Investor Presentation Scotia Howard Weil Energy Conference March 26 - 28, 2018 Exhibit 99
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, in the view of the Company, could cause actual results to differ materially from those discussed in the forward-looking statements: 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; 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; impairments under the SEC’s full cost ceiling test for natural gas and oil reserves; changes in the price of natural gas or oil; 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; 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 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; economic disruptions or uninsured losses resulting from major accidents, fires, severe weather, natural disasters, terrorist activities, acts of war, cyber attacks or pest infestation; 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, 2017 and the Form 10-Q for the quarter ended December 31, 2017. 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.
NFG: A Diversified Natural Gas Company Providing significant base of stable, regulated earnings and cash flows 743,500 Utility customer accounts in NY & PA For the trailing twelve months ended December 31, 2017. 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. Upstream E&P Midstream Gathering Pipeline & Storage Downstream Utility Energy Marketing Developing our large, high quality acreage position in Marcellus & Utica shales with a focus on returns 785,000 Net acres in Appalachia Expanding and modernizing pipeline infrastructure to provide access to Appalachian supplies $273 million1 Annual Adjusted EBITDA
Creating Long-Term, Sustainable Shareholder Value Opportunity for Considerable Upstream and Midstream Growth in Appalachia 1 Unique Integration and Diversified Asset Mix Serves as Foundation for Growth Strategy 2 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 acreage a significant competitive advantage Stacked Marcellus and Utica development / reutilization of gathering infrastructure improves drilling economics and enhances consolidated returns Positioned to expand / modernize pipeline systems to accommodate regional supply growth Geographic and operational integration lowers costs and drives financial efficiencies Significant base of stable, regulated earnings and cash flows supports dividend and helps to lower our cost of capital 100% ownership of midstream assets (no MLP) preserves capital flexibility and better aligns corporate strategic goals Long-term capital plans designed to grow earnings for each business segment, live within cash flows and achieve value-added returns on capital employed Production and gathering growth underpinned by long-term sales contracts and hedges Strong balance sheet provides financial flexibility 47-year track record of growing the dividend
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 pipeline infrastructure projects Higher returns on investment Strong balance sheet Growing, stable dividend Utility and Pipeline & Storage Operational Synergies Upstream and Midstream Strategic Development Commercial Relationships Financial Efficiencies Rate-regulated entities reduce operating expenses by sharing common: Management Engineering Field labor Facilities Back office Gas dispatch center Warehouse IT systems Vehicles Tools & equipment Investment grade credit rating Shared borrowing capacity Consolidated income tax return Balanced earnings and diversified cash flows support dividend Benefits of NFG Integrated Model Utility and Energy Marketing segments are significant Pipeline & Storage customers: 29% of contracted firm transport capacity 43% of contracted firm storage capacity Coordinated development in Appalachia drives long-term growth and enhances consolidated returns: Co-development of Marcellus and Utica Installing just-in-time gathering infrastructure Expanding pipeline transmission infrastructure to reach demand markets
Dividend Track Record $2.8 Billion Dividend payments since 1970 $1.66 per share 47 Years Consecutive Dividend Increases $0.19 per share 115 Years Consecutive Payments 3.3% yield(1) As of March 21, 2018.
Adjusted EBITDA by Segment ($ 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.
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. FY16, FY17, and FY18 guidance reflects the netting of $157 million, $7 million, and $17 million, respectively, of up-front proceeds received from joint development partner for working interest in joint development wells. Capital Expenditures by Segment ($ millions)(1)
Maintaining Strong Balance Sheet & Liquidity Total Debt 53% $3.9 Billion Total Capitalization as of December 31, 2017 Net Debt / Adjusted EBITDA(1) Capitalization Debt Maturity Profile ($MM) Liquidity Committed Credit Facilities Short-term Debt Outstanding Available Short-term Credit Facilities Cash Balance at 12/31/17 Total Liquidity at 12/31/17 $ 750 MM $ 0 MM $ 750 MM $ 166 MM $ 916 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.
Near-term Growth Strategy Exploration & Production Gathering Pipeline & Storage Grow Marcellus and Utica production and gathering throughput at a 10%+ CAGR over next 3 years WDA Development (1-rig program) Return to developing 100% NRI wells following completion of 75-well program with joint development partner Transition to a Utica development program on existing Marcellus pads expected to require minimal additional gathering capital investment EDA Development (1-rig program) Develop highly economic acreage in Lycoming County and prepare well inventory for Atlantic Sunrise capacity Commence Utica development in FY18 at Tract 007 (Tioga County) to add another 100 to 150 MMcf/d by FY20 Pursue opportunities for system expansion and modernization Foundation shipper agreements are in place for Empire North Project and new Supply Line N expansions Continue appeal of Northern Access project / pursue alternative solution for Seneca’s WDA production Need for modernization of NFG Supply Corp system will result in rate base growth Utility Invest in utility pipeline replacement and modernization Improve system safety and reliability Seek timely recovery through tracker mechanism in New York
Fiscal 2018 Earnings Guidance FY 2017 Earnings Non-regulated Businesses Exploration & Production Gathering $3.30 /share $3.20 to $3.40 /share FY2018 Earnings Guidance(1) Seneca Net Production: 180 to 195 Bcfe Gathering Revenues: $110 to $120 million Natural Gas: ~$2.50 /Mcf(2) (vs. $2.95 /Mcf in FY17) Crude Oil: ~$57 /Bbl(3) (vs. $53.87 /Mcf in FY17) Key Guidance Drivers Excludes the $111.0 million, or $1.29 per share, reduction in tax expense due to the remeasurement of deferred taxes resulting from the 2017 Tax Reform Act. See non-GAAP disclosure on slide #53. Assumes NYMEX natural gas pricing of $3.00 /MMBtu and basin spot pricing of $2.40/$2.00 /Mmbtu (winter/summer) and reflects the impact of existing financial hedge, firm sales and firm transportation contracts. Assumes NYMEX (WTI) oil pricing of $60.00 /Bbl and California-MWSS pricing differentials of 98% to WTI, and reflects impact of existing financial hedge contracts. Production & Gathering Throughput Realized natural gas prices (after-hedge) Utility Normal Weather Regulated Businesses Pipeline & Storage Utility Warmer than normal weather impacted FY17 utility earnings by ~$0.06 /share ~$295 million in revenues (flat vs. FY17) Pipeline & Storage Revenues Tax Reform Realized oil prices (after-hedge) Lower effective tax rate Effective tax rate ~27% (federal rate 24.5%) Earnings neutral for Utility segment – tax savings offset by regulatory refund provision (~$16 million pre-tax)
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 $112.2 million earnings benefit recorded in Q1 FY18. Pipeline & Storage Evaluating impact of FERC 3/15/18 notice of proposed rulemaking Expect any adjustment to rates to be prospective – no refund provision recorded Recorded reduction in deferred income taxes as a regulatory liability Utility Evaluating NY PSC 12/29/17 and PA PUC 3/15/18 orders instituting proceedings on tax reform Expect any adjustment to rates to be retroactive - recorded $6.0 million ($4.4 million after-tax) refund provision in Q1 FY18 Recorded reduction in deferred income taxes as regulatory liability NFG Consolidated Higher earnings / Lower effective tax rate: ~27% in FY 18 and ~25% FY19 and beyond Cash flow is expected to be positive over long-term
Upstream Overview Exploration & Production
Growing Production within Disciplined Capital Program E&P Net Production (Bcfe) E&P Net Capital Expenditures(1) ($ millions) 2-rig development program Target 10%+ production 3-year CAGR Resumed development on prolific Marcellus acreage in Lycoming County, Pa. Return to developing 100% NRI wells in the WDA (last JDA pad expected on-line in 1H FY18) Transition to Utica development in WDA and EDA in FY18 Layer-in firm sales to reduce spot market risk and take advantage of attractive regional pricing Seneca’s Near-term Operational Plan Appalachia Natural Gas California Oil Flat to modest growth on minimal capital investment Development focus on new farm-in acreage in Midway Sunset Low cost structure helps generate significant positive cash flows at $60 /bbl Upstream 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 guidance 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.
Proved Reserves 225% Reserve Replacement Rate (adjusted for revisions) Seneca Drill-bit F&D = $0.60/Mcfe(1) Appalachia Drill-bit F&D = $0.51/Mcfe(1) Seneca “Drill-bit” finding and development (“F&D”) costs exclude the impact of reserve revisions. Upstream Total Proved Reserves (Bcfe) Fiscal 2017 Proved Reserves Stats 3-Year Average F&D Cost ($/Mcfe)
Significant Appalachian Acreage Position Current gross production: ~340 MMcf/d Mostly leased (16-18% royalty) with no significant near-term lease expirations 100+ remaining Marcellus and Utica locations economic under ~$1.90/Mcf Additional Utica & Geneseo potential Eastern Development Area (EDA) EDA - 70,000 Acres Western Development Area (WDA) WDA - 715,000 Acres Current gross production: ~275 MMcf/d Large inventory of high quality Marcellus and Utica acreage economic at $2.00/Mcf Fee ownership enhances economics Highly contiguous nature drives cost and operational efficiencies Fee Acreage Lease Acreage Upstream
Western Development Area WDA Core Acreage – 200,000 Acres Significant multi-zone drilling inventory economic at ~$2.00 /Mcf Marcellus Shale : 640 well locations Utica Shale: 125 to 500+ well locations (2) Fee acreage / stacked pay provides flexibility & enhances economics No royalty or lease expirations on most acreage Expected Utica development will re-use existing upstream and midstream infrastructure to maximize ROI Highly contiguous position drives best in class well costs Multi-well pad drilling with laterals approaching 8,000 ft. Water management operations keeping water costs low Long-term firm contracts support growth and returns Marcellus EURs only. The Utica Shale lies approx. 5,000 feet beneath Seneca’s WDA Marcellus acreage. Appraisal program currently in progress to determine extent of economic Utica inventory on acreage. Clermont/ Rich Valley Hemlock Ridgway 2 - 4 BCF/well 7- 9.5 BCF/well 4 - 6 BCF/well EUR Color Key(1) Upstream Niagara Expansion Project (TGP and NFG) FT Capacity: 158,000 Dth/d @ $0.67/Dth Firm Sales: NYMEX & DAWN WDA - TGP 300 Firm Sales
WDA Utica Appraisal Results and Initial Type Curve Tested / producing from 8 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 shallower vs. Marcellus Upstream WDA Utica Appraisal Update WDA Utica Test Well Results "Type Curve" Well Best Well Pad D09-NF-A C09-D Well 196HU 214HU Lateral Length 6,300 5,530 Days on-line 325 days 160 days Est. EUR /1,000 ft 1.8 Bcf 2.1 Bcf Production Results (per day): 7-day IP 6.0 MMcf 8.1 MMcf 30-day IP 6.0 MMcf 7.7 MMcf 60-day IP 5.7 MMcf 7.3 MMcf 90-day IP 5.5 MMcf 7.2 MMcf Initial WDA-CRV Utica type curve based on production results and reservoir expectations from the first 5 appraisal wells in the WDA-CRV area.
Transitioning to Utica Development in CRV WDA-CRV Marcellus (Depth ~7,000 feet) Existing Line Leased Seneca Fee Producing FY18 Producer Development WDA-CRV Utica (Depth ~12,000 feet) Upstream 156 wells producing 250 Mcf/d Remaining Avg. EUR 1.0 Bcf / 1,000 lat ft. Remaining Avg. Well Costs = $655/lat ft. 125+ locations on existing Marcellus pads Est. EURs 1.7 Bcf / 1,000 lat ft. Est. Development Well Costs = ~$915/lat ft FY 18 WDA Utica Transition Plan Finish Marcellus Pads in Development Drill 10 / complete 17 Marcellus wells (100% Seneca) Complete and bring final 12 joint development online by end of Q2 FY18 (63 of 75 JDA wells now producing) Optimize Utica D&C design Drill 10 Utica wells off Marcellus pads Optimization to include: Well spacing Completion design / stage spacing Landing zone targets Best water handling methods Transition to Utica development by FY19 Continue shift toward multi-well Utica pads Tailor development plan to reuse existing pad, water and gathering infrastructure WDA Utica Development Will Reuse Existing Pad, Water, and Gathering Infrastructure to Drive Economics
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 ~50 remaining Utica locations economic at ~$1.90 /Mcf Covington & DCNR Tract 595 (Tioga Co., Pa.) Gross daily production: ~105 MMcf/d Marcellus locations fully developed Opportunity for future Utica appraisal DCNR Tract 100 & Gamble (Lycoming Co., Pa.) Gross daily production: ~230 MMcf/d 55 remaining Marcellus locations economic at ~$1.65 /Mcf Atlantic Sunrise capacity (190 MDth/d) in mid-2018 Geneseo shale to provide 100-120 additional locations 3
EDA Marcellus: Lycoming County Development Upstream Prolific Marcellus acreage with peer leading well results 66 Marcellus wells producing w/ average IP rate of 17.0 MMcf/d 55 remaining Marcellus locations economic at ~$1.65 /Mcf Near-term development focused on filling Atlantic Sunrise capacity forecasted to be available in July 2018 Transco Firm Sales(1) Marcellus Development in Lycoming County has Resumed in Anticipation of Atlantic Sunrise Includes physical fixed price and NYMEX-based firm sales contracts that do not carry any additional transportation costs.
EDA Utica: Tioga County Development Upstream Utica Development in Tioga County – Tract 007 Expected to Begin in 2H FY18 Northeast Supply Diversification Project FT Capacity: 50,000 Dth/d @ $0.50/Dth Firm Sales: NYMEX and DAWN EDA - TGP 300 Firm Sales(1) 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: 50 locations economic at ~$1.90 /Mcf Targeting to grow production by 100 to 150 MDth/d by FY20 Expected Development Costs: $1,045 per lateral ft. Gathering Infrastructure: NFG Midstream Wellsboro Modest build-out required to connect to TGP 300 Sales/Takeaway Strategy: Layer-in firm sales with shippers holding capacity on TGP 300 Includes physical fixed price and NYMEX-based firm sales contracts that do not carry any additional transportation costs. Tract 007 Utica Appraisal Well Results vs. Industry
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 structure, LOE, and Gathering tariffs anticipated for each prospect. Large Inventory of Marcellus and Utica Location Economic Below $2.00/MMBtu(1) Upstream Prospect Reservoir Locations Remainingto Be Drilled Completed Lateral Length (ft) EUR / 1000' (Bcf) Well Cost$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 55 4900 2.5 $1,115 0.61 0.48 0.34 $1.63 Transco Leidy &Atlantic Sunrise Southeast US(NYMEX+) DCNR 007Tioga Co. Utica 50 7500 2 $1,045 0.45 0.31 0.19 $1.91 TGP 300 WDA Clermont Rich Valley Utica 125 - 500+ 7500 1.7 $915 0.28999999999999998 0.23 0.16 $1.95 TGP 300 &Niagara Expansion Canada (Dawn) Core Areas Marcellus 640 8500 1.0 to 1.1 $655 0.25 0.19 0.13 $2.09 Major Changes FY15Q4: 1. WDA - CRV --> TLL increased to 8,800, remaining locations reduced to 79 2. WDA - Hemlock --> TLL increased to 8,800 3. WDA - Ridgway --> TLL increasd to 8,800, merged with Hemlock (using Hemlock CAPEX, BTU, etc) 4. WDA - CRV/Hemlock/Ridgway --> updated LOE, shrink, and BTU 5. WDA- Tier 1 Locations --> TLL increased to 8,500 ft. (G&G guidance) FY15Q3: 1. EDA- DCNR 100 --> Updated Type Curve (Higher IP) and Lower Capital Structure (190 ft. Stages) 2. EDA- Gamble --> Updated Type Curve (based on DCNR 100) and Lower Capital Structure (190 ft. Stages) 3. WDA- CRV --> Updated Type Curve and Lower Capital Structure (Optimization Mode $5.4 MM/Well) 4. WDA- Hemlock/Ridgway/Tier 1/Future Resources --> Updated Capital Structure (Optimization Mode $5.4 MM/Well)
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 Dth/d 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. Firm Transportation Long-term firm sales contracts in place at physical delivery points realizing NYMEX / Dawn less transport cost Upstream Regional Firm Sales Converting 95 Mdth/d of Northern Access sales from Dawn back to basin Recent deals providing attractive netback prices well above $2/MMbtu 10% Production CAGR FY 2019 FY 2020 FY 2021 Seneca continues to layer-in firm sales contracts with attractive realizations at regional pricing points to lock-in drilling economics and minimize spot exposure as it waits for Northern Access FY 2018
Firm Transportation Commitments Volume (Dth/d) Production Source Delivery Market Demand Charges ($/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 & Empire Delayed 50,000 189,405 158,000 350,000 EDA -Tioga County Covington & Tract 595 EDA - Lycoming County Tract 100 & Gamble WDA – Clermont/ Rich Valley WDA – Clermont/ Rich Valley 12,000 140,000 Canada (Dawn) Mid-Atlantic/ Southeast Canada (Dawn) TETCO (SE Pa.) Canada (Dawn) TGP 200 (NY) $0.50 (3rd party) $0.73 (3rd party) NFG pipelines = $0.24 3rd party = $0.43 NFG pipelines = $0.12 NFG pipelines = $0.38 NFG pipelines = $0.50 3rd party = $0.21 Firm Sales Contracts 50,000 Dth/d Dawn/NYMEX+ 10 years Currently In-Service Future Capacity Firm Sales Contracts 158,000 Dth/d Dawn/NYMEX+ 8 to 15 years Firm Sales Contracts 189,405 Dth/d NYMEX+ First 5 years Firm Sales Contracts At Dawn When Project Goes In-Service Upstream
Firm Sales Provide Market for Appalachian Production Net Contracted Firm Sales Volumes (Dth per day) Contracted Index Price Differentials ($ per Dth)(1) Values shown represent the weighted average fixed price or contracted fixed differential relative to NYMEX (netback price) less any associated transportation costs. Upstream Actual Daily Net Production 584,700 534,600 597,600 571,100 570,300 624,200 617,400 Gross Firm Sales Volumes (Dth/d)
California Oil Stable Oil Production | Minimal Capital Investment | Steady Free Cash Flow 1 2 3 4 5 6 Location Formation Production Method FY17 Gross Daily Production (Boe/d) 1 East Coalinga Temblor Primary 711 2 North Lost Hills Tulare & Etchegoin Primary/ Steam flood 951 3 South Lost Hills Monterey Shale Primary 1,578 4 North Midway Sunset Tulare & Potter Steam flood 3,183 5 South Midway Sunset Antelope Steam flood 1,968 6 Sespe Sespe Primary 1,335 TOTAL CALIFORNIA GROSS PRODUCTION 9,726 Boe/d Upstream
California Capital Expenditures vs. Production Upstream 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.
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 South MWSS Acreage North MWSS Acreage Sec. 17N North South South North Midway Sunset Economics MWSS Project IRRs at $60 /Bbl(1) Reflects pre-tax IRRs at a $60/Bbl WTI. Upstream
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 9 months of FY18 hedged at the midpoint of the production guidance range. Seneca’s remaining FY18 production reflect the total FY18 production guidance 180 to 195 Bcfe, or 187.5 Bcfe at the midpoint, less Q1 FY18 actual production. Upstream Crude Oil Swap Contracts (Thousands Bbls) (1) FY 18 Nat Gas 62% Hedged(2) FY 2018 Remaining Production(3) FY 2018 Remaining Production(3)
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. 83 Bcf locked-in realizing net ~$2.50/Mcf (1) 32 Bcf of additional basis protection Upstream Spot production assumed to be sold at ~$2.40/Mmbtu (winter) & ~$2.00/Mmbtu (summer) 115 Bcf Protected by Firm Sales for Remainder of Year 73% of oil production hedged at $54.99 /Bbl
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) (1) Excludes $7.9 million , or $0.05 per Mcfe, of professional fees relating to the joint development agreement announced in December 2015. The total of the two LOE components represents the midpoint of the LOE guidance range of $0.90 to $1.00 for fiscal 2018. Upstream
Midstream Businesses
Midstream Businesses Midstream Midstream Midstream Businesses Adjusted EBITDA ($MM)(1) 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 System Map NFG Supply Corp. FERC-Regulated Pipeline & Storage NFG Midstream Corp Marcellus & Utica Gathering & Compression Empire Pipeline, Inc. FERC-Regulated Pipeline & Storage
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: $286 million Future Build-Out FY 2018 CapEx: $10 MM - $15MM Modest gathering pipeline and compression investment required to support Seneca’s transition to Utica development Ultimate capacity can exceed 1 Bcf/d Over 300 miles of pipelines and five compressor stations (+60,000 HP installed) Deliverability into TGP 300 and NFG Supply Gathering System Build-Out Tailored to Accommodate Seneca’s WDA Development Midstream Clermont Gathering System Map
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): $185 million FY 2018 Capital Expenditures: $35 MM - $50 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 Midstream Interconnects Wellsboro Gathering System Total Investment (to date): $7 million FY 2018 Capital Expenditures: $10 MM - $20 MM Capacity: 200,000 Dth per day (Interconnect w/ TGP 300) Production Source: Seneca Resources – Tioga Co. (DCNR Tract 007)
Pipeline & Storage Segment Overview As of September 30, 2017 as disclosed in the Company’s fiscal 2017 form 10-K. As of December 31, 2016 calculated from National Fuel Supply Corporation’s and Empire Pipeline, Inc.’s 2016 FERC Form-2 reports, respectively. Midstream Empire Pipeline, Inc. National Fuel Gas Supply Corporation Empire Pipeline NFG Supply Contracted Capacity(1): Firm Transportation: 3,157 MDth per day Firm Storage: 68,042 Mdth (fully subscribed) Rate Base(2): ~$805 million FERC Rate Proceeding Status: Rate case settlement extension approved Nov. ‘15 Required to file a rate case by 12/31/19 Contracted Capacity(1): Firm Transportation: 954 MDth per day Firm Storage: 3,753 Mdth (fully subscribed) Rate Base(2): ~$259 million FERC Rate Proceeding Status: Section 5 rate settlement approved Oct. ‘16 Required to file a rate case by 7/1/21
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 million Expanding Our Pipelines to Assure Supply Security for New York Markets Integration of Seneca’s WDA Production Into Broader Interstate System Midstream 40,000 Dth per day went in-service on November 1, 2015. The remaining 100,000 Dth per day was placed in-service on December 1, 2015. Northern Access 2016 (Delayed) In-Service: TBD Systems: NFG Supply Corp. & Empire Pipeline Capacity: 490,000 Dth per day Total Expected Cost: ~$500 million Project Status: Delayed pending appeal of NYS DEC WQC 401 notice of denial Chippewa To Dawn Niagara East Aurora NE US (TGP 200)
Northern Access Project Status Regulatory / Appeal Status US Court of Appeals for the 2nd Circuit: On April 21, 2017, NFG filed appeal of NY DEC notice of denial of the Clean Water Act Section 401 Water Quality Certification (WQC) Decision from the Court is pending Federal Energy Regulatory Commission: On March 3, 2017, NFG filed petition for rehearing with FERC seeking waiver of NYS DEC Clean Water Act Section 401 WQC and preemption on state level permits Decision from FERC is pending Project Spending Update: Total project spending to-date: $75.5 million Minimal remaining commitments National Fuel Remains Committed to Building the Northern Access Pipeline Project Midstream
Empire System Expansion Target In-Service: November 2019 Est. Capital Cost: $142 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 - precedent agreements in place for 205,000 Mdth/d Major Facilities: 2 new compressor stations in NY (1) & Pa. (1) No new pipeline construction Regulatory Process: Filed FERC 7(c) certificate on 2/16/18 Midstream
Continued Expansion of the NFG Supply System Line N Expansion Opportunities Line D Expansion Project Midstream Project Status: In-service on November 1, 2017 Contracted Capacity: 77,500 Dth/d from an interconnect with TGP 300 at Lamont, Pa. into Erie, Pa. market Est. Capital Cost: $28 million ($8 million modernization) Line D Expansion Project Line N Expansion Opportunities Line N Expansion Opportunity #1 (Supply OS #220) Project: Firm transportation service to a new ethylene cracker facility being built by Shell Chemical Appalachia, LLC. Target In-Service: July 2019 Est. Capital Cost: $17 million Contracted Capacity: 133,000 Dth/d with foundation shipper Line N Expansion Opportunity #2 (Supply OS #221) Project: New firm transportation service for on-system demand Target In-Service: July 2020 Open Season Capacity: Awarded 165,000 to foundation shipper. Precedent agreement in negotiations. Future NFG Supply System Expansions
NFG Supply Corp. System Modernization NFG plans to increase investments in the modernization of its Supply Corp system over the next 5 years Retire pre-1970 vintage pipelines Replace portions of Supply’s existing system to enhance service for distribution, storage and local production customers Upgrade compressor station facilities to employ best available technologies and environmental controls Improved system safety and service reliability Operational flexibility Lower greenhouse gas emissions Investment in rate base Opportunity for companion expansions Modernization Program Objectives: Expected Impact: Midstream
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 Midstream
Downstream Overview Utility ~ Energy Marketing
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) Pennsylvania Total Customers(1): 213,200 ROE: Black Box Settlement (2007) Rate Mechanisms: Low Income Rates Merchant Function Charge As of September 30, 2017. Downstream
New York Rate Case Outcome Rate Order Summary: Revenue Requirement:$5.9 million Rate Base:$704 million (prior case $632 million1) Allowed Return on Equity (ROE):8.7% (prior case allowed 9.1%1) Capital Structure:42.9% equity Other notable items: New rates became effective 5/1/17 Retains rate mechanisms in place under prior order (revenue decoupling, weather normalization, merchant function charge, 90/10 large customer sharing) No stay-out clause Earnings sharing would start 4/1/18 if NFG Distribution Corp. does not file for new rates to become effective on or before 10/1/18 (50/50 sharing starts at earnings in excess of 9.1%) Article 78 appeal filed on 7/28/17 On April 20, 2017, the New York Public Service Commission issued a Rate Order relating to NFG Distribution’s rate case (No. 16-G-0257) filed in April 2016. Case 13-G-0136 rate year ended September 30, 2015. Downstream
Utility: Shifting Trends in Customer Usage Weighted Average of New York and Pennsylvania service territories (assumes normal weather). Usage Per Account (1) 12-Months Ended December 31 Downstream
Utility: Strong Commitment to Safety The Utility remains focused on maintaining the ongoing safety and reliability of its system Capital Expenditures ($ millions)(1) Downstream A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation.
Accelerating Pipeline Replacement & Modernization NY 9,723 miles PA* 4,832 miles * No Cast Iron Mains in Pa.* Miles of Utility Main Pipeline Replaced Utility Mains by Material Downstream
A Proven History of Controlling Costs O&M Expense ($ millions) Downstream
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. Appendix (1) Natural Gas Volumes in thousand MMBtu; Prices in $/MMBtu Fiscal 2018 (last 9 mos.) Fiscal 2019 Fiscal 2020 Fiscal 2021 Fiscal 2022 Volume Avg.Price Volume Avg.Price Volume Avg.Price Volume Avg.Price Volume Avg.Price NYMEX Swaps 30780 $3.17 46420 $3.03 18640 $3.04 4840 $3.01 - - Dawn Swaps 5400 $3 7200 $3 7200 $3 600 $3 - - Fixed Price Physical 49898 $2.42 34503 $2.48 38689 $2.2799999999999998 41572 $2.2200000000000002 40567 $2.23 Total 86078 $2.73 88123 $2.81 64529 $2.58 47012 $2.31 40567 $2.23 Crude Oil Volumes & Prices in Bbl Fiscal 2018 (last 9 mos.) Fiscal 2019 Fiscal 2020 Fiscal 2021 Fiscal 2022 Volume Avg. Volume Avg. Volume Avg. Volume Avg. Volume Avg. Price Price Price Price Price Brent Swaps 342000 $63.55 612000 $61.26 456000 $59.16 300000 $60 - - NYMEX Swaps 1260000 $52.67 1068000 $53.42 324000 $50.32 156000 $51 156000 $51 Total 1602000 $54.99 1680000 $56.28 780000 $55.57 456000 $56.92 156000 $51
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 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. The Company’s fiscal 2018 earnings guidance does not include the impact of the remeasurement of deferred income taxes resulting from the 2017 Tax Reform Act, which reduced the Company’s consolidated income tax expense and benefited earnings for the three months ended December 31, 2017 by $111.0 million, or $1.29 per share. While the Company expects to record additional adjustments to its deferred income taxes as a result of the 2017 Tax Reform Act during the remaining nine months of fiscal 2018, the amounts of these and other potential adjustments are not reasonably determinable at this time. The final determination of the impact of the income tax effects of certain items will require additional analysis and further interpretation of the 2017 Tax Reform Act from yet to be issued U.S. Treasury regulations, state income tax guidance, federal and state regulatory guidance, and technical corrections. Some or all of these factors may be significant. Because the amounts of final adjustments are not reasonably determinable at this time, the Company is unable to provide earnings guidance other than on a non-GAAP basis that excludes the impact of the remeasurement of deferred income taxes and other potential adjustments. Appendix
Non-GAAP Reconciliations – Adjusted EBITDA Appendix
Non-GAAP Reconciliations – Capital Expenditures Appendix
Non-GAAP Reconciliations – E&P Operating Expenses Appendix
