DUG East Tim Dugan Chief Operating Officer, CONSOL Energy

Transcription

1 DUG East 2016 Tim Dugan Chief Operating Officer, CONSOL Energy

2 Cautionary Language This presentation contains statements, estimates and projections which are forward-looking statements (as defined in Section 21E of the Securities Exchange Act of 1934, as amended). Statements that are not historical, are forward-looking, and include our operational and strategic plans; estimates of coal and gas reserves and resources; the projected timing and rates of return of future investments; and projections and estimates of future production, revenues, income and capital spending. These forward-looking statements involve risks and uncertainties that could cause actual results to differ materially from those statements, plans, estimates and projections. Accordingly, investors should not place undue reliance on forward-looking statements as a prediction of future actual results. Factors that could cause future actual results to differ materially from the forward-looking statements include risks, contingencies and uncertainties that relate to, among other matters, the following: we may not receive the prices we expect to receive for our natural gas and coal; we may not obtain on a timely basis the permits required for drilling and mining; we may not accurately estimate our economically recoverable gas, oil and condensate; we may encounter unexpected operational issues when we drill and mine, including equipment failures, geological conditions and higher than expected costs for equipment, supplies, services and labor; we may not achieve the efficiencies we expect to realize in our drilling and completion operations, and as a result, our projected cost savings may not be fully realized; our joint venture partners, who operate assets in which we have a significant interest, may not perform as we expect; we may not be able to sell non-core assets on acceptable terms; we may be unable to incur indebtedness on reasonable terms; with respect to the sale of the Buchanan and Amonate mines and other coal assets to Coronado IV LLC - disruption to our business, including customer, employee and supplier relationships resulting from this transaction, and the impact of the transaction on our future operating results; and other factors, many of which are beyond our control. Additional factors are described in detail under the captions "Forward Looking Statements" and "Risk Factors" in CONSOL Energy Inc. s annual report on Form 10-K for the year ended December 31, 2015 filed with the Securities and Exchange Commission (SEC), as updated by any subsequent quarterly reports on Form 10-Qs. The forward-looking statements in this presentation speak only as of the date of this presentation; we disclaim any obligation to update the statements, and we caution you not to rely on them unduly. The SEC permits oil and gas companies, in their filings with the SEC, to disclose only proved, probable and possible oil and gas reserves that a company anticipates as of a given date to be economically and legally producible and deliverable by application of development projects to known accumulations. We may use certain terms in this presentation, such as EUR (estimated ultimate recovery), unproved reserves and total resource potential, that the SEC's rules strictly prohibit us from including in filings with the SEC. We caution you that the SEC views such estimates as inherently unreliable and these estimates may be misleading to investors unless the investor is an expert in the natural gas industry. These measures are by their nature more speculative than estimates of reserves prepared in accordance with SEC definitions and guidelines and accordingly are less certain. We also note that the SEC strictly prohibits us from aggregating proved, probable and possible reserves in filings with the SEC due to the different levels of certainty associated with each reserve category. Except for proved reserve data, the information included in this presentation is based on a summary review of the title to the gas rights we hold. As is customary in the gas industry, prior to the commencement of gas drilling operations on our properties, we conduct a thorough title examination and perform curative work with respect to significant defects. We are typically responsible for curing any title defects at our expense. As a result of our title review or otherwise, we may be required to acquire property rights from third parties at our expense in order to effectively drill and produce the oil and gas rights we control and third parties may participate in the wells we drill, thereby reducing our working interest in those wells. This presentation does not constitute an offer to sell or a solicitation of offers to buy securities of CONSOL Energy Inc. or CNX Coal Resources LP. 2

3 The CONSOL Energy Evolution Transformative Journey Into a Pure-Play E&P Company Late 2013 transaction with Murray Energy Corp. that transitioned half of coal assets and related assets April 19, 2014 CONSOL Energy 150th Anniversary June 12, 2014 Analyst Day to roll out growing Appalachian E&P Division with best-in-class coal assets September 25, 2014 IPO of CONE Midstream Partners LP (NYSE: CNNX) July 1, 2015 IPO of CNX Coal Resources (NYSE: CNXC) July 28, 2015 Announced first PA Dry Utica well (Gaut 4I) result in Westmoreland County March 31, 2016 Sold Buchanan Mine and associated met coal reserves Coal-E&P Revenue Split, 2012 E&P Revenues Coal Revenues Coal-E&P Revenue Split, 2014 E&P Revenues Coal Revenues Coal-E&P Revenue Split, 2015, excl. Buchanan E&P Revenues Coal Revenues Transforming this 152-year-old coal company into a powerful E&P company 3

4 Bcfe E&P Operations: Radical Rate of Change Beginning to outperform peers on growth and unit cost performance Production by Area 128 E&P Production Volumes 2015A 2016E Marcellus 51% 54% CBM 23% 19% Utica (Wet & Dry) 17% 21% Other 9% 6% E ~15% Focused on reaching critical mass with the ability to be a standalone company 15 th largest producer of natural gas, according to the Natural Gas Supply Association Currently producing over 1 Bcfe of net production as of Q Marcellus CBM Utica Other Source: Company filings. Note: Acquired ~23 Bcfe of Conventional gas production from Dominion E&P in Divested ~11 Bcfe in $4.00 $3.50 $3.00 $2.50 $2.00 $1.50 $1.00 $0.50 $0.00 $1.17 $0.84 $0.59 $0.17 $1.10 $0.23 Full-cycle Breakeven Operating Metrics $1.11 $0.17 $1.02 $0.38 $0.82 $0.37 $0.09 $1.04 $0.48 $0.29 $0.07 $1.00 $0.24 $ E Cash OpEx (plus G&A) of $1.52/Mcfe, plus PUD-to-PDP CapEx of $0.48/Mcfe, equals total full cycle cash costs of $2.00/Mcfe Rate of change in reducing operating expenses has been substantial ~20% CAGR reduction in OPEX from ; expected to further decline in 2016 Approximately 2/3 rds the production from Appalachian peers, while driving costs lower SG&A Direct Admin Gathering & Transport. Production Taxes Lifting PUD F&D $/MCFE Exceeded cost reduction target of 15% in 2015 with a 19% reduction and projecting an additional 13% reduction for

5 Utica Success ~622,000 CONSOL net acres (1) Over 3,500 gross locations 97 wells online, as of 3/31/ wells TIL in Q ,574 ft average TIL laterals in Q wells per pad 180-acre spacing (1,100 ft. inter-lateral spacing) assuming 7,000 ft lateral EURs: Ohio Wet: 2.3 Bcfe EUR/1,000 ft of lateral Ohio Dry: 2.8 Bcfe EUR/1,000 ft of lateral PA/WV Dry: 3.0 Bcfe EUR/1,000 ft of lateral Note: Townships are shown in yellow and purple (acres owned in fee) where CONSOL holds 3,000 or more acres (as of 12/31/2015). Gross locations are as of 12/31/2015. (1) Comprised of ~119,000 net acres in Ohio Utica (~79,000 in the JV and ~40,000 non-jv) and ~306,000 and ~197,000 net prospective acres in PA and WV respectively. 5

6 Model Centric Approach 3D Unconventional Reservoir / Frac Model Earth Model Performance Forecasting Performance Dashboards Advanced Planning Tool Shortens decision timeline and reduces the number of wells to optimization 6

7 1 Gaut-4I MND-6H GH-9 Switz 6H Switz 6F 5 6 Switz 6D Switz 6B Normalized A k Utica Success Normalized Well-to-Well Productivity Comparison A k: Additional benchmark metric, which in a way, replaces initial production, or IP, testing, by normalizing: 46 Lateral length Stage spacing 37 Pressure management A represents the area in square feet of the contributing hydraulic fracture we create k is the permeability or the ability of the reservoir-hydraulic fracture system to flow gas wells in current Earth Model 28 with production data * Well CONSOL has 5 out of the top 10 wells on list * Non-Operated well. 7

8 Lessons Learned: Proppant Testing Dry Utica: Monroe County, Ohio Switz 6D well: Lateral length: 9,859' Proppant: 100-mesh 40/70 Ceramic 30/50 Ceramic Switz 6F well: Lateral length: 10,122 Proppant: 100-mesh 40/70 Curable Resin 30/50 Curable Resin Switz 6H well: Lateral length: 9,157 Proppant: 40/70 White Sand 30/50 White Sand 30/50 Curable Resin In Monroe County, Ohio, recently increased average EURs per 1,000 ft of lateral increase from 2.4 Bcfe to 2.8 Bcfe 100% working interest (WI) The Switz 6 pad produced ~5.7 Bcf through March 31, 2016 while average flowing casing pressure remains strong at approximately 5,000 psi TVD depth is ~10,500 Maintained consistent stage spacing and # proppant / ft on all wells Proppant selection drives a large part of a well AFE and performance it is imperative to get the right balance 8

9 3.0 BCF/1000' NRI (%) Land Economic Uplift $2.00 Realized Gas Price CAPEX ($MM) $10.0 $12.5 $15.0 $17.5 $ % 38% 21% 15% 10% 8% 95% 29% 18% 13% 9% 7% 90% 25% 15% 10% 8% 5% 85% 20% 13% 9% 6% 4% 80% 17% 10% 7% 5% 4% CONSOL benefits from high NRI acreage position ~70,000 Utica fee acres Expect to reduce dry Utica D&C costs to under $15 million over the next 2-3 wells GH9 NRI is ~96% The 10% increase in NRI due to fee acreage yields ~5% increase in IRR% 9

10 Volume Type Curve Economic Uplift Model centric approach accelerates optimization of: Completion # proppant / foot, spacing Optimal design is determined by reservoir characteristics Time Before After Production Protocol Managing pressure has proven to positively impact production in dry Utica wells and should have a similar positive impact after reaching line pressure Uplift from optimization will result in over 30% in IRR% 10

11 Average Days/Well Feet / Day Operational Efficiencies Economic Uplift Completions Cycle Time Efficiency Gains , , ,500 1,000 Stimulation Efficiency Drillout Efficiency Flowback Efficiency Note: Average days per well is normalized and unit costs are for typical stage and job size. Lowering costs by managing vendors through KPIs who share CONSOL s core values Note: Efficiency gains are normalized and Utica cost includes all PA and OH wells Technology and experience: broad base of experience and the right application of technology Operating efficiencies add an additional 6% of IRR% uplift 11

12 Midstream Economic Uplift Access to Dry Marcellus gathering systems help both E&P and midstream service providers lower cost and maximize the value of existing assets Diversified Marcellus operators have an advantage Dry Utica offers additional blending capacity for damp Marcellus production, further optimizing the stacked play High reservoir pressures allows deferment of compression Current gathering rates for Dry Utica is half that of legacy Marcellus 5% IRR increase for incremental versus greenfield system build out 12

13 Conclusions: Game Changer ATAX IRR (%) 70% 60% 50% Expected CPA Dry Utica Economic Progression 5% 61%+ 6% 30%+ 40% 30% 20% 10% 0% 15% Industry Average ATAX IRR 5% Land Type Curve Efficiencies Midstream Total Expected Uplift The Dry Utica significantly changes our opportunity set 13

14 DUG East 2016 Tim Dugan Chief Operating Officer, CONSOL Energy