounded bottom mud tanks 50 Series Rig

New-Build Features 17  State-of-the-art 550K and 750K sub & mast AC new- builds  Integrated 500 ton top drives in mast section for faster rig up and rig down  Crane free rig up / rig down design  30 loads on base rig for fast moves  BOP handling systems  Automatic catwalk  1,600 HP and 2,000 HP mud pumps  Ability to drill multi-well single-row pads and walk easily between wells with above ground heads

New-Build Pad Drilling Capability 18  Pin On Walking System  Can walk in either direction or spin the rig  Can walk with full set back of drill pipes in mast  Amphion AC Control Systems  Latest features in rig control software  Climatized driller’s cabin  Joystick control

New-Build Advanced Electrical System 19 Festoon System to Manage Electrical Supply to Substructure

20 Financials

21 $176 $145 $215 $75 $103 $191 $0 $50 $100 $150 $200 $250 2006 2007 2008 2009 2010 2011 Strong Revenue and Adjusted EBITDA Growth Revenue ($ millions) Adjusted EBITDA ($ millions) $396 $417 $611 $326 $487 $716 $0 $100 $200 $300 $400 $500 $600 $700 $800 2006 2007 2008 2009 2010 2011 Note: Fiscal year end was changed from March 31 to December 31 effective on December 31, 2007; all data points reflect calendar year and trailing twelve months information derived from 10K and 10Q filings. Please refer to Reconciliation of Adjusted EBITDA to Net Income on slide 27.

22 Contribution by Segment Note: Fiscal year end was changed from March 31 to December 31 effective on December 31, 2007; all data points reflect calendar year and trailing twelve months information derived from 10K and 10Q filings. 25% 32% 36% 39% 42% 75% 68% 64% 61% 58% 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% 2008 2009 2010 2011 Q4 2011 % o f T o ta l R e ve nu e Production Services Drilling Revenue Gross Margin 28% 34% 45% 45% 48% 72% 66% 55% 55% 52% 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% 2 08 20 9 20 0 Q4 2011 % o f T o ta l M a rg in Production Services Drilling

Strong Liquidity and Capital Structure 23 Capitalization (As of December 31, 2011) December 31, 2011 ($ in millions) Actual Cash $ 86.2 Revolving Credit Facility 0.0 Sr. Unsecured Notes(1) 417.7 Other 1.9 Total Debt $ 419.6 Stockholders' Equity 510.4 Total Capitalization $ 930.0 Liquidity(2) 327.0 Debt / LTM EBITDA(3) 2.2x Debt / Total Book Capitalization 45.1% (1) Reflects $250MM principal amount of initial notes net of $8.9MM unamortized discount as well as $175MM principal amount of new notes plus $1.6MM of unamortized bond premium. (2) Defined as remaining credit facility capacity plus cash less LCs outstanding. (3) Total consolidated leverage ratio as reported in Form 10-K for 2011.

24 Appendix

Resurgence in U.S. Land Rig Count 1 25  Steady rig count improvement since the second half of 2009  Horizontal and oil rig counts have surpassed Fall 2008 peak levels Land Rig Count Horizontal & Oil Rig Count Source: Baker Hughes Source: Baker Hughes. -5.0% -2.5% 0.0% 2.5% 5.0% 600 1,000 1,400 1,800 2,200 Jan-07 Jan-08 Jan-09 Jan-10 Jan-11 Jan-12 Land Rigs BHI Rolling 4-Week Avg. Weekly Change 0 200 400 600 800 1,000 1,200 1,400 Jan-07 Jan-08 Jan-09 Jan-10 Jan-11 Jan-12 Oil Horizontal Oil March 16, 2012: 1,317 Horizontal March 2, 2012: 1,180

Benefits of Growing Shale Plays 1 26  Oilfield service companies stand to benefit from shale production due to its lower risk development and increased service intensity (up to 3 - 5x conventional)  Shale gas is expected to make up 47% of total U.S. production in 2035 vs. its 16% share in 2009(1)  Reintroduction of the Majors in the U.S. market should result in greater activity levels Recent U.S. Shale Investments Growing Importance of Shale $Millions $40,991 12/14/2009 $12,100 7/13/2011 $4,700 5/28/2010 $3,500 6/1/2011 $3,375 11/11/2008 $3,200 11/9/2010 $2,250 12/30/2009 $1,900 9/2/2008 T ri ll io n c u bic f e e t p e r y e a r (1) SOURCE: EIA “ANNUAL ENERGY OUTLOOK 2011” APRIL 2011 U.S. NATURAL GAS PRODUCTION 1990 – 2035(1)

27 Reconciliation of Adjusted EBITDA to Net Income We define Adjusted EBITDA as earnings (loss) before interest income (expense), taxes, depreciation, amortization, impairments, and the Colombian Net Equity Tax. Although not prescribed under GAAP, we believe the presentation of Adjusted EBITDA is relevant and useful because it helps our investors understand our operating performance and makes it easier to compare our results with those of other companies that have different financing, capital or tax structures. Adjusted EBITDA should not be considered in isolation from or as a substitute for net earnings (loss) as an indication of operating performance or cash flows from operating activities or as a measure of liquidity. A reconciliation of net earnings (loss) to Adjusted EBITDA is included in the table below. Adjusted EBITDA, as we calculate it, may not be comparable to EBITDA measures reported by other companies. In addition, Adjusted EBITDA does not represent funds available for discretionary use. ($ in millions) 2007 2008 2009 2010 2011 Adjusted EBITDA 144.5 214.8 74.9 103.2 191.2 Colombian Net Equity Tax - - - - (7.3) Depreciation & Amortization (63.6) (88.1) (106.2) (120.8) (132.8) Net Interest 3.3 (11.8) (8.9) (26.6) (29.7) Impairment Expense - (171.5) - (3.3) (0.5) Income Tax (Expense) Benefit (27.4) (6.1) 17.0 14.3 (9.7) Net Income (Loss) 56.9 (62.7) (23.2) (33.3) 11.2 Year-Ending December 31, ($ in millions) Q1 2011 Q2 2011 Q3 2011 Q4 2011 TTM Adj st EBITDA 38.9 45.1 51.6 55.5 191.2 Col mbi N t Equity Tax (7.3) - - - (7.3) D p eciation & Amortization (32.3) (32.4) (33.0) (35.2) (132.8) Net Interest (7.5) (8.0) (6.1) (8.1) (29.7) Impairment Expense - - (0.5) - (0.5) Income Tax (Expense) Benefit 2.1 (1.0) (5.3) (5.5) (9.7) Net Income (Loss) (6.0) 3.7 6.7 6.8 11.2

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