8-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d) of

the Securities Exchange Act of 1934

Date of Report (Date of earliest event reported): February 27, 2013

PIONEER ENERGY SERVICES CORP.

(Exact name of registrant as specified in its charter)

Texas	1-8182	74-2088619
(State or other jurisdiction of incorporation)	(Commission File Number)	(IRS Employer Identification No.)

1250 NE Loop 410, Suite 1000 San Antonio, Texas	78209
(Address of principal executive offices)	(ZIP Code)

Registrant's telephone number, including area code: (210) 828-7689

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions (see General Instruction A.2. below):

[ ]  Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

[ ]  Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

[ ]  Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

[ ]  Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Item 7.01 Regulation FD Disclosure.

From time to time, senior management of Pioneer Energy Services (the “Company”) meets with groups of investors and business analysts. The slides attached to this report have been prepared in connection with management's participation in such meetings and participation in the 2013 Deutsche Bank Energy Day on February 27, 2013. The slides provide an update on the Company's operations and certain recent developments and are included in Exhibit 99.1 to this report and are incorporated herein by reference. The slides are available on the Company's website at www.pioneeres.com.

Safe Harbor Statement

Statements contained in Exhibit 99.1 to this report that state the Company's or its management's expectations and assumptions about future events are forward-looking statements intended to be covered by the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. It is important to note that the Company's actual results could differ materially from those projected or assumed in such forward-looking statements. Factors that could affect those results include, among others, those mentioned in the Company's annual report on Form 10-K for the fiscal year ended December 31, 2012 which has been filed with the Securities and Exchange Commission.

Item 9.01 Financial Statements and Exhibits.

(d)Exhibits.

99.1Slides for Company presentations to be used from time to time.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

PIONEER ENERGY SERVICES

By: /s/ Lorne E. Phillips

Lorne E. Phillips

Executive Vice President and Chief Financial Officer

Dated: February 27, 2013

EX-99.1

2013 DEUTSCHE BANK ENERGY DAY February 27th, 2013

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 general economic and business conditions and industry trends, levels and volatility of oil and gas prices, decisions about exploration and development projects to be made by oil and gas exploration and production companies, risks associated with economic cycles and their impact on capital markets and liquidity, the continued demand for the drilling services or production services in the geographic areas where we operate, the highly competitive nature of our business, our future financial performance, including availability, terms and deployment of capital, future compliance with covenants under our senior secured revolving credit facility and our senior notes, the supply of marketable drilling rigs, well servicing rigs, coiled tubing and wireline units within the industry, the continued availability of drilling rig, well servicing rig, coiled tubing and wireline unit components, the continued availability of qualified personnel, the success or failure of our acquisition strategy, including our ability to finance acquisitions, manage growth and effectively integrate acquisitions, and changes in, or our failure or inability to comply with, governmental regulations, including those relating to the environment. 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, 2012. 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. 2

Overview Ticker Symbol: PES Market Cap: $526 million (February 22nd, 2013) Stock price: $8.65 (February 22nd, 2013) Average 3-month daily trading volume: 543,077 shares Public float: Approximately 61.9 million shares Employees: 3,650 Headquarters: San Antonio, Texas Website: www.pioneeres.com 3

Pioneer Energy Services 108 Well Servicing Rigs in 12 Locations Approximately 7th largest well servicing provider 119 Wireline Units in 23 Locations  103 cased-hole  16 open-hole 13 Coiled Tubing Units in 4 Locations Approximately 14th largest coiled tubing provider  9 onshore units  4 offshore units 71 Drilling Rigs in 7 Locations Approximately 9th largest contract driller 4

Recent Updates  All eight rigs in Colombia are currently working  Term contracts for six of the rigs have been extended through Q1 2013 to allow additional time for long-term contract negotiations  Current drilling utilization is 85%  72% of working rigs are backed by term contracts  Re-allocation of E&P budgets from vertical to horizontal drilling in West Texas has impacted activity levels  Seven rigs are currently stacked and two additional rigs will be stacked by the end of Q1 2013; however, five of the nine rigs are on term contract and will be paid into Q3 2013  Opportunities may exist in the market to put these rigs back to work in the coming quarters 5

Leading Service Provider Across Well Life Cycle DISTRICT AND DIVISION OFFICES 6

50% 50% 46% 54% Stable, Balanced Earnings FY 2012 Total Revenue: $919 million Total Margin: $333 million Drilling Services Production Services 7

Steady Organic Asset Growth 40 52 61 66 70 71 71 64 69 72 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013E 3 6 10 13 13 2009 2010 11 2012 2013 Coiled Tubing Units Wireline Units Land Drilling Rigs Well Servicing Rigs  Continued organic growth opportunities in core businesses  Signed multi-year term contracts for 10 new-build drilling rigs  Added a total of 19 well servicing rigs, 15 wireline units, and 3 coiled tubing units in 2012  Will add one wireline unit (net), one well servicing rig and three drilling rigs in 2013 (first quarter) Note: Rig counts for 2004, 2005 and 2006 represent fiscal years ended March 31, 2004, 2005 and 2006 (1) Figure reflects the retirement of seven rigs effective on September 30, 2011 and two rigs retired effective March 31, 2012. 59 63 84 105 120 121 2008 2009 2010 2011 2012 2013E 74 74 74 89 108 109 20 8 2009 2010 2011 2012 2013E 8

Top-tier Safety PIONEER Total Recordable Incident Rate Drilling Contractors – US Land Top 15 busiest contractors by man-hours in 2011  Pioneer Energy Services was the safest among the 15 largest land contract drillers in the United States for 2011 as reported through the IADC  Awarded 1st place in Division IV of the 2011 Association of Energy Service Contractors (AESC) Annual Safety Awards 9

0 1 2 3 4 5 6 7 Top-tier Safety PIONEER Total Recordable Incident Rate Drilling Contractors – US Land Top 15 busiest contractors by man-hours through Q3 2012  Pioneer Energy Services was the 4th safest among the 15 largest land contract drillers in the United States through the third quarter of 2012 as reported through the IADC  Awarded 3rd place in Division IV of the 2012 Association of Energy Service Contractors (AESC) Annual Safety Awards 10

Well Servicing  100% of rigs are capable of working in the unconventional plays  Newest well servicing fleet in the industry with an average age of less than four years  Highest average horsepower fleet in the industry with all rigs either 550HP or 600HP  Highest percentage of taller mast rigs in the industry with all masts either 104’, 112’ or 116’ in height  Highest utilization rate of top-tier well servicing providers for the past two years  Highest average hourly rate of top-tier well servicing providers for the past two years 11

Well Servicing  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  Established in the Bakken, Eagle Ford, Permian, Fayetteville, Haynesville and Tuscaloosa Marine Shale  Approximately 70% of the fleet is working on oil and liquid-rich wells Fleet Overview Well Servicing Locations ARKANSAS Greenbrier LOUISIANA Lafayette MISSISSIPPI Laurel NORTH DAKOTA Williston TEXAS Alice, Bryan, El Campo, Liberty, Longview, Kenedy, Palestine, Snyder 12

Wireline  One of the newest large-scale wireline fleets in the industry  Leading market share position in a number of key geographic markets  Majority of revenue derived from cased- hole operations that include perforating, logging, and pipe recovery  Established in the Bakken, Eagle Ford, Permian, Niobrara, Mississippian, Haynesville, and Tuscaloosa Marine Shale Fleet Overview Wireline Locations COLORADO Brighton, Ft. Morgan, Wray KANSAS Liberal, Hays, Pratt LOUISIANA Bossier City, Broussard, Houma MONTANA Billings, Cut Bank, Havre NORTH DAKOTA Dickinson, Williston OKLAHOMA Enid TEXAS Alice, Graham, Houston, Laredo, Victoria, Midland UTAH Roosevelt WYOMING Casper 13

Coiled Tubing  Significant player in the offshore coiled tubing market  Young fleet with all 13 units placed into service since 2009  Established in the Eagle Ford, Haynesville, Granite Wash, and offshore Gulf of Mexico 14

Coiled Tubing  Provides a broad range of production and completion services  Completion applications include frac plug drillouts, tubing conveyed perforating (TCP) and well cleanouts  Servicing wells up to a total depth of 22,500’ with 2” coil  Eight units utilize large-diameter 2” coiled tubing, five units operate 1.25” – 1.50” coiled tubing Fleet Overview Coiled Tubing Locations LOUISIANA Arcadia, Maurice OKLAHOMA Weatherford TEXAS George West 15

Drilling Services 16

High Quality Drilling Fleet, Focused On Unconventional Plays SOUTH TEXAS 14 rigs EAST TEXAS 4 rigs NORTH DAKOTA 13 rigs UTAH 5 rigs COLOMBIA 8 rigs APPALACHIA 4 rigs DRILLING LOCATIONS WEST TEXAS 23 rigs 17

54% 46% 1% 13% 56% 31% Pioneer Rig Class Comparison High-End Mechanical Top Drive High-End Mechanical Electric 2012/2013 New-Build Deliveries Drawworks 750-1,200HP 1,000-1,300HP 1,000-2,000HP 1,000-1,500HP Top Drive --- 250-500 Ton AC 250-500 Ton AC 500 Ton AC Mud Pumps 1,000-1,300HP 1,000-1,600HP 1,300-1,600HP 1,600-2,000HP Rounded-Bottom Mud Tanks 78% 80% 97% 100% Iron Roughneck 57% 100% 93% 100% Number of Rigs 23 10 29 10 % of Fleet* 32% 14% 40% 14% Utilization % 61% 70% 93% 100% *Percentages based on 72 rig fleet, “Electric” includes two 750HP rigs; “High-End Mechanical” includes one 550HP rig; Utilization as of 2/13/13 Q4 2012 earnings conference call; Four lowest HP rigs have 750-800HP mud pumps Projected Rig Fleet Mix** Electric Mechanical 750-900HP 1,000-1,400HP 1,500-2,000HP <750 HP **Based on 72 rig fleet 18

0% 20% 40% 60% 80% 100% Pioneer Helmerich & Payne Patterson-UTI Nabors Precision (U.S.) 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 Energy Services utilization rates include Colombian operations beginning Q3 2007. (1) PES utilization as of February 20th, 2013; figure reflects the retirement of seven rigs effective on September 30, 2011 and two rigs effective March 31, 2012.  Averaged over 80% utilization through cycles since 2001, comparing favorably to peers  Current utilization of 85%(1) Comparable Utilization Rates 19

Modern, Efficient Drilling Fleet  46 rigs with top drives (65% of fleet)  25 walking/skidding systems on rigs  46 pairs of 1,300/1,600/2,000HP mud pumps  83% of rigs have iron roughnecks  54% of rigs are electric  89% of rigs have rounded-bottom mud tanks 50 Series Rig 20

New-Build Features 21  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 22  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 23 Festoon System to Manage Electrical Supply to Substructure

Financials 24

$176 $145 $215 $75 $103 $191 $249 $0 $50 $100 $150 $200 $250 $300 2006 2007 2008 2009 2010 2011 2012 Strong Revenue and Adjusted EBITDA Growth Revenue ($ millions) Adjusted EBITDA ($ millions) $396 $417 $611 $326 $487 $716 $919 $0 $100 $200 $300 $400 $500 $600 $700 $800 $900 $1,000 2006 2007 2008 2009 2010 2011 2012 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 29 25

25% 32% 36% 39% 46% 75% 68% 64% 61% 54% 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% 2008 2009 2010 2011 2012 % o f T ot al R ev en ue Production Services Drilling 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. Revenue Gross Margin 28% 34% 45% 45% 50% 72% 66% 55% 55% 50% 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% 2008 2009 2010 2011 2012 % o f T ot al M ar gi n Production Services Drilling 26

Liquidity and Capital Structure December 31st, 2012 ($ in millions) Actual Cash $ 23.7 Revolving Credit Facility 100.0 Sr. Unsecured Notes(1) 418.6 Other 1.0 Total Debt $ 519.6 Shareholders' Equity 547.7 Total Capitalization $ 1,067.3 Liquidity(2) 164.7 Debt/TTM EBITDA(3) 2.1x Debt/Total Book Capitalization 48.7% (1) Reflects $250MM principal amount of initial notes net of $7.9MM unamortized discount as well as $175MM principal amount of new notes plus $1.5MM 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 2012. 27

Appendix 28

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) 2008 2009 2010 2011 2012 Adjusted EBITDA 214.8 74.9 103.2 191.2 249.3 Colombian Net Equity Tax - - - (7.3) - Depreciation & Amortization (88.1) (106.2) (120.8) (132.8) (164.7) Net Interest (11.8) (8.9) (26.6) (29.7) (37.0) Impairment Expense (171.5) - (3.3) (0.5) (1.1) Income Tax (Expense) Benefit (6.1) 17.0 14.3 (9.7) (16.4) Net Income (Loss) (62.7) (23.2) (33.3) 11.2 30.0 Year-Ending December 31, ($ in millio ) Q1 2012 Q2 2012 Q3 2012 Q4 2012 TTM Adjust d EBITDA 70.1 63.3 55.6 60.3 249.3 D preciatio & Amortization (38.4) (40.0) (42.1) (44.3) (164.7) Net Interest (9.6) (7.7) (9.5) (10.4) (37.0) Impairment Expense (1.0) - - (0.1) (1.1) Income Tax (Expense) Benefit (7.0) (6.0) (1.5) (1.9) (16.4) Net Income (Loss) 14.2 9.7 2.6 3.6 30.0 29