DUG East 2016 Tim Dugan Chief Operating Officer, CONSOL Energy - - PowerPoint PPT Presentation
DUG East 2016 Tim Dugan Chief Operating Officer, CONSOL Energy - - PowerPoint PPT Presentation
DUG East 2016 Tim Dugan Chief Operating Officer, CONSOL Energy 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
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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
- n 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.
Coal-E&P Revenue Split, 2012
E&P Revenues Coal Revenues 3
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
Transforming this 152-year-old coal company into a powerful E&P company
Coal-E&P Revenue Split, 2014
E&P Revenues Coal Revenues
Coal-E&P Revenue Split, 2015, excl. Buchanan
E&P Revenues Coal Revenues
The CONSOL Energy Evolution
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Beginning to outperform peers on growth and unit cost performance
E&P Operations: Radical Rate of Change
128 154 156 172 236 329 ~15% 50 100 150 200 250 300 350 400 450 2010 2011 2012 2013 2014 2015 2016E Bcfe Marcellus CBM Utica Other
E&P Production Volumes
Source: Company filings. Note: Acquired ~23 Bcfe of Conventional gas production from Dominion E&P in 2010. Divested ~11 Bcfe in 2011. Production by Area 2015A 2016E Marcellus 51% 54% CBM 23% 19% Utica (Wet & Dry) 17% 21% Other 9% 6%
Focused on reaching “critical mass” with the ability to be a standalone company
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15th largest producer of natural gas, according to the Natural Gas Supply Association
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Currently producing over 1 Bcfe of net production as of Q4 2015
Rate of change in reducing operating expenses has been substantial
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~20% CAGR reduction in OPEX from 2013- 2016; expected to further decline in 2016
Approximately 2/3rds the production from Appalachian peers, while driving costs lower
$0.23 $0.38 $0.24 $0.16 $1.10 $1.02 $1.04 $1.00 $0.17 $0.17 $0.09 $0.07 $0.84 $0.59 $0.37 $0.29 $1.17 $1.11 $0.82 $0.48 $0.00 $0.50 $1.00 $1.50 $2.00 $2.50 $3.00 $3.50 $4.00 2013 2014 2015 2016E SG&A Direct Admin Gathering & Transport. Production Taxes Lifting PUD F&D $/MCFE
Cash OpEx (plus G&A)
- f $1.52/Mcfe, plus
PUD-to-PDP CapEx of $0.48/Mcfe, equals total full cycle cash costs of $2.00/Mcfe
Full-cycle Breakeven Operating Metrics
Exceeded cost reduction target of 15% in 2015 with a 19% reduction and projecting an additional 13% reduction for 2016
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Utica Success
- ~622,000 CONSOL net
acres(1)
- Over 3,500 gross
locations
─ 97 wells online, as of
3/31/2016
─ 10 wells TIL in Q1 2016 ─ 8,574 ft average TIL
laterals in Q1 2016
─ 4 – 6 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.
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Model Centric Approach
Shortens decision timeline and reduces the number of wells to optimization
Performance Dashboards Advanced Planning Tool Earth Model 3D Unconventional Reservoir / Frac Model Performance Forecasting
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Utica Success
CONSOL has 5 out of the top 10 wells on list
Normalized Well-to-Well Productivity Comparison
66 62 46 37 29 29 25 24 23 23 21 21 19 19 19 17 17 15 14 10 10 10 10 9 7 6 6 6 10 20 30 40 50 60 70 1 Gaut-4I MND-6H 2 3 4 GH-9 Switz 6H Switz 6F 5 6 Switz 6D 7 8 9 10 11 12 13 14 15 16 17 18 Switz 6B 19 20 21 Normalized 𝐁√𝐥 Well
𝐁√k: Additional benchmark metric, which in a way, replaces initial production, or IP, testing, by normalizing:
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Lateral length
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Stage spacing
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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
104 wells in current Earth Model – 28 with production data
*
* Non-Operated well.
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Lessons Learned: Proppant Testing
Switz 6D well:
- Lateral length: 9,859'
- Proppant:
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100-mesh
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40/70 Ceramic
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30/50 Ceramic Switz 6F well:
- Lateral length: 10,122’
- Proppant:
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100-mesh
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40/70 Curable Resin
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30/50 Curable Resin Switz 6H well:
- Lateral length: 9,157’
- Proppant:
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40/70 White Sand
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30/50 White Sand
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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
Dry Utica: Monroe County, Ohio
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Land Economic Uplift
CONSOL benefits from high NRI acreage position
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~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%
$10.0 $12.5 $15.0 $17.5 $20.0 100%
38% 21% 15% 10% 8%
95%
29% 18% 13% 9% 7%
90%
25% 15% 10% 8% 5%
85%
20% 13% 9% 6% 4%
80%
17% 10% 7% 5% 4%
CAPEX ($MM) $2.00 Realized Gas Price NRI (%)
3.0 BCF/1000'
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Type Curve Economic Uplift
Volume Time Before After
Model centric approach accelerates optimization of:
Completion
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# proppant / foot, spacing
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Optimal design is determined by reservoir characteristics
Production Protocol
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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%
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Note: Efficiency gains are normalized and Utica cost includes all PA and OH wells
Operational Efficiencies Economic Uplift
Completions Cycle Time
32 26 16 5 10 15 20 25 30 35 2014 2015 2016 Average Days/Well
Note: Average days per well is normalized and unit costs are for typical stage and job size.
Efficiency Gains
Lowering costs by managing vendors through KPIs who share CONSOL’s core values
500 1,000 1,500 2,000 2,500 2014 2015 2016 Feet / Day Stimulation Efficiency Drillout Efficiency Flowback Efficiency
Operating efficiencies add an additional 6% of IRR% uplift
Technology and experience: broad base of experience and the right application of technology
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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
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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
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Conclusions: Game Changer
15% 5% 30%+ 6% 5% 61%+ 0% 10% 20% 30% 40% 50% 60% 70% Industry Average ATAX IRR Land Type Curve Efficiencies Midstream Total Expected Uplift ATAX IRR (%)