National Fuel Gas Company · NYSE:NFG
National Fuel Gas — Q2 FY2017 Earnings Presentation
54 slides from National Fuel Gas's earnings presentation, May 4, 2017
Slide 1: Investor Presentation Q2 Fiscal 2017 Update
Investor Presentation Q2 Fiscal 2017 Update May 4, 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: Quality Assets – Exceptional Location – Unique Integration
Quality Assets – Exceptional Location – Unique Integration 1.8 Tcfe Proved Reserves (1) 785,000 net acres in Appalachia - mostly held in fee with no royalty 3 million Bbls annual CA crude oil production $285 million annual adjusted EBITDA (2) $1.3+ billion midstream investments since 2010 Coordinate
Slide 4: Adjusted EBITDA by Segment
Adjusted EBITDA by Segment ($ millions) Balanced Earnings and Cash Flows 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.
Slide 5: Flexibility to Responsibly Deploy Capital
Flexibility to Responsibly Deploy Capital (1) FY 2016 actual capital expenditures reflects the netting of $157 million of up-front proceeds received from joint development partner for working interest in joint development wells. FY 2017 guidance also reflects the netting of anticipated proceeds rece
Slide 6: 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 7: The Bridge to Northern Access
The Bridge to Northern Access Exploration & Production Strategy Midstream Strategy Corporate Strategy Near-term in-basin pricing supports plans for 10%+ annual production growth over next 3 years WDA Development – Maintain 1 rig program Convert Northern Access firm sales from Dawn (95 MMcf/d) and la
Slide 8: Near-term Capital Budget and Operating Plan
Gathering: Just-in-time installation of gathering pipelines and compression facilities to accommodate Seneca’s development plans Pipeline & Storage: FY17 capex reduced by $115 million due to Northern Access delay Line D expansion and system maintenance and modernization Near-term Capital Budget and
Slide 9: Strong Balance Sheet & Liquidity
Strong Balance Sheet & Liquidity Total Debt 56% $3.7 Billion Total Capitalization as of March 31, 2017 Debt/Adjusted EBITDA Capitalization Debt Maturity Profile ($MM) Liquidity Committed Credit Facilities Short-term Debt Outstanding Available Short-term Credit Facilities Cash Balance at 03/31/17 Tot
Slide 10: Committed to the Dividend
Committed to the Dividend Annual Dividend Rate ($ /share) Consecutive Payments 114 Years Consecutive Increases 46 Years Current Dividend Rate $1.62 per Share Current Dividend Yield (1) 3.0% As of May 3, 2017. NFG’s Dividend Consistency
Slide 11: Upstream Overview: Exploration & Production
Upstream Overview Exploration & Production
Slide 12: Significant Appalachian Acreage Position
Significant Appalachian Acreage Position Daily gross production: ~300 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 fi
Slide 13: Marcellus Shale: Western Development Area
Marcellus Shale: Western Development Area WDA Tier 1 Acreage – 200,000 Acres WDA Tier 1 Marcellus Economics(1) WDA Highlights Large drilling inventory of quality Marcellus dry gas ~1,100 locations economic < $2.00/MMBtu realized Fee acreage provides flexibility/enhances economics No royalty on most
Slide 14: WDA Clermont/Rich Valley Development
WDA Clermont/Rich Valley Development Gross daily production: ~270 MMcf/d 1-rig/daylight only frac crew Marcellus well costs averaging ~$660 per lateral ft. Developing 75 Marcellus wells with joint development partner (IOG) 75 wells drilled 63 wells online/producing Just-in-time gathering infrastruct
Slide 15: Best in Class Marcellus Well Costs
Best in Class Marcellus Well Costs Down 60% since 2012 Down 77% since 2012 Seneca Average Marcellus Well Cost(1) vs. Appalachian Peers (2) Seneca CRV reflects a $5.3 million “all-in” total well cost for a 8,000 ft. lateral. Total well costs include drilling, completions, allocated pad level and prod
Slide 16: Marcellus Shale: Eastern Development Area
Marcellus Shale: 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 2 Marcellus producing wells Utica 30-day IP = 15.8 MMcf/d Utica resource potential ~1 Tcf Development expected to begin in fiscal 2018 Covington & DCNR Tr
Slide 17: Utica Shale Opportunities
Utica Shale Opportunities Seneca’s Utica Activity on Trend with Strong Results in Northern Pa. Upstream Pennsylvania Utica Activity Seneca’s Utica Opportunities Western Development Area First 2 Utica test wells in Clermont / Rich Valley area are exceeding Marcellus performance Executing 10 well appr
Slide 18: WDA Utica Update
WDA Utica Update Results: WDA Utica Results (1) vs Avg WDA Marcellus WDA-CRV Utica Test Wells WDA-CRV Marcellus Wells (Average) Well 113HU Well 196HU(1) 121 wells Initial Test June 2016 Nov 2016 Lateral Length 4,630 ft 6,288 ft 7,139 ft Choke Avg ( /64th) 35/64th 28/64th 64/64th 30 Day IP/1,000 ft 1
Slide 19: WDA Utica Appraisal Program
WDA Utica Appraisal Program Plan to drill 10 total Utica appraisal wells off Marcellus development pads Two wells on pad EO9-S producing under 30 days Testing target zone and D&C design Can leverage existing upstream and midstream infrastructure to drive capital, operational, and marketing efficienc
Slide 20: EDA Utica Update
EDA Utica Update Northeast PA Utica Well Performance – Tioga and Potter County SRC EDA – Tract 007 Utica Test Well Gathering Line In-Service November 2016 Lateral Length 4,640 ft 30 Day IP /1,000 ft 3.4 MMcf/d Est. EUR /1,000 ft 2.4 Bcf Seneca DCNR 007 Utica Well Among the Best in Northeastern PA Up
Slide 21: California Oil
California Oil Stable Oil Production | Minimal Capital Investment | Free Cash Flow Positive 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 Mon
Slide 22: 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) 2013 2014 2015 2016 2017 Forecast 2013 2014 2015 2016 2017 Forecast
Slide 23: 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.) = $6.50/Boe Midway-Sunset
Slide 24: Proved Reserves & Development Costs
Proved Reserves & Development Costs (1) 117% Reserve Replacement Rate (adjusted for revisions and sales) 65% Proved Developed 35% Proved Undeveloped Includes approximately 69 Bcf of natural gas proved reserves in Appalachia that will be transferred in fiscal 2017 as interests in the joint developmen
Slide 25: Seneca Production
Seneca Production Upstream 10%+ CAGR Target Significant base of long-term firm contracts and relatively strong near-term regional pricing outlook supports Appalachian development program that will drive 10%+ annual Appalachian production growth while NFG works through Northern Access delay Near-term
Slide 26: Long-term Contracts Supporting Appalachian Production
Long-term Contracts Supporting Appalachian Production Atlantic Sunrise (Transco) Delivery Markets: Mid-Atlantic & Southeast U.S. 189,405 Dth/d In-Basin Firm Sales Contracts(1) Niagara Expansion (TGP & NFG) Delivery Markets: Canada-Dawn & TETCO 158,000 Dth/d Northeast Supply Diversification 50,000 Dt
Slide 27: Firm Transportation Commitments
Firm Transportation Commitments Volume (Dth/d) Production Source Delivery Market Demand Charges ($/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 28: Firm Sales Provide Market for Appalachian Production
Firm Sales Provide Market for Appalachian Production Gross vs. Net Firm Sales Volumes (Dth per Day) Q3 FY17 Q4 FY17 Gross 503,000/d 478,000/d NRI Owners(2) 143,800/d 122,200/d Net 359,200/d 355,800/d FY 17 Net Contracted Volumes (Dth per day) Contracted Index Price Differentials ($ per Dth)(1) Value
Slide 29: Strong Hedge Book
Strong Hedge Book Natural Gas Swap & Fixed Physical Sales Contracts (Millions MMBtu) Remaining Fiscal 2017 Natural Gas Production ~80% hedged (1) at $3.30 per MMBtu (2) Assumes midpoint of natural gas production guidance, adjusted for year-to-date actual results. Fixed price physical sales exclude j
Slide 30: Fiscal 2017 Production and Price Certainty
Fiscal 2017 Production and Price Certainty FINANCIAL HEDGE + FIRM SALE = PRICE CERTAINTY Average realized price reflects uplift from financial hedges less fixed differentials under firm sales contracts and any firm transportation costs. Indicates firm sales contracts with fixed index differentials b
Slide 31: Operating Costs
Operating Costs Competitive, low cost structure in Appalachia and California supports strong cash margins Gathering fee generates significant revenue stream for affiliated gathering company DD&A decrease due to improving Marcellus F&D costs and reduction in net plant resulting from ceiling test impa
Slide 32: Midstream Businesses
Midstream Businesses
Slide 33: Midstream Businesses
Midstream Businesses Midstream Midstream Midstream Businesses Adjusted EBITDA ($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 34: Integrated Development – WDA Gathering System
Integrated Development – WDA Gathering System Current System In-Service ~70 miles of pipe/26,220 HP of compression Current Capacity: 470 MMcf per day Interconnects with TGP 300 Total CapEx To Date: $272 million FY 2017 CapEx: ~$30 million Timing and extent of gathering & compression investments are
Slide 35: Integrated Development – EDA Gathering Systems
Integrated Development – EDA Gathering Systems Capital Expenditures (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 acreage) Capital Expenditures (to date): $168 Million Capacity: 466,000 to
Slide 36: 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 37: Empire System Expansion
Empire System Expansion Target In-Service: as early as Nov. 1, 2019 System: Empire Pipeline Estimated Cost: $150 to $200 million (scalable) Receipt Point: Jackson (Tioga Co., Pa.) Available Capacity / Delivery Points: 180,000 Dth/d to Chippawa (TCPL) 120,000 Dth/d to Hopewell (TGP) Major Facilities:
Slide 38: 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: Nov. 1, 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 modernizatio
Slide 39: 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 40: Downstream Overview
Downstream Overview Utility ~ Energy Marketing
Slide 41: 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: Earnings Sharing Revenue Decoupling Weather Normalization Low Income Rates Merchant Function Charge (Uncollectibles Adj.) 90/10 Sharing (Large Customers) P
Slide 42: 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 43: 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 March 31 Downstream
Slide 44: Utility: Strong Commitment to Safety
Utility: Strong Commitment to Safety Recent increase due to ~$60MM upgrade of the Utility’s Customer Information System and anticipated acceleration of pipeline replacement program The Utility remains focused on maintaining the ongoing safety and reliability of its system Capital Expenditures ($ mil
Slide 45: A Proven History of Controlling Costs
A Proven History of Controlling Costs O&M Expense ($ millions) Downstream
Slide 46: Appendix
Appendix
Slide 47: 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 (ft) Covington Tioga County 47 5.2 4.1 4,023’ Tract 595 Tioga County 44(2) 7.4 4.9 4,754’ Tract 100 Lycoming County 60(2) 17.0 12.6 5,221’
Slide 48: Marcellus Shale Program Economics
Marcellus Shale Program Economics Internal Rate of Return (IRR) is pre-tax and includes estimated well costs under current cost structure, LOE, and Gathering tariffs anticipated for each prospect. Net realized price reflects either (a) price received at the well-head or (b) price received at deliver
Slide 49: 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 $/MMBtu Fiscal 2017 (last 6 mos.) Fiscal 2018 Fiscal 2019 Fiscal 2020
Slide 50: Seneca WDA Joint Development Agreement
Assets: 75 current and future Marcellus development wells in the Clermont/Rich Valley region of Seneca’s WDA. Locations Developed Under Initial Obligation: 39 wells Remaining Locations to be Developed: 36 wells Partner Option: IOG has one-time option to participate in a 7-well pad to be completed be
Slide 51: Comparable GAAP Financial Measure Slides & Reconciliations
Comparable GAAP Financial Measure Slides & Reconciliations This presentation contains certain non-GAAP financial measures. For pages that contain non-GAAP financial measures, pages containing the most directly comparable GAAP financial measures and reconciliations are provided in the slides that fol
Slide 52: Non-GAAP Reconciliations – Adjusted EBITDA
Non-GAAP Reconciliations – Adjusted EBITDA Appendix Reconciliation of Adjusted EBITDA to Consolidated Net Income ($ Thousands) Total Adjusted EBITDA Exploration & Production Adjusted EBITDA 492,383 $ 539,472 $ 422,289 $ 363,830 $ 389,528 Pipeline & Storage Adjusted EBITDA 161,226 186,022 188,042 199
Slide 53: Non-GAAP Reconciliations – Capital Expenditures
Non-GAAP Reconciliations – Capital Expenditures Appendix Reconciliation of Segment Capital Expenditures to Consolidated Capital Expenditures ($ Thousands) FY 2017 FY 2013 FY 2014 FY 2015 FY 2016 Forecast Capital Expenditures from Continuing Operations Exploration & Production Capital Expenditures 53
Slide 54: Non-GAAP Reconciliations – E&P Operating Expenses
Non-GAAP Reconciliations – E&P Operating Expenses Appendix Reconciliation of Exploration & Production Segment Operating Expenses by Division ($000s unless noted otherwise) Appalachia West Coast (2) Total E&P Appalachia West Coast (2) Total E&P Appalachia West Coast (2) Total E&P Appalachia West Coas