Economics : Rates of Return/ IRR

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Top-Tier Assets Regional Well Projected Economics 2017 capital program focusing on areas with top tier returns RockStar Wolfcamp A Sweetie Peck Lower Spraberry 120% 120% 100% 100% 80% 80% IRR 60% 60% IRR 40% 40% 20% 20% 0% 0% 40 45 50 55 60 40 45 50 55 60 NYMEX WTI NYMEX WTI 7,600' 10,000' 7,600' 10,000' Well Cost: 5.6MM Well Cost: 6.8MM Well Cost: 5.9MM Well Cost: 7.0MM Well Spacing: 660 Well Spacing: 660 Well Spacing: 660 Well Spacing: 660 Sand loading: 1,900 lbs/ft; Stage Spacing: 167 Sand loading: 1,900 lbs/ft; Stage Spacing: 167 Eagle Ford East 100% 80% Eagle Ford East 1Q17 Average 60% Mt. Belvieu (/Gal) IRR 35% NGLs 40% 20% 0% 0.60 0.65 0.70 Mt. Belvieu /Gal Well Cost: 5.2MM, Lateral Length: 8,000, Well Spacing: 625, Sand Loading: 2,000 lbs/ft, Stage Spacing: 150 Note: well costs include drill, complete, and equip; sensitivities at 3.00/MMBtu NYMEX; Eagle Ford East oil flat at 50/Bbl WTI 13
SM Energy Company
June 2017

Eagle Ford Shale Well Economics Summary Type Curve Core Tier 1 700 210 Total Well Cost 4.0 MM 4.2 MM 650 195 600 180 Frac Stages 31.6 32.1 550 165 Lateral Length 6,300 ft. 6,400 ft. 500 150 Percent of Inventory 84% 16% 450 135 Daily Average Oil, BOPD Cumulative Oil, MBO Gross 553 Mboe 403 Mboe 400 120 EUR Oil Only 423 Mbo 233 Mbo 350 105 Net 419 Mboe 320 Mboe 300 90 F&D Cost 9.55 / Boe 13.13 / Boe 250 75 200 60 IRR 250% 96% 75 Oil 150 45 NPV 9.2 MM 3.7 MM 100 30 IRR 150% 56% 65 Oil 50 15 IRR NPV 7.1 MM 2.5 MM & 0 0 IRR 116% 28% 0 2 4 6 8 10 12 14 16 18 20 22 24 NPV (1) 55 Oil NPV 5.1 MM 1.2 MM Producing Months IRR 58% 10% Daily Production, BOPD Cum Production, MBO 45 Oil NPV 3.0 MM NYMEX NPV10 Breakeven 30.50 45.00 (1) Economics based on NYMEX prices and include 2.50/Bbl deduct for oil, 3.00/Mcf NYMEX gas price, NGL pricing 29% of NYMEX oil price. (2) Total well cost includes 200K for allocated infrastructure. 12 CRZO
Carrizo Oil & Gas Inc.
May 2017

Compelling Rationale for Transformative Acquisition Largely undeveloped acreage contiguous to the existing Eagle Ford position 111,000 net acres in the Eagle Ford Increases total Eagle Ford acres by 40% Adds Significant Scale Direct bolt-on helps mitigate planning issues around partially owned units Pro forma total WRD daily production of approximately 25.2 MBoe/d (1) Single-well IRRs consistent with existing Gen 3 Eagle Ford wells High Quality Eagle 711 net locations in the Eagle Ford 91 Boe/ft type curve area with attractive single-well IRRs of 55%(2) Ford Inventory Average 8/8ths NRI of 80% Current Gen 3 wells outperforming the Eagle Ford type curve by 11% Expect to allocate a portion of our 2017 development program to higher working interest wells in and around the acquired acreage Solid PDP base with acquired 4Q16 production of 7.6 MBoe/d (89% liquids) Liquidity Enhancing Financing structure supports liquidity and ability to fund development plan; expected pro forma liquidity after giving and Credit Neutral effect to the acquisition but not any borrowing base increase of 620mm Net debt / Annualized EBITDAX(3) remains approximately 1.9x pro forma for the acquisition 62% of remaining 2017E pro forma production hedged at attractive prices (4) Pipeline infrastructure in place Midstream Takeaway capacity leads to low differentials Infrastructure in Place Competitive advantage on water cost Second landing target in the Eagle Ford with potential downspacing opportunities adds significant upside Additional Upside Additional upside potential in other horizons: Austin Chalk, Georgetown, Buda, Pecan Gap and Woodbine Refrac potential on initial understimulated Eagle Ford wells with an average of 1,100 lbs / ft gel fracs 1. WRD status quo Q1 2017 reported production; announced acquisition adjustment based on Q4 2016 production. 2. WRD location count for acquisition based on 500 spacing and includes only net locations located in the 91 Boe/ft type curve area. See slide 14 for assumptions embedded in Eagle Ford IRR calculation. IRR based on Consensus Pricing as of 4/26/2017: 54.00 / 3.15 for 2017, 60.00 / 3.11 for 2018, 61.00 / 3.09 for 2019, 66.50 / 3.25 for 2020, 70.00 / 3.45 for 2021 and thereafter for WTI and Henry Hub, respectively. 3 3. 4. See Net Debt and EBITDAX reconciliations on page 23 and 25. WRD status quo Q1 2017 reported EBITDAX; announced acquisition adjustment based on Q4 2016 EBITDAX. Based on midpoint of updated FY 2017 guidance.
WildHorse Resource Development Corp.
May 2017

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