National Fuel Gas Company Investor Presentation May 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; 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; changes in demographic patterns and weather conditions; changes in the availability, price or accounting treatment of derivative financial instruments; 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; 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; the cost and effects of legal and administrative claims against the Company or activist shareholder campaigns to effect changes at the Company; 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 and March 31, 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 Exceptional Assets, Focused on Execution 3 1.549 Tcfe of Proved Reserves (1) 800,000 Net Acres in Pennsylvania 2.9 MMBbl of Crude Oil Production (2) $221 Million of Midstream Adjusted EBITDA (2) (1) As of September 30, 2013 (2) 12 months ended March 31, 2014. Includes the Pipeline & Storage segment and Gathering segment. Note: A reconciliation of Adjusted EBITDA to Net Income is included at the end of this presentation. |
National Fuel Gas Company Targeting Sustained Growth Over the Next Five Years 4 2014 – 2018 10-15% Forecasted Adjusted EBITDA CAGR $164 $167 $169 $160 $172 $177 $131 $121 $111 $137 $161 $176 $45 $280 $327 $377 $397 $492 $537 $581 $632 $668 $704 $852 $934 $0 $250 $500 $750 $1,000 $1,250 2009 2010 2011 2012 2013 12-Months Ended 3/31/14 2014 Forecast 2015 Forecast Fiscal Year Exploration & Production Segment Gathering Segment Pipeline & Storage Segment Utility Segment Energy Marketing & Other 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 5 $56 $58 $58 $58 $72 $85-$95 $90-$100 $53 $38 $129 $144 $56 $115- $135 $225- $275 $80 $55 $100- $145 $100- $150 $188 $398 $649 $694 $533 $550- $625 $650- $750 $307 (1) $501 $854 $977 $717 $850- $1,000 $1,065- $1,275 $0 $250 $500 $750 $1,000 $1,250 $1,500 2009 2010 2011 2012 2013 2014 Forecast 2015 Forecast Fiscal Year Exploration & Production Segment Gathering Segment Pipeline & Storage Segment Utility Segment Energy Marketing & Other 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 6 Total Debt (1) 42% $3.949 Billion As of March 31, 2014 2.02 x 1.98 x 1.75 x 1.89 x 1.89 x 1.76 x 0.0 0.5 1.0 1.5 2.0 2.5 2009 2010 2011 2012 2013 12-Months Ended 3/31/14 Fiscal Year Debt / Adjusted EBITDA Capitalization Shareholders’ Equity 58% 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 |
National Fuel Gas Company Dividend Track Record 7 (1) As of May 7, 2014 Current Dividend Yield (1) 2.0% Dividend Consistency Consecutive Dividend Payments 111 Years Consecutive Dividend Increases 43 Years Current Annualized Dividend Rate $1.50 per Share $0.00 $0.50 $1.00 $1.50 $2.00 Annual Rate at Fiscal Year End |
8 Exploration & Production Overview |
Seneca Resources Proven Record of Growth 9 (1) Represents a three-year average U.S. finding and development cost 2013 F&D Cost = $1.31 Marcellus F&D: $0.99 Doubled Proved Reserves Since 2010 71% Proved Developed 46.2 46.6 45.2 43.3 42.9 41.6 226 249 428 675 988 1,300 503 528 700 935 1,246 1,549 0 500 1000 1500 2000 2008 2009 2010 2011 2012 2013 At September 30 Natural Gas (Bcf) Crude Oil (MMbbl) Fiscal Years 3-Year F&D Cost (1) ($/Mcfe) 2006-2008 $7.63 2007-2009 $5.35 2008-2010 $2.37 2009-2011 $2.09 2010-2012 $1.87 2011-2013 $1.67 |
Seneca Resources Delivering Tremendous Production Growth 10 19.8 19.2 20.5 20.0 20-22 21-23 16.5 43.2 62.9 100.7 135-143 159-197 13.3 49.7 67.6 83.4 120.7 155-165 180-220 0 75 150 225 2010 2011 2012 2013 2014 Forecast Fiscal Year Gulf of Mexico (Divested in 2011) East Division (Appalachia) West Division (California/Kansas) Forecast 2015 |
Seneca Resources Disciplined Capital Spending 11 (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 12 (1) Represents the midpoint of current General & Administrative Expense guidance of $0.40 to $0.45 per Mcfe for fiscal 2014 (2) The total of the two Lease Operating Expense components represents the midpoint of current Lease Operating Expense guidance of $0.95 to $1.05 per Mcfe for fiscal 2014 Seneca expects to convert its long-term firm transport (FT) contracts into firm sales (FS) agreements, with the cost reflected in price realization. As such, it is not included in LOE. |
Marcellus Shale Prolific Pennsylvania Acreage 13 Eastern Development Area (EDA) 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 720,000 Acres 60,000 Acres No near-term lease expiration Drilling activity will HBP key acreage Ongoing development drilling in Tioga and Lycoming counties Mostly leased (16-18% royalty) Seneca Lease Seneca Fee Western Development Area (WDA) |
Marcellus Shale EDA Delivering Significant Growth 14 Covington – Fully Developed Gross Production: ~50 MMcf per Day 47 Wells Drilled and Producing DCNR Tract 595 Gross Production: ~80 MMcf per Day 39 Wells Drilled (52 Total Locations) 32 Wells Producing DCNR Tract 100 Gross Production: ~300 MMcf per Day 58 Wells Drilled (70 Total Locations) 43 Wells Producing Gamble Recently, 30 to 50 future locations 3 Wells Drilled; 1 Well Producing were added in Lycoming County 1 1 (1) One well included in this total is drilled into and producing from the Geneseo Shale |
Marcellus Shale EDA – Historical Well Results Are Exceptional 15 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 32 7.4 6.1 5.1 8.1 4,736’ 1.72 Tract 100 Lycoming County 36 (1) 15.9 14.0 11.6 11.6 5,153’ 2.24 Seneca is the industry leader in Lycoming County (1) Includes one horizontal well producing from the Geneseo Shale. Does not include seven new Marcellus Shale wells with less than 30 days of production history. |
Marcellus Shale Seneca’s Lycoming Economics are in the Top 3 16 Source: ITG IR, raw data provided by didesktop and state agencies There are an additional 109 breakeven data points greater than $3.69/Mcf |
Marcellus Shale Huge Position – Varies in Understanding 17 Seneca Lease Seneca Fee Tier I ~200,000 Acres Northeast Core ~30,000 acres in NE Core Tier I Acres ~200,000 acres Economic at $2.80 to $3.80/Mcfe Longer-Term Evaluation ~250,000 acres (Minimal Lease Expiration) Requires Gas Price Above $4/Mcf ~300,000 acres Understanding Seneca’s 780,000 Net Acres Size of combined EDA current development areas |
Marcellus Shale 2013 & 2014 WDA Delineation Program 18 Rich Valley – Full Development 2 Wells Completed 7-Day IP of 7.8 MMcf/d & EUR of 7.4 Bcf 2 nd Well 7-Day IP: 4.5 MMcf/d Clermont – Full Development 2 Wells Completed 9H: 7-Day IP of 10 MMcf/d & EUR of 8.6 Bcf 10H: 7-Day IP of 7.3 MMcf/d & EUR of 6.6 Bcf Owl’s Nest – Delineating 2 High Btu Wells Completed Tested Two Completion Designs Church Run – Delineating 1 Well Completed Tionesta – Delineating 1 Well Completed Heath – Delineating 1 Well Planned Seneca Operated Sulger Farms – Delineating 1 Well Drilled Hemlock – Delineating 1 Well Drilled Ridgway – Delineating 1 Well Completed 2013 Drill Program 2014 Drill Program SRC Lease Acreage SRC Fee Acreage EOG Earned JV Acreage |
Marcellus Shale Strong Wells Across WDA Acreage 19 Well Name Completion Design Treatable Lateral Length Stages Peak 24-Hour Rate (MMcfd) Peak 7-Day Rate (MMcfd) EUR (Bcf) Status Clermont 9H RCS 1 5,500’ 37 11.4 10.0 8.6 Producing Clermont 10H Non-RCS 5,565’ 23 8.1 7.3 6.9 Producing Rich Valley 27H RCS 6,372’ 42 8.1 7.8 7.9 Producing Rich Valley 25H RCS 4,492’ 30 5.0 4.5 4.5 Producing Ridgway 19H RCS 5,537’ 37 7.1 6.4 6-8 Flowback Test Church Run 2H RCS 4,435’ 29 4.8 4.5 4.5-5.5 Producing Owl’s Nest 54H RCS 6,139’ 41 6.1 5.8 4-7 Flowback Test (1) RCS – Reduced Cluster Spacing |
Marcellus Shale Clermont Wells Improved from Early Non-Op JV Wells 20 Clermont 5H & 6H (Non-op wells) Avg. lateral length: 3,344’ Small casing: 4.5” Restricted pump rates Wide stage spacing: 350’ No “soaking”, low Sw’s Clermont 9H & 10H (Seneca wells) Avg. lateral length: >5,500’ Larger casing: 5.5” Increased pump rates 9H (RCS): 150’ spacing 10H (Standard): 240’ spacing “Soaked” both wells: 30 Days |
Marcellus Shale Clermont/Rich Valley RCS Wells Outperforming Typecurve 21 |
Marcellus Shale CRV is in Full Development Mode 22 Marcellus Faults Marcellus & Basement Faults 200-250 Horizontal Locations SRC Lease Acreage SRC Fee Acreage Planned Wells Drilled Wells Producing Wells Pad D08-N: Spacing Test JV Wells Pad E09-H Pad E09-E Rich Valley 2 nd Well 7-day IP: 4.5 MMcf/d Lateral Length: 4,492’ Rich Valley 7-day IP: 7.8 MMcf/d EUR: 7.4 BCF Lateral Length: 6,372’ Clermont RCS: 9H 7-day IP: 10.0 MMcf/d (EUR: 8.6 Bcf) Non-RCS: 10H 7-day IP: 7.4 MMcf/d Pad D08-G Pad C08-F Pad D09-D Pad C08-G |
Marcellus Shale 200,000 Acres With 6-8 Bcfe EUR Wells 23 Note: Assumes 6,000’ treated lateral length |
Marcellus Shale ~2,000 Economic Locations at $2.00 to $3.80/Mcfe 24 Prospect County Product Approx. Remaining Locations EUR (Bcfe) BTU IRR (1) @ $4/MMBtu 15% IRR (1) Breakeven Price ($/Mcf) Tract 100 Lycoming Dry Gas 28 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 20 8.1 1,030 45% $2.63 Clermont/Rich Valley Elk/Cameron Dry Gas 228 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 Covington Tioga Dry Gas Developed 5.8 1,030 22% $3.49 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 2013 Appraisal prospects 2014 Appraisal prospects Internal Rate of Return (IRR) includes estimated well costs under current cost structure, LOE, and Gathering tariffs anticipated for each prospect (1) |
Natural Gas Marketing How Does Seneca Sell its Production? 25 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 26 Project Volume (Dth/d) In-Service Date Comments Northeast Supply Diversification Project (TGP) 50,000 2012 Executed firm sales agreements for entire capacity over 10 years Niagara Expansion (TGP/NFG) 170,000 November 2015 Executed firm sales agreements for 140,000 Dth/d for the entire 15 years Atlantic Sunrise (Transco) 189,405 2017 Evaluating marketing opportunities Agreements Executed Project Volume (Dth/d) Target In- Service Date Comments Northern Access 2016 (NFG)/ TransCanada Open Season 350,000 2016 Evaluating market potential for transportation path from WDA into Canada Under Evaluation Additional current and future Appalachian marketing opportunities are continuously under evaluation |
Natural Gas Marketing Significant Base of Long-Term Firm Contracts 27 Atlantic Sunrise Northern Access 2016 (Under Evaluation) Niagara Expansion/ Northern Access 2015 - 250 500 750 1,000 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 Gross Firm Sales Firm Transport Over time, Seneca plans to convert most or all of its firm transportation capacity to firm sales agreements |
Natural Gas Marketing Firm Sales Provide a Market for Appalachian Production 28 (1) Subject to change in transport rates on TransCanada Pipeline 28 EDA 311,834 MMBtu/Day 270,036 MMBtu/Day 230,036 MMBtu/Day WDA 21,314 MMBtu/Day 41,100 MMBtu/Day 20,000 MMBtu/Day Values shown represent the price or differential to a reference price (netback price) at the first non-affiliated interstate pipeline, including the cost of all related downstream transportation. |
Natural Gas Marketing Current Natural Gas Hedge Positions 29 (1) 2014 hedge positions are for the remaining six months of the fiscal year. Full details can be found in the appendix. (1) |
Natural Gas Marketing Current Hedge Book has Seneca Positioned Very Well 30 (1) 2014 hedge positions are for the remaining six months of the fiscal year Note: Hedge positions for fiscal years 2016-2018 reflect the midpoint of Seneca’s target annual production growth (20%) starting with the midpoint of Fiscal 2015 guidance (180-220 Bcfe) Natural Gas $4.07/MMBtu $4.10/MMBtu $4.12/MMBtu $4.23/MMBtu $4.59/MMBtu Crude Oil $100.22/Bbl $95.27/Bbl $92.95/Bbl $92.30/Bbl $91.00/Bbl (1) |
Natural Gas Marketing FY 2014 Production – Firm Sales & Hedge Composition 31 Price Certainty Seneca has an additional ~13 Bcf of NYMEX hedges to help mitigate commodity exposure on its sales Price Certainty There were no spot volume curtailments in April 2014 64 Bcf 29 Bcf 13.7 Bcf 0.5 Bcf 13.5 Bcf 11 Bcf 7.3 Bcf 135-143 0 30 60 90 120 150 Q1 & Q2 DOM Production NYMEX Firm Sales Firm Sales Fixed Price Sales EDA Spot Sales WDA Total Spot Sales East Division Production |
Natural Gas Marketing FY 2015 Production – Firm Sales & Hedge Composition 32 Price Certainty Seneca will continue to pursue firm sales agreements to mitigate spot market exposure during the year Price Certainty 54 Bcf 17.8 Bcf 4 Bcf 56 Bcf 36 Bcf 10.2 Bcf 159-197 0 50 100 150 200 NYMEX Firm Sales DOM Firm Sales Dawn EDA Firm Sales Spot Sales WDA Spot Sales Total East Division Production |
Geneseo Shale Path to Geneseo Development – 2018/2019 Start 33 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 |
Point Pleasant & Utica Shale Industry Activity & 2014 Appraisal Program 34 MT JEWETT Horizontal: Completed September 2013 Peak 24-Hour Rate: 8.5 MMcf/d RANGE RESOUCES 1.4 MMcf/d “Not Effectively Stimulated” HALCON 2.5 MMcf/d, 360 Bbls/d HALCON 4.5 MMcf/d, 860 Bbls/d HALCON 6.6 MMcf/d, 750 Bbls/d REX 9.2 MMcf/d RANGE 4.4 MMcf/d CHESAPEAKE 6.4 MMcf/d TIONESTA Horizontal: Completed Fall 2012 Peak 24-Hour Rate: 3.9 MMcf/d HEATH Core Pilot DCNR 007 Core & Drill |
California Stable Production Fields; Modest Growth Potential 35 East Coalinga Temblor Formation Primary North Lost Hills Tulare & Etchegoin Formation Primary/Steamflood South Lost Hills Monterey Shale Primary North Midway Sunset Tulare & Potter Formation Steamflood South Midway Sunset Antelope Formation Steamflood Sespe Sespe Formation Primary Key Areas of Focus in 2014 1. East Coalinga Evaluation 2. South Midway Sunset Extensions 3. South Lost Hills Monterey Evaluation |
California East Coalinga Summary 36 Production has increased from 214 BOPD to 849 BOPD • Highest on leases since 2000 Drilled 12 evaluation wells in 2013 • Producing ~150 BOPD Currently drilling 33 new producers and 2 water disposal wells in 2014 |
California South Midway Sunset Has Delivered Significant Growth 37 252 Pool 97X Pool SE Pool 251 Pool B Pool A Pool Extended Pool Boundary Original Pool Boundary Existing Wells 1000’ 16X Pool Seneca Acquired in June 2009 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 38 Upper Antelope A Upper Antelope B Truman 1H 2013 190 BOEPD Citrus 2H Waiting on Completion Truman 2H Waiting on Completion GR SP ResD Brittleness Gas Oil 18 potential locations in each of the three horizons (concept) Seneca Lease 1000’ Lower Reef Ridge McDonald Citrus 11 |
California Limited Growth Opportunities, But Strong Economics 39 Field Average Well Cost Average EUR (MBO) Estimated IRR @$100/Bbl Fiscal 2014 Locations South Midway Sunset $250,000 30 75% 23 East Coalinga $400,000 40 50% 33 Sespe – Coldwater $2,800,000 180 35% 4 |
California Modest Growth Anticipated in 2014 and 2015 40 Forecast Fiscal Year |
California Outstanding Cash Flow (1) 41 (1) Adjusted EBITDA and Capital Expenditures represent Seneca Resources Corporation’s West Division, which includes its activity in Kansas. A reconciliation of Adjusted EBITDA to Net Income is included at the end of this presentation. |
California Looking Forward 42 1. Manage decline of base production 2. Pursue and develop opportunities for growth from current assets Sespe East Coalinga South Midway Sunset 3. Continue to pursue additional acquisition and farm-in opportunities |
Seneca Resources What Will Seneca Look Like Moving Forward? 43 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 Rates of Return 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 |
44 Midstream Businesses Overview |
Midstream Businesses Positioned to Serve Seneca’s Rapidly Growing Production 45 |
Gathering Gathering is the First Step to Reaching a Market 46 TGP 300 Transco TGP 200 Trout Run Gathering System (In-Service) Covington Gathering System (In-Service) Clermont Gathering System (Under Construction) Gathering Interconnects (In-Service and Under Construction) |
Gathering Existing Systems Supporting Seneca’s Near-Term Growth 47 Covington Gathering System In-service date: November 2009 Capacity: 220,000 Dth per day Interconnect: TGP 300 Capital expenditures (to date): $31.2 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): $144 million Capital expenditures (future): $50 to $80 million Interconnects |
Gathering Clermont Gathering System has Large Expandability 48 C Clermont Gathering System In-Service: Ongoing build-out Ultimate Trunkline Capacity: 700 to 1,000 MMcf per day Interconnects TGP 300 and National Fuel Gas Supply Corporation (anticipated) Capital: 2014: $60- $92 million 2015: $75 - $125 million Seneca Pads Connected Up to 25 pads connected following the 2015 expansion C C Compressor Station Interconnect C |
Gathering Capital Deployment Will Deliver Long-Term Growth 49 Revenue Growth (2013 to 2015): ~60% CAGR Capital Investment (2013 to 2015): ~60% CAGR |
Pipeline & Storage Project Opportunities to Support WDA Growth 50 Develop multiple outlets to high-value markets |
Pipeline & Storage Expansions to Move Gas from the WDA are Significant 51 Projects to Support WDA Growth Project Capacity (Dth/day) Northern Access 2015 140,000 Northern Access 2016¹ 350,000 Total New Capacity 490,000 Project Capital Cost Northern Access 2015 $66 million Northern Access 2016¹ $410 million Total Capital Expenditures $476 million Northern Access 2015 (November 2015) Northern Access 2016 (2016) Clermont (1) Previously referred to as the Clermont to Chippawa expansion project |
Pipeline & Storage Major Expansion Designed for Canadian Deliveries 52 In-Service: November 2015 System: NFG Supply Corp. Capacity: 140,000 Dth per day Lease to TGP (Kinder) as part of their Niagara Expansion project Interconnect Niagara (TransCanada) Total Cost: $66 Million Major Facilities 23,000 HP Compressor Northern Access 2015 Northern Access 2015 (November 2015) Clermont |
Pipeline & Storage Northern Access 2016 Provides Additional Access to Canada 53 In-Service: 2016 System: NFG Supply Corp. & Empire Pipeline, Inc. Capacity 350,000 Dth per day Interconnect Chippawa (TransCanada) Total Cost: ~$410 Million Northern Access 2016 (2016) Clermont Northern Access 2016 (1) (1) Previously referred to as the Clermont to Chippawa expansion project |
Pipeline & Storage Recent 3 rd Party Expansions Have Been Highly Successful 54 Completed Expansions for 3 Parties Project 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 Project Capital Cost Northern Access 2012 $72 million Tioga County Extension $58 million Line N (2011, 2012 & 2013) $104 million Total Capital Expenditures $234 million Northern Access 2012 Tioga County Extension Line N Projects rd |
Pipeline & Storage Additional Line N Expansions Planned for the Future 55 In-Service: November 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 56 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 System 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 57 In-Service: November 2015 System: NFG Supply & Empire Pipeline New No-Notice Services 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 Precedent agreements executed with RG&E and NYSEG Negotiating an additional precedent agreement with a third shipper Interconnect Tuscarora (NFG/Supply) Total Cost: $45 Million Major Facilities 1,500 HP Compressor 17 miles – 12” Pipeline Tuscarora Lateral Tuscarora Lateral |
Pipeline & Storage Significant Expansions Are Driving Growth 58 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 (1) Total Capacity 1,160 MDth/d Other Projects Lamont Compressor Tuscarora Lateral Total Capacity 154 MDth/d Planned Projects (2014 -2015) Precedent Agreements Executed Planned Capacity Additions 484,000 Dth/day Potential Projects (2016+) Currently Evaluating Potential Capacity Additions 350,000 Dth/day Total (2009-2016+) Capacity Additions 1,947,000 Dth/day (1) Previously referred to as the Clermont to Chippawa expansion project |
Pipeline & Storage Expansion Project Revenue Growth 59 Larger projects under consideration for fiscal 2016 and 2017 will drive significant revenue growth Annual Expansion Revenue Projects Placed in Service Since Fiscal 2011 |
60 Utility Overview |
Utility New York & Pennsylvania Service Territories 61 Total Customers: 522,000 Rate Mechanisms: Natural Gas Vehicle Pilot Program Target ROE: 9.1% (Litigated - 2007) Pennsylvania Total Customers: 213,000 Rate Mechanisms: ROE: Black Box Settlement (2007) New York Revenue Decoupling Weather Normalization Low Income Rates Choice Program/Purchase of Receivables Merchant Function Charge (Uncollectibles Adjustment) 90/10 Sharing (Large Customers) Low Income Rates Choice Program/Purchase of Receivables Merchant Function Charge |
Utility Customer Usage 62 Residential Usage Industrial Usage (1) Weighted Average of New York and Pennsylvania service territories (assumes normal weather) 80 90 100 110 120 12-Months Ended March 31 15 20 25 30 35 12-Months Ended March 31 |
Utility Ongoing Cost Control Helps Provide Earnings Stability 63 $178 $164 $167 $168 $168 $172 $178 $25 $27 $14 $11 $9 $6 $7 $203 $191 $181 $179 $177 $178 $185 $0 $50 $100 $150 $200 $250 2008 2009 2010 2011 2012 2013 12 Months Ended 3/31/14 Fiscal Year All Other O&M Expenses O&M Uncollectible Expense |
Utility Capital Spending Largely Focused on Maintenance 64 The Utility remains focused on spending to maintain the ongoing safety and reliability of its system $44.4 $45.0 $44.3 $43.8 $48.1 $56.2 $58.0 $58.4 $58.3 $72.0 $85-$95 $90-$100 $0 $20 $40 $60 $80 $100 2009 2010 2011 2012 2013 2014 Forecast 2015 Forecast Fiscal Year Capital Expenditures for Safety Total Capital Expenditures |
Utility Achieved a Settlement in New York 65 March 27, 2013 Filed a plan with the NY PSC to adopt an earnings sharing and stabilization mechanism on earnings above a 9.96% ROE April 19, 2013 NY PSC issued an Order to Show Cause (OTSC) commencing a proceeding to establish “temporary rates” June 1, 2013 OTSC suggests “temporary rates” could become effective NY PSC approved the Joint Proposal on May 8, 2014 May 8, 2013 Company responds to OTSC June 14, 2013 “Temporary rates” become effective July 26, 2013 Settlement discussions commence for permanent rates December 6, 2013 Joint Proposal filed October 1, 2013 Effective date of two-year rate plan under proposed settlement |
National Fuel Gas Company A History of Success & A Future of Opportunity 66 30% CAGR Since 2009 Adjusted EBITDA Growth Production Growth Midstream Businesses Adjusted EBITDA 10-15% CAGR 2014 to 2018 Adjusted EBITDA Growth 15-25% CAGR 2014 to 2018 Production Growth 10-15% CAGR 2014 to 2018 Midstream Businesses Adjusted EBITDA A History of Success 10% CAGR Since 2009 10% CAGR Since 2009 Note: A reconciliation of Adjusted EBITDA to Net Income as presented on the Consolidated Statement of Income and Earnings is included at the end of this presentation. A Future of Opportunity |
67 Appendix |
National Fuel Gas Company Current Hedge Positions 68 Fiscal Year NYMEX Volume (MMBtu) Average Price ($/MMBtu) Dominion Volume (MMBtu) Average Price ($/MMBtu) SoCal Volume (MMBtu) Average Price ($/MMBtu) Total Volume (MMBtu) Average Price ($/MMBtu) 2014 (1) 44,100,000 $4.07 14,400,000 $4.06 600,000 $4.35 59,100,000 $4.07 2015 69,590,000 $4.16 18,720,000 $3.88 1,200,000 $4.35 89,510,000 $4.10 2016 37,740,000 $4.25 18,840,000 $3.88 - - 56,580,000 $4.12 2017 24,960,000 $4.49 18,840,000 $3.88 - - 43,800,000 $4.23 2018 5,550,000 $4.59 - - - - 5,550,000 $4.59 Natural Gas Hedges Fiscal Year MWSS Volume (Bbl) Average Price ($/Bbl) Brent Volume (Bbl) Average Price ($/Bbl) NYMEX Volume (Bbl) Average Price ($/Bbl) Total Volume (Bbl) Average Price ($/Bbl) 2014 (1) 312,000 $95.68 672,000 $102.32 - - 948,000 $100.22 2015 258,000 $92.10 903,000 $98.42 396,000 $90.14 1,557,000 $95.27 2016 36,000 $92.10 933,000 $95.18 300,000 $86.09 1,269,000 $92.95 2017 - - 384,000 $92.30 - - 384,000 $92.30 2018 - - 75,000 $91.00 - - 75,000 $91.00 Crude Oil Hedges (1) 2014 hedge positions are for the remaining six months of the fiscal year |
National Fuel Gas Company Comparable GAAP Financial Measure Slides and Reconciliations 69 This presentation contains certain non-GAAP financial measures. For pages that contain non-GAAP financial measures, pages containing the most directly comparable GAAP financial measures and reconciliations are provided in the slides that follow. The Company believes that its non-GAAP financial measures are useful to investors because they provide an alternative method for assessing the Company’s ongoing operating results, for measuring the Company’s cash flow and liquidity, and for comparing the Company’s financial performance to other companies. The Company’s management uses these non-GAAP financial measures for the same purpose, and for planning and forecasting purposes. The presentation of non-GAAP financial measures is not meant to be a substitute for financial measures prepared in accordance with GAAP. The Company defines Adjusted EBITDA as reported GAAP earnings before the following items: interest expense, depreciation, depletion and amortization, interest and other income, impairments, items impacting comparability and income taxes. |
70 Reconciliation of Adjusted EBITDA to Consolidated Net Income ($ 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 $ 212,153 $ Exploration & Production - All Other Divisions Adjusted EBITDA 108,139 139,624 189,854 170,232 277,341 324,820 Total Exploration & Production Adjusted EBITDA 279,711 $ 327,462 $ 377,457 $ 397,129 $ 492,383 $ 536,973 $ Total Adjusted EBITDA Exploration & Production Adjusted EBITDA 279,711 $ 327,462 $ 377,457 $ 397,129 $ 492,383 $ 536,973 $ Pipeline & Storage Adjusted EBITDA 130,857 120,858 111,474 136,914 161,226 175,852 Gathering Adjusted EBITDA (141) 2,021 9,386 14,814 29,777 45,478 Utility Adjusted EBITDA 164,443 167,328 168,540 159,986 171,669 177,432 Energy Marketing Adjusted EBITDA 11,589 13,573 13,178 5,945 6,963 7,942 Corporate & All Other Adjusted EBITDA (5,434) 408 (12,346) (10,674) (9,920) (9,395) Total Adjusted EBITDA 581,025 $ 631,650 $ 667,689 $ 704,114 $ 852,098 $ 934,282 $ Total Adjusted EBITDA 581,025 $ 631,650 $ 667,689 $ 704,114 $ 852,098 $ 934,282 $ Minus: Net Interest Expense (81,013) (90,217) (75,205) (82,551) (89,776) (92,497) Plus: Other Income 9,762 6,126 5,947 5,133 4,697 7,548 Minus: Income Tax Expense (52,859) (137,227) (164,381) (150,554) (172,758) (195,543) Minus: Depreciation, Depletion & Amortization (170,620) (191,199) (226,527) (271,530) (326,760) (357,488) 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) (7,500) Minus: Plugging and Abandonment Accrual (E&P) - - - - - (5,002) Rounding - - - (1) - - Consolidated Net Income 100,708 $ 225,913 $ 258,402 $ 220,077 $ 260,001 $ 283,800 $ 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 - - Total Debt (End of Period) 1,249,000 $ 1,249,000 $ 1,089,000 $ 1,570,000 $ 1,649,000 $ 1,649,000 $ 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 $ 1,649,000 $ Average Total Debt to Total Adjusted EBITDA 2.02 x 1.98 x 1.75 x 1.89 x 1.89 x 1.76 x FY 2013 12-Months Ended 3/31/14 |
71 Reconciliation of Segment Capital Expenditures to Consolidated Capital Expenditures ($ Thousands) FY 2014 FY 2009 FY 2010 FY 2011 FY 2012 FY 2013 Forecast Capital Expenditures from Continuing Operations Exploration & Production Capital Expenditures 188,290 $ 398,174 $ 648,815 $ 693,810 $ 533,129 $ $550,000-625,000 Pipeline & Storage Capital Expenditures 52,504 37,894 129,206 144,167 56,144 $ $115,000-135,000 Gathering Segment Capital Expenditures 9,433 6,538 17,021 80,012 54,792 $ $100,000-145,000 Utility Capital Expenditures 56,178 57,973 58,398 58,284 71,970 $ $85,000-95,000 Energy Marketing, Corporate & All Other Capital Expenditures 396 773 746 1,121 1,062 $ - Total Capital Expenditures from Continuing Operations 306,801 $ 501,352 $ 854,186 $ 977,394 $ 717,097 $ $850,000-1,000,000 Capital Expenditures from Discountinued Operations All Other Capital Expenditures 216 150 $ - $ - $ - $ - $ Plus (Minus) Accrued Capital Expenditures Exploration & Production FY 2013 Accrued Capital Expenditures - $ - $ - $ - $ (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 2013 Accrued Capital Expenditures - - - - (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 2013 Accrued Capital Expenditures - - - - (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 2013 Accrued Capital Expenditures - - - - (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) $ - $ Eliminations (344) $ - $ - $ - $ - $ - $ Total Capital Expenditures per Statement of Cash Flows 313,633 $ 443,101 $ 814,278 $ 1,035,007 $ 703,461 $ $850,000-1,000,000 |