National Fuel Gas Company Investor Presentation November 2014 Exhibit 99 |
National Fuel Gas Company Safe Harbor For Forward Looking Statements 2 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: 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; the cost and effects of legal and administrative claims against the Company or activist shareholder campaigns to effect changes at the Company; 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; 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 the price of natural gas or oil; 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; impairments under the SEC’s full cost ceiling test for natural gas and oil reserves; uncertainty of oil and gas reserve estimates; significant differences between the Company’s projected and actual production levels for natural gas or oil; 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; changes in demographic patterns and weather conditions; changes in the availability, price or accounting treatment of derivative financial instruments; 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 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; 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; increasing health care costs and the resulting effect on health insurance premiums and on the obligation to provide other post-retirement benefits; 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, 2013 and the Forms 10-Q for the quarters ended December 31, 2013, March 31, 2014 and June 30, 2014. 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. |
National Fuel Gas Company Quality Assets - Exceptional Location - Unique Integration 3 1.914 Tcfe of Proved Reserves (1) 811,000 Net Acres in Pennsylvania 3 Million Bbls of Crude Oil Production (2) $250 Million of Midstream Adjusted EBITDA (2)(3) (1) As of September 30, 2014 (2) Fiscal year ended September 30, 2014. Midstream includes the Pipeline & Storage segment and Gathering segment. (3) A reconciliation of Adjusted EBITDA to Net Income is included at the end of this presentation. |
National Fuel Gas Company Upstream and Midstream – Common Vision For Growth 4 Western Development Area Tier I Acreage: 200,000 Acres Clermont Gathering System NFG Supply & Other Interconnects Northern Access Projects 490 MMcf/d to Canada by 2016 High quality Marcellus acreage Connected to our interstate pipeline network Pipeline capacity to premium and alternate markets |
National Fuel Gas Company Regulated Operations Provide Significant Synergies 5 |
National Fuel Gas Company What Makes NFG Unique, Also Maximizes Value 6 Foundation of Our Appalachian Growth Strategy |
National Fuel Gas Company Targeting Sustained EBITDA Growth over the next Five Years 2015 – 2019 10-15% Forecasted Adjusted EBITDA CAGR $164 $167 $169 $160 $172 $165 $131 $121 $111 $137 $161 $186 $64 $280 $327 $377 $397 $492 $539 $581 $632 $668 $704 $852 $953 $0 $250 $500 $750 $1,000 $1,250 2009 2010 2011 2012 2013 2014 2019E Fiscal Year Exploration & Production Segment Gathering Segment Pipeline & Storage Segment Utility Segment Energy Marketing & Other 7 Note: A reconciliation of Adjusted EBITDA to Net Income as presented on the Consolidated Statement of Income and Earnings Reinvested in the Business is included at the end of this presentation. |
National Fuel Gas Company Capital Spending Adjusts to Capitalize on Opportunities 8 Note: A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation. (1) Does not include the $34.9 MM Seneca Resources Corporation’s acquisition of Ivanhoe’s U.S.-based assets in California, as this was accounted for as an investment in subsidiaries on the Statement of Cash Flows, and was not included in the Exploration & Production segment’s Capital Expenditures. |
National Fuel Gas Company Maintaining a Strong Balance Sheet 9 Total Debt (1) 42% $4.1 Billion As of September 30, 2014 Debt/Adjusted EBITDA Capitalization Note: A reconciliation of Adjusted EBITDA to Net Income is included at the end of this presentation. (1) Long-term debt of $1.649 billion and short-term debt of $85.6 million |
National Fuel Gas Company Dividend Track Record 10 Dividend Consistency Consecutive Dividend Payments 112 Years Consecutive Dividend Increases 44 Years Current Annualized Dividend Rate $1.54 per Share (1) As of November 5, 2014 |
11 Exploration & Production Overview |
Seneca Resources Proven Record of Growth 12 Fiscal Years 3-Year F&D Cost (1) ($/Mcfe) 2007-2009 $5.35 2008-2010 $2.37 2009-2011 $2.09 2010-2012 $1.87 2011-2013 $1.67 2012-2014 $1.38 (1) Represents a three-year average U.S. finding and development cost 2014 F&D Cost = $1.15 Marcellus F&D: $1.00 327% Reserve Replacement Rate 73% Proved Developed |
Seneca Resources Delivering Tremendous Production Growth 13 |
Disciplined Capital Spending 14 $31 $28 $47 $63 $105 $83 $55-$80 $139 $356 $596 $631 $428 $520 $545 - $620 $188 (1) $398 $649 $694 $533 $603 $600-$700 $0 $200 $400 $600 $800 $1,000 2009 2010 2011 2012 2013 2014 2015E Fiscal Year Gulf of Mexico (Divested in 2011) East Division West Division Seneca Resources (1) Does not include the $34.9 MM Seneca Resources Corporation’s acquisition of Ivanhoe’s U.S.-based assets in California, as this was accounted for as an investment in subsidiaries on the Statement of Cash Flows, and was not included in the Exploration & Production segment’s Capital Expenditures. |
Seneca Resources LOE: Operating Costs down; Transportation Costs up 15 (1) Represents the midpoint of current General & Administrative Expense guidance of $0.35 to $0.40 per Mcfe for fiscal 2015 (2) The total of the two LOE components represents the midpoint of current LOE guidance of $0.95 to $1.05 per Mcfe for fiscal 2015 Seneca matches its long-term firm transport (FT) contracts with firm sales (FS) agreements, with the cost of transportation reflected in price realization. As such, it is not included in LOE. |
Marcellus Shale Prolific Pennsylvania Acreage 16 Eastern Development Area (EDA) Mostly leased (16-18% royalty) No near-term lease expiration Limited development drilling until firm transportation capacity on Atlantic Sunrise becomes available in late 2017 Drilling activity will HBP key acreage Western Development Area (WDA) Average net revenue interest (NRI): 98% No lease expiration No royalty on most acreage Highly contiguous Significant economies of scale 1,700 to 2,000 locations de-risked Seneca Lease Seneca Fee 720,000 Acres 60,000 Acres |
Marcellus Shale EDA Delivering Significant Growth 17 Covington – Fully Developed Gross Production: ~45MMcf per Day 47 Wells Drilled and Producing DCNR Tract 595 Gross Production: ~90 MMcf per Day 45 Wells Drilled (1) (52 Total Locations) 38 Wells Producing DCNR Tract 100 Gross Production: ~410 MMcf per Day 58 Wells Drilled (2) (70 Total Locations) 53 Wells Producing (2) Opportunity for Geneseo development Gamble 30 to 50 future locations 3 Wells Drilled; 1 Well Producing Opportunity for Geneseo development (1) One well included in this total is drilled into the Geneseo Shale (2) One well included in this total is drilled into and producing from the Geneseo Shale |
Marcellus Shale EDA – Historical Well Results are Exceptional 18 Development Area Producing Well Count Average IP Rate (MMcf/d) Average 7-Day (MMcf/d) Average 30-Day (MMcf/d) Average EUR per Well (Bcf) Average Lateral Length EUR per 1,000’ of Lateral (Bcfe) Covington Tioga County 47 5.2 4.7 4.1 5.8 4,023’ 1.44 Tract 595 Tioga County 38 7.2 6.0 5.2 8.0 4,716’ 1.70 Tract 100 Lycoming County 52 (1) 17.0 14.9 12.7 12.6 5,304’ 2.38 (1) Does not include a well drilled into and producing from the Geneseo Shale |
Marcellus Shale Focusing on WDA Development 19 SRC Lease Acreage SRC Fee Acreage EOG Earned JV Acreage Note: Assumes 6,000’ treated lateral length Seneca’s Tier I Acreage: 200,000 Acres 6-8 Bcfe EUR Wells Economic at $2.80 to $3.80/Mcfe |
Marcellus Shale Strong Wells Currently Producing Across WDA Acreage 20 Area Producing Well Count Peak 24-Hour Rate (MMcfd) Average 7-Day (MMcf/d) Average Treatable Lateral Length Clermont/Rich Valley Elk, Cameron & McKean counties 19 8.1 7.2 5,710’ WDA Development Areas: WDA Delineation Areas: Area Producing Well Count Peak 24-Hour Rate (MMcfd) Average 7-Day (MMcf/d) Average Treatable Lateral Length Ridgway Elk County 1 7.1 6.4 5,537’ Church Run Elk & Jefferson counties 2 4.8 4.5 4,690’ Owl’s Nest Elk & Forest counties 1 6.1 5.8 6,137’ Sulger Farms Jefferson County 1 6.1 5.6 5,778’ |
Marcellus Shale Clermont/Rich Valley (CRV) Area Marcellus Faults Marcellus & Basement Faults Planned Wells Drilled Wells Producing Wells Pad H 6 Wells Ave. IP: 8.0 MMCFD Pad N 9 Wells Ave. IP: 8.2 MMCFD Clermont/Rich Valley 200-250 Planned Horizontal Locations FY 2014 Year-end: 19 Wells; ~ 75 MMcfd FY 2015 Fcst Year-end:~50 Wells; ~180 MMcfd SRC Lease Acreage SRC Fee Acreage Pad C8-F Completing Pad C8-G Drilling Pad D9-D 6 Wells Drilled 21 |
Marcellus Shale WDA Mineral Interests Significantly Enhance Returns 22 ($/Mcf) Typical Producer 15% Royalty Average Net Realized Price $ 3.27 Less: Cash Operating Expenses (0.65) Less: Royalty Payment (0.47) Cash Margin $ 2.15 Before Tax IRR (1) 15% In Clermont/Rich Valley, a typical producer burdened by a 15% royalty would require a $0.47 higher net realized price to achieve same level of economics as Seneca Resources The Seneca Advantage 0% Royalty $ 2.80 (0.65) (0.00) $ 2.15 15% (1) Internal Rate of Return (IRR) includes estimated well costs under current coststructure, LOE, and Gathering tariffs anticipated for each prospect. Clermont/Rich Valley Example |
Natural Gas Marketing How Does Seneca Sell its Production? 23 Well Head Interconnection with Interstate Pipeline Network Gathering System 3rd Party Marketer (or spot market) Firm Transport Demand Center (firm sales or spot market) Contracted Basis Differential FT Rate Breakeven economics based on a realized price after gathering Spot Market |
Natural Gas Marketing Adding Long-Term Firm Transport to the Portfolio 24 Project (Counterparty) In- Service Date Contract Term Delivery Market FT Capacity (Dth/day) Matched Firm Sales Fiscal 2015 Fiscal 2016 Fiscal 2017 Fiscal 2018 Northeast Supply Diversification Project (TGP) Nov. 2012 15 years Canada 50,000 50,000 50,000 50,000 Executed Contracts 50,000 Dth/d for 10 years Niagara Expansion/ TETCO (TGP/ NFG/TETCO) Nov. 2015 15 years Canada/ TETCO --- 170,000 170,000 170,000 Executed Contracts 140,000 Dth/d for 15 years Northern Access 2016 (NFG/ TransCanada/ Union) Nov. 2016 15 years Canada --- --- 350,000 350,000 Evaluating marketing opportunities Atlantic Sunrise (Transco) Nov. 2017 15 years Mid- Atlantic/ Southeast --- --- --- 189,405 Executed Contracts 189,405 Dth/d for first 5 years (1) Total Firm Transportation Capacity 50,000 220,000 570,000 759,405 (1) A large majority of the executed firm sales agreements continue for the remainder of the firm transportation contract term. |
Natural Gas Marketing Significant Base of Long-Term Firm Contracts 25 |
Natural Gas Marketing Firm Sales Provide a Market for Appalachian Production 26 26 EDA (2) 318,033 Dth/d 320,036 Dth/d 280,036 Dth/d 280,036 Dth/d WDA (2) 58,034 Dth/d 61,100 Dth/d 60,000 Dth/d 60,000 Dth/d (1) Fixed price sales contracts totaling 50,000 Dth/day at an average fixed price of $3.77 per Dth starting November 2014 through October 2017 (2) EDA and WDA carryan average net revenue interest (NRI) of 82% - 84% and 98%, respectively |
Natural Gas Marketing Current Natural Gas Hedge Positions 27 |
Natural Gas Marketing Current Hedge Book has Seneca Positioned Very Well 28 (1) Natural gas hedges include fixed price firm sales (2) Hedge positions reflect the midpoint of Seneca’s target annual production growth (20%) starting with the midpoint of Fiscal 2015 guidance (180-220 Bcfe) Natural Gas $4.01/MMBtu $4.03/MMBtu $4.11/MMBtu $4.41/MMBtu Crude Oil $95.27/Bbl $92.95/Bbl $92.30/Bbl $91.00/Bbl |
Natural Gas Marketing FY 2015 Production – Firm Sales & Hedge Composition 29 Firm Sales with Price Certainty 108 Bcf at ~$3.70 /Mcf Spot Price Exposure 66 Bcf at $2.50-$2.75 /Mcf (1) (1) Spot price assumptions reflected in fiscal 2015 earnings guidance range (2) Dominion based firm sales contracts without a matching Dominion financial hedge 68.1 Bcf 24.1 Bcf 16.2 Bcf 22.0 Bcf 43.5 Bcf 4.1 Bcf (2) 159-197 Bcf 0 50 100 150 200 NYMEX Firm Sales DOM Firm Sales Fixed Price Sales WDA Spot Sales EDA Spot Sales Total East Division Production |
Utica Shale Seneca Activity in Tioga County 30 Seneca - Tionesta Horizontal: Completed Fall 2012 Peak 24-Hour Rate: 3.9 MMcf/d Seneca - Mt Jewett Horizontal: Completed September 2013 Peak 24-Hour Rate: 8.5 MMcf/d Seneca - DCNR 007 Drilling Shell 26 MMcf/d Shell 11 MMcf/d |
California Stable Production Fields; Modest Growth Potential 31 |
California East Coalinga Summary 32 Production has increased from 214 BOPD to 800 BOPD • Highest on leases since 2000 Drilled 12 evaluation wells in 2013 • Producing ~150 BOPD Drilled 31 new producers and 1 water disposal well in 2014. Currently have 27 of the new producers on line. 2014 Location 2013 Well Active Well Idle Well P&A Seneca Lease Field Boundary |
California South Midway Sunset Has Delivered Significant Growth 33 252 Pool 97X Pool SE Pool 251 Pool B Pool A Pool Extended Pool Boundary Original Pool Boundary Existing Wells 1000’ 16X Pool Highlights Since Acquisition Increased daily production 310% to approximately 1,700 BOPD Drilled 102 new producers Added 3.3 MMBO of proven reserves Increased steam capacity by 280% Identified opportunities for additional pool development |
California Evaluating the Monterey Shale at South Lost Hills 34 |
California Modest Growth Opportunities, But Strong Economics 35 Field Average Well Cost Average EUR (MBO) Estimated IRR @$85/Bbl Fiscal 2015 Locations North Midway Sunset $300,000 32 59% 29 South Midway Sunset $300,000 38 96% 42 East Coalinga $580,000 35 30% 25 |
California Modest Growth Anticipated in 2015 36 |
California Strong Margins Support Significant Free Cash Flow 37 Average Revenue for Fiscal 2014 $87.71 per BOE Note: A reconciliation of Exploration & Production West Division EBITDA to Exploration & Production Segment Net Income is included at the end of this presentation. |
Seneca Resources What Will Seneca Look Like Moving Forward? 38 Consistent Production Growth: 15-25% CAGR Driven by a very large, high-quality Appalachian acreage position Maintain Oil Production Expand When Possible Excellent operator and significant cash flow generation Disciplined Spending Driven by Firm Pace of development adapts to changing market dynamics A Leader in Technology, Safety & Environmental Responsibility Maintain a leadership role in using technology and developing best practices |
39 Midstream Businesses Overview |
Midstream Businesses Positioned to Serve Rapidly Growing Production in Appalachia 40 |
Gathering Gathering is the First Step to Reaching a Market 41 |
Gathering Gathering Systems Supporting Seneca’s EDA Production 42 Covington Gathering System In-Service Date: November 2009 Capacity: 220,000 Dth per day Interconnect: TGP 300 Capital Expenditures (to date): $32 Million Trout Run Gathering System In-Service Date: May 2012 Capacity: 466,000 to 585,000 Dth per day Interconnect: Transco – Leidy Lateral Capital Expenditures (to date): $162 Million Capital Expenditures (future): $30 to $70 Million Interconnects 7.0 30.9 44.7 51.0 48.3 45-50 45.0 87.4 100-120 0 25 75 100 125 150 2010 2011 2012 2013 2014 2015E Fiscal Year Throughput by Project (Covington & Trout Run Systems) Covington Trout Run 50 5.3 |
Gathering Clermont Gathering System has Large Expandability 43 Clermont Gathering System In-Service: July 2014 Ultimate Trunkline Capacity: 1+ Bcf per day Interconnects TGP 300 (current) NFG Supply Corporation (Northern Access 2016) Capital: 2014: $96 Million 2015: $110 - $160 Million Seneca Pads Connected SRC Pad N (9 wells) connected July 2014 SRC Pad H (6 wells) connected September 2014 Up to 25 pads connected following the 2015 expansion |
Pipeline & Storage Project Opportunities to Support Appalachian Growth 44 |
Pipeline & Storage Expansions to Move Gas from the WDA Are Significant 45 Projects to Support WDA Growth Project Capacity (Dth/day) Northern Access 2015 140,000 Northern Access 2016 350,000 Total New Capacity 490,000 Project Capital Cost Northern Access 2015 $66 Million Northern Access 2016 $410 Million Total Capital Expenditures $476 Million Clermont Northern Access 2015 (November 2015) Northern Access 2016 (Late 2016) |
Pipeline & Storage Major Expansion Designed for Canadian Deliveries 46 Customer: Seneca Resources In-Service: November 2015 System: NFG Supply Corp. Capacity: 140,000 Dth per day Lease to TGP as part of their Niagara Expansion project Interconnect Niagara (TransCanada) Total Cost: $66 Million Major Facilities 23,000 HP Compression Northern Access 2015 Northern Access 2015 (November 2015) Clermont |
Pipeline & Storage Northern Access 2016 Provides Additional Access to Canada 47 Customer: Seneca Resources In-Service: Late 2016 System: NFG Supply Corp. & Empire Pipeline, Inc. Capacity 350,000 Dth per day Interconnect Chippawa (TransCanada) Total Cost: ~$410 Million FERC Timing Pre-filing: July 2014 Certificate filing: anticipated Q2 FY2015 Northern Access 2016 Northern Access 2016 (Late 2016) |
Pipeline & Storage Recent 3 rd Party Expansions Have Been Highly Successful 48 Completed Expansions for 3 rd Parties Capacity (Dth/day) Northern Access 2012 320,000 Tioga County Extension 350,000 Line N (2011, 2012 & 2013) 353,000 Total New Capacity 1,023,000 Capital Cost ($Millions) Northern Access 2012 $72 Tioga County Extension $58 Line N (2011, 2012 & 2013) $ 104 Total Capital Expenditures $234 Northern Access 2012 Tioga County Extension Line N Projects Annual Reservation Charges ($Millions) Northern Access 2012 $ 14.5 Tioga County Extension $ 41.9 Line N (2011, 2012 & 2013) $ 16.0 Total Reservation Charges $ 72.4 |
Pipeline & Storage Additional Line N Expansions 49 Customer: Third Party Placed in-service November 1, 2014 System: NFG Supply Corp. Capacity: 105,000 Dth per day Precedent agreements signed for all available capacity Interconnect Mercer (TGP Station 219) Total Cost: $34 Million Expansion: $30 Million System Modernization: $4 Million Major Facilities 3,550 HP Compressor 2.1 miles – 24” Replacement Pipeline Mercer Expansion Mercer (TGP Station 219) Mercer Expansion |
Mercer (TGP Station 219) Pipeline & Storage Pairing Line N Expansions with System Modernization 50 Customer: Third Party In-Service: November 2015 System: NFG Supply Corp. Capacity: 175,000 Dth per day Precedent agreements signed for all available capacity Interconnect Mercer (TGP Station 219) Holbrook (TETCO) Total Cost: $76 Million Expansion: $39 Million Modernization: $37 Million Major Facilities 3,550 HP Compressor 23.3 miles – 24” Replacement Pipeline Westside Expansion & Modernization Holbrook (TETCO) Westside Expansion & Modernization |
Pipeline & Storage Developing Unique Solutions for Shippers 51 In-Service: November 2015 System: NFG Supply & Empire Pipeline New No-Notice Services Precedent agreements executed with RG&E, NYSEG & NFG Utility Preserving 172,500 Dth per day (RG&E) Preserving 20,000 Dth per day (NYSEG) Retained Storage: 3.3 Bcf New incremental transportation capacity of 49,000 Dth per day Interconnect Tuscarora (NFG/Supply) Total Cost: $45 Million Major Facilities 1,500 HP Compressor 17 miles – 12”/16” Pipeline Tuscarora Lateral Tuscarora Lateral |
Pipeline & Storage Significant Expansions Are Driving Growth 52 Completed Projects (Since 2009) Recent Capacity Additions 1,113,000 Dth/day Line N Corridor Line “N” Expansion Line “N” 2012 Expansion Line “N” 2013 Expansion Mercer Expansion West Side Expansion Total Capacity 633 MDth/d Delivering Gas North Tioga County Extension Northern Access 2012 Northern Access 2015 Northern Access 2016 Total Capacity 1,160 MDth/d Other Projects Lamont Compressor Tuscarora Lateral Total Capacity 139 MDth/d Planned Projects (2014+) Precedent Agreements Executed Total Expansion (2009-2016+) Capacity Additions 1,932,000 Dth/day In-Service 2014 105,000 Dth/day In-Service 2015 364,000 Dth/day In-Service 2016+ 350,000 Dth/day |
53 Utility Overview |
Utility New York & Pennsylvania Service Territories 54 Total Customers: 524,300 Rate Mechanisms: Revenue Decoupling Weather Normalization Low Income Rates Merchant Function Charge (Uncollectibles Adjustment) 90/10 Sharing (Large Customers) NY PSC Rate Case Settlement, May 2014 Rates Unchanged 9.1% ROE Confirmed 2-Tier Earnings Sharing Mechanism 9.5% to 10.5% - Share 50% 10.5% > - Share 80% $8.2 MM CapEx - system replacement $8.0 MM incremental O&M (post- retirement benefits) Natural Gas Vehicle Pilot Program Total Customers: 213,500 Rate Mechanisms: Low Income Rates Merchant Function Charge ROE: Black Box Settlement (2007) New York Pennsylvania |
Utility Shifting Trends in Customer Usage 55 Residential Usage Industrial Usage (1) Weighted Average of New York and Pennsylvania service territories (assumes normal weather) |
Utility A Proven History of Controlling Costs 56 |
Utility Strong Commitment to Safety 57 The Utility remains focused on maintaining the ongoing safety and reliability of its system Near-term increase in capital expenditures is due to the approx. $60MM upgrade of the Utility’s Customer Information System (CIS) $44.4 $45.0 $44.3 $43.8 $48.1 $49.8 $56.2 $58.0 $58.4 $58.3 $72.0 $88.8 $95-$105 $0 $20 $40 $60 $80 $100 2009 2010 2011 2012 2013 2014 2015E Fiscal Year Capital Expenditures for Safety Total Capital Expenditures |
National Fuel Gas Company A History of Success & A Future of Opportunity 58 32% CAGR Since 2010 Adjusted EBITDA Growth Production Growth Midstream Businesses Adjusted EBITDA A History of Success 11% CAGR Since 2010 19% CAGR Since 2010 Note: A reconciliation of Adjusted EBITDA to Net Income as presented on the Consolidated Statement of Income and Earnings is included at the end of this presentation. A Future of Opportunity Adjusted EBITDA Growth Production Growth Midstream Businesses Adjusted EBITDA 10-15% CAGR 2015 to 2019 15-25% CAGR 2015 to 2019 10-15% CAGR 2015 to 2019 |
59 Appendix |
National Fuel Gas Company Natural Gas Hedge Positions 60 (Volumes in thousands Mmbtu; Prices in $/Mmbtu) Fiscal 2015 Fiscal 2016 Fiscal 2017 Fiscal 2018 Volume Avg. Price Volume Avg. Price Volume Avg. Price Volume Avg. Price NYMEX Swaps 70,690 $4.16 32,350 $4.24 23,130 $4.50 5,550 $4.59 Dominion Swaps 24,840 $3.74 18,840 $3.78 12,720 $3.87 - - SoCal Swaps 1,200 $4.35 - - - - - - MichCon Swaps - - 9,000 $4.10 3,000 $4.10 - - Dawn Swaps - - 5,490 $4.36 7,950 $4.14 - - Fixed Price Physical Sales 16,700 $3.77 18,300 $3.77 18,250 $3.77 1,550 $3.77 Total 113,430 $4.01 83,980 $4.03 65,050 $4.11 7,100 $4.41 |
National Fuel Gas Company Crude Oil Hedge Positions 61 Fiscal 2015 Fiscal 2016 Fiscal 2017 Fiscal 2018 Volume Avg. Price Volume Avg. Price Volume Avg. Price Volume Avg. Price Midway Sunset (MWSS) Swaps 258,000 $92.10 36,000 $92.10 - - - - Brent Swaps 903,000 $98.42 933,000 $95.18 384,000 $92.30 75,000 $91.00 NYMEX Swaps 396,000 $90.14 300,000 $86.09 - - - - Total 1,557,000 $95.27 1,269,000 $92.95 384,000 $92.30 75,000 $91.00 (Volumes & Prices in Bbl) |
Marcellus Shale Position Offers Attractive Economics at $2.00 to $3.80/Mcfe 62 Prospect County Product Approx. Remaining Locations EUR (Bcfe) BTU IRR (1) @ $4/MMBtu 15% IRR (1) Breakeven Price ($/Mcf) EASTERN DEVELOPMENT AREA (EDA) Tract 100 Lycoming Dry Gas 18 11.5-12.5 1,030 90% $1.92 Gamble Lycoming Dry Gas 29 10-11 1,030 77% $2.05 Tract 595 Tioga Dry Gas 14 8.1 1,030 45% $2.63 Covington Tioga Dry Gas Developed 5.8 1,030 22% $3.49 WESTERN DEVELOPMENT AREA (WDA) Clermont/Rich Valley Elk/Cameron Dry Gas 213 6-8 1,050 38% $2.80 Ridgway Elk Dry Gas 450-570 6-8 1,111 26% $3.30 Hemlock Elk Dry Gas 130-170 6-8 1,070 23% $3.40 Church Run Elk Dry Gas 60-70 6-8 1,125 22% $3.45 (W) West Branch McKean Dry Gas 47 6-8 1,050 22% $3.48 Heath Jefferson Dry Gas 260-330 5-8 1,060 19% $3.65 Sulger Farms Jefferson Dry Gas 170-210 5-8 1,020 19% $3.66 Owl’s Nest/James City Elk/Forest Dry Gas 120-160 5-8 1,125 18% $3.69 Boone Mt. Elk Dry Gas 230-290 4-6 1,020 18% $3.76 Church Run Elk Wet Gas 40-50 2-4 1,140 13% $4.32 Tionesta Forest/Venango Wet Gas/ Liquids 300-340 4-6 1,325 12% $4.50 Owl’s Nest/James City Elk/Forest Wet Gas 150-180 4-6 1,140 11% $4.51 Mt. Jewett McKean Wet Gas 90-110 2-4 1,140 6% $5.50 Beechwood Cameron Dry Gas 210-280 2-4 1,030 2% $7.14 Red Hill Cameron Dry Gas 150-200 2-4 1,030 2% $7.14 (1) Internal Rate of Return (IRR) includes estimated well costs under current cost structure, LOE, and Gathering tariffs anticipated for each prospect. |
Geneseo Shale Path to Geneseo Development – 2018/2019 Start 63 1 st Well (Tract 100 – Pad N) Peak IP: 14.1 MMcf per day 30-Day Average Rate: 8.6 MMcf per day Estimated EUR: 7.0 Bcf Lateral Length: 4,920’ Frac Stages: 33 stages Current developed infrastructure from DCNR 100 & Gamble: 13 well pads 3 compressor pads 3 water impoundments Gathering infrastructure Savings estimate of ~$300,000 per well from shared infrastructure • >125 Wells • Water Infrastructure = $13MM • Usable Pads = $16MM • Road Infrastructure = $16MM Tract 100/Gamble (Lycoming County) Geneseo Well |
National Fuel Gas Company Comparable GAAP Financial Measure Slides and Reconciliations 64 This presentation contains certain non-GAAP financial measures. For pages that contain non-GAAP financial measures, pages containing the most directly comparable GAAP financial measures and reconciliations are provided in the slides that follow. The Company believes that its non-GAAP financial measures are useful to investors because they provide an alternative method for assessing the Company’s ongoing operating results, for measuring the Company’s cash flow and liquidity, and for comparing the Company’s financial performance to other companies. The Company’s management uses these non-GAAP financial measures for the same purpose, and for planning and forecasting purposes. The presentation of non-GAAP financial measures is not meant to be a substitute for financial measures prepared in accordance with GAAP. The Company defines Adjusted EBITDA as reported GAAP earnings before the following items: interest expense, depreciation, depletion and amortization, interest and other income, impairments, items impacting comparability and income taxes. |
65 Reconciliation of Adjusted EBITDA to Consolidated Net Income ($ Thousands) FY 2009 FY 2010 FY 2011 FY 2012 Exploration & Production - West Division Adjusted EBITDA 171,572 $ 187,838 $ 187,603 $ 226,897 $ 215,042 $ 217,150 $ Exploration & Production - All Other Divisions Adjusted EBITDA 108,139 139,624 189,854 170,232 277,341 322,322 Total Exploration & Production Adjusted EBITDA 279,711 $ 327,462 $ 377,457 $ 397,129 $ 492,383 $ 539,472 $ Total Adjusted EBITDA Exploration & Production Adjusted EBITDA 279,711 $ 327,462 $ 377,457 $ 397,129 $ 492,383 $ 539,472 $ Pipeline & Storage Adjusted EBITDA 130,857 120,858 111,474 136,914 161,226 186,022 Gathering Adjusted EBITDA (141) 2,021 9,386 14,814 29,777 64,060 Utility Adjusted EBITDA 164,443 167,328 168,540 159,986 171,669 164,643 Energy Marketing Adjusted EBITDA 11,589 13,573 13,178 5,945 6,963 10,335 Corporate & All Other Adjusted EBITDA (5,434) 408 (12,346) (10,674) (9,920) (11,078) Total Adjusted EBITDA 581,025 $ 631,650 $ 667,689 $ 704,114 $ 852,098 $ 953,454 $ Total Adjusted EBITDA 581,025 $ 631,650 $ 667,689 $ 704,114 $ 852,098 $ 953,454 $ Minus: Net Interest Expense (81,013) (90,217) (75,205) (82,551) (89,776) (90,107) Plus: Other Income 9,762 6,126 5,947 5,133 4,697 9,461 Minus: Income Tax Expense (52,859) (137,227) (164,381) (150,554) (172,758) (189,614) Minus: Depreciation, Depletion & Amortization (170,620) (191,199) (226,527) (271,530) (326,760) (383,781) Minus: Impairment of Oil and Gas Properties (E&P) (182,811) - - - - - Plus/Minus: Income/(Loss) from Discontinued Operations, Net of Tax (Corp. & All Other) (2,776) 6,780 - - - - Plus: Gain on Sale of Unconsolidated Subsidiaries (Corp. & All Other) - - 50,879 - - - Plus: Elimination of Other Post-Retirement Regulatory Liability (P&S) - - - 21,672 - - Minus: Pennsylvania Impact Fee Related to Prior Fiscal Years (E&P) - - - (6,206) - - Minus: New York Regulatory Adjustment (Utility) - - - - (7,500) - Minus: Plugging and Abandonment Accrual (E&P) - - - - - - Rounding - - - (1) - - Consolidated Net Income 100,708 $ 225,913 $ 258,402 $ 220,077 $ 260,001 $ 299,413 $ Consolidated Debt to Total Adjusted EBITDA Long-Term Debt, Net of Current Portion (End of Period) 1,249,000 $ 1,049,000 $ 899,000 $ 1,149,000 $ 1,649,000 $ 1,649,000 $ Current Portion of Long-Term Debt (End of Period) - 200,000 150,000 250,000 - - Notes Payable to Banks and Commercial Paper (End of Period) - - 40,000 171,000 - 85,600 Total Debt (End of Period) 1,249,000 $ 1,249,000 $ 1,089,000 $ 1,570,000 $ 1,649,000 $ 1,734,600 $ Long-Term Debt, Net of Current Portion (Start of Period) 999,000 1,249,000 1,049,000 899,000 1,149,000 1,649,000 Current Portion of Long-Term Debt (Start of Period) 100,000 - 200,000 150,000 250,000 - Notes Payable to Banks and Commercial Paper (Start of Period) - - - 40,000 171,000 - Total Debt (Start of Period) 1,099,000 $ 1,249,000 $ 1,249,000 $ 1,089,000 $ 1,570,000 $ 1,649,000 $ Average Total Debt 1,174,000 $ 1,249,000 $ 1,169,000 $ 1,329,500 $ 1,609,500 $ 1,691,800 $ Average Total Debt to Total Adjusted EBITDA 2.02 x 1.98 x 1.75 x 1.89 x 1.89 x 1.77 x FY 2013 FY 2014 |
66 Reconciliation of Segment Capital Expenditures to Consolidated Capital Expenditures ($ Thousands) FY 2015 FY 2009 FY 2010 FY 2011 FY 2012 FY 2013 FY 2014 Forecast Capital Expenditures from Continuing Operations Exploration & Production Capital Expenditures 188,290 $ 398,174 $ 648,815 $ 693,810 $ 533,129 $ 602,705 $ $600,000-700,000 Pipeline & Storage Capital Expenditures 52,504 37,894 129,206 144,167 56,144 $ 139,821 $ $225,000-275,000 Gathering Segment Capital Expenditures 9,433 �� 6,538 17,021 80,012 54,792 $ 137,799 $ $1250,000-200,000 Utility Capital Expenditures 56,178 57,973 58,398 58,284 71,970 $ 88,810 $ $95,000-105,000 Energy Marketing, Corporate & All Other Capital Expenditures 396 773 746 1,121 1,062 $ 772 $ - Total Capital Expenditures from Continuing Operations 306,801 $ 501,352 $ 854,186 $ 977,394 $ 717,097 $ 969,907 $ $1,070,000-1,238,000 Capital Expenditures from Discountinued Operations All Other Capital Expenditures 216 150 $ - $ - $ - $ - $ - $ Plus (Minus) Accrued Capital Expenditures Exploration & Production FY 2014 Accrued Capital Expenditures - $ - $ - $ - $ - $ (80,108) $ Exploration & Production FY 2013 Accrued Capital Expenditures - - - - (58,478) 58,478 - Exploration & Production FY 2012 Accrued Capital Expenditures - - - (38,861) 38,861 - - Exploration & Production FY 2011 Accrued Capital Expenditures - - (103,287) 103,287 - - - Exploration & Production FY 2010 Accrued Capital Expenditures - (78,633) 78,633 - - - - Exploration & Production FY 2009 Accrued Capital Expenditures (9,093) 19,517 - - - - - Pipeline & Storage FY 2014 Accrued Capital Expenditures - - - - - (28,122) Pipeline & Storage FY 2013 Accrued Capital Expenditures - - - - (5,633) 5,633 - Pipeline & Storage FY 2012 Accrued Capital Expenditures - - - (12,699) 12,699 - - Pipeline & Storage FY 2011 Accrued Capital Expenditures - - (16,431) 16,431 - - - Pipeline & Storage FY 2010 Accrued Capital Expenditures - - 3,681 - - - - Pipeline & Storage FY 2008 Accrued Capital Expenditures 16,768 - - - - - - Gathering FY 2014 Accrued Capital Expenditures - - - - - (20,084) Gathering FY 2013 Accrued Capital Expenditures - - - - (6,700) 6,700 - Gathering FY 2012 Accrued Capital Expenditures - - - (12,690) 12,690 - - Gathering FY 2011 Accrued Capital Expenditures - - (3,079) 3,079 - - - Gathering FY 2009 Accrued Capital Expenditures (715) 715 - - - - - Utility FY 2014 Accrued Capital Expenditures - - - - - (8,315) Utility FY 2013 Accrued Capital Expenditures - - - - (10,328) 10,328 - Utility FY 2012 Accrued Capital Expenditures - - - (3,253) 3,253 - - Utility FY 2011 Accrued Capital Expenditures - - (2,319) 2,319 - - - Utility FY 2010 Accrued Capital Expenditures - - 2,894 - - - - Total Accrued Capital Expenditures 6,960 $ (58,401) $ (39,908) $ 57,613 $ (13,636) $ (55,490) $ - $ Eliminations (344) $ - $ - $ - $ - $ - $ - $ Total Capital Expenditures per Statement of Cash Flows 313,633 $ 443,101 $ 814,278 $ 1,035,007 $ 703,461 $ 914,417 $ $1,070,000-1,238,000 |