Vital Energy 8K Regulation FD Disclosure | VTLE 3 Dec 12

Exhibit 99.1

December 2012 NYSE: LPI www.laredopetro.com

This presentation (which includes oral statements made in connection with 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 fact, included in this presentation that address activities, events or developments that Laredo Petroleum Holdings, Inc. (the “Company”, “Laredo” or “LPI”) assumes, plans, expects, believes or anticipates will or may occur in the future are forward-looking statements. The words “believe,” “expect,” “may,” “estimates,” “will,” “anticipate,” “plan,” “intend,” “foresee,” “should,” “would,” “could,” or other similar expressions are intended to identify forward-looking statements, which are generally not historical in nature. However, the absence of these words does not mean that the statements are not forward-looking. Without limiting the generality of the foregoing, forward-looking statements contained in this presentation specifically include the expectations of 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 expectations 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 or expressed by the forward-looking statements. These include risks relating to financial performance and results, current economic conditions and resulting capital restraints, prices and demand for oil and natural gas, availability of drilling equipment and personnel, availability of sufficient capital to execute the Company’s business plan, impact of compliance with legislation and regulations, successful results from our identified drilling locations, the Company’s ability to replace reserves and efficiently develop and exploit its current reserves and other important factors that could cause actual results to differ materially from those projected as described in the Company’s Rule 424(b)(1) prospectus as filed with the Securities and Exchange Commission (“SEC”) on October 12, 2012 as well as the Company’s Annual Report on Form 10-K for the year ended December 31, 2011, Quarterly Report on Form 10-Q for the quarter ended March 31, 2012, Quarterly Report on Form 10-Q for the quarter ended September 30, 2012 and other reports filed with the SEC. 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. The SEC generally permits oil and gas companies, in filings made with the SEC, to disclose proved reserves, which are reserve estimates that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions and certain probable and possible reserves that meet the SEC’s definitions for such terms. In this presentation, the Company may use the terms “unproved reserves” , which the SEC guidelines restrict from being included in filings with the SEC without strict compliance with SEC definitions. The Company does not choose to include unproved reserve estimates in its filings with the SEC. “Unproved reserves” refers to the Company’s internal estimates of hydrocarbon quantities that may be potentially discovered through exploratory drilling or recovered with additional drilling or recovery techniques. Unproved reserves may not constitute reserves within the meaning of the Society of Petroleum Engineer’s Petroleum Resource Management System or SEC rules and do not include any proved reserves. Actual quantities that may be ultimately recovered from the Company’s interests will differ substantially. Factors affecting ultimate recovery include the scope of the Company’s 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, as well as actual drilling results, including geological and mechanical factors affecting recovery rates. Estimates of unproved reserves may change significantly as development of the Company’s core assets provide additional data. In addition, the Company’s 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. This presentation includes financial measures that are not in accordance with generally accepted accounting principles (“GAAP”), including Adjusted EBITDA. While management believes that such measures are useful for investors, they should not be used as a replacement for financial measures that are in accordance with GAAP. For a reconciliation of Adjusted EBITDA to the nearest comparable measure in accordance with GAAP, please see the Appendix. Forward-Looking / Cautionary Statements 2

Investment Highlights ~196,000 net acres in the Permian with potential in multiple horizons Significant operational control: operate ~97% of production Meaningful exposure to Anadarko Granite Wash liquids-rich natural gas Extensive library of petrophysical data in our Permian core asset 140 proprietary logs 10 whole and >300 side-wall cores 740 square miles of 3D seismic Permian Basin – Garden City ~70,000 net acres de-risked for Cline Hz development ~60,000 net acres de-risked for Upper Wolfcamp Hz development Evaluation of Middle and Lower Wolfcamp zones is ongoing Optimization of spacing, lateral lengths and completion techniques Flexibility for multi-zone development >5,600 gross identified locations in the Permian - Garden City area Experienced management team with proven record of success Well capitalized with liquidity of ~$700 million Proactively hedge commodity price risk Owned gathering infrastructure provides secure and timely takeaway capacity and enhanced economics 3

Company Overview Total Company Midland Office Dallas Office Tulsa Headquarters Anadarko: Granite Wash 30,835 BOE/D average daily production during Q3 2012 1 156.5 MMBOE proved reserves at December 31, 20111 Permian oil focused Transitioning into development phase Drilling inventory of greater than 10 years Currently operating 14 drilling rigs 564,000 gross / 425,000 net acres 2 company-wide Other Areas / New Ventures 191,000 net acres 2 Central Texas Panhandle – 45,000 net acres 2 Eastern Anadarko Basin – 25,000 net acres 2 Dalhart Basin – 102,000 net acres 2 Other – 19,000 net acres 2 1 Production and reserves reported on a two-stream basis. Reserves are gas price adjusted to reflect NGL benefit. Proved reserves per Ryder Scott evaluation at 12/31/11, at SEC pricing. 2 Acreage figures rounded as of 9/30/12 Permian: Vertical Wolfberry, Horizontal Wolfcamp, Cline Shales 37,000 net acres 2, Liquids-rich natural gas 196,000 net acres 2, Oil and liquids-rich natural gas ~65% of total company reserves 1 ~67% of Q3-2012 total production 1 4 NYSE: LPI Market Cap: ~$2.6 Billion Shares Outstanding: 128.2 MM Share Price (11/7/12): $20.07/share Total Enterprise Value: ~$3.7 B

Consistent Growth in Reserves and Production Permian oil is driving repeatable growth Reserves reported on a two-stream basis with gas price adjusted to reflect NGL benefit; per Ryder Scott evaluation at 12/31/11, at SEC pricing. Production data includes production from Broad Oak Energy, Inc. on a combined basis and presented on a two-stream basis CAGR in MBOE/D production from 2008 through midpoint of projected 2012 5 Reserves >52% CAGR Production ~65% CAGR

Laredo reports on a two-stream basis to match its ownership in the production Pricing Impact Gas Q3 -2012 Avg. LPI realizations $4.12 Q3-2012 Avg. NYMEX Henry Hub $2.80 Benefit to LPI +47% Two-Stream vs. Three-Stream Q3-2012 Production Q3-2012 Revenue Three-Stream ~ 20% Increase No revenue impact Two-Stream Q3-2012 Production: 30,835 BOE/D Q3-2012 Revenue: $144.7 million 6

Permian Basin: Garden City Core Area ~142,000 net acres in Glasscock, Reagan, Howard and Sterling counties; >325 sections Ongoing vertical program Multiple horizontal targets, each now with proven production: Cline shale Upper Wolfcamp shale Middle Wolfcamp shale Lower Wolfcamp shale Six vertical rigs and four horizontal rigs operating ~ 92% average working interest; ~ 24% average royalty Energen Range El Paso COP Exco EOG Petrohawk / BHP Apache Approach Devon Pioneer Laredo Laredo Acreage illustrated in map above represents publicly released leasehold positions 7

Penn Shale Early Stage Exploration Late Stage Exploration Early Stage Development Late Stage Development Permian Basin: Recognizing the Potential Exploration / Development Phases Upper Wolfcamp Middle Wolfcamp Dean Lower Sprayberry Upper Sprayberry Clearfork Canyon Strawn Atoka Barnett Woodford Fusselman 16 33 1 Well counts as of 10/31/12 >1,300 feet of combined potential pay thickness! Cline 8 1 Completed Hz Wells 1 2 Lower Wolfcamp

Laredo Permian Shales Other Industry Shales Wolfcamp Bakken Barnett Oil Combo Eagle Ford Upper Middle Lower Cline Combined Basin Midland Midland Midland Midland Midland Williston Fort Worth South Texas Age Permian Permian Permian Penns. Permian & Penns. L. Dev./ E. Miss. Mississippian Cretaceous Depth (ft) 7,000 - 7,500 7,300 - 7,900 7,900 - 8,500 9,000 - 9,500 7,000 - 8,000 - 10,500 6,500 - 8,500 7,000 - 12,000 9,500 Average thickness (ft) 300 - 400 400 - 500 475 - 575 200 - 350 1,375 - 1,825 10 - 120 150 - 600 150 - 300 TOC (%) 2.0 - 9.0 2.0 - 5.0 2.0 - 5.0 2.0 - 7.5 2.0 - 9.0 5.0 - 20.0 3.0 - 7.0 2.0 - 6.5 Thermal maturity (% RSO) 0.7 - 0.8 0.8 - 0.9 0.8 - 0.9 0.85 - 1.1 0.7 - 1.1 0.5 - 1.0 0.8 - 1.7 0.8 - 1.4 Total porosity (%) 5.0 - 7.0 3.0 - 12.0 3.0 - 12.0 3.0 - 12.0 3.0 - 12.0 3.0 - 12.0 4.0 - 6.0 5.0 - 12.0 Pressure gradient (psi/ft) 0.45 - 0.50 0.45 - 0.50 0.45 - 0.50 0.55 - 0.65 0.45 – 0.65 0.60 - 0.80 0.45 - 0.53 0.55 - 0.65 OOIP (MMBOE/Section) 25 - 45 25 - 40 20 - 30 25 - 40 95 - 155 5 - 10 10 - 20 25 - 55 Laredo’s Four Shale Plays Compared to Other Top Shale Plays Wolfcamp & Cline shales properties from proprietary LPI core analysis; analog play properties from various industry sources Permian-Garden City’s multi-zone, stacked horizontal potential 9

Permian-Garden City: What We Have Done to Date Martin Howard Mitchell Midland Upton Glasscock Reagan Sterling Tom Green Irion Completed 54 gross horizontal wells on acreage 1 33 Cline wells 16 Upper Wolfcamp wells 2 Middle and 1 Lower Wolfcamp and 2 Strawn wells Drilled >700 gross vertical wells Identified a large inventory of repeatable, economic development locations Approximate de-risked acreage areas Cline: ~70,000 net acres Upper Wolfcamp: ~ 60,000 net acres LPI acreage Exploitation Phase Exploration Phase Basin Shelf De-risked ~70,000 and ~60,000 net acres for Hz Cline & Upper Wolfcamp development, respectively 10 1 Well counts as of 10/31/12

Permian-Garden City: Cline Shale Completed 33 Hz Cline wells 1 Optimizing wells; increasing lateral lengths Up to 7,500 feet Up to 28 stages of fracture stimulation Expect to spud three additional Hz wells during 4th quarter of 2012 Activity concentrated west and south of the facies change Basin Shelf Cline area de-risked for development Cline Hz well 4Q-`12 scheduled Cline Hz well LPI acreage Exploration Phase Martin Howard Mitchell Midland Upton Glasscock Reagan Sterling Tom Green Irion De-risked ~70,000 net acres for Hz Cline development 11 Exploitation Phase 1 Well counts as of 10/31/12

Permian Basin-Garden City: Regional Cline Cross Section GLASSCOCK Co. REAGAN Co. N S CLINE HIGH-QUALITY RESOURCE PLAY Cline shale across LPI’s acreage position 87 MILES Cross section line 12 Glasscock Reagan Midland Upton Mitchell Sterling Tom Green Martin Howard

Permian-Garden City: Wolfcamp Shale – Three Zones 13 1 Well counts as of 10/31/12 Upper Wolfcamp area de-risked for development Upper Wolfcamp Hz well Middle Wolfcamp Hz well Lower Wolfcamp Hz well Upper Wolfcamp Middle Wolfcamp Lower Wolfcamp LPI acreage Completed 19 Hz Wolfcamp wells 1 16 Upper Wolfcamp 2 Middle Wolfcamp 1 Lower Wolfcamp Expect to spud seven additional Hz Wolfcamp wells during 4th quarter of 2012 5 Upper Wolfcamp 1 Middle Wolfcamp 1 Lower Wolfcamp Basin Shelf Exploitation Phase Exploration Phase Martin Howard Mitchell Midland Upton Glasscock Reagan Sterling Tom Green Irion De-risked ~60,000 net acres for Hz Upper Wolfcamp development 4Q-`12 scheduled Hz well

Permian-Garden City: Regional Wolfcamp Cross Section N GLASSCOCK Co. REAGAN Co. Upper Wolfcamp Middle Wolfcamp Lower Wolfcamp 87 MILES S Wolfcamp shale intervals underlie LPI’s Permian-Garden City acreage position LPI acreage Cross section line 14 Midland Glasscock Reagan Martin Upton Howard Mitchell Sterling Irion

2012 Horizontal Drilling Results Based on all 2012 horizontal wells that have been on production for at least 30 days following peak IP Production reported on a two-stream basis. Well Cox Bundy 16 #3H Calverley 4 #5H Bearkat #904H Sugg-A-142-1H Lazy E #1402H Cox 32 #5H Guthrie Trust A #1906H Calverley 40 #5H Moore 25 #6H East Boxcar 48 #4H Lynda 41 #3H Sugg A 157 1H Bodine A 174 1H Sugg-B-162-1HU Sugg-A-142OH Yellow Rose 40 #6H Sugg-B-109-1H SRH-A-9-1H Sugg-B-133-1HU Sugg B 131 1H Lacy Creek 34 #3H Barbee-B-2-1H Sugg-A-183-1HM Sugg-A-183-2HL Frac Stages 15 15 19 25 26 15 12 15 15 15 15 23 15 25 22 15 28 26 25 14 15 10 26 26 Lateral Length 4,382 3,986 4,807 6,790 7,054 3,848 4,068 3,816 3,968 3,824 3,632 6,128 3,937 6,648 5,972 3,798 7,473 6,935 6,841 3,700 3,656 6,664 6,930 6,933 30-Day IP 756 653 615 607 570 543 509 400 325 325 191 909 750 748 693 606 517 486 466 430 427 269 924 715 Upper Wolfcamp Cline Middle Wolfcamp BOEPD Feet Average of 30 BOEPD/stage Average of 30 BOEPD/stage 15 Lower Wolfcamp Average of 36 BOEPD/stage Average of 28 BOEPD/stage

Permian Basin-Garden City: Vertical Wolfberry LPI has >700 gross vertical wells to date Large inventory of repeatable, economic development locations Well density of ~200 acres per well Provides a technical and economic foundation for defining additional upside of horizontal shale drilling programs Six vertical rigs operating GLASSCOCK HOWARD STERLING IRION REAGAN TOM GREEN MARTIN MITCHELL MIDLAND UPTON LPI acreage LPI vertical well 16 Solid economics with significant downspacing potential

Houston Cushing Wichita Falls Longview Existing Takeaway (MBOPD) Total Refineries 410 Total Oil Pipelines 770 Total Existing Capacity 1,180 Expansion Capacity (MBOPD) Capacity Completion Date Longhorn Reversal (Phase I) 75 1Q13 Permian Express I 90 1Q13 Longhorn Reversal (Phase II) 150 2Q13 Permian Express I (expansion) 60 3Q13 BridgeTex Crude Oil Pipeline 278 2Q14 Permian Express II 200 3Q14 Total Expansion Capacity 853 Total Takeaway Capacity 2H14 2,033 Existing Refinery Existing Pipelines New Pipelines and Additions BridgeTex Longhorn Permian Express II Permian Express I 10,000 BOPD on Longhorn 10,000 BOPD on BridgeTex LPI Firm Capacity LPI Permian Takeaway Capacity 17

Anadarko Granite Wash: Multiple Porosity Trends Land position consists of 54,000 gross; 37,000 net acres 1 Drilled and completed >20 horizontal Granite Wash wells in the play 2 Approximately 100 potential horizontal Granite Wash locations identified Horizontal well locations technically defined by geology and reservoir characteristics Majority of the Laredo Granite Wash program will have two horizontal wells or less per zone per section Our average well performance continues to meet or exceed expectations Detailed geological mapping and engineering have resulted in high ROR, high-rate completions 1 Acreage figures rounded as of 9/30/12 2 Well counts as of 10/31/12 Stacked, liquids-rich porosity trends extend across Laredo’s acreage 18

2012 Guidance Annual production >11.2 MMBOE Capital expenditures of approximately $900 million (excluding acquisitions) Q4-2012 Guidance Price Realizations (pre-hedge, two-stream basis, % of NYMEX): Crude oil 90% - 94% Natural gas, including natural gas liquids 140% - 150% Operating Costs & Expenses Lease operating expenses ($/BOE) $5.50 - $6.00 Production taxes (% of oil and natural gas revenues) 7.5% General and administrative expenses ($/BOE) $5.75 - $6.25 Depreciation, depletion and amortization ($/BOE) $22.00 - $23.00 19

Focused Capital Program $900 MM Capital 1 Budget - 2012 $813 MM Drilling Budget - 2012 $702 MM Permian Basin $89 MM Granite Wash $22 MM Other $813 MM Drilling $52 MM Land & Seismic $14 MM Pipeline $21 MM Other Drilling Capital Plan Summary Currently 14 operated rigs Permian 4 horizontal 6 vertical Anadarko Granite Wash 3 horizontal New Ventures 1 horizontal Exit 2012 with approximately the same operated rig count 1 The mix of Laredo’s planned capital deployment (rig count, area and horizontal and vertical well type) is driven by continuously emerging data and is subject to change, excludes acquisitions. Approximately 86% of 2012 drilling capital directed to Hz Wolfcamp, Hz Cline and vertical Wolfberry shales 20

Strong Financial & Liquidity Profile 21 Liquidity position of >$750 Million No near-term debt maturities: 2016 (Revolver) 2019 (9.5% Notes) 2022 (7.375% Notes) Borrowing base increased to $825 MM (Effective 11/7/12) e Borrowings of $135 MM drawn as of 11/13/12 Debt Ratings (Moody’s / S&P): Corporate = B1 / B+ Notes = B3 / B- 1 Borrowing base increased from $785 MM to $825 MM effective 11/7/2012 2 Current borrowings of $135 MM as of 11/13/2012 3 First nine months of 2012 adjusted EBITDA annualized, see appendix for a reconciliation 4 Proved reserves per Ryder Scott evaluation at 12/31/11, at SEC pricing Cash and marketable securities $29 Current Borrowing Base 1 785 Borrowings 2 (50) Liquidity 764 Long Term Debt $50 9.5% Senior Notes due 2019 552 7.375% Senior Notes due 2022 500 Total Long Term Debt 1,102 Stockholders' Equity 817 Total Book Capitalization $1,919 Financial Debt Ratios Total Debt Debt / Adj. EBITDA 3 2.4x Debt / Proved Reserves ($/Boe) 4 $7.04 Debt / Total Book Capitalization 57% Liquidity and Capitalization ($ millions) 9/30/2012 Senior Revolving Credit Facility due 2016 2

Ability to Continue Consistent Growth 22 Funding flexibility for 2012 and beyond Rapidly growing cash flow from operations Revolver expected to continue to grow Proven ability to access multiple capital market sources Flexible capital program 2012 capital program focused on liquids-rich plays Drilling program provides high economic returns Annualized Historical Annual YTD Q3-2012 Annualized Q3-2012

Hedging: Protect and Stabilize Cash Flows Oil Positions As of September 30, 2012 1 Oil derivatives are settled based on the month's average daily NYMEX price of WTI Light Sweet Crude Oil. 23 Current Hedge Position Q4 2012 2013 2014 2015 Total OIL (1) Puts: Hedged Volume (Bbls) 168,000 1,080,000 540,000 456,000 2,244,000 Average price ($/Bbl) 65.79 $ 65.00 $ 75.00 $ 75.00 $ 69.50 $ Swaps: Hedged Volume (Bbls) 183,000 600,000 - - 783,000 Average price ($/Bbl) 93.52 $ 96.32 $ - $ - $ 95.67 $ Collars: Hedged Volume (Bbls) 301,500 768,000 726,000 252,000 2,047,500 Average floor price ($/Bbl) 79.50 $ 79.38 $ 75.45 $ 75.00 $ 77.47 $ Average ceiling price ($/Bbl) 118.09 $ 121.67 $ 129.09 $ 135.00 $ 125.41 $ Total Volume with a floor 652,500 2,448,000 1,266,000 708,000 5,074,500 Weighted average floor price 79.90 $ 77.19 $ 75.26 $ 75.00 $ 76.75 $

Hedging: Protect and Stabilize Cash Flows Natural Gas Positions As of September 30, 2012 1 Natural gas derivatives are settled based on NYMEX gas futures, the Northern Natural Gas Co. demarcation price or the Panhandle Eastern Pipe Line spot price of natural gas for the calculation period. the basis swap derivatives are settled based on the differential between the NYMEX gas futures and the West Texas WAHA index gas price. 2 $/Mcf is converted based upon Company average BTU content of 1.2124; prices include basis swaps 24

Appendix

Permian Basin: Identified Potential Drilling Locations 1 PUD Locations as identified in third-party reserve report prepared by Ryder Scott for 12/31/11 2 IPD Locations are recognized based on a combination of available geological, production and engineering data 3 Booked % represents PUD Locations as a proportion of Total IPD Locations 4 Vertical wells assume 40-acre spacing 5 Horizontal wells assume 160-acre spacing and 4,000-foot laterals 27

Anadarko Granite Wash: Identified Potential Drilling Locations 1 PUD Locations as identified in third-party reserve report prepared by Ryder Scott for 12/31/11 2 IPD Locations are recognized based on a combination of available geological, production and engineering data 3 Booked % represents PUD Locations as a proportion of Total IPD Locations 4 Locations assume 40-acre spacing for the Granite Wash Vertical Program 5 The majority of the technically identified horizontal locations have two or less wells/zone/section and assumes 4,000-foot laterals 28

Historical Financial & Operating Data $ millions, except per unit data 1 Prices include realized hedge revenue 2 See following slide for a reconciliation of adjusted EBITDA 29

Adjusted EBITDA Reconciliation ($ thousands, unaudited) 30 2010 2011 Q1 2012 Q2 2012 Q3 2012 Net income (loss) 86,248 105,554 26,235 30,975 (7,384) Plus: Interest expense 18,482 50,580 14,684 21,674 24,423 Depreciation, depletion & amortization 97,411 176,366 51,523 60,697 63,925 Impairment of long-lived assets – 243 – – – Write-off of deferred loan costs – 6,195 – – – Loss on disposal of assets 30 40 – 8 1 Unrealized losses (gains) on derivative financial instruments 11,648 (20,890) 3,334 (20,263) 31,150 Realized losses on interest rate derivatives 5,238 4,873 1,103 835 84 Non-cash equity-based compensation 1,257 6,111 2,247 2,588 2,767 Income tax expense (benefit) (25,812) 59,374 14,757 17,424 (4,154) Adjusted EBITDA $194,502 $388,446 $113,883 $113,938 $110,812

NYSE: LPI www.laredopetro.com

Vital Energy (VTLE) 8-KRegulation FD Disclosure