National Fuel Gas Company · NYSE:NFG
National Fuel Gas — Q3 2017 Earnings Presentation
56 slides from National Fuel Gas's earnings presentation, Aug 3, 2017
Slide 1: Investor Presentation Q3 Fiscal 2017 Update
Investor Presentation Q3 Fiscal 2017 Update August 3, 2017 Exhibit 99
Slide 2: Safe Harbor For Forward Looking Statements
Safe Harbor For Forward Looking Statements This presentation may contain “forward-looking statements” as defined by the Private Securities Litigation Reform Act of 1995, including statements regarding future prospects, plans, objectives, goals, projections, estimates of oil and gas quantities, strat
Slide 3: NFG: A Diversified, Integrated Natural Gas Company
NFG: A Diversified, Integrated Natural Gas Company Providing significant base of stable, regulated earnings & cash flows 740,000 Utility customer accounts in NY & PA For the trailing twelve months ended June 30, 2017. A reconciliation of Adjusted EBITDA to Net Income as presented on the Consolidated
Slide 4: Adjusted EBITDA by Segment
Adjusted EBITDA by Segment ($ millions)(1) Balanced Earnings and Cash Flows A reconciliation of Adjusted EBITDA to Net Income as presented on the Consolidated Statement of Income and Earnings Reinvested in the Business is included at the end of this presentation.
Slide 5: Disciplined, Flexible Capital Allocation
Disciplined, Flexible Capital Allocation (2) A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation. FY 2016 actual capital expenditures reflects the netting of $157 million of up-front proceeds received from join
Slide 6: Near-term Growth Strategy
Near-term Growth Strategy Exploration & Production Strategy Midstream Strategy Corporate Strategy Grow Marcellus and Utica production at a 10%+ CAGR over next 3 years WDA Development (1-rig program) Return to developing 100% NRI Seneca wells post-JDA in FY18 Optimize Utica D&C designs and transition
Slide 7: Strong Balance Sheet & Liquidity
Strong Balance Sheet & Liquidity Total Debt 55% $3.7 Billion Total Capitalization as of June 30, 2017 Debt/Adjusted EBITDA Capitalization Debt Maturity Profile ($MM) Liquidity Committed Credit Facilities Short-term Debt Outstanding Available Short-term Credit Facilities Cash Balance at 06/30/17 Tota
Slide 8: Committed to the Dividend
Committed to the Dividend Annual Dividend Rate ($ /share) Consecutive Payments 115 Years Consecutive Increases 47 Years Current Dividend Rate $1.66 per Share Current Dividend Yield (1) 2.8% As of August 3, 2017. NFG’s Dividend Consistency
Slide 9: Upstream Overview Exploration & Production
Upstream Overview Exploration & Production
Slide 10: Growing Production within Disciplined Capital Program
Growing Production within Disciplined Capital Program E&P Net Production (Bcfe) E&P Net Capital Expenditures(1) ($ millions) 2-rig development program Target 10%+ production 3-year CAGR Resume development on prolific Marcellus acreage in Lycoming County, Pa. Return to developing 100% NRI wells in th
Slide 11: Proved Reserves
Proved Reserves (1) 117% Reserve Replacement Rate (adjusted for revisions and sales) 65% Proved Developed 35% Proved Undeveloped Includes approximately 69 Bcf of natural gas proved reserves in Appalachia that will be transferred in fiscal 2017 as interests in the joint development wells are conveyed
Slide 12: Significant Appalachian Acreage Position
Significant Appalachian Acreage Position Current gross production: ~255 MMcf/d Mostly leased (16-18% royalty) with no significant near-term lease expirations > 100 remaining Marcellus and Utica locations economic under $1.80/Mcf Additional Utica & Geneseo potential Near-term development tailored to
Slide 13: Western Development Area
Western Development Area WDA Marcellus Tier 1 Acreage – 200,000 Acres Significant multi-zone drilling inventory economic under $2.00 /Mcf Marcellus Shale : 1,000+ well locations Utica Shale: 125 to 500+ well locations (2) Fee acreage / stacked pay provides flexibility & enhances economics No royalty
Slide 14: WDA Marcellus: Clermont/Rich Valley Development
WDA Marcellus: Clermont/Rich Valley Development Gross daily production: ~315 MMcf/d 1-rig / daylight only frac crew Developing 75 Marcellus wells with joint development partner (IOG) 75 wells drilled 63 wells online/producing Just-in-time gathering infrastructure build-out provides significant capit
Slide 15: WDA Utica: Early Results and Economic Impact
WDA Utica: Early Results and Economic Impact 15/16 WDA Marcellus WDA Utica WDA Utica vs Marcellus Utica Early Test Results: Drawdown management is important Restricted drawdown improves well EURs Higher pressure significantly enhances well productivity (Utica ~5,000’ deeper than Marcellus) Completio
Slide 16: WDA Utica: Transition to Development
WDA Utica: Transition to Development WDA Marcellus (Depth ~7,000 feet) Existing Line Leased Seneca Fee Producing FY18 Producer Development WDA Utica (Depth ~12,000 feet) Seneca and NFG Midstream can leverage existing upstream and midstream infrastructure to drive capital, operational, and marketing
Slide 17: Eastern Development Area
Eastern Development Area EDA Acreage – 70,000 Acres EDA Highlights 3 1 2 1 2 Upstream DCNR Tract 007 (Tioga Co., Pa) 1 Utica and 1 Marcellus producing well Utica 30-day IP = 15.8 MMcf/d Utica development expected to begin in fiscal 2018 59 remaining Utica locations economic under $1.95 /Mcf Covingto
Slide 18: EDA Marcellus: Lycoming County Development
EDA Marcellus: Lycoming County Development Upstream Prolific Marcellus acreage with peer leading well results 60 Marcellus wells producing w/ average IP rate of 17.0 MMcf/d 63 remaining Marcellus locations economic under $1.65 /Mcf Near-term development focused on filling Atlantic Sunrise capacity f
Slide 19: EDA Utica: Tioga County Development
EDA Utica: Tioga County Development Upstream Utica Development in Tioga County – Tract 007 Expected to Begin in FY18 Northeast Supply Diversification Project FT Capacity: 50,000 Dth/d @ $0.50/Dth Firm Sales: NYMEX and DAWN EDA - TGP 300 Firm Sales SRC EDA – Tract 007 Utica Test Well Gathering Line I
Slide 20: Marcellus: Drilling & Completions Efficiencies
Marcellus: Drilling & Completions Efficiencies Normalized to adjust for daylight only frac operations that began in 2016. Marcellus Drilling Marcellus Completions Upstream Down 42% since 2014 Operational Efficiencies and Investment in Water Infrastructure Have Resulted in Peer Leading Well Costs Dow
Slide 21: Appalachia Drilling Program Economics
Appalachia Drilling Program Economics Net realized price reflects either (a) price received at the gathering system inteconnect or (b) price received at delivery market net of firm transportation charges. Internal Rate of Return (IRR) is pre-tax and includes estimated well costs under current cost s
Slide 22: Long-term Contracts Supporting Appalachian Production
Long-term Contracts Supporting Appalachian Production Atlantic Sunrise (Transco) Delivery Markets: Mid-Atlantic & Southeast U.S. 189,405 Dth/d In-Basin Firm Sales Contracts(1) Niagara Expansion (TGP & NFG) Delivery Markets: Canada-Dawn & TETCO 158,000 Dth/d Northeast Supply Diversification 50,000 Dt
Slide 23: Firm Transportation Commitments
Firm Transportation Commitments Volume (Dth/d) Production Source Delivery Market Demand Charges ($/Dth) Gas Marketing Strategy Northeast Supply Diversification Project Tennessee Gas Pipeline Atlantic Sunrise WMB - Transco In-service: Mid-2018 Niagara Expansion TGP & NFG Northern Access NFG – Supply
Slide 24: Firm Sales Provide Market for Appalachian Production
Firm Sales Provide Market for Appalachian Production Net Contracted Firm Sales Volumes (Dth per day) Contracted Index Price Differentials ($ per Dth)(1) Values shown represent the price or differential to a reference price (netback price) at the point of sale less any associated transportation costs
Slide 25: California Oil
California Oil Stable Oil Production | Minimal Capital Investment | Steady Free Cash Flow 1 2 3 4 5 6 Location Formation Production Method FY16 Gross Daily Production (Boe/d) 1 East Coalinga Temblor Primary 770 2 North Lost Hills Tulare & Etchegoin Primary/ Steam flood 1,000 3 South Lost Hills Monte
Slide 26: California Average Daily Net Production
California Average Daily Net Production Less than $40 Million Annual Capital Spending Needed to Keep CA Production Flat Upstream California Average Net Daily Production (BOE/D) California Annual Capital Expenditures ($MM) Guidance Guidance
Slide 27: Future Development Focused on Midway Sunset
Future Development Focused on Midway Sunset Modest near-term capital program focused on locations that earn attractive returns in current oil price environment A&D will focus on low cost, bolt-on opportunities Sec. 17 and Pioneer farm-ins to provide future growth F&D (est.) = $6.50/Boe Midway-Sunset
Slide 28: Seneca Production
Seneca Production Upstream Net Production (Bcfe)
Slide 29: Strong Hedge Book in FY 2018
Strong Hedge Book in FY 2018 Natural Gas Swap & Fixed Physical Sales Contracts (Millions MMBtu) Fixed price physical sales exclude joint development partner’s share of fixed price contract WDA volumes as specified under the joint development agreement. Upstream Crude Oil Swap Contracts (Thousands Bb
Slide 30: Fiscal 2017 Production and Price Certainty
Fiscal 2017 Production and Price Certainty Average realized price reflects uplift from financial hedges less fixed differentials under firm sales contracts and any firm transportation costs. Indicates firm sales contracts with fixed index differentials but not backed by a matching NYMEX financial he
Slide 31: Fiscal 2018 Production and Price Certainty
Fiscal 2018 Production and Price Certainty FINANCIAL HEDGE + FIRM SALE = PRICE CERTAINTY Average realized price reflects uplift from financial hedges less fixed differentials under firm sales contracts and any firm transportation costs. Indicates firm sales contracts with fixed index differentials b
Slide 32: Seneca Operating Costs
Seneca Operating Costs Competitive, low cost structure in Appalachia and California supports strong cash margins Gathering fee generates significant revenue stream for affiliated gathering company DD&A decrease due to improving Marcellus F&D costs and reduction in net plant resulting from ceiling te
Slide 33: Midstream Businesses
Midstream Businesses
Slide 34: Midstream Businesses
Midstream Businesses Midstream Midstream Midstream Businesses Adjusted EBITDA ($MM) Note: A reconciliation of Adjusted EBITDA to Net Income as presented on the Consolidated Statement of Income and Earnings Reinvested in the Business is included at the end of this presentation. Midstream Businesses S
Slide 35: Integrated Development – WDA Gathering System
Integrated Development – WDA Gathering System Current System In-Service ~70 miles of pipe / 31,220 HP of compression Current Capacity: 470 MMcf per day Interconnects with TGP 300 Total Investment to Date: $277 million FY 2018 CapEx: ~$10 million Modest Midstream compression and pipeline investment r
Slide 36: Integrated Development – EDA Gathering Systems
Integrated Development – EDA Gathering Systems Total Investment (to date): $33 million Capacity: 220,000 Dth per day (Interconnect w/ TGP 300) Production Source: Seneca Resources – Tioga Co. (Covington and DCNR Tract 595) Total Investment (to date): $173 million FY 2018 Capital Expenditures: ~$45 mi
Slide 37: Infrastructure Expansions Bolster Supply Diversity
Infrastructure Expansions Bolster Supply Diversity Northern Access 2015 (In-Service(1)) System: NFG Supply Corp. Capacity: 140,000 Dth per day Leased to TGP as part of TGP’s Niagara Expansion project Delivery Interconnect: Niagara (TransCanada) Total Cost: $67.1 million Annual Revenues: $13.3 millio
Slide 38: Northern Access Project Status
Northern Access Project Status Project in-service not expected before 2019 due to regulatory delays February 3, 2017 – NFG received FERC 7(c) certificate March 3, 2017 – NFG filed petition for rehearing with FERC seeking waiver of NYS DEC Clean Water Act Section 401 Water Quality Certification (WQC)
Slide 39: Empire System Expansion
Empire System Expansion Target In-Service: November 2019 System: Empire Pipeline Estimated Cost: $135 million Receipt Point: Jackson (Tioga Co., Pa. production) Design Capacity and Delivery Points: 175,000 Dth/d to Chippawa (TCPL interconnect) 30,000 Dth/d to Hopewell (TGP 200 interconnect) Customer
Slide 40: Continued Expansion of the NFG Supply System
Continued Expansion of the NFG Supply System Line N Expansion Opportunities Line D Expansion Project Midstream Target In-Service: November 2017 Contracted Capacity: 77,500 Dth/d from an interconnect with TGP 300 at Lamont, Pa. into Erie, Pa. market Estimated Cost: $28 million ($8 million modernizati
Slide 41: Pipeline & Storage Customer Mix
Pipeline & Storage Customer Mix 4.1 MMDth/d Contracted as of 10/20/2016. Customer Transportation by Shipper Type(1) Affiliated Customer Mix (Contracted Capacity) Firm Transport Midstream
Slide 42: Downstream Overview Utility ~ Energy Marketing
Downstream Overview Utility ~ Energy Marketing
Slide 43: New York & Pennsylvania Service Territories
New York & Pennsylvania Service Territories New York Total Customers(1): 528,312 ROE: 8.7% (NY PSC Rate Case Order, April 2017) Rate Mechanisms: Revenue Decoupling Weather Normalization Low Income Rates Merchant Function Charge (Uncollectibles Adj.) 90/10 Sharing (Large Customers) Pennsylvania Total
Slide 44: New York Rate Case Outcome
New York Rate Case Outcome Downstream Rate Order Summary: Revenue Requirement:$5.9 million Rate Base:$704 million (prior case $632 million1) Allowed Return on Equity (ROE):8.7% (prior case allowed 9.1%1) Capital Structure:42.9% equity Other notable items: New rates effective 5/1/17 Retains rate mech
Slide 45: Utility: Shifting Trends in Customer Usage
Utility: Shifting Trends in Customer Usage Weighted Average of New York and Pennsylvania service territories (assumes normal weather). Usage Per Account (1) 12-Months Ended June 30 Downstream
Slide 46: Utility: Strong Commitment to Safety
Utility: Strong Commitment to Safety The Utility remains focused on maintaining the ongoing safety and reliability of its system Capital Expenditures ($ millions)(1) Downstream A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of
Slide 47: Accelerating Pipeline Replacement & Modernization
Accelerating Pipeline Replacement & Modernization NY 9,700 miles PA* 4,830 miles * No Cast Iron Mains in Pa.* Miles of Utility Main Pipeline Replaced(1) Utility Mains by Material Downstream As reported to the Department of Transportation on calendar year basis. Coated
Slide 48: A Proven History of Controlling Costs
A Proven History of Controlling Costs O&M Expense ($ millions) Downstream
Slide 49: Appendix
Appendix
Slide 50: Earnings Guidance
Earnings Guidance Fiscal 2017 EPS Guidance Non-regulated Businesses Exploration & Production Gathering $3.25/sh to $3.35/sh $2.70/sh to $3.05/sh Fiscal 2018 EPS Guidance Seneca Net Production: 185 to 200 Bcfe (up 17.5 Bcf or 10% vs FY 17) Gathering Revenues: $115 to $125 million (up $10 million or 9
Slide 51: Marcellus Operated Well Results
Marcellus Operated Well Results EDA Development Wells: Area Producing Well Count Average IP Rate (MMcfd) Average 30-Day (MMcf/d) Average Treatable Lateral Length Covington Tioga County 47 5.2 4.1 4,023 ft Tract 595 Tioga County 44(2) 7.4 4.9 4,754 ft Tract 100 Lycoming County 60(2) 17.0 12.6 5,221 f
Slide 52: Hedge Positions
Hedge Positions Fixed price physical sales exclude joint development partner’s share of fixed price contract WDA volumes as specified under the joint development agreement. Appendix Natural Gas Volumes in thousand MMBtu; Prices in $/MMBtu Fiscal 2017 (last 3 mos.) Fiscal 2018 Fiscal 2019 Fiscal 2020
Slide 53: Comparable GAAP Financial Measure Slides & Reconciliations
Comparable GAAP Financial Measure Slides & Reconciliations This presentation contains certain non-GAAP financial measures. For pages that contain non-GAAP financial measures, pages containing the most directly comparable GAAP financial measures and reconciliations are provided in the slides that fol
Slide 54: Non-GAAP Reconciliations – Adjusted EBITDA
Non-GAAP Reconciliations – Adjusted EBITDA Appendix
Slide 55: Non-GAAP Reconciliations – Capital Expenditures
Non-GAAP Reconciliations – Capital Expenditures Appendix
Slide 56: Non-GAAP Reconciliations – E&P Operating Expenses
Non-GAAP Reconciliations – E&P Operating Expenses Appendix