National Fuel Gas Company · NYSE:NFG
National Fuel Gas — Q3 2018 Earnings Presentation
61 slides from National Fuel Gas's earnings presentation, Aug 2, 2018
Slide 1: Investor Presentation Q3 Fiscal 2018 Update
Investor Presentation Q3 Fiscal 2018 Update August 2, 2018 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
Developing our large, high quality acreage position in Marcellus & Utica shales NFG: A Diversified, Integrated Natural Gas Company Providing safe, reliable and affordable service to customers in WNY and NW Pa. Upstream E&P Midstream Gathering Pipeline & Storage Downstream Utility Energy Marketing Ex
Slide 4: Why National Fuel?
Why National Fuel? Unique Integration and Diversified Asset Mix Serves as Foundation for Growth Strategy Long-term, Disciplined Approach to Capital Allocation and Returns 3 Large, contiguous footprint in Appalachia drives peer leading low-cost development Fee-ownership (no royalty) on majority of ac
Slide 5: Benefits of Integration
Benefits of Integration Unique Geographic and Operational Integration Drives Synergies that Maximize Shareholder Value Large Appalachian footprint with considerable opportunity for growth Operational scale Lower cost of capital Lower operating costs More efficient capital investment More competitive
Slide 6: Diversified, Balanced Earnings and Cash Flows
Adjusted Operating Results ($ per share)(1) Diversified, Balanced Earnings and Cash Flows A reconciliation of Adjusted Operating Results to Earnings per Share, by segment, as presented on the Consolidated Statement of Income and Earnings Reinvested in the Business is included at the end of this pres
Slide 7: Near-Term Growth Strategy
Near-Term Growth Strategy Exploration & Production Gathering Pipeline and Storage Utility 3-rig program designed to grow Marcellus and Utica production and gathering throughput at a 15-20% CAGR over next 5 years Utilize significant existing gathering infrastructure to support further WDA development
Slide 8: Disciplined, Flexible Capital Allocation
Disciplined, Flexible Capital Allocation (2) Capital Expenditure totals include Energy Marketing, and Corporate and All Other Segments. A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation. FY16, FY17, and FY18
Slide 9: Maintaining Strong Balance Sheet & Liquidity
Maintaining Strong Balance Sheet & Liquidity Total Debt 52% $4.0 Billion Total Capitalization as of June 30, 2018 Net Debt / Adjusted EBITDA(1) Capitalization Debt Maturity Profile ($MM) Liquidity Committed Credit Facilities Short-term Debt Outstanding Available Short-term Credit Facilities Cash Bal
Slide 10: Dividend Track Record
Dividend Track Record $2.9 Billion Dividend payments since 1970 $1.70 per share 48 Years Consecutive Dividend Increases $0.19 per share 116 Years Consecutive Payments 3.2% yield(1) As of August 1, 2018.
Slide 11: Financial Highlights Q3 Fiscal 2018
Financial Highlights Q3 Fiscal 2018
Slide 12: Third Quarter Fiscal 2018 Results and Drivers
Net Oil and Gas Production Third Quarter Fiscal 2018 Results and Drivers Operating Results ($/share)(1) Operating results of $0.69 for Q3 Fiscal 2017 and $0.73 for Q3 Fiscal 2018 includes operating results of Energy Marketing and Corporate & All Other segments. Realized price after hedging. Oil and
Slide 13: Impact of Federal Tax Reform
Impact of Federal Tax Reform Non-Rate Regulated Segments Rate Regulated Segments Exploration & Production and Gathering Positive ongoing earnings impact expected from reduction in federal income tax rate from 35% to 21% (blended 24.5% in FY 2018) Remeasurement of deferred income taxes resulted in $1
Slide 14: Earnings Guidance
Earnings Guidance FY2018 Earnings Guidance(1) Non-regulated Businesses Exploration & Production Gathering $3.30 to $3.40 /share $3.30 to $3.60 /share FY2019 Earnings Guidance Seneca Net Production: 210 to 230 Bcfe Gathering Revenues: $130-140 million Natural Gas: ~$2.35 /Mcf(2) (vs. $2.55 /Mcf FYTD
Slide 15: Exploration & Production and Gathering Overview
Exploration & Production and Gathering Overview Seneca Resources Company, LLC ~ National Fuel Gas Midstream Company, LLC
Slide 16: Proved Reserves
Proved Reserves 225% Reserve Replacement Rate (adjusted for revisions) Seneca Drill-bit F&D = $0.60/Mcfe(1) Appalachia Drill-bit F&D = $0.51/Mcfe(1) Seneca “Drill-bit” finding and development (“F&D”) costs exclude the impact of reserve revisions. Total Proved Reserves (Bcfe) Fiscal 2017 Proved Reser
Slide 17: Growing Production within Disciplined Capital Program
Growing Production within Disciplined Capital Program E&P Net Production (Bcfe) E&P Net Capital Expenditures(1) ($ millions) 3-rig drilling program, with new rig in the WDA focused on redevelopment of Clermont-Rich Valley acreage for Utica Target 15-20%+ production CAGR over next 5 years Resumed dev
Slide 18: Significant Appalachian Acreage Position
Significant Appalachian Acreage Position Current gross production: ~267 MMcf/d Mostly leased (16-18% royalty) with no significant near-term lease expirations ~100 remaining Marcellus & Utica locations economic under $1.80/Mcf Additional Utica & Geneseo potential across position Eastern Development A
Slide 19: Western Development Area Marcellus Core vs. Utica Appraisal Trend
Western Development Area Marcellus Core Acreage vs. Utica Appraisal Trend(1) The Utica Shale lies approximately 5,000 feet beneath Seneca’s WDA Marcellus acreage. Appraisal program currently in progress. Additional tests are planned. Prior Marcellus delineation tests helped define the prospective li
Slide 20: WDA Utica Appraisal Results and Initial Type Curve
WDA Utica Appraisal Results and Initial Type Curve Tested / producing from 10 Utica wells in WDA-CRV Higher pressure significantly enhances well productivity (Utica ~5,000’ deeper than Marcellus) Drawdown management is critical: restricted drawdown improves well EURs Early production declines much s
Slide 21: Transitioning to Utica Development in CRV
Transitioning to Utica Development in CRV WDA-CRV Marcellus (Depth ~7,000 feet) WDA-CRV Utica (Depth ~12,000 feet) Average CRV Marcellus Production: 267 Mcf/d Rem. Avg. EUR 1.0-1.1 Bcf / 1,000 lat ft. Rem. Avg. Well Costs = $627/lat ft. 125+ locations on existing Marcellus pads Est. EURs 1.7 Bcf / 1
Slide 22: Integrated Development – WDA Gathering System
Integrated Development – WDA Gathering System Current System In-Service ~70 miles of pipe / 36,220 HP of compression Current Capacity: 470 MMcf per day Interconnects with TGP 300 Total Investment to Date: $292 million Future Build-Out FY 2018 CapEx: $15MM - $20MM Modest gathering pipeline and compre
Slide 23: Leveraging Existing Gathering Infrastructure Enhances Consolidated Returns
Leveraging Existing Gathering Infrastructure Enhances Consolidated Returns WDA Development Consolidated Economics WDA Well Costs(1) WDA Consolidated Economics The addition of a 3rd rig will be incremental to returns, while also providing economies of scale and significant operational flexibility E&P
Slide 24: WDA Firm Transportation and Sales Capacity
WDA Firm Transportation and Sales Capacity Seneca’s net production will utilize more of its gross capacity through time as JDA production declines Will continue to layer-in firm sales deals of short and longer duration on TGP 300 to reduce spot exposure WDA spot realizations track TGP Station 313 pr
Slide 25: Eastern Development Area
Eastern Development Area EDA Acreage – 70,000 Acres EDA Highlights 3 1 2 DCNR Tract 007 (Tioga Co., Pa) 1 Utica and 1 Marcellus producing well Utica 30-day IP = 15.8 MMcf/d Utica development resumed in third quarter fiscal 2018 47 remaining Utica locations economic at ~$1.75 /Mcf Covington & DCNR Tr
Slide 26: EDA Marcellus: Lycoming County Development
EDA Marcellus: Lycoming County Development Prolific Marcellus acreage with peer leading well results Average Marcellus IP rate of 17.0 MMcf/d 49 remaining Marcellus locations economic at ~$1.50 /Mcf Near-term development focused on filling Atlantic Sunrise capacity now forecasted to be available by
Slide 27: EDA Utica: Tioga County Development
EDA Utica: Tioga County Development Utica Development in Tioga County – Tract 007 Development Resumed in Q3 FY18 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 Inventory: 47 locations economic at ~$1.75 /Mcf Targeting to grow production by
Slide 28: Integrated Development – EDA Gathering Systems
Integrated Development – EDA Gathering Systems Total Investment (to date): $45 million FY 2018 Capital Expenditures: $13MM - $15MM 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): $195 m
Slide 29: Long-term Contracts Supporting Appalachian Growth
Long-term Contracts Supporting Appalachian Growth Represents base firm sales contracts not tied to firm transportation capacity. Base firm sales are either fixed priced or priced at an index (e.g., NYMEX ) +/- a fixed basis and do not carry any transportation costs. Seneca continues to layer-in firm
Slide 30: Near-term Firm Sales Provide Market & Price Certainty
Near-term Firm Sales Provide Market & Price Certainty Net Contracted Firm Sales Volumes (Dth per day) Contracted Index Price Differentials ($ per Dth)(1) Values shown represent the weighted average fixed price or contracted fixed differential relative to NYMEX (netback price) less any associated tra
Slide 31: California Oil
California Oil Stable Oil Production | Minimal Capital Investment | Steady Free Cash Flow 1 2 3 4 5 Location Formation Production Method FY17 Daily Production (net Boe/d) 1 East Coalinga Temblor Primary 570 2 North Lost Hills Tulare & Etchegoin Primary/ Steam flood 933 3 South Lost Hills Monterey Sh
Slide 32: California Capital Expenditures vs. Production
California Capital Expenditures vs. Production West Division Average Net Daily Production (BOE/D) West Division Annual Capital Expenditures ($MM)(1) Guidance Guidance Seneca West Division capital expenditures includes Seneca corporate and eliminations. Sale closed on 5/1/18. The impact for the remai
Slide 33: 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 Midway-Sunset Midway-Sunset Pioneer
Slide 34: Fiscal 2018 Production
Fiscal 2018 Production 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 financial hedge. 34 Bcf locked-in real
Slide 35: Fiscal 2019 Production
Fiscal 2019 Production 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 financial hedge. 140 Bcf locked-in rea
Slide 36: Strong Hedge Book
Strong Hedge Book 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. Reflects percentage of projected production for the remain
Slide 37: 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 Seneca DD&A Rate $/Mcfe Appalachia LOE & Gathering $/Mcfe California LOE $/Boe Total Seneca Cash OpEx $
Slide 38: Pipeline and Storage Overview
Pipeline and Storage Overview National Fuel Gas Supply Corporation ~ Empire Pipeline, Inc.
Slide 39: Pipeline & Storage Segment Overview
Pipeline & Storage Segment Overview As of September 30, 2017 as disclosed in the Company’s fiscal 2017 form 10-K. As of December 31, 2017 calculated from National Fuel Gas Supply Corporation’s and Empire Pipeline, Inc.’s 2017 FERC Form-2 reports, respectively. Empire Pipeline, Inc. National Fuel Gas
Slide 40: FM100 Project Provides Consolidated Benefit
FM100 Project Provides Consolidated Benefit 300,000 Dth/d of new transportation capacity from WDA and EDA acreage positions to premium markets New Transco pipeline capacity: ~300,000 Dth/day Rate: expected to be competitive with other expansion project rates in Seneca’s current transportation portfo
Slide 41: FM100 Project
FM100 Project Target In-Service: late calendar year 2021 Facilities (all in Pennsylvania): Approximately 30 miles of new pipeline 2 new compressor Stations (totaling approximately 34,000 HP) 2 new interconnection stations and modification of existing meter and regulation station Abandonment of appro
Slide 42: Empire North Project
Empire North Project Target In-Service: Second half of fiscal 2020 Est. Capital Cost: $145 million Est. Annual Revenues: $25 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
Slide 43: Northern Access Project Status
Northern Access Project Status Capacity: 490,000 Dth/day Total Expected Cost: ~$500MM ($75.5MM spent to date, with minimal remaining commitments) Regulatory Status: FERC issued 7(c) certificate on February 3, 2017 Legal Actions Remain Pending: US Court of Appeals for the 2nd Circuit: On April 21, 20
Slide 44: Continued Expansion of the NFG Supply System
Continued Expansion of the NFG Supply System Line N Expansion Opportunities Line N to Monaca Project Project: Firm transportation service to a new ethylene cracker facility being built by Shell Chemical Appalachia, LLC Target In-Service: as early as June 2019 Est. Capital Cost: $20 million Contracte
Slide 45: Pipeline & Storage Customer Mix
Pipeline & Storage Customer Mix 4.1 MMDth/d Contracted as of 11/1/2017. Customer Transportation by Shipper Type(1) Affiliated Customer Mix (Contracted Capacity) Firm Transport Pipeline & Storage
Slide 46: Utility Overview
Utility Overview National Fuel Gas Distribution Corporation
Slide 47: New York & Pennsylvania Service Territories
New York & Pennsylvania Service Territories New York Total Customers(1): 530,400 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) System Modernizati
Slide 48: New York Rate Case Outcome
New York Rate Case Outcome Rate Order Summary: Revenue Requirement:$5.9 million Rate Base:$704 million Allowed Return on Equity (ROE):8.7% Capital Structure:42.9% equity Other notable items: New rates became effective 5/1/17 Retains rate mechanisms in place under prior order (revenue decoupling, wea
Slide 49: Utility: Strong Commitment to Safety
Utility: Strong Commitment to Safety The Utility remains focused on maintaining the ongoing safety and reliability of its system Capital Expenditures ($ millions)(1) A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this prese
Slide 50: Accelerating Pipeline Replacement & Modernization
Accelerating Pipeline Replacement & Modernization NY 9,723 miles PA* 4,832 miles * No Cast Iron Mains in Pa.* Miles of Utility Main Pipeline Replaced(1) Utility Mains by Material Utility (1) As reported to the Department of Transportation on calendar year basis.
Slide 51: A Proven History of Controlling Costs
A Proven History of Controlling Costs O&M Expense ($ millions) Utility
Slide 52: Appendix
Appendix
Slide 53: Hedge Positions and Prices
Hedge Positions and Prices Fixed price physical sales exclude joint development partner’s share of fixed price contract WDA volumes as specified under the joint development agreement. (1) Appendix Natural Gas Volumes in thousand MMBtu; Prices in $/MMBtu Fiscal 2018 (last 3 mos.) Fiscal 2019 Fiscal 2
Slide 54: Appalachia Drilling Program Economics
Appalachia Drilling Program Economics Net realized price reflects either (a) price received at the gathering system interconnect or (b) price received at delivery market net of firm transportation charges. Internal Rate of Return (IRR) is pre-tax and includes estimated well costs under current cost
Slide 55: Firm Transportation Commitments
Firm Transportation Commitments Volume (Dth/d) Production Source Delivery Market Demand Charges ($/Dth) Gas Marketing Strategy Northeast Supply Diversification Project Tennessee Gas Pipeline Niagara Expansion TGP & NFG Northern Access NFG – Supply & Empire Delayed 50,000 158,000 350,000 EDA -Tioga C
Slide 56: 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 57: Non-GAAP Reconciliations – Adjusted EBITDA
Non-GAAP Reconciliations – Adjusted EBITDA Appendix
Slide 58: Non-GAAP Reconciliations – Adjusted EBITDA, by Segment
Non-GAAP Reconciliations – Adjusted EBITDA, by Segment Appendix
Slide 59: Non-GAAP Reconciliations – Adjusted Operating Results
Non-GAAP Reconciliations – Adjusted Operating Results AppendixThree Months EndedNine Months EndedJune 30,June 30,(in thousands except per share amounts)2018201720182017Reported GAAP Earnings$63,025$59,714$353,527$237,906Items impacting comparabilityRemeasurement of deferred income taxesunder 2017 Ta
Slide 60: Non-GAAP Reconciliations – Capital Expenditures
Non-GAAP Reconciliations – Capital Expenditures Appendix
Slide 61: Non-GAAP Reconciliations – E&P Operating Expenses
Non-GAAP Reconciliations – E&P Operating Expenses Appendix