Investor Presentation Q3 Fiscal 2019 Update August 1, 2019 Exhibit 99
National Fuel is committed to the safe and environmentally conscious development, transportation, storage, and distribution of natural gas and oil resources. For additional information, please visit our corporate responsibility website at https://responsibility.natfuel.com
Developing our large, high quality acreage position in Marcellus & Utica shales(1) NFG: A Diversified, Integrated Natural Gas Company Providing safe, reliable and affordable service to customers in WNY and NW Pa. Upstream Exploration & Production Midstream Gathering Pipeline & Storage 38% of NFG EBITDA(1) Downstream Utility Energy Marketing % of NFG 20EBITDA(1) Expanding and modernizing pipeline infrastructure to provide outlets for Appalachian natural gas production 785,000 Net acres in Appalachia ~560 MMcf/day Net Appalachian natural gas production $1.6 Billion Investments since 2010 4.2 MMDth Daily interstate pipeline capacity under contract 750,000 Utility customers $300 Million Investments in safety since 2014 California: oil production generates significant cash flow (1) This presentation includes forward-looking statements. Please review the safe harbor for forward looking statements on slide 57 of this presentation. (2) Twelve months ending June 30, 2019. 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. 44% of NFG EBITDA(2) 34% of NFG EBITDA(2) 22% of NFG EBITDA(2) :
Why National Fuel? Large Appalachian Footprint Providing Long-Term Growth Opportunities
Midstream Integrated Model Enhances Shareholder Value . . . Ability to adjust to changing commodity price environments More efficient capital investment Higher returns on investment Operational scale Lower cost of capital Lower operating costs More competitive pipeline infrastructure projects Strong balance sheet Growing, stable dividend Geographic and Operational Integration Drives Synergies: Benefits of National Fuel’s Integrated Structure: Financial Efficiencies: Investment grade credit rating Shared borrowing capacity Consolidated income tax return Downstream Utility Energy Marketing Midstream Gathering Pipeline & Storage Upstream Exploration & Production Co-Development of Marcellus and Utica Just-in-time gathering facilities Pipeline expansion opportunities Upstream Rate-regulated entities share common resources, reducing operating expense Utility business is a large Pipeline & Storage customer Downstream Midstream 1
Integrated Upstream and Midstream development of 785,000 acre Marcellus and Utica shale position Drilling program focused on return trips to existing pads and use of existing infrastructure NFG Gathering transports 100% of natural gas production, driving consolidated returns NFG pipeline expansions under development create new firm takeaway capacity for NFG production Further expansion of interstate pipeline systems to satisfy growing natural gas supply and demand Supply push – Appalachian producers Demand pull – regional demand-driven projects and utilities Ongoing investment in safety and modernization of pipeline transportation and distribution systems $500+ million in new investments expected over the next 5 years . . . and Drives Organic Growth Opportunities Near Term Strategy Leverages Integration Across the Value Chain Utility Gathering Pipeline & Storage Exploration & Production
Impressive Dividend History $2.9 Billion Dividend payments since 1970 $1.74 per share 49 Years Consecutive Dividend Increases $0.19 per share 117 Years Consecutive Payments 3.7% yield(1) As of July 30, 2019. 2
1 E&P Growth Supported by Existing Firm Sales Portfolio . . . . . . And New Firm Transportation Capacity Providing Access to Premium Markets Production Growth Drives Consistent Increase in Gathering Revenues E&P 3 Future FT Capacity (Transco Zone 6) Firm Sales tied to Firm Transportation (FT) Capacity (Mid-Atlantic/Southeast & Canada-Dawn) Gross Production Trend (1) Gathering trend line represents 12.5% revenue growth, on average, from fiscal 2018 through fiscal 2022. 10-15% Gathering Revenue CAGR(1)
Utilization of Existing Infrastructure for Ongoing Utica Development Amplifies Consolidated Returns L Leveraging Existing Infrastructure to Enhance Returns Approximate WDA Marcellus gathering facility costs for 192 wells drilled and completed as of September 30, 2018. Estimated WDA Utica gathering facility costs for the assumed 120 well locations in the Clermont Rich Valley area of redevelopment. Internal Rate of Return for Seneca WDA includes estimated well costs under current cost structure, and anticipated LOE and Gathering costs. Internal Rate of Return for Seneca WDA and Gathering includes expected gathering capital expenditures through FY 2022, well costs under current cost structure, and non-gathering LOE. Gathering CapEx/Well ($ thousands) Marcellus (pre-2019) $1,489(1) Utica (2019-2022) $505(2) Gathering Pipelines Compression Water Handling Facilities Roadways and Pads Gathering Costs in Western Development Area (CRV) ~10% IRR Uplift Expected(3) Requires modest investment in new Gathering facilities to support production growth Utica development on Marcellus pads allows use of existing: Resulting in significant consolidated return uplift for E&P and Gathering 4
$1 Billion+ Backlog in Pipeline & Storage Projects Northern Access Delivery: Canada & NY 490,000 Dth/d Line N to Monaca Delivery: Shell ethane cracker facility (Beaver Co., Pa) 133,000 Dth/d FM100 Delivery: Transco (Leidy) 330,000 Dth/d Empire North Delivery: Canada & NY 205,000 Dth/d ~$150 Million in Potential Annual Expansion Revenues: Line N to Monaca: $5 MM Empire North: $25 MM FM100: $35 MM Northern Access: $84 MM $1.0 – $1.1 Billion in Pipeline Projects under Development: Expansion Projects: ~$850 million Supply Corp. Modernization: $150 - $250 million 5
Financial Highlights Third Quarter Fiscal 2019
Net Oil and Gas Production Third Quarter Fiscal 2019 Results and Drivers Adjusted Operating Results ($/share)(1) Adjusted Operating results of $0.73 for Q3 FY18 and $0.71 for Q3 FY19 include operating results of Energy Marketing and Corporate & All Other Segments segment. See slide 64 for a Reconciliation of Adjusted Operating Results to Earnings Per Share. Realized price after hedging. Oil and Gas Pricing(2) Natural Gas ($/Mcfe) Crude Oil ($/Bbl) Oil Prices Natural Gas Prices Gathering Revenue Seneca Gross Production Drivers Natural Gas Production Oil Production Crude Oil (Mbbl) Natural Gas (Bcf)
Earnings Guidance FY2019 Earnings Guidance Non-regulated Businesses Exploration & Production Gathering $3.40 to $3.50 /share(1) $3.25 to $3.55/share FY2020 Earnings Guidance Seneca Net Production: 235 to 245 Bcfe Gathering Revenues: $135-$145 million Natural Gas: ~$2.25/Mcf(2) (vs. $2.51/Mcf in FYTD 2019) Crude Oil: ~$63/Bbl(3) (vs. $61.88/Bbl in FYTD 2019) Key Guidance Drivers Excludes items impacting comparability. See non-GAAP disclosure on slide 64 of this presentation. For FY20, assumes NYMEX natural gas pricing of $2.55/MMBtu and in-basin spot pricing of $2.20/MMBtu for winter and $2.00/MMBtu for summer, and reflects the impact of existing financial hedges, firm sales and firm transportation contracts. Assumes NYMEX (WTI) oil pricing of $55.00/Bbl and California-MWSS pricing differentials of 108% to WTI for FY20 and reflects impact of existing financial hedge contracts. Production & Gathering Throughput Realized natural gas prices (after-hedge) Utility Operating Income Regulated Businesses Pipeline & Storage Utility Guidance assumes normal weather; higher gross margin expected to be offset by cost inflation ~$290-295 million in revenues (expansion revenues partial offset by full year of Empire contract expiration) Pipeline & Storage Revenues Tax Rate Realized oil prices (after-hedge) Higher effective tax rate Effective tax rate ~25% (enhanced oil recovery credit unavailable in FY2020)
Exploration & Production and Gathering Overview Seneca Resources Company, LLC ~ National Fuel Gas Midstream Company, LLC
Proved Reserves 361% Reserve Replacement Rate Seneca Drill-bit F&D = $0.66/Mcfe(1) Appalachia Drill-bit F&D = $0.65/Mcfe(1) Seneca “Drill-bit” finding and development (“F&D”) costs exclude the impact of reserve revisions. Total Proved Reserves (Bcfe) Fiscal 2018 Proved Reserves Stats 3-Year Average F&D Cost ($/Mcfe) E&P and Gathering
2-rig development program, with flexibility to adjust activity level Development focused in WDA-Utica, with return trips to existing pads expected to drive strong E&P and Gathering returns Gross production growth will benefit NFG’s Gathering segment Layer in additional firm sales in advance of new firm transportation capacity expected in late 2021 (Leidy South) Minimal capital investment in California to generate significant cash flow Growing Production within Disciplined Capital Program Near-Term Growth Strategy E&P Net Capital Expenditures ($ millions)(1) E&P Net Production (Bcfe) E&P and Gathering A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation. FY17 and FY18 reflects the netting of $157 million, $7 million and $17 million, respectively, of up-front proceeds received from joint development partner for working interest in joint development wells.
Significant Appalachian Acreage Position Average gross production: ~364 MMcf/d Mostly leased (16-18% royalty) with no significant near-term lease expirations ~79 remaining Marcellus & Utica locations economic at ~$1.82/Mcf Additional Marcellus (Tioga Co.) & Geneseo (Lycoming Co.) potential Eastern Development Area (EDA) Western Development Area (WDA) Average gross production(1): ~347 MMcf/d Large inventory of Marcellus & Utica locations economic at ~$2.00/Mcf Royalty free mineral ownership enhances well economics Highly contiguous nature drives cost and operational efficiencies E&P and Gathering EDA - 70,000 Acres WDA - 715,000 Acres (1) Average EDA and WDA gross production, as well as WDA-CRV Utica production (see slide 20) and Covington/Tract 595 Production (see slide 24), is for the quarter ended June 30, 2019.
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 limits of the Marcellus core acreage; planned testing in the Utica is expected to do the same. Area of Re-Development ~120 Utica locations on existing Marcellus pads ? Key Utica tests Past Marcellus delineation tests Utica Trend (currently evaluating) Marcellus Core Acreage Large well inventory economic at ~$2.00 /Mcf Marcellus Shale: 600+ well locations remaining / 200,000 acres Utica Shale: 500+ potential locations across Utica trend / evaluating extent of prospective acreage(2) Fee acreage (no royalty) enhances economics and provides development flexibility Use of existing gathering, pad, and water infrastructure for Utica drives increased Appalachian program returns Highly contiguous position drives best in class well costs Long-term firm contracts support growth Additional appraisal tests planned to delineate the Rich Valley to Boone Mountain corridor Boone Mountain Utica Test Well 2.3 Bcf /1,000ft Rich Valley Utica Test Well 2.3 Bcf /1,000ft E&P and Gathering WDA Highlights
WDA Utica Appraisal Results and Initial Type Curve Tested / producing from 21 Utica wells in WDA-CRV Drawdown management is critical: restricted drawdown appears to significantly improve well performance and EURs Produced fluid blend %: At high produced water blend rates, both well performance and EURs appear to be negatively impacted WDA Utica Appraisal Update WDA Economics Internal Rate of Return (IRR) is pre-tax and includes estimated well costs under current cost structure, LOE, and anticipated gathering tariffs. Initial WDA-CRV Utica type curve based on production results and reservoir expectations from the first 5 appraisal wells in the WDA-CRV area. WDA-CRV Utica Average includes 19 of 21 Utica wells brought online to date, including wells where produced fluid blend was greater than 95%. Average excludes 2 Utica wells (Pad E09-S) on which drawdown management was not used. E&P and Gathering EUR (Bcf/1000’) Well Cost ($M/1000’) IRR % $2.25(1) Break-even 15% IRR(1) Utica - CRV 1.7 $895 23% $1.97 Marcellus 1.0 – 1.1 $667 18% $2.11 (3) WDA-CRV Utica Wells – Normalized to 9,000’ (2)
CRV Return Trips Drive Utica Economics WDA-CRV Marcellus (Depth ~7,000 feet) WDA-CRV Utica (Depth ~12,000 feet) Avg. CRV Marcellus Production: 242 MMcf/d Rem. Avg. EUR 1.0-1.1 Bcf / 1,000 lat ft. Rem. Avg. Well Costs = $667/lat ft. CRV Utica Development Plan 1) Continue Optimizing Utica D&C design Additional optimization wells focusing on: Completion design (proppant loading, stage spacing, produced fluid blend) Landing zone targets Drawdown management 2) Continue transition to Utica development Future drilling on multi-well pads Continue using optimization results to determine development well design Tailor development plan to use existing pad, water and gathering infrastructure CRV Utica Development Utilizes Existing Pad, Water, and Gathering Infrastructure E&P and Gathering Avg. CRV Utica Production: 69 MMcf/d Est. EURs 1.7 Bcf / 1,000 lat ft. Est. Development Wells Costs = $895/lat ft. UPDATE Rich Valley Utica Test Existing Line Leased Seneca Fee Producing FY19 Producer Development
Leveraging Existing Gathering, Water and Pad Infrastructure Enhances Returns Limited New Infrastructure Needed to Support Production Growth WDA Well Costs(1) WDA Consolidated Economics Coordination between upstream and midstream activities enhances return, provides economies of scale and significant operational flexibility WDA Marcellus well costs reflect drilling, completion & gathering costs for 192 drilled and completed wells as of 9/30/18. WDA Utica well costs reflect expected drilling, completion & gathering costs for the ~120 well locations in area of redevelopment. Internal Rate of Return for Seneca WDA includes estimated well costs under current cost structure, and anticipated LOE and Gathering costs. Internal Rate of Return for Seneca WDA and Gathering includes expected gathering capital expenditures through FY 2022, well costs under current cost structure, and non-gathering LOE. Total cost per well expected to marginally increase WDA EURs At a $2.25 netback price, consolidated Seneca WDA and Gathering IRR is approximately 30%, an uplift of ~10% over standalone Seneca WDA economics(2) ~10% IRR Uplift Expected E&P and Gathering
Integrated Development – WDA Gathering System Current System In-Service ~98 miles of pipe / 36,220 HP of compression Current Capacity: 470 MMcf per day Interconnects with TGP 300 and NFG Supply Total Investment to Date: $306 million Future Build-Out FY 2019 CapEx: $9 - $12 million Modest gathering pipeline and compression investment required to support Seneca’s Utica development Opportunity for 300 miles of pipelines and six compressor stations (+60,000 HP installed) as Seneca’s drilling activity continues Gathering System Build-Out Tailored to Accommodate Seneca’s WDA Development Clermont Gathering System Map E&P and Gathering
WDA Firm Transportation and Sales Capacity 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 pricing, typically 10¢ - 20¢ better than TGP Marcellus Zone 4 Leidy South will provide additional capacity to premium markets (Transco Zone 6) WDA Exit Capacity Supports Long-term Production Growth and Enhances Consolidated Returns WDA Contracted Firm Transport and Gross Sales Volumes (MDth/d) Seneca gross production trend E&P and Gathering Niagara Expansion Project (TGP and NFG) FT Capacity: 158,000 Dth/d @ $0.67/Dth Firm Sales: NYMEX & DAWN WDA - TGP 300 Firm Sales Leidy South Transco Zone 6 330,000 Dth/d(1) Will layer-in firm sales to minimize spot exposure Portion of Leidy South capacity will likely be utilized by EDA Lycoming County production. WDA Gas Marketing Strategy
Eastern Development Area EDA Acreage – 70,000 Acres EDA Highlights 1 DCNR Tract 007 (Tioga Co., Pa) Utica development resumed in third quarter fiscal 2018 ~43 remaining Utica locations economic at ~$1.82 /Mcf Gathering infrastructure: NFG Midstream Wellsboro Marcellus Shale expected to provide ~60 additional locations E&P and Gathering 2 1 3 2 Covington & DCNR Tract 595 (Tioga Co., Pa.) Marcellus locations fully developed (average daily gross production of ~79 MMcf/d) Gathering infrastructure: NFG Midstream Covington Opportunity for future Utica appraisal 3 DCNR Tract 100 & Gamble (Lycoming Co., Pa.) ~36 remaining Marcellus locations economic at ~$1.59 /Mcf Firm transportation capacity: Atlantic Sunrise (189 MDth/d) Gathering infrastructure: NFG Midstream Trout Run Geneseo Shale expected to provide 100-120 additional locations
EDA Marcellus: Lycoming County Development Marcellus Development in Lycoming County has Resumed in Connection with Atlantic Sunrise Includes physical fixed price and NYMEX-based firm sales contracts that do not carry any additional transportation costs. E&P and Gathering Prolific Marcellus acreage with peer leading well results ~36 remaining Marcellus locations economic at ~$1.59 /Mcf Near-term development focused on filling Atlantic Sunrise capacity Transco Firm Sales(1) Existing Line Leased Seneca Fee Producing FY19 Producer Development
EDA Utica: Tioga County Development Development Focused on Tract 007 Production Area, with Production Underpinned by Firm Sales (1) Includes physical fixed price and NYMEX-based firm sales contracts that do not carry any additional transportation costs. E&P and Gathering Northeast Supply Diversification Project FT Capacity: 50,000 Dth/d @ $0.50/Dth Firm Sales: NYMEX and DAWN EDA - TGP 300 Firm Sales(1) Existing Line Leased Seneca Fee Producing FY19 Producer Development UPDATE EDA – TGP 300 Firm Contracts DCNR Tract 007
EDA Utica: Tioga County Development Tract 007 Utica Wells Brought Online in Q2 Fiscal 2019 Tracking Best Industry Results to Date Production from first multi-well pad (4 wells) brought online in February/March 2019 Early results compare favorably with industry Potter/Tioga Co. wells Expected development cost: $1,027 per lateral ft. ~43 remaining locations economic at ~$1.82/Mcf Tract 007 Utica Well Results vs. Industry E&P and Gathering Tract 007 Utica Development Update Tract 007 Pad K Early Well Results(1) All numbers are average of 4 Pad K wells brought online in February and March 2019. Three wells brought online in February 2019 restricted to 15 MMCFPD, and one well brought online in late March 2019 restricted to ~10 MMCFPD. (1) Well Count: 4 Lateral Length: 7,582’ Months On-Line: 4-5 IP30 Rate (Avg.): 13.8 MMcf/day IP120 Rate (Avg.): 13.8 MMcf/day Drawdown Management: restricted drawdown appears to improve well performance Early production limited to 10-15 MMcf/day by drawdown management(2)
Integrated Development – EDA Gathering Systems Total Investment (to date): ~$47 million FY 2019 Estimated Capital Expenditures: $1 MM - $2 MM 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): ~$226 million FY 2019 Estimated Capital Expenditures: $24 MM - $30 MM Capacity: 466,000 to 585,000 Dth per day (Interconnect w/ Transco) Production Source: Seneca Resources – Lycoming Co. (DCNR Tract 100 and Gamble) Future third-party volume opportunities Covington Gathering System Trout Run Gathering System Gathering Segment Supporting Seneca’s EDA Production & Future Development Wellsboro Gathering System Total Investment (to date): ~$20 million FY 2019 Estimated Capital Expenditures: $11 MM - $13 MM Capacity: up to 200,000 Dth per day (Interconnect w/ TGP 300) Production Source: Seneca Resources – Tioga Co. (DCNR Tract 007) E&P and Gathering 2 1 3
Long-term Contracts Supporting Appalachian Growth Represents base firm sales contracts not tied to firm transportation capacity. Base firm sales are either fixed priced or priced at an index (e.g., NYMEX ) +/- a fixed basis and do not carry any transportation costs. Seneca continues to layer-in firm sales contracts with attractive realizations to lock-in drilling economics and minimize spot exposure ahead of firm transportation in-service dates E&P and Gathering Gross Production Trend Northeast Supply Diversification 50,000 Dth/d Niagara Expansion (TGP & NFG) Delivery Markets: Canada-Dawn & TETCO 158,000 Dth/d Atlantic Sunrise (Transco) Delivery Markets: Mid-Atlantic & Southeast U.S. 189,405 Dth/d In-Basin Firm Sales Contracts(1) Leidy South (Transco & NFG) Transco Zone 6 330,000 Dth/d Seneca Appalachia Natural Gas Marketing Gross Firm Contract Volumes (Mdth/day)
Near-term Firm Sales Provide Market & Price Certainty Net Contracted Firm Sales Volumes (Dth per day) Contracted Index Price Differentials ($ per Dth)(1) Actual Daily Net Production 653,400 640,500 659,300 684,400 676,900 Gross Firm Sales Volumes (Dth/d) E&P and Gathering Actual Daily Net Production Actual Daily Net Production Values shown represent the weighted average fixed price or weighted average differential relative to NYMEX (netback price) less any associated transportation costs. Transportation costs include minor variable components such as the Canadian exchange rate and fuel components. With respect to “Other”, the weighted average differential relative to NYMEX (netback price) includes net contracted firm sales at various indices, which are to subject to fluctuations in the market, such as seasonal demand swings, and is calculated using forward basis at various associated locations as specified by the underlying contract.
California Oil Stable Oil Production | Minimal Capital Investment | Steady Free Cash Flow 1 2 3 4 5 Location Formation Production Method Avg. Daily Production (net Boe/d)(1) 1 East Coalinga/ Other Temblor Primary 482 2 North Lost Hills Tulare & Etchegoin Primary/ Steam flood 878 3 South Lost Hills Monterey Shale Primary 1,268 4 North Midway Sunset Tulare & Potter Steam flood 2,853 5 South Midway Sunset Antelope Steam flood 1,745 TOTAL WEST DIVISION AVG. NET PRODUCTION(1) 7,226 Boe/d E&P and Gathering (1) Average daily net production (oil and natural gas) for West division for quarter ended June 30, 2019.
California Capital Expenditures vs. Production West Division Average Net Daily Production (Boe) West Division Annual Capital Expenditures ($ MM)(1) Estimate Estimate Seneca West Division capital expenditures includes Seneca corporate and eliminations. E&P and Gathering Sespe Sale Closed on 5/1/18 (reduced production by ~900 Boe/d) Estimate Estimate
Pioneer South MWSS Acreage North MWSS Acreage Sec. 17N California Development Activities 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, Pioneer, and East Coalinga development to provide future growth Midway-Sunset North Project IRRs at $57.50/Bbl(1) Reflects pre-tax IRRs at a $57.50/Bbl WTI. E&P and Gathering Seneca West Economics South East Coalinga North South
Fiscal 2019 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 financial hedge. 40 Bcf locked-in realizing net ~$2.42/Mcf (1) 6 Bcf of additional basis protection Spot production assumed to be sold at $2.10 / MMBtu 46 Bcf of Appalachian Production Protected by Firm Sales for Remainder of Year 79% of oil production hedged at $57.57 /Bbl E&P and Gathering
Fiscal 2020 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 financial hedge. 92 Bcf locked-in realizing net ~$2.40/Mcf (1) 103 Bcf of additional basis protection Spot production assumed to be sold at ~$2.20/MMBtu (winter) and ~$2.00/ MMBtu (summer) 195 Bcf of Appalachian Production Protected by Firm Sales 67% of oil production hedged at $61.77 /Bbl E&P and Gathering
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 remaining 3 months of FY19 hedged at the midpoint of Seneca’s production guidance. Reflects percentage of projected production for FY20 hedged at the midpoint of the production guidance range. Seneca’s remaining FY19 production reflects guidance of 205-215 Bcfe less actual production for Q1, Q2 and Q3 FY 2019. Crude Oil Swap Contracts (Thousands Bbls) (1) FY 19 Nat Gas 75% Hedged(2) FY 2019 Remaining Production(4) FY 2019 Remaining Production(4) E&P and Gathering FY 20 Nat Gas 41% Hedged(3)
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 $/Mcfe (1) (2) (2) G&A estimate represents the midpoint of the G&A guidance of ~$0.30 for fiscal 2019, and of $0.25 to $0.30 for fiscal 2020. The total of the two LOE components represents the midpoint of the LOE guidance range of $0.85 to $0.90 for fiscal 2019, and $0.85 to $0.90 for fiscal 2020. E&P and Gathering
Pipeline and Storage Overview National Fuel Gas Supply Corporation ~ Empire Pipeline, Inc.
Pipeline & Storage Segment Overview As of September 30, 2018 as disclosed in the Company’s fiscal 2018 form 10-K. As of December 31, 2018 calculated from National Fuel Gas Supply Corporation’s and Empire Pipeline, Inc.’s 2018 FERC Form-2 reports, respectively. Empire Pipeline, Inc. National Fuel Gas Supply Corporation Empire Pipeline Supply Corp. Contracted Capacity(1): Firm Transportation: 3,187 MDth per day Firm Storage: 71,938 Mdth (fully subscribed) Rate Base(2): ~$863 million FERC Rate Proceeding Status: Filed rate case on 7/31/19 New rates expected to go into effect (subject to refund) on 2/1/20 Contracted Capacity(1): Firm Transportation: 978 MDth per day Firm Storage: 3,753 Mdth (fully subscribed) Rate Base(2): ~$247 million FERC Rate Proceeding Status: Rate case settlement approved May 2019 New transportation rates went into effect on 1/1/19 Pipeline & Storage
All Seneca volumes will flow through wholly-owned NFG gathering facilities FM100 Project - Consolidated Benefit for NFG 330,000 Dth/d of new transportation capacity from WDA and EDA acreage positions to premium markets New Transco capacity (Leidy South): 330,000 Dth/day Rate(1) : competitive with other expansion project rates in Seneca’s current transportation portfolio Delivery point(s): Transco Zone 6 interconnections Seneca Lease to Transco of new capacity: 330,000 Dth/day Estimated annual lease revenues: ~$35 million Target in-service: late calendar year 2021 Supply Corp. Project expected to provide long-term earnings uplift to Seneca, Supply Corp. and Gathering Pipeline & Storage Gathering (1) Includes lease of new capacity from Supply Corp. to Transco.
FM100 Project – Significant Investment by Supply Corp. Pipeline & Storage Estimated capital cost: $279 million Expansion facilities: ~159 million Modernization facilities: ~$120 million Facilities (all in Pennsylvania) include: Approximately 30 miles of new pipeline 2 new compressor stations (totaling approximately 37,000 HP) New interconnection station and modification of existing interconnection station Abandonment of approximately 45 miles of existing pipeline and compressor station Regulatory process: FERC 7(b) / 7(c) certificate application submitted 7/18/19
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 interconnect) Customers: Fully subscribed (205,000 Dth/day) Major facilities: 2 new compressor stations in NY (1) & Pa. (1) No new pipeline construction Regulatory process: FERC Certificate issued 3/7/19 FERC Notice to Proceed issued 5/2/19 Pipeline & Storage Fully Subscribed Project will Provide 205,000 Dth/day of Incremental Firm Transportation
Northern Access Project In-service: as early as fiscal 2022 Total cost: ~$500 MM(1) (~$57 MM spent to date) Estimated annual revenues: ~$84 million Delivery points: 350,000 Dth/d to Chippawa (TCPL interconnect) 140,000 Dth/d to East Aurora (TGP 200 line) Regulatory/legal status: Feb. 2017 – FERC 7(c) certificate issued Aug. 2018 – FERC issued Order finding that NY DEC waived water quality certification (WQC) Feb. 2019 – U.S. Second Circuit Court of Appeals vacated and remanded NY DEC denial of WQC April 2019 – FERC denied rehearing of WQC waiver order (upholding waiver finding) Supply and Empire currently working to finalize remaining federal authorizations Pipeline & Storage To Dawn NE US (TGP 200) (1) Preliminary Cost Estimate
Continued Expansion of the NFG Supply System Line N Expansion Opportunities Line N to Monaca Project Project: Firm transportation service to a new ethane cracker facility being built by Shell Chemical Appalachia, LLC Target in-service: Sept. 2019 (under construction) Estimated capital cost: $24 million Contracted capacity: 133,000 Dth/day Additional Line N Expansion Opportunity (Supply OS #221) Project: New firm transportation service for on-system demand Open season capacity: Awarded 165,000 Dth/day to foundation shipper. Precedent agreement in negotiations. Pipeline & Storage
Pipeline & Storage Customer Mix 4.2 MMDth/d Contracted as of 10/31/2018. Customer Transportation by Shipper Type(1) Affiliated Customer Mix (Contracted Capacity) Firm Transport Pipeline & Storage
Utility Overview National Fuel Gas Distribution Corporation
New York & Pennsylvania Service Territories New York Total Customers(1): 535,800 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 Modernization Tracker Pennsylvania Total Customers(1): 214,400 ROE: Black Box Settlement (2007) Rate Mechanisms: Low Income Rates Merchant Function Charge As of September 30, 2018. Utility
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, weather normalization, merchant function charge, 90/10 large customer sharing) System modernization tracker for Leak Prone Pipe (LPP) Earnings sharing started 4/1/18 (50/50 sharing starts at ROE in excess of 9.2%) On April 20, 2017, the New York Public Service Commission issued a Rate Order relating to NFG Distribution’s rate case (No. 16-G-0257) filed in April 2016. Utility
Utility Continues its Significant Investments in Safety Modernization Spending in NY Expected to Grow Gross Margin By $2 MM - $5 MM Annually (1) A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation. Utility System modernization tracker in NY allows recovery of pipeline replacement costs, which is expected to drive modest gross margin and rate base growth
Accelerating Pipeline Replacement & Modernization NY 9,726 miles PA* 4,830 miles * No Cast Iron Mains in Pa.* Miles of Utility Main Pipeline Replaced Utility Mains by Material(1) Utility (1) All values are reported on a calendar year basis as of December 31, 2018.
A Proven History of Controlling Costs Utility O&M Expense ($ millions) Utility (1) (1) For purposes of comparability to FY 2015, 2016 and 2017, Utility Operation and Maintenance Expense for FY 2018 and the twelve months ended June 30, 2019 was adjusted by approximately $31.4 million and $29.3 million, respectively, to include non-service pension costs, which were re-classified as Other Income (Deductions) as of October 1, 2018 on the Company’s Income Statement. See Slide 67 for non-GAAP reconciliation of Adjusted Operation and Maintenance Expense to Operation and Maintenance Expense, by segment.
Consolidated Financial Overview Upstream I Midstream I Downstream
Adjusted Operating Results ($ 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 presentation. Consolidated Adjusted EBITDA includes Energy Marketing, and Corporate & All Other Segments. A reconciliation of Adjusted EBITDA to Net Income, by segment, as presented on the Consolidated Statement of Income and Earnings Reinvested in the Business is included at the end of this presentation. Adjusted EBITDA ($ millions)(2) Rate Regulated ~45% Rate Regulated ~44%
Disciplined, Flexible Capital Allocation (2) Total Capital Expenditures include Energy Marketing, Corporate and All Other. 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 reflects the netting of $157 million, $7 million, and $17 million, respectively, of up-front proceeds received from joint development partner for working interest in joint development wells, and $21M in intercompany asset transfers in FY18. Capital Expenditures by Segment ($ millions)(1)
Maintaining Strong Balance Sheet & Liquidity Total Debt 50% $4.3 Billion Total Capitalization as of June 30, 2019 Net Debt / Adjusted EBITDA(1) Capitalization Debt Maturity Profile ($MM) Liquidity Committed Credit Facilities Short-term Debt Outstanding Available Short-term Credit Facilities Cash Balance at 6/30/19 Total Liquidity at 6/30/19 $ 750 MM 0 MM 750 MM 88 MM $ 838 MM Net Debt is net of cash and temporary cash investments. Reconciliations of Net Debt and Adjusted EBITDA to Net Income are included at the end of this presentation.
Appendix
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, strategies, future events or performance and underlying assumptions, capital structure, anticipated capital expenditures, completion of construction projects, projections for pension and other post-retirement benefit obligations, impacts of the adoption of new accounting rules, and possible outcomes of litigation or regulatory proceedings, as well as statements that are identified by the use of the words “anticipates,” “estimates,” “expects,” “forecasts,” “intends,” “plans,” “predicts,” “projects,” “believes,” “seeks,” “will,” “may,” and similar expressions. Forward-looking statements involve risks and uncertainties which could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. The Company’s expectations, beliefs and projections are expressed in good faith and are believed by the Company to have a reasonable basis, but there can be no assurance that management’s expectations, beliefs or projections will result or be achieved or accomplished. In addition to other factors, the following are important factors that could cause actual results to differ materially from those discussed in the forward-looking statements: changes in laws, regulations or judicial interpretations to which the Company is subject, including those involving derivatives, taxes, safety, employment, climate change, other environmental matters, real property, and exploration and production activities such as hydraulic fracturing; delays or changes in costs or plans with respect to Company projects or related projects of other companies, including difficulties or delays in obtaining necessary governmental approvals, permits or orders or in obtaining the cooperation of interconnecting facility operators; governmental/regulatory actions, initiatives and proceedings, including those involving rate cases (which address, among other things, target rates of return, rate design and retained natural gas), environmental/safety requirements, affiliate relationships, industry structure, and franchise renewal; financial and economic conditions, including the availability of credit, and occurrences affecting the Company’s ability to obtain financing on acceptable terms for working capital, capital expenditures and other investments, including any downgrades in the Company’s credit ratings and changes in interest rates and other capital market conditions; changes in the price of natural gas or oil; impairments under the SEC’s full cost ceiling test for natural gas and oil reserves; factors affecting the Company’s ability to successfully identify, drill for and produce economically viable natural gas and oil reserves, including among others geology, lease availability, title disputes, weather conditions, shortages, delays or unavailability of equipment and services required in drilling operations, insufficient gathering, processing and transportation capacity, the need to obtain governmental approvals and permits, and compliance with environmental laws and regulations; increasing health care costs and the resulting effect on health insurance premiums and on the obligation to provide other post-retirement benefits; changes in price differentials between similar quantities of natural gas or oil sold at different geographic locations, and the effect of such changes on commodity production, revenues and demand for pipeline transportation capacity to or from such locations; other changes in price differentials between similar quantities of natural gas or oil having different quality, heating value, hydrocarbon mix or delivery date; the cost and effects of legal and administrative claims against the Company or activist shareholder campaigns to effect changes at the Company; uncertainty of oil and gas reserve estimates; significant differences between the Company’s projected and actual production levels for natural gas or oil; changes in demographic patterns and weather conditions; changes in the availability, price or accounting treatment of derivative financial instruments; changes in laws, actuarial assumptions, the interest rate environment and the return on plan/trust assets related to the Company’s pension and other post-retirement benefits, which can affect future funding obligations and costs and plan liabilities; changes in economic conditions, including global, national or regional recessions, and their effect on the demand for, and customers’ ability to pay for, the Company’s products and services; the creditworthiness or performance of the Company’s key suppliers, customers and counterparties; the impact of information technology, cybersecurity or data security breaches; economic disruptions or uninsured losses resulting from major accidents, fires, severe weather, natural disasters, terrorist activities or acts of war; significant differences between the Company’s projected and actual capital expenditures and operating expenses; or increasing costs of insurance, changes in coverage and the ability to obtain insurance. Forward-looking statements include estimates of oil and gas quantities. Proved oil and gas reserves are those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible under existing economic conditions, operating methods and government regulations. Other estimates of oil and gas quantities, including estimates of probable reserves, possible reserves, and resource potential, are by their nature more speculative than estimates of proved reserves. Accordingly, estimates other than proved reserves are subject to substantially greater risk of being actually realized. Investors are urged to consider closely the disclosure in our Form 10-K available at www.nationalfuelgas.com. You can also obtain this form on the SEC’s website at www.sec.gov. For a discussion of the risks set forth above and other factors that could cause actual results to differ materially from results referred to in the forward-looking statements, see “Risk Factors” in the Company’s Form 10-K for the fiscal year ended September 30, 2018 and the Forms 10-Q for the quarter ended December 31, 2018, March 31, 2019, and June 30, 2019. The Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date thereof or to reflect the occurrence of unanticipated events. Appendix
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 2019 (last 3 mos.) Fiscal 2020 Fiscal 2021 Fiscal 2022 Fiscal 2023 Volume Avg.Price Volume Avg.Price Volume Avg.Price Volume Avg.Price Volume Avg.Price NYMEX Swaps 20040 $2.93 40990 $2.92 6790 $2.95 - - - - Dawn Swaps 1800 $3 7200 $3 600 $3 - - - - Fixed Price Physical 19579.555 $2.61 46430.853999999999 $2.37 41381.641000000003 $2.2200000000000002 40533.125 $2.23 37174.129999999997 $2.25 Total 41419.555 $2.78 94620.853999999992 $2.65 48771.641000000003 $2.33 40533.125 $2.23 37174.129999999997 $2.25 Crude Oil Volumes & Prices in Bbl Fiscal 2019 (last 3 mos.) Fiscal 2020 Fiscal 2021 Fiscal 2022 Fiscal 2023 Volume Avg. Volume Avg. Volume Avg. Volume Avg. Volume Avg. Price Price Price Price Price Brent Swaps 186000 $63.52 1260000 $64.66 576000 $64.48 300000 $60.07 - - NYMEX Swaps 267000 $53.42 324000 $50.52 156000 $51 156000 $51 - - Total 453000 $57.57 1584000 $61.77 732000 $61.61 456000 $56.97 - -
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 structure, LOE, and Gathering tariffs anticipated for each prospect. Large Marcellus and Utica Inventory Economic at ~$2.00/MMBtu(1) Appendix Prospect Reservoir Locations Remainingto Be Drilled Completed Lateral Length (ft) EUR / 1000' (Bcf) Well Cost$M/1,000 ft Internal Rate of Return % (2) Realized Price(1) Required for 15% IRR Anticipated DeliveryMarkets EUR / 1000' (Bcf) $2.50Realized $2.25Realized $2.00Realized EDA Tract 100 & GambleLycoming Co. Marcellus 36 4700 2.5 $1,135 0.67 0.51 0.38 $1.59 Transco Leidy &Atlantic Sunrise Southeast US(NYMEX+) DCNR 007Tioga Co. Utica 43 8300 2 $1,027 0.51 0.37 0.24 $1.82 TGP 300 WDA Clermont Rich Valley Utica 120+ 9000 1.7 $895 0.3 0.23 0.16 $1.97 TGP 300, Niagara Expansion Canada (Dawn), & FM100/Leidy South (Transco Zone 6) Core Areas Marcellus 600+ 8500 1.0 to 1.1 $667 0.24 0.18 0.13 $2.11 FY15Q3:
Firm Transportation Commitments Volume (Dth/d) Production Source Delivery Market Demand Charges ($/Dth) Gas Marketing Strategy Northeast Supply Diversification Tennessee Gas Pipeline Niagara Expansion TGP & NFG Northern Access NFG – Supply & Empire In-service: as early as FY 2022 50,000 158,000 350,000 EDA -Tioga County Covington & Tract 595 WDA – Clermont/ Rich Valley WDA – Clermont/ Rich Valley 12,000 140,000 Canada (Dawn) Canada (Dawn) TETCO (SE Pa.) Canada (Dawn) TGP 200 (NY) $0.50 (3rd party) NFG pipelines = $0.24 3rd party = $0.43 NFG pipelines = $0.12 NFG pipelines = $0.38 NFG pipelines = $0.50 3rd party = $0.21 Firm Sales Contracts 50,000 Dth/d Dawn/NYMEX+ 10 years Currently In-Service Future Capacity Firm Sales Contracts 158,000 Dth/d Dawn/NYMEX+ 8 to 15 years Atlantic Sunrise WMB - Transco 189,405 EDA - Lycoming County Tract 100 & Gamble Mid-Atlantic/ Southeast $0.73 (3rd party) Firm Sales Contracts 189,405 Dth/d NYMEX+ First 5 years Firm Sales Contracts at Dawn when project goes in-service Transco Leidy South / NFG FM100 WMB – Transco; NFG - Supply In-service: late 2021 330,000 WDA – Clermont/ Rich Valley and EDA - Lycoming County Transco Zone 6 Competitive with other expansion project rates in Seneca’s transportation portfolio(1) Seneca to pursue Firm Sales Contracts as project development progresses (1) Seneca’s Leidy South transportation rate is inclusive of Transco’s lease payments (~$35 million annually) to Supply Corp. for new capacity created by FM100 Project. Appendix
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 follow. The Company believes that its non-GAAP financial measures are useful to investors because they provide an alternative method for assessing the Company’s ongoing operating results and for comparing the Company’s financial performance to other companies. The Company’s management uses these non-GAAP financial measures for the same purpose, and for planning and forecasting purposes. The presentation of non-GAAP financial measures is not meant to be a substitute for financial measures prepared in accordance with GAAP. Management defines Adjusted Operating Results as reported GAAP earnings before items impacting comparability. The Company’s fiscal 2019 earnings guidance range does not include the impact of certain items that impacted the comparability of earnings during the nine months ended June 30, 2019, including: (1) the remeasurement of deferred income taxes resulting from the 2017 Tax Reform Act, which reduced the Company’s income tax expense and benefited consolidated earnings in the nine months ended June 30, 2019 by $0.06 per share; (2) the full year impact of the Exploration and Production segment’s unrealized gain on hedging ineffectiveness; and (3) the unrealized loss on other investments due to the change in an accounting rule, which lowered earnings by $0.01 per share. While the Company expects to record additional adjustments to one or more of these items during the remaining three months ending September 30, 2019, the amounts of these and other potential adjustments are not reasonably determinable at this time. As such, the Company is unable to provide earnings guidance other than on a non-GAAP basis. Management defines Adjusted EBITDA as reported GAAP earnings before the following items: interest expense, income taxes, depreciation, depletion and amortization, interest and other income, impairments, and other items reflected in operating income that impact comparability. Appendix
Non-GAAP Reconciliations – Adjusted EBITDA Appendix Total Adjusted EBITDA for FY 2018 and the twelve months ended June 30, 2019 include the reclassification of non-service pension costs from Operating and Maintenance Expense to Other Income (Deductions) as of October 1, 2018 on the Company’s Income Statement, which on a consolidated basis were approximately $32.6 million in FY 2018 and approximately $29.5 million for the twelve months ended June 30, 2019. This reclassification is not reflected in Total Adjusted EBITDA for FY 2015, FY 2016 or FY 2017. (1) (1)
Non-GAAP Reconciliations – Adjusted EBITDA, by Segment Appendix
Non-GAAP Reconciliations – Adjusted Operating Results Appendix Three Months Ended Nine Months Ended June 30, June 30, (in thousands except per share amounts) 2019 2018 2019 2018 Reported GAAP Earnings $ 63,753 $ 63,025 $ 257,009 $ 353,527 Items impacting comparability Remeasurement of deferred income taxes under 2017 Tax Reform — — (5,000 ) (107,000 ) Mark-to-market adjustments due to hedge ineffectiveness (E&P) (1,020 ) 339 (783 ) 436 Tax impact of mark-to-market adjustments due to hedge ineffectiveness 214 (83) 164 (107 ) Unrealized (gain) loss on other investments (Corporate / All Other) (1,420 ) — 1,096 — Tax impact of unrealized (gain) loss on other investments 298 — (230 ) — Adjusted Operating Results $ 61,825 $ 63,281 $ 252,256 $ 246,856 Reported GAAP Earnings per share $ 0.73 $ 0.73 $ 2.96 $ 4.09 Items impacting comparability Remeasurement of deferred income taxes under 2017 Tax Reform — — (0.06 ) (1.24 ) Mark-to-market adjustments due to hedge ineffectiveness (E&P) (0.01 ) — (0.01) 0.01 Tax impact of mark-to-market adjustments due to hedge ineffectiveness — — — — Unrealized (gain) loss on other investments (Corporate / All Other) (0.02 ) — 0.01 — Tax impact of unrealized (gain) loss on other investments — — — — Rounding 0.01 — 0.01 — Adjusted Operating Results per share $ 0.71 $ 0.73 $ 2.91 $ 2.86 Fiscal Year Ended September 30, (in thousands except per share amounts) 2018 2017 Reported GAAP Earnings $ 391,521 $ 283,482 Items impacting comparability Remeasurement of deferred income taxes under 2017 Tax Reform (103,484 ) — Premium paid on early redemption of debt (E&P) 962 — Tax impact on premium paid on early redemption of debt (235 ) — Adjusted Operating Results $ 288,764 $ 283,482 Reported GAAP Earnings per share $ 4.53 $ 3.30 Items impacting comparability Remeasurement of deferred income taxes under 2017 Tax Reform (1.20 ) — Premium paid on early redemption of debt, net of tax 0.01 — Adjusted Operating Results per share $ 3.34 $ 3.30
Non-GAAP Reconciliations – Capital Expenditures Appendix
Non-GAAP Reconciliations – E&P Operating Expenses Appendix
Non-GAAP Reconciliations – Adjusted Operation & Maintenance Expense Appendix
