JOHNSON RICE 2015 ENERGY CONFERENCE. Carrizo Oil & Gas, Inc. September 28-30, 2015

Transcription

1 JOHNSON RICE 2015 ENERGY CONFERENCE Carrizo Oil & Gas, Inc. September 28-30, 2015

2 Forward Looking Statements / Note Regarding Reserves This presentation contain statements concerning the Company s intentions, expectations, projections, assessments of risk, estimations, plans or predictions for the future, beliefs, objectives, goals, strategies, future events or performance and underlying assumptions and other statements that are not historical facts. These statements are forward-looking statements within the meaning of the Private Securities Litigation Reform Act of The forward-looking statements in this presentation include, but are not limited to, statements relating to the Company s business and financial outlook, cost and risk profile of oil and gas exploration and development activities, quality and risk profile of Company s assets, liquidity and the ability to finance exploration and development activities, including accessibility of borrowings under the Company s revolving credit facility, hedging activities, growth strategies, ability to explore for and develop oil and gas resources successfully and economically, estimates and forecasts of the timing, number and results of wells we expect to drill and other exploration activities, drilling inventory, downspacing, estimates regarding timing and levels of production or reserves, estimated ultimate recovery, the Company s capital expenditure plan and allocation by area, cost reductions and savings, efficiency of capital, changes in oil and gas prices, the price of oil and gas at which projects break-even, future market conditions in the oil and gas industry, ability to make, integrate and develop acquisitions, midstream arrangements and agreements, gas marketing strategy, lease terms, expected working or net revenue interests, the ability to adhere to our drilling schedule, acquisition of acreage and 3-D seismic data, including number, timing and size of projects, planned evaluation of prospects, probability of prospects having oil and gas, acreage, working capital requirements, liquids weighting, rates of return, net present value, exploration and development plans, any other statements regarding future operations, financial results, business plans and cash needs and all other statements that are not historical facts. Statements in this presentation regarding availability under our revolving credit facility are based solely on the current elected borrowing base commitment amount and amounts outstanding on such date. The amounts we are able to borrow under the revolving credit facility are subject to, and may be less due to, compliance with financial covenants and other provisions of the credit agreement governing our revolving credit facility. You generally can identify forward-looking statements by the words anticipate, believe, budgeted, continue, could, estimate, expect, forecast, goal, intend, may, objective, plan, potential, predict, projection, scheduled, should, or other similar words. Such statements are inherently subject to risks and uncertainties, including, but not limited to, those relating to the worldwide economic downturn, adverse market conditions and assessments, availability of financing, the Company s dependence on its exploratory drilling activities, the volatility of and changes in oil and gas prices, the need to replace reserves depleted by production, operating risks of oil and gas operations, the Company s dependence on key personnel, factors that affect the Company s ability to manage its growth and achieve its business strategy, results, delays and uncertainties that may be encountered in drilling, development or production, interpretations and impact of oil and gas reserve estimation and disclosure requirements, activities and approvals of our partners and parties with whom we have alliances, technological changes, capital requirements, timing and amount of borrowing base determinations (including determinations by lenders) and availability under our revolving credit facility, evaluations of us by lenders under our revolving credit facility, the potential impact of government regulations, including current and proposed legislation and regulations related to hydraulic fracturing, oil and gas drilling, air emissions and climate change, regulatory determinations, litigation, competition, the uncertainty of reserve information and future net revenue estimates, acquisition risks, availability of equipment and crews, actions by our midstream and other industry partners, weather, actions by lenders, our ability to obtain permits and licenses, the results of audits and assessments, the failure to obtain certain bank and lease consents, the existence and resolution of title defects, new taxes and impact fees, risks associated with the trend towards increased anti-development activity, delays, costs and difficulties relating to our joint ventures, actions by joint venture partners, results of exploration activities, the availability and completion of land acquisitions, completion and connection of wells, and other factors detailed in the Risk Factors and other sections of the Company s Annual Report on Form 10-K for the year ended December 31, 2014 and other filings with the Securities and Exchange Commission ( SEC ). Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual outcomes may vary materially from those indicated. Each forward-looking statement speaks only as of the date of the particular statement or, if not stated, the date printed on the cover of the presentation. When used in this presentation, the word current and similar expressions refer to the date printed on the cover of the presentation. Each Forward-looking statement is expressly qualified by this cautionary statement and the Company undertakes no obligation to update or revise any forward-looking statement, whether as a result of new information, future events or otherwise. All subsequent written and oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by reference to these risks and uncertainties. You should not place undue reliance on forward-looking statements. The information contained in this presentation does not purport to be allinclusive or to contain all information that potential investors may require. We use certain terms in this presentation such as Potential, Potential Reserves, Potential Exposure, Estimated Resource, Unrisked Exploration Potential and Unrisked Reserve Potential, Recoverable and similar terms that the SEC s guidelines strictly prohibit us from including in filings with the SEC. Our Probable (2P) and Possible (3P) reserves do not meet SEC rules and guidelines (including those relating to pricing) for such reserves. These terms include reserves with substantially less certainty, and no discount or other adjustment is included in the presentation of such reserve numbers. U.S. investors are urged to consider closely the disclosure in our Form 10-K for the year ended December 31, 2014, File No , and in our other filings with the SEC, available from us at 500 Dallas, Suite 2300, Houston, Texas, These forms can also be obtained from the SEC by calling SEC This presentation includes non-gaap financial measures as that term is defined in Regulation G. The most directly comparable GAAP financial measures and information reconciling these non-gaap financial measures to the Company s financial results prepared in accordance with GAAP are included at the end of this presentation. 2

3 Carrizo Today Positioned for a Low Commodity Price Environment Acreage focused on high-quality, low-cost oil and condensate resource plays Eagle Ford Shale, Delaware Basin, Utica Shale, and Niobrara Formation Solid financial position / liquidity Net Debt-to-EBITDA of ~2.6x at end of Q2 Significant liquidity available under the revolver No near-term debt maturities Well-hedged in 2015 Significant operational flexibility Leasehold obligations can be easily managed Ability to quickly ramp production growth back up as prices recover Large resource potential >495 MMBoe of probable reserves, equivalent to ~3.2x proved reserves (1) >55% of undrilled locations are economic (IRR > 10%) below $45/Bbl Strong technical team Management team has drilled >700 horizontal wells EURs consistently rank among the best in our core areas Highly efficient drilling and completion operations (1) Based on internal estimate of reserves as of 6/30/15. 3

4 Portfolio of Assets Niobrara Formation 35,600 net acres 6.0 MMBOE Proved Utica Shale 28,900 net acres 1.8 MMBOE Proved Marcellus Shale 32,400 net acres 20.1 MMBOE Proved Delaware Basin 26,000 net acres Eagle Ford Shale 84,000 net acres MMBOE Proved 6/30/15 Proved NPV10 ($MM) Eagle Ford 2,158 Niobrara 102 Utica 39 Marcellus 73 Total 2,372 4 Notes: Based on 6/30/15 internal reserves and SEC pricing ($71.68/Bbl and $3.39/Mcf).

5 Carrizo Acreage is Concentrated in Low-Cost Basins $120 Estimated Break-Even WTI ($/Boe; 22.5:1 Oil / Gas Ratio) $100 $80 $60 $40 $20 $0 SCOOP Eagle Ford Delaware Wolfcamp Hz NW Shelf Hz Carrizo s Eagle Ford Weighted Average Break-Even Cost is <$40/bbl (1) Midland Vt Bone Spring Hz Midland Wolfcamp Hz Marcellus Bakken DJ Basin CBP Hz CBP Vt San Joaquin San Juan Basin - Gallup Miss Lime Cleveland Fayetteville Uinta Vt Cotton Valley Hz Piceance NW Shelf Vt Cana Woodford Haynesville Pinedale Eaglebine Utica Marmaton Powder River Arkoma Woodford Uinta Hz Jonah Barnett Granite Wash TMS Freestone Trend Barnett Combo Gulf Coast 5 Source: ITG Investment Research. (1) Based on internal estimates.

6 6 Highlights of 2015 Plan Manage capex to preserve balance sheet and liquidity Financial leverage is below peer average and significant liquidity is available on the borrowing base Manage leasehold obligations to preserve assets Eagle Ford acreage can be held with <1 rig; minimal leasehold obligations in Utica and Niobrara Hold full-year average oil production roughly flat with 4Q 2014 Production guidance has been increased twice due primarily to strong well performance and operational efficiencies and now yields growth vs. 4Q 2014 Drive cost reductions and efficiencies throughout operations Eagle Ford wells costs are down >35% vs. late 2014 Test Delaware Basin acreage Currently fracking first operated well Take advantage of opportunities to expand core positions Acreage has been bolted-on in all core plays since the beginning of the year

7 2015 Capital Program (All figures in $MM) Est. Eagle Ford Utica Niobrara Delaware Basin 1 35 Marcellus/Other Land & Seismic Total Capital Continued focus on oily plays Results in growth vs. Q Manages leasehold obligations Flexibility to adjust should commodity prices improve or worsen Service costs have may have additional downside at current commodity price levels $375 Eagle Ford Land & Seismic Detail 7 Eagle Ford 17 Utica 4 Niobrara 14 Other Land 10 Seismic - $45 $10 Marcellus/ Other Delaware Basin Note: 2015 D&C capital estimates represent the midpoint of guidance range. $35 $35 Niobrara $25 Utica

8 Downshifting Production Growth in 2015 Oil plays have driven growth in recent years Targeting crude oil production growth of 19% Y-o-Y in 2015 Net Daily Prod, (MBoepd) Positioned to reaccelerate production growth as commodity prices recover Net Daily Prod, (MBoepd) Eagle Ford Niobrara Utica Marcellus Barnett Other % of Total 26% 10% 64% - Oil NGL Gas Note: 2015 production represents the midpoint of guidance. 8

9 Financial Leverage is Below Peer Average Net Debt / LTM EBITDA 7.0x 6.0x 5.0x Adjusted Net Debt / LTM EBITDA 4.0x 3.0x 2.0x 1.0x 0.0x 9 Note: EBITDA computed in accordance with debt covenants and therefore debt is net of cash and excludes debt premium/discount; LTM EBITDA excludes/includes LTM EBITDA of assets sold/acquired. Note: Net debt is Q2 15 adjusted for Q3 15 capital market transactions and M&A. Peer companies include BCEI, EPE, FANG, GPOR, LPI, MTDR, OAS, PDCE, PE, PVA, REXX, RSPP, SN, WLL. Source: Bloomberg, Company reports.

10 Sustainable Growth Project Development Summary (1) Net Acres Drillable Net Acres Net Proved Developed Wells Net Proved Undeveloped Wells Additional Net Probable Wells Total Net Undrilled Wells Undrilled Well Details (PUD & Probable) Effective Lateral Length (Ft.) Frac Stages Spacing Between Laterals (Ft.) Well Spacing (Acres/ well) Eagle Ford 84,000 78, , /500 45/70 Niobrara 35,600 32, , /450 40/60 Utica 28,900 23, , NE PA Marcellus 5,000 4, , , Total 153, , ,480 1,719 Reserves (MMboe) Undrilled NPV10 ($ Million) Undrilled Proved Developed Proved Undeveloped Probable Total Undrilled Total 2P Proved Developed Proved Undeveloped Probable Total Undrilled Eagle Ford ,034 1,124 2,490 3,614 4,648 Niobrara Utica NE PA Marcellus Total ,230 1,142 3,566 4,708 5,938 Total 2P (1) Based on 6/30/15 internal reserves and SEC pricing ($71.68/Bbl and $3.39/Mcf). NPV10 value excludes hedge gains. 10

11 Eagle Ford Shale The Premier Industry Asset 11 CHK EOG CHK EOG EOG MRO 84,000 net acres Acreage almost entirely in the volatile oil window 15+ year drilling inventory with all locations identified, planned, and de-risked Project To-Date 273 gross / 222 net wells drilled 33 gross / 29 net wells awaiting completion EPE 2015 Operated Activity 2-3 rig program Drill 69 gross / 62 net wells Frac 65 gross / 58 net wells Black Oil Volatile Oil Gas Producing Pads

12 Eagle Ford Shale Optimizing the Development Program 12 Performance of 330 ft. spaced wells looks very similar to wells drilled at wider spacing in each area tested LASALLE Plan to test further downspacing through stagger-stacks in the Lower Eagle Ford during 2015 Initial Upper Eagle Ford test expected to be on-line in 4Q 2015 Black Oil Volatile Oil Gas 330 Ft Spacing 500 Ft Spacing Testing a variety of completion enhancements including engineered completions, diversion techniques, increased proppant loading and advanced microseismic, and fiber optic monitoring 330 Ft Well 330 Ft Producer Stagger Stack 2H 2015 Upper EF Completion Optimization

13 Eagle Ford Shale Stagger Stack Potential to Materially Expand Inventory ft. 330 ft. 330 ft. 330 ft. 330 ft. Current development 330 ft. effective spacing ~1,090 total locations at full 330 ft. spacing 330 ft. 330 ft. 330 ft. 330 ft. Full stagger stack 165 ft. effective spacing ~80% increase to inventory 440 ft. 440 ft. 440 ft. Partial stagger stack 220 ft. effective spacing ~45% increase to inventory 540 ft. 540 ft. Partial stagger stack 270 ft. effective spacing ~20% increase to inventory

14 Eagle Ford Shale PV-10 Break-Even Oil Price by Project Area 25% $55 % Of Total EF Locations 20% 15% 10% 5% 4% 12% $ % 22% $35.75 $ % $ % $40.50 $ % $ % $50.50 $49.25 $48.50 % Of Total EF Locations PV-10 Break-Even Price 4% 3% 2% $ % $50 $45 $40 $35 PV-10 Break-Even Oil Price ($/Bbl) $ $30 >80% of locations have a WTI break-even cost of $41/Bbl or less 14

15 Eagle Ford Shale Well Economics Summary 15 Type Curve Total Well Cost $4.8 MM Frac Stages 25.5 Lateral Length 6,120 ft. Gross 510 Mboe EUR Oil Only 393 Mbo Net 380 Mboe F&D Cost $12.63 / Boe $75 NYMEX Oil IRR >100% NPV $6.6 MM Daily Average Oil, BOPD Cumulative Oil, MBO IRR & NPV (1) $65 NYMEX Oil $55 NYMEX Oil $45 NYMEX Oil NYMEX NPV10 Breakeven IRR 80% NPV $4.8 MM IRR 47% NPV $2.9 MM IRR 22% NPV $39.50 $1.0 MM Producing Months Daily Production, BOPD Cum Production, MBO (1) Economics include ~$1.80/Bbl deduct to NYMEX for oil; $3.00/Mcf NYMEX gas price; NGL pricing 29% NYMEX oil price.

16 Eagle Ford Shale High Returns Achievable at Low Oil Prices 140% 120% 100% 80% IRR 60% 40% 20% 0% $45 $55 $65 $75 $85 $95 NYMEX Oil Price ($/Bbl) 2014 Cost Level 10% Cost Reduction 20% Cost Reduction 30% Cost Reduction Current Cost Expectations 16

17 Delaware Basin Wolfcamp Shale Focus Area 17 ~26,000 net acres in Culberson and Reeves counties targeting the oil and condensate windows Initial development targeting Culberson/Reeves border Continuing to block up other acreage positions Recent industry results have been strong following changes in completion techniques Targeting Upper Wolfcamp A in areas with potential for Eagle Ford profitability Carrizo focus (Wolfcamp Shale A Bench) Potential for other stacked pay development Bone Springs Wolfcamp B Wolfcamp C Wolfcamp D / Cline

18 18 Delaware Basin Initial Development Area Culberson Reeves Cimarex Capitan BHP EOG 12,400 net acres located along Culberson/Reeves border either closed or expected to close Seek to create operated drilling units that support at least 7,500 ft. laterals Acreage located near strong industry wells, as indicated on the following page Fracking first operated well and drilling second operated well 2015 Operated Activity 1 rig program Drill 5 gross / 4 net wells Frac 3 gross / 3 net wells

19 Delaware Basin Nearby Industry Well Performance Culberson Horizontal Wolfcamp A Wells Chart Displays Oil Production For: 6 Cimarex Wolfcamp A Bench wells (3 are 2015 completions) 5 Capitan Wolfcamp A Bench wells 2 BHP wells (Horseshoe Springs) Cumulative Oil Production (Mbbls) EF TC 6,000 lateral Cimarex Capitan BHP Wells are normalized to 6,000 lateral EF type curve is shown for comparison Months since first production 19

20 Utica Shale High-Rate, Rich-Condensate Focus Area 20 28,900 net acres Wagler wells produced >470 Bbls/d of condensate per well on a restricted choke over initial 90 days; both wells currently producing into sales Evaluating potential for future well cost reductions Mostly year and HBP leases ~35% HBP Project To-Date 4 gross / 3 net wells drilled 16 gross / 12.8 additional wells drilled with spudder rig 6 pads built near midstream infrastructure 2015 Operated Activity Fracked 2 gross / 1.7 net wells Prepare for Southern Guernsey infrastructure build-out

21 Utica Shale Guernsey County Type Curve Economics Type Curve 3-String 2-String Total Well Cost $9.0 MM $8.2 MM EUR Gross Condensate Only Net 898 Mboe 451 Mbo 727 Mboe F&D Cost $12.38 / Boe $11.28 / Boe IRR & NPV (1) $75 NYMEX Oil $65 NYMEX Oil $55 NYMEX Oil NYMEX NPV10 Breakeven IRR 43% 54% NPV $5.7 MM $6.5 MM IRR 28% 35% NPV $3.5 MM $4.3 MM IRR 16% 21% NPV $1.3 MM $2.1 MM $49.00 $45.50 (1) Economics includes $7.50/Bbl deduct for condensate, 20% NYMEX oil for NGL mix assuming ethane rejection, and $3.00/Mcf NYMEX gas less $1.25/Mcf 21 21

22 22 Niobrara Formation Preserving Option Value Weld County 35,600 net acres Recently added >1,300 net acres in core of Area 1 position Have tested multiple benches and spacing configurations Participating in highdensity projects with Noble and Whiting to test A, B, and C benches Monitoring industry Codell activity Noble HBP Acreage Non-HBP Acreage Above oil-in-place cut-off Below oil-in-place cut-off Project To-Date 132 gross / 56 net wells drilled 17 gross / 9 net wells awaiting completion 2015 Operated Activity Drilled 13 gross / 5 net wells Fracked 3 gross / 2 net wells

23 23 Niobrara Formation PV-10 Break-Even Oil Price by Area 50% 45% 40% % Of Total Nio Locations PV-10 Break-Even Price 45% $100 $90 % Of Total Nio Locations 35% 30% 25% 20% 15% 10% 5% 29% $43.25 $ % $66.00 $80 $70 $60 $50 $40 PV-10 Break-Even Oil Price ($/Bbl) - $30 Niobrara weighted average break-even cost of $49/Bbl

24 Niobrara Formation Type Curve Economics 24 Total Well Cost Area 1 / 2A Type Curve $2.8 MM EUR F&D Cost Gross Oil Only Net 289 Mboe 217 Mbo 243 Mboe $11.52 / Boe IRR & NPV (1) $75 NYMEX Oil $65 NYMEX Oil $55 NYMEX Oil NYMEX NPV10 Breakeven IRR 75% NPV $2.9 MM IRR 46% NPV $1.9 MM IRR 25% NPV $0.9 MM $45.75 (1) $8/Bbl deduct to NYMEX oil; $3.00/Mcf NYMEX gas; NGL pricing 15% of NYMEX oil price. Daily Production, BOPD Cum Production, MBO

25 25 Summary Acreage position provides years of inventory with a best-in-class breakeven cost Solid financial position provides liquidity to weather a prolonged downturn Ample operational flexibility to reaccelerate or further decelerate quickly in response to commodity prices Top-tier operational team with significant experience in unconventional plays Positioned to capitalize on opportunities

26 Appendix

27 Guidance Summary Carrizo Production and Cost Guidance Trailing Four Quarter Actuals Q and FY 2015 Guidance ACTUAL GUIDANCE Q Q Q Q Q FY 2015 Production Volumes: Crude Oil (Bbls/d) 20,000 22,130 21,373 22,284 22,400-22,700 22,350-22,500 NGLs (Bbls/d) ,022 3,529 3,494 2,900-3,100 3,250-3,350 Natural Gas (Mcf/d) 63,630 75,283 58,159 62,042 47,000-51,000 54,000-56,000 Equivalent Production (Boe/d) 33,587 37,696 34,595 36,118 33,133-34,300 34,600-35,183 Unhedged Price Realizations: Crude Oil (% of NYMEX oil) 96.9% 94.6% 88.9% 94.6% 91.0% 93.0% N/A NGLs (% of NYMEX oil) 29.3% 26.5% 29.0% 20.6% 17.0% 22.0% N/A Natural Gas (% of NYMEX gas) 65.5% 63.9% 85.0% 54.5% 48.0% 55.0% N/A Realized Gain on Derivatives ($MM) ($7.7) $12.0 $49.1 $45.1 $ $44.0 N/A Production Costs: Lease Operating ($/Boe) $6.80 $6.68 $6.97 $7.11 $ $7.75 $ $7.50 Production Taxes (% of Oil & Gas Revenues) 4.28% 4.21% 4.02% 4.07% 4.25% % 4.25% % Ad Valorem Taxes ($MM) $2.2 $2.9 $3.0 $1.7 $2.2 - $2.7 $ $11.0 G&A Expense (Cash only, $MM) $10.5 $13.9 $18.5 $10.9 $ $12.5 $ $55.5 DD&A Expense ($/Boe) $27.05 $25.51 $23.73 $24.14 $ $24.50 $ $

28 28 Financial Position Revolving Credit Facility (due 2018) Facility revised May 5, 2015 $685 million borrowing base commitment with interest rate of LIBOR % % - $117.0 million drawn at June 30, 2015 Consortium of 19 banks led by Wells Fargo Restrictive covenant: Net Debt < 4.00x TTM EBITDA 7.50% Senior Unsecured Notes (due 2020) $600 million outstanding Callable on September 15, 2016 No liquidity or performance-based covenants 6.25% Senior Unsecured Notes (due 2023) $650 million outstanding Callable on April 15, 2018 No liquidity or performance-based covenants Corporate Credit Rating B1/B+

29 Hedge Position Period Type of Contract Daily Volume (Bbl/d) Floor Price Ceiling Price Short Put Price Basis Differential Cash From Restructuring ($MM) % of Q3 Oil Forecast 1 Q Total Volume 16,200 $ % Collars 16,200 $50.00 $67.34 Q Total Volume 16,200 $ % Collars 16,200 $50.00 $67.34 Q Total Volume 13,000 $ % Swaps 3,000 $60.00 Collars 10,000 $52.13 $72.60 Q Total Volume 7,000 $9.3 31% Swaps 3,000 $60.00 Collars 4,000 $50.00 $76.50 Q Total Volume 7,000 $9.3 31% Swaps 3,000 $60.00 Collars 4,000 $50.00 $76.50 Q Total Volume 7,000 $7.9 31% Swaps 3,000 $60.00 Collars 4,000 $50.00 $76.50 FY 2016 Total Volume 8,492 $44.8 Swaps 3,000 $60.00 Collars 5,492 $50.97 $74.73 Period Type of Contract Daily Volume (MMBtu/d) Floor Price Ceiling Price Short Put Price Basis Differential Cash From Restructuring ($MM) % of Q3 Gas Forecast 1 Q Total Volume 30,000 61% Swaps 30,000 $4.29 Q Total Volume 30,000 61% Swaps 30,000 $ (1) Q gas production guidance of 49.0 MMcf/d at midpoint, oil at 22,550 Bbl/d.

30 Eagle Ford Shale Operator Comparison 400 Eagle Ford March 2015 Average Production By Well Source: IHS - Total Volume Divided by Active Wells for Companies with More than 100 Active Wells BOPD MCFD TVD, Ft BOPD/Well Avg. TVD MCFD/Well 30

31 31 Eagle Ford Shale API Gravity Q Net Sales Revenue by Product Zavala Dimmit Frio LaSalle Atascosa McMullen 3% 4% 93% Oil Gas NGL Q Volumes by API Gravity 86% Webb Source: DrillingInfo initial completion reports. 13% 1% 35-45

32 Utica Shale Point Pleasant Condensate API Gravity 32 API gravities increase from NW to SE with increasing depth and thermal maturity Trend-wise, data are very consistent and over the length of a 10,000 wellbore gravities can change 2 O in API Brown Light crudes generally classified as <= 45 O API Condensates generally classified as > 45 O API Nearly all Carrizo s acreage is in the rich condensate window Rector gravity = 60 O API Brown gravity = 49 O API Rector API gravity trends are consistent with condensate gas ratios

33 Niobrara Formation Acreage Ranking 33 Identified several discreet areas within Niobrara project and evaluated development potential and economics separately Ranking criteria: Geologic / petrophysical quality Activity level Production results

34 Marcellus Shale NE Pennsylvania Baker Bonnice Giangrieco/Trecoske Ricci Frystak 5,000 net acres Productive capacity of ~80 MMcf/d net 95% of acreage HBP d on 1,000 spacing Focus on operational efficiencies and cost control Limit production when local gas prices are especially weak Williams Pipeline interconnects with Millennium and Tennessee pipelines Project To-Date 98 gross / 32 net wells drilled 11 gross / 4 net wells awaiting completion Susquehanna County Tennessee Pipeline Mazzara Sickler Wyoming County Plushanski Kile Yarasavage Solanick Penn Virginia pipeline with connection to Transco 34