Investor Presentation Q1 Fiscal 2019 Update January 31, 2019 - - PowerPoint PPT Presentation
Investor Presentation Q1 Fiscal 2019 Update January 31, 2019 National Fuel is committed to the safe and environmentally conscious development, transportation, storage, and distribution of natural gas and oil resources. For additional
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For additional information, please visit our corporate responsibility website at https://responsibility.natfuel.com
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Developing our large, high quality acreage position in Marcellus & Utica shales(1)
Providing safe, reliable and affordable service to customers in WNY and NW Pa.
Upstream
Exploration & Production
Midstream
Gathering Pipeline & Storage
38% of NFG EBITDA(1)
Downstream
Utility Energy Marketing
% of NFG 20EBITDA(1)
Expanding and modernizing pipeline infrastructure to provide outlets for Appalachian natural gas production
Net acres in Appalachia
Net Appalachian natural gas production
Investments since 2010
Daily interstate pipeline capacity under contract
Utility Customers
Investments in safety since 2014
California: oil production
generates significant cash flow
(1) This presentation includes forward-looking statements. Please review the safe harbor for forward looking statements on slide 55 of this presentation. (2) Twelve months ending December 31, 2018. 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..
42% of NFG EBITDA(2) 36% of NFG EBITDA(2) 22% of NFG EBITDA(2)
:
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Co-Development of Marcellus and Utica Installation of just-in-time gathering facilities Expansion of pipeline transmission infrastructure to reach demand markets
Rate-regulated entities reduce operating expenses by sharing common resources Utility and Energy Marketing segments are significant Pipeline & Storage customers
Investment grade credit rating Shared borrowing capacity Consolidated income tax return
Utility Energy Marketing
Gathering Pipeline & Storage
Exploration & Production
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Dividend payments since 1970
per share
Consecutive Dividend Increases
per share
Consecutive Payments
yield(1)
(1) As of January 29, 2019.
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(1) Production trend line represents 17.5% net growth, on average, from fiscal 2018 through fiscal 2022
235.5 270.9 311.5 178.1 210- 230 50 100 150 200 250 300 350 400 2018 2019E 2020 2021 2022 Seneca Net Production (Bcfe) 15% Annual Growth 20% Annual Growth $107.9 $130- $140 $0 $50 $100 $150 $200 $250 2018 2019E 2020 2021 2022 Gathering Revenues ($MM) 15% Annual Growth 20% Annual Growth
E&P
(2) Revenue trend line represents 17.5% growth, on average, from fiscal 2018 through fiscal 2022
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(1) Approximate WDA Marcellus gathering facility costs for 192 wells drilled and completed as of September 30, 2018. (2) Estimated WDA Utica gathering facility costs for the assumed 120 well locations in Clermont Rich Valley area of redevelopment. (3) Internal Rate of Return for Seneca WDA includes estimated well costs under current cost structure, and anticipated LOE and Gathering costs. Internal Rate of Return for Seneca WDA and Gathering includes expected gathering capital expenditures through FY 2022, well costs under current cost structure, and non-gathering LOE.
Gathering CapEx/Well ($ thousands) Marcellus (pre-2019) $1,489(1) Utica (2019-2022) $392(2)
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Line N to Monaca Northern Access FM100 Empire North
(1) Parentheticals represent target in-service dates for the respective expansion projects.
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673 572 36.1 45.8 Net Oil and Gas Production
Exploration & Production $0.34 Exploration & Production $0.37 Gathering $0.13 Gathering $0.16 Pipeline & Storage $0.29 Pipeline & Storage $0.29 Utility $0.25 Utility $0.30 $1.02 $1.12
Energy Marketing: $0.01 Energy Marketing: ($0.01) Corporate/All Other: $0.01
Q1 FY18 Q1 FY19
Adjusted Operating Results ($/share)(1)
(1) Adjusted Operating results of $1.02 for Q1 Fiscal 2018 and $1.12 for Q1 Fiscal 2019 include operating results of Energy Marketing and Corporate & All Other segments. See slide 61 for a Reconciliation of Adjusted Operating Results to Earnings Per Share. (2) Realized price after hedging.
$59.79 $61.70 $2.72 $2.61 Q1 FY 2018 Q1 FY 2019 Oil and Gas Pricing(2) Natural Gas ($/Mcfe) Crude Oil ($/Bbl)
Oil Prices Natural Gas Prices
$23.8 $29.7 Gathering Revenue ($MM)
Increased Seneca Natural Gas Production
Drivers
Natural Gas Production Oil Production (sale of Sespe field)
Crude Oil (Mbbl) Natural Gas (Bcf)
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FY2018 Adjusted Operating Results
Non-regulated Businesses Exploration & Production Gathering
FY2019 Earnings Guidance
210 to 230 Bcfe
$130-140 million
~$59/Bbl(3) (vs. $58.66/Bbl in FY 2018) Key Guidance Drivers
(1) Excludes the $103.5 million, or $1.20 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 61 of this presentation. (2) Assumes NYMEX natural gas pricing of $3.25/MMBtu (winter) and $2.75/MMBtu (summer) and basin spot pricing of $2.75/MMBtu (winter) and $2.25/MMBtu (summer) for FY19, and reflects the impact of existing financial hedges, firm sales and firm transportation contracts. (3) Assumes NYMEX (WTI) oil pricing of $55.00/Bbl and California-MWSS pricing differentials of 102% to WTI for FY19, and reflects impact of existing financial hedge contracts.
Production & Gathering Throughput Realized natural gas prices (after-hedge) Utility Operating Income Regulated Businesses Pipeline & Storage Utility
gross margin expected to be offset by cost inflation
due to expiration of contract on Empire system) Pipeline & Storage Revenues Tax Reform Realized oil prices (after-hedge) Lower effective tax rate
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38.5 33.7 29.0 30.2 27.7 1,683 2,142 1,675 1,973 2,357
1,914 2,344 1,849 2,154 2,523
500 1,000 1,500 2,000 2,500 3,000 2014 2015 2016 2017 2018
At September 30 Natural Gas (Bcf) Crude Oil (MMbbl)
(1) Seneca “Drill-bit” finding and development (“F&D”) costs exclude the impact of reserve revisions.
$1.38 $1.12 $1.32 $0.98 $0.74 $0.50 $1.00 $1.50 2014 2015 2016 2017 2018
70% 30%
PDPs PUDs
E&P and Gathering
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20.5 19.4 17.6 ~16 140.6 154.1 160.5 194-214 161.1 173.5 178.1 210-230 50 100 150 200 250 2016 2017 2018 2019E
$38 $38 $26 ~$25
$61 $208 $330 $435-$470 $99 $246 $356 $460-$495 $0 $200 $400 $600 2016 2017 2018 2019E
Appalachia West Coast (California)
E&P and Gathering
(1) 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.
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significant near-term lease expirations
locations economic at ~$1.84/Mcf
Geneseo (Lycoming Co.) potential
Eastern Development Area (EDA) Western Development Area (WDA)
locations economic at ~$2.00/Mcf
enhances well economics
E&P and Gathering
(1) Average EDA and WDA gross production, as well as WDA-CRV Utica production (see slide 19) and Covington/Tract 595 Production (see slide 23), is for the quarter ended December 31, 2018.
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(1) The Utica Shale lies approximately 5,000 feet beneath Seneca’s WDA Marcellus acreage. (2) Appraisal program currently in progress. Additional tests are planned. Prior Marcellus delineation tests helped define the prospective limits of the Marcellus core acreage; planned testing in the Utica expected to do the same.
Area of Re-Development
~120 Utica locations on existing Marcellus pads
Key Utica tests Past Marcellus delineation tests Utica Trend (currently evaluating) Marcellus Core Acreage
Large well inventory economic at ~$2.00 /Mcf
acres
evaluating extent of prospective acreage(2) Fee acreage (no royalty) enhances economics and provides development flexibility Addition of 2nd WDA drilling rig in Q3 FY18 focused on redevelopment of Clermont-Rich Valley acreage for Utica Use of existing gathering, pad, and water infrastructure for Utica drives increased Appalachian program returns Highly contiguous position drives best in class well costs
Utica test results on trend with other Utica wells in NE Pa.
Long-term firm contracts support growth
Boone Mountain Utica Test Well 2.3 Bcf /1,000ft Rich Valley Utica Test Well 2.3 Bcf /1,000ft
E&P and Gathering
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Tested / producing from 17 Utica wells in WDA-CRV Higher pressure significantly enhances well productivity (Utica ~5,000’ deeper than Marcellus) Drawdown management is critical: restricted drawdown appears to improve well EURs Early production declines much shallower vs. Marcellus
(1) Internal Rate of Return (IRR) is pre-tax and includes estimated well costs under current cost structure, LOE, and anticipated gathering tariffs. (2) Initial WDA-CRV Utica type curve based on production results and reservoir expectations from the first 5 appraisal wells in the WDA-CRV area. (3) WDA-CRV Utica Average includes all 17 producing wells, including 2 wells (pad E09-S) for which drawdown management was not used.
E&P and Gathering
EUR Bcf/1000’ Well Cost $M/1000’ IRR % $2.25 Break-even 15% IRR(1) Utica - CRV 1.7 $887 23% $1.97 Marcellus 1.0 – 1.1 $643 19% $2.06
(2)
1 2 3 4 5 6 7 8 9 12 24 36 48 60 72 84 96 108 120 Cumulative Production, BCF Months On
Utica Type Curve CRV Utica Average WDA Marcellus Type Curve Boone Mountain Appraisal Well WDA-CRV Utica Type Curve(2) WDA-CRV Utica Average(3)
0.0 0.5 1.0 1.5 2.0 2.5 3.0 3.5 2 4 6 8 10 12
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WDA-CRV Marcellus
(Depth ~7,000 feet)
WDA-CRV Utica
(Depth ~12,000 feet)
120+ locations on existing Marcellus pads
CRV Utica Transition Plan
1)Finish Marcellus Pads in Development
2)Continue Optimizing Utica D&C design
3)Continue transition to Utica development
determine development well design
pad, water and gathering infrastructure
E&P and Gathering
Rich Valley Utica Test
Existing Line Leased Seneca Fee Producing FY19 Producer Development
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(1) WDA Marcellus well costs reflect drilling, completion & gathering costs for 192 drilled and completed wells as of 9/30/18. WDA Utica well costs reflect expected drilling, completion & gathering costs for the ~120 well locations in area of redevelopment. (2) Internal Rate of Return for Seneca WDA includes estimated well costs under current cost structure, and anticipated LOE and Gathering costs. Internal Rate of Return for Seneca WDA and Gathering includes expected gathering capital expenditures through FY 2022, well costs under current cost structure, and non-gathering LOE.
$685 $887 $210
$0 $200 $400 $600 $800 $1,000
Marcellus (Historic) Utica - CRV (Current)
$/ lateral foot
Drilling & Completion Gathering
$931 $895 1.0 - 1.1 1.7
0.0 0.3 0.6 0.9 1.2 1.5 1.8
Marcellus (Historic) Utica - CRV (Current)
EUR/ 1,000 feet (Bcf)
60-70% EUR increase expected per well Total cost per well expected to marginally increase
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Current System In-Service
Future Build-Out
investment required to support Seneca’s transition to Utica development
compressor stations (+60,000 HP installed) as Seneca’s drilling activity continues
Clermont Gathering System Map
E&P and Gathering
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Seneca gross production trend
E&P and Gathering
100 200 300 400 500 600 700
Niagara Expansion Project (TGP and NFG) FT Capacity: 158,000 Dth/d @ $0.67/Dth Firm Sales: NYMEX & DAWN WDA - TGP 300 Firm Sales Leidy South Transco Zone 6 Markets 330,000 Dth/d(1)
Will layer-in firm sales to minimize spot exposure
(1) Portion of Transco Project capacity will likely be utilized by EDA Lycoming County production.
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1
E&P and Gathering
2 1 3
2 Covington & DCNR Tract 595 (Tioga Co., Pa.)
3 DCNR Tract 100 & Gamble (Lycoming Co., Pa.)
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(1) Includes physical fixed price and NYMEX-based firm sales contracts that do not carry any additional transportation costs.
E&P and Gathering
Existing Line Leased Seneca Fee Producing FY19 Producer Development
50 100 150 200 250 Gross Firm Volumes (MDth/d)
EDA – Transco Firm Contracts
Atlantic Sunrise (Transco) FT Capacity: 189,405 Dth/d Cost: $0.73/Dth Firm Sales: NYMEX+
Transco Firm Sales(1)
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In-Service November 2016 Lateral Length 4,640 ft 30 Day IP /1,000 ft 3.4 MMcf/d
2.4 Bcf Inventory: ~43 locations economic at ~$1.84 /Mcf
Expected Development Costs: $1,045 per lateral ft. Gathering Infrastructure: NFG Midstream Wellsboro
Sales/Takeaway Strategy: Layer-in firm sales with shippers holding capacity on TGP 300
(1) 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
E&P and Gathering
100,000 200,000 300,000 400,000 500,000 600,000 700,000 800,000 100 200 300 Normalized Cumulative (Mcf/1,000’) Days On Production Industry Potter/Tioga Wells Seneca DCNR 007 73H
25 50 75 100 125 150
Gross Firm Volumes (MDth/d)
EDA – TGP 300 Firm Contracts
Northeast Supply Diversification Project FT Capacity: 50,000 Dth/d @ $0.50/Dth Firm Sales: NYMEX and DAWN EDA - TGP 300 Firm Sales(1)
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E&P and Gathering
2 1 3
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(1) 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.
E&P and Gathering
200 300 400 500 600 700 800 900 1,000 1,100 1,200
FY 2019 FY 2020 FY 2021 FY 2022
Northeast Supply Diversification 50,000 Dth/d Niagara Expansion (TGP & NFG) Delivery Markets: Canada-Dawn & TETCO 158,000 Dth/d Atlantic Sunrise (Transco) Delivery Markets: Mid-Atlantic & Southeast U.S. 189,405 Dth/d In-Basin Firm Sales Contracts(1) Leidy South (Transco & NFG) Transco Zone 6 Markets 330,000 Dth/d
Seneca Appalachia Natural Gas Marketing Gross Firm Contract Volumes (Mdth/day)
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297,000 ($0.61) 305,200 ($0.61) 305,600 ($0.63) 337,000 ($0.57) 370,800 ($0.24) 369,600 ($0.60) 367,900 ($0.67)
33,400 ($0.70) 74,500 ($0.77) 74,900 ($0.77) 81,100 ($0.78)
85,900 ($0.78) 92,000 ($0.73) 91,300 ($0.73) 178,800 $2.55 196,000 $2.34 195,500 $2.34 149,900 $2.32 129,500 $2.30 105,400 $2.22 104,500 $2.22
~517,800 509,200 575,700 576,000 568,000 586,200 567,000 563,700 Q1 FY19 Q2 FY19 Q3 FY19 Q4 FY19 Q1 FY20 Q2 FY20 Q3 FY20 Q4 FY20 Fixed Price Dawn NYMEX
Net Contracted Firm Sales Volumes (Dth per day) Contracted Index Price Differentials ($ per Dth)(1)
(1) Values shown represent the weighted average fixed price or contracted fixed differential relative to NYMEX (netback price) less any associated transportation costs.
Actual Daily Net Production
641,200 716,500 708,700 693,500 708,400 674,400 667,000
Gross Firm Sales Volumes (Dth/d)
E&P and Gathering
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1 2 3 4 5
Location Formation Production Method FY18 Daily Production (net Boe/d) 1 East Coalinga/ Other Temblor Primary 512 2 North Lost Hills Tulare & Etchegoin Primary/ Steam flood 892 3 South Lost Hills Monterey Shale Primary 1,359 4 North Midway Sunset Tulare & Potter Steam flood 2,786 5 South Midway Sunset Antelope Steam flood 2,048 TOTAL WEST DIVISION NET PRODUCTION(1) 7,597 Boe/d
E&P and Gathering
(1) West division net production for FY 2018 excludes production from Sespe field, which was divested on May 1, 2018.
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9,341
8,863 8,033
~7,300 2016 2017 2018 2019 Fiscal Year West Division Average Net Daily Production (Boe) West Division Annual Capital Expenditures ($ MM)(1) $38 $38 $26 ~$25 2016 2017 2018 2019 Fiscal Year Guidance Guidance
(1) Seneca West Division capital expenditures includes Seneca corporate and eliminations.
E&P and Gathering
Sepse Sale Closed on 5/1/18 (reduced production by ~900 boe/d)
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Pioneer South MWSS Acreage North MWSS Acreage
41% 49% 51%
NMWSS & 17N SMWSS & Pioneer East Coalinga
Modest near-term capital program focused on locations that earn attractive returns in current oil price environment A&D will focus on low cost, bolt-on opportunities Sec. 17, Pioneer, and East Coalinga development to provide future growth
North
Project IRRs at $55/Bbl(1)
(1) Reflects pre-tax IRRs at a $55/Bbl WTI.
E&P and Gathering
Seneca West Economics
South East Coalinga
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~49 Bcfe 210 – 230 Bcfe ~114 Bcf ~29 Bcf (2)
16+/- Bcf ~12 Bcfe 40 80 120 160 200 240 YTD FY19 Actuals Fixed Price + Firm Sales w/ Hedge Firm Sales (Unhedged) Spot Sales California Total Seneca
(1) Average realized price reflects uplift from financial hedges less fixed differentials under firm sales contracts and any firm transportation costs. (2) Indicates firm sales contracts with fixed index differentials but not backed by a matching financial hedge.
Spot production assumed to be sold at ~$2.75/Mmbtu (winter) and ~$2.25 (summer)
79% of oil production hedged at $57.57 /Bbl
E&P and Gathering
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Natural Gas Swap & Fixed Physical Sales Contracts (Millions MMBtu)
(1) Fixed price physical sales exclude joint development partner’s share of fixed price contract WDA volumes as specified under the joint development agreement. (2) Reflects percentage of projected production for FY19 hedged at the midpoint of the production guidance range. (3) Seneca’s remainder FY19 Production reflects the total FY19 production guidance of 210-230 Bcfe, or 220 Bcfe at the midpoint, less Q1 actual production.
Crude Oil Swap Contracts (Thousands Bbls) 1,359 1,188 732 456
500 1,000 1,500 2,000 2,500 FY 2019 FY 2020 FY 2021 FY 2022 NYMEX (WTI) Brent
FY 19 Crude Oil 79% Hedged (2)
FY 2019 Remaining Production (3)
E&P and Gathering
117.4 70.9 46.9 40.6
50 100 150 200 250 FY 2019 FY 2020 FY 2021 FY 2022 NYMEX Swaps Dawn Swaps Fixed Price Physical Sales
(1)
FY 2019 Remaining Production (3)
FY 19 Nat Gas 71% Hedged (2)
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$0.65 $0.70 $0.70 - $0.75 FY 2017 FY 2018 FY 2019E
$0.60 $0.60 $0.60
$0.11 $0.09 $0.07
$0.71 $0.69 ~$0.67 FY 2017 FY 2018 FY 2019E
Gathering & Transport LOE (non-Gathering) G&A Taxes & Other
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
$0.54 $0.54 $0.56 $0.42 $0.38 $0.31 $0.34 $0.34 $0.30 $0.17 $0.14 $0.15
$1.47 $1.40 ~$1.32 FY 2017 FY 2018 FY 2019E
(1)
$17.91 $17.46 ~$20.50 FY 2017 FY 2018 FY 2019E
Appalachia LOE & Gathering
$/Mcfe
California LOE
$/Boe
Total Seneca Cash OpEx
$/Mcfe
(1) (2) (2)
(1) G&A estimate represents the midpoint of the G&A guidance range of $0.25 to $0.35 for fiscal 2019. (2) The total of the two LOE components represents the midpoint of the LOE guidance range of $0.85 to $0.90 for fiscal 2019.
E&P and Gathering
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Recycled Water
Fiscal 2018
E&P and Gathering
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(1) As of September 30, 2018 as disclosed in the Company’s fiscal 2018 form 10-K. (2) As of December 31, 2017 calculated from National Fuel Gas Supply Corporation’s and Empire Pipeline, Inc.’s 2017 FERC Form-2 reports, respectively.
Empire Pipeline, Inc. National Fuel Gas Supply Corporation Empire Pipeline Supply Corp.
Contracted Capacity(1):
Rate Base(2): ~$820 million FERC Rate Proceeding Status:
Contracted Capacity(1):
Rate Base(2): ~$249 million FERC Rate Proceeding Status:
12/21/18; FERC approval pending
Pipeline & Storage
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All Seneca volumes will flow through wholly-owned NFG gathering facilities
330,000 Dth/d of new transportation capacity from WDA and EDA acreage positions to premium markets
New Transco capacity (Leidy South): 330,000 Dth/day Rate(1) : competitive with other expansion project rates in Seneca’s current transportation portfolio Delivery Point(s): Transco Zone 6 interconnections
Seneca
Lease to Transco of new capacity: 330,000 Dth/day Estimated annual lease revenues: ~$35 million Target In-Service: late calendar year 2021
Supply Corp. Project expected to provide long-term earnings uplift to Seneca, Supply Corp. and Gathering
Pipeline & Storage
Gathering
(1) Includes lease of new capacity from Supply Corp. to Transco.
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Pipeline & Storage
approximately 37,000 HP)
existing pipeline and compressor station
2017 for original modernization project
(1) Includes expansion and modernization portions of the project.
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Pipeline & Storage
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Pipeline & Storage To Dawn
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Line N Expansion Opportunities Line N to Monaca Project
cracker facility being built by Shell Chemical Appalachia, LLC
Additional Line N Expansion Opportunity (Supply OS #221)
demand
foundation shipper. Precedent agreement in negotiations.
Pipeline & Storage
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Producer 33% LDC 42% Marketer 10%
Outside Pipeline 9% End User 6%
4.2 MMDth/d
(1) Contracted as of 10/31/2018.
66% 5% 21% 41% 34% 95% 79% 59% LDCs Producers Marketers Firm Storage Affiliated Non-Affiliated Firm Transport
Pipeline & Storage
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New York
Total Customers(1): 535,800 ROE: 8.7% (NY PSC Rate Case Order, April 2017) Rate Mechanisms:
Pennsylvania
Total Customers(1): 214,400 ROE: Black Box Settlement (2007) Rate Mechanisms:
(1) As of September 30, 2018.
Utility
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Rate Order Summary:
$5.9 million
$704 million
8.7%
42.9% equity
merchant function charge, 90/10 large customer sharing)
Utility
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$54.4 $61.8 $63.6 $69.9 $94.4 $98.0 $80.9 $85.6 $90-100 $0.0 $25.0 $50.0 $75.0 $100.0 $125.0 2015 2016 2017 2018 2019E Capital Expenditures ($ millions)
Fiscal Year Capital Expenditures for Safety Total Capital Expenditures
Modernization Spending in NY Expected to Grow Gross Margin By $2 MM - $5 MM in FY 2019
(1) (1) A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation.
Utility
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Wrought Iron Plastic Coated Bare
2014 2015 2016 2017 2018
Calendar Year
* No Cast Iron Mains in Pa.*
Wrought Iron Cast Iron Plastic Coated Bare
Utility
(1) All values are reported on a calendar year basis as of December 31, 2018.
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$200 $189 $195 $166 $166 $31 $31 $197 $197 $0 $50 $100 $150 $200 $250 2015 2016 2017 2018 TTM 12/31/18
O&M Expense Non-Service Pension Costs
Utility (1)
(1) For purposes of comparability to FY 2015, 2016 and 2017, Utility Operation and Maintenance Expense for FY 2018 and the twelve months ended December 31, 2018 was adjusted by approximately $31.4 million and $31.2 million, respectively, to include non-service pension costs, which were re-classified as Other Income (Deductions) as of October 1, 2018 on the Company’s Income Statement. See Slide 64 for non-GAAP reconciliation of Adjusted Operation and Maintenance Expense to Operation and Maintenance Expense, by segment.
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(1) A reconciliation of Adjusted Operating Results to Earnings per Share, by segment, as presented on the Consolidated Statement of Income and Earnings Reinvested in the Business is included at the end of this presentation (2) Consolidated Adjusted EBITDA includes Energy Marketing, and Corporate & All Other Segments. A reconciliation of Adjusted EBITDA to Net Income, by segment, as presented on the Consolidated Statement of Income and Earnings Reinvested in the Business is included at the end of this presentation
$176 $179 $184 $181 $92 $97 $318 $327
$761 $775
$- $200 $400 $600 $800 FY 2018 TTM 12/31/18
$0.59 Utility $0.97 Pipeline & Storage $0.57 Gathering $1.25 Exploration & Production
$3.34 $3.45 to $3.65
$- $1.00 $2.00 $3.00 $4.00 FY 2018 FY 2019 Guidance
Rate Regulated 40-45%
$728
Rate Regulated ~46%
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$89 $94 $98 $81 $86 $90-$100 $140 $230 $114 $95 $93 $120-$150 $138
$118
$54 $33 $48 $55-$65 $603 $557 $99 $246 $356 $460-$495
$970 $1,001 $366 $455 $583 $725-$810 $0 $250 $500 $750 $1,000 $1,250 2014 2015 2016 2017 2018 2019 Guidance
Fiscal Year
Exploration & Production Gathering Pipeline & Storage Utility
(2) (1) Total Capital Expenditures include Energy Marketing, Corporate and All Other. A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation. (2) FY16, FY17, and FY18 reflects the netting of $157 million, $7 million, and $17 million, respectively, of up-front proceeds received from joint development partner for working interest in joint development wells, and $21M in intercompany asset transfers in FY18.
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Total Equity 49% Total Debt 51%
$4.2 Billion Total Capitalization as of December 31, 2018
2.18 x 2.51 x 2.45 x 2.47 x 2.56 x 2015 2016 2017 2018 TTM 12/31/18 Fiscal Year End
Net Debt / Adjusted EBITDA(1) Capitalization Debt Maturity Profile ($MM) Liquidity
Committed Credit Facilities Short-term Debt Outstanding Available Short-term Credit Facilities Cash Balance at 12/31/18 Total Liquidity at 12/31/18 $ 750 MM 0 MM 750 MM 110 MM $ 860 MM
$500 $549 $500 $300 $300 $0 $200 $400 $600
(1) 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.
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This presentation may contain “forward-looking statements” as defined by the Private Securities Litigation Reform Act of 1995, including statements regarding future prospects, plans, objectives, goals, projections, estimates of oil and gas quantities, strategies, future events or performance and underlying assumptions, capital structure, anticipated capital expenditures, completion of construction projects, projections for pension and other post-retirement benefit obligations, impacts of the adoption of new accounting rules, and possible outcomes of litigation or regulatory proceedings, as well as statements that are identified by the use of the words “anticipates,” “estimates,” “expects,” “forecasts,” “intends,” “plans,” “predicts,” “projects,” “believes,” “seeks,” “will,” “may,” and similar expressions. Forward-looking statements involve risks and uncertainties which could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. The Company’s expectations, beliefs and projections are expressed in good faith and are believed by the Company to have a reasonable basis, but there can be no assurance that management’s expectations, beliefs or projections will result or be achieved or accomplished. In addition to other factors, the following are important factors that could cause actual results to differ materially from those discussed in the forward-looking statements: delays
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; financial and economic conditions, including the availability of credit, and occurrences affecting the Company’s ability to obtain financing on acceptable terms for working capital, capital expenditures and other investments, including any downgrades in the Company’s credit ratings and changes in interest rates and other capital market conditions; changes in the price of natural gas or oil; impairments under the SEC’s full cost ceiling test for natural gas and oil reserves; factors affecting the Company’s ability to successfully identify, drill for and produce economically viable natural gas and oil reserves, including among others geology, lease availability, title disputes, weather conditions, shortages, delays or unavailability of equipment and services required in drilling operations, insufficient gathering, processing and transportation capacity, the need to obtain governmental approvals and permits, and compliance with environmental laws and regulations; increasing health care costs and the resulting effect on health insurance premiums and on the
effect of such changes on commodity production, revenues and demand for pipeline transportation capacity to or from such locations; other changes in price differentials between similar quantities of natural gas or oil having different quality, heating value, hydrocarbon mix or delivery date; the cost and effects of legal and administrative claims against the Company or activist shareholder campaigns to effect changes at the Company; uncertainty of oil and gas reserve estimates; significant differences between the Company’s projected and actual production levels for natural gas or oil; changes in demographic patterns and weather conditions; changes in the availability, price or accounting treatment of derivative financial instruments; changes in laws, actuarial assumptions, the interest rate environment and the return on plan/trust assets related to the Company’s pension and other post-retirement benefits, which can affect future funding obligations and costs and plan liabilities; changes in economic conditions, including global, national or regional recessions, and their effect on the demand for, and customers’ ability to pay for, the Company’s products and services; the creditworthiness or performance of the Company’s key suppliers, customers and counterparties; the impact of potential information technology, cybersecurity or data security breaches; economic disruptions or uninsured losses resulting from major accidents, fires, severe weather, natural disasters, terrorist activities or acts of war; significant differences between the Company’s projected and actual capital expenditures and operating expenses; or increasing costs of insurance, changes in coverage and the ability to obtain insurance. Forward-looking statements include estimates of oil and gas quantities. Proved oil and gas reserves are those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible under existing economic conditions, operating methods and government
than estimates of proved reserves. Accordingly, estimates other than proved reserves are subject to substantially greater risk of being actually realized. Investors are urged to consider closely the disclosure in our Form 10-K available at www.nationalfuelgas.com. You can also obtain this form on the SEC’s website at www.sec.gov. For a discussion of the risks set forth above and other factors that could cause actual results to differ materially from results referred to in the forward-looking statements, see “Risk Factors” in the Company’s Form 10-K for the fiscal year ended September 30, 2018 and the Forms 10-Q for the quarter ended March 31, 2018, June 30, 2018, and December 31, 2018. The Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date thereof or to reflect the occurrence of unanticipated events. Appendix
56
Natural Gas Volumes in thousand MMBtu; Prices in $/MMBtu Volume Avg. Price Volume Avg. Price Volume Avg. Price Volume Avg. Price NYMEX Swaps 60,120 $2.93 18,640 $3.04 4,840 $3.01
5,400 $3.00 7,200 $3.00 600 $3.00
51,915 $2.68 45,046 $2.34 41,488 $2.22 40,580 $2.23 Total 117,435 $2.82 70,886 $2.59 46,928 $2.31 40,580 $2.23 Crude Oil Volumes & Prices in Bbl Avg. Avg. Avg. Avg. Price Price Price Price Brent Swaps 558,000 $63.52 864,000 $63.51 576,000 $64.68 300,000 $60.07 NYMEX Swaps 801,000 $53.42 324,000 $50.52 156,000 $51.00 156,000 $51.00 Total 1,359,000 $57.57 1,188,000 $59.96 732,000 $61.61 456,000 $56.97 Fiscal 2022 Volume Fiscal 2020 Fiscal 2021 Fiscal 2019 Fiscal 2019 Fiscal 2020 Volume Fiscal 2021 Volume Fiscal 2022 Volume
(1) Fixed price physical sales exclude joint development partner’s share of fixed price contract WDA volumes as specified under the joint development agreement.
(1)
Appendix
57
(1) Net realized price reflects either (a) price received at the gathering system interconnect or (b) price received at delivery market net of firm transportation charges. (2) 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.
$2.50 Realized $2.25 Realized $2.00 Realized
Tract 100 & Gamble
Lycoming Co.
Marcellus 45 4,900 2.5 $1,057 76% 58% 44% $1.53 Transco Leidy & Atlantic Sunrise Southeast US (NYMEX+) DCNR 007
Tioga Co.
Utica 43 8,300 2.0 $1,045 49% 36% 22% $1.84 TGP 300 Clermont Rich Valley Utica 120+ 9,000 1.7 $887 30% 23% 16% $1.97 Core Areas Marcellus 600+ 8,500 1.0 to 1.1 $643 26% 19% 14% $2.06
TGP 300, Niagara Expansion Canada (Dawn), & FM100/Leidy South (Transco Zone 6)
Realized Price(1) Required for 15% IRR Anticipated Delivery Markets
Prospect Reservoir Locations Remaining to Be Drilled Completed Lateral Length (ft) EUR / 1000' (Bcf) Internal Rate of Return % (2) Well Cost $M/1,000 ft
Appendix
58
This presentation contains certain non-GAAP financial measures. For pages that contain non-GAAP financial measures, pages containing the most directly comparable GAAP financial measures and reconciliations are provided in the slides that follow. The Company believes that its non-GAAP financial measures are useful to investors because they provide an alternative method for assessing the Company’s ongoing operating results and for comparing the Company’s financial performance to other companies. The Company’s management uses these non-GAAP financial measures for the same purpose, and for planning and forecasting purposes. The presentation of non-GAAP financial measures is not meant to be a substitute for financial measures prepared in accordance with GAAP. Management defines Adjusted Operating Results as reported GAAP earnings before items impacting comparability. The Company’s earnings guidance range does not include the impact of certain items that impacted the comparability of earnings during the first quarter, including: (1) the remeasurement of deferred income taxes resulting from the 2017 Tax Reform Act, which reduced the Company’s income tax expense and benefited consolidated earnings in the first quarter by $0.06 per share; (2) the full year impact of the Exploration and Production segment’s unrealized gain on hedging ineffectiveness, which increased earnings by $0.06 per share in the first quarter ($3.2 million, or $0.03 per share, of the unrealized gain relates to hedge contracts that will settle during the remaining nine months ending September 30, 2019); and (3) the unrealized loss on other investments due to the change in an accounting rule, which lowered earnings by $0.06 per share. While the Company expects to record additional adjustments to one or more of these items during the remaining nine months ending September 30, 2019, the amounts of these and other potential adjustments are not reasonably determinable at this time. As such, the Company is unable to provide earnings guidance other than on a non-GAAP basis. Management defines Adjusted EBITDA as reported GAAP earnings before the following items: interest expense, income taxes, depreciation, depletion and amortization, interest and other income, impairments, and other items reflected in operating income that impact comparability.
Appendix
59
Appendix
(1) Total Adjusted EBITDA for FY 2018 and the twelve months ended December 31, 2018 include the reclassification of non-service pension costs from Operating and Maintenance Expense to Other Income (Deductions) as of October 1, 2018 on the Company’s Income Statement, which on a consolidated basis were approximately $32.64 million in FY 2018 and approximately $32.57 million for the twelve months ended December 31, 2018.. This reclassification is not reflected in Total Adjusted EBITDA for FY 2015, FY 2016 or FY 2017. Reconciliation of Adjusted EBITDA to Consolidated Net Income ($ Thousands) Total Adjusted EBITDA Exploration & Production Adjusted EBITDA 418,726 $ 363,438 $ 361,079 $ 317,706 $ 327,381 $ Pipeline & Storage Adjusted EBITDA 188,042 199,446 180,328 183,973 181,380 Gathering Adjusted EBITDA 68,881 78,685 94,380 91,937 97,072 Utility Adjusted EBITDA 164,037 148,683 151,078 175,555 178,974 Energy Marketing Adjusted EBITDA 12,237 6,655 2,080 1,033 (1,492) Corporate & All Other Adjusted EBITDA (11,900) (8,238) (11,805) (8,735) (8,145) Total Adjusted EBITDA 840,023 $ 788,669 $ 777,140 $ 761,469 $ 775,170 $ Total Adjusted EBITDA 840,023 $ 788,669 $ 777,140 $ 761,469 $ 775,170 $ Minus: Interest Expense (99,471) (121,044) (119,837) (114,522) (112,445) Plus: Other Income (Deductions) 11,961 14,055 11,156 (21,177) (27,276) Minus: Income Tax Expense 319,136 232,549 (160,682) 7,494 (96,692) Minus: Depreciation, Depletion & Amortization (336,158) (249,417) (224,195) (240,961) (249,386) Minus: Impairment of Oil and Gas Properties (E&P) (1,126,257) (948,307)
7,776
3,563 392 (100) (782) 6,156 Minus: Joint Development Agreement Professional Fees (E&P)
(379,427) $ (290,958) $ 283,482 $ 391,521 $ 295,527 $ Consolidated Debt to Total Adjusted EBITDA Long-Term Debt, Net of Current Portion (End of Period) 2,099,000 $ 2,099,000 $ 2,099,000 $ 2,149,000 $ 2,149,000 $ Current Portion of Long-Term Debt (End of Period)
(113,596) (129,972) (555,530) (229,606) (109,754) Total Net Debt (End of Period) 1,985,404 $ 1,969,028 $ 1,843,470 $ 1,919,394 $ 2,039,246 $ Long-Term Debt, Net of Current Portion (Start of Period) 1,649,000 2,099,000 2,099,000 2,099,000 2,099,000 Current Portion of Long-Term Debt (Start of Period)
85,600
(36,886) (113,596) (129,972) (555,530) (166,289) Total Net Debt (Start of Period) 1,697,714 $ 1,985,404 $ 1,969,028 $ 1,843,470 $ 1,932,711 $ Average Total Net Debt 1,841,559 $ 1,977,216 $ 1,906,249 $ 1,881,432 $ 1,985,979 $ Average Total Net Debt to Total Adjusted EBITDA 2.19 x 2.51 x 2.45 x 2.47 x 2.56 x 12-Months Ended 12/31/18 FY 2015 FY 2016 FY 2017 FY 2018
(1) (1)
60
Appendix
Reconciliation of Adjusted EBITDA to Net Income, by Segment ($ Thousands) Exploration and Production Segment Reported GAAP Earnings $ 180,632 $ 38,214 $ 106,698 $ 112,148 Depreciation, Depletion and Amortization 124,274 34,700 27,425 131,549 Interest and Other Income (308) (278) (3) (584) Interest Expense 54,288 13,163 13,374 54,077 Income Taxes (41,962) 10,602 (67,707) 36,347 Unrealized (Gain) Loss of Hedge Ineffectiveness 782 (6,505) 433 (6,156) Adjusted EBITDA $ 317,706 $ 89,896 $ 80,221 $ 327,382 Pipeline and Storage Segment Reported GAAP Earnings $ 97,246 $ 25,102 $ 38,462 $ 83,886 Depreciation, Depletion and Amortization 43,463 11,114 10,596 43,981 Interest and Other Income (5,925) (1,926) (1,645) (6,206) Interest Expense 31,383 7,286 7,876 30,793 Income Taxes 17,806 6,248 (4,872) 28,926 Adjusted EBITDA $ 183,973 $ 47,824 $ 50,417 $ 181,380 Gathering Segment Reported GAAP Earnings $ 83,519 $ 14,183 $ 45,400 $ 52,302 Depreciation, Depletion and Amortization 17,313 4,679 4,088 17,904 Interest and Other Income (778) (43) (316) (505) Interest Expense 9,560 2,377 2,340 9,597 Income Taxes (17,677) 4,752 (30,699) 17,774 Adjusted EBITDA $ 91,937 $ 25,948 $ 20,813 $ 97,072 FY19 FY18 12-Months FY 2018 FYTD FYTD Ended 12/31/18 ($ Thousands) Utility Segment Reported GAAP Earnings $ 51,217 $ 25,649 $ 20,993 $ 55,873 Depreciation, Depletion and Amortization 53,253 13,290 13,325 53,218 Interest and Other Income 29,074 6,216 6,691 28,599 Interest Expense 26,753 5,893 6,837 25,809 Income Taxes 15,258 6,521 6,304 15,475 Adjusted EBITDA $ 175,555 $ 57,569 $ 54,150 $ 178,974 Energy Marketing Segment Reported GAAP Earnings $ 373 $ (302) $ 1,046 $ (975) Depreciation, Depletion and Amortization 275 70 69 276 Interest and Other Income (269) (45) (13) (301) Interest Expense 22 5 11 16 Income Taxes 632 (449) 691 (508) Adjusted EBITDA $ 1,033 $ (721) $ 1,804 $ (1,492) Corporate and All Other Reported GAAP Earnings $ (21,466) $ (186) $ (13,945) $ (7,707) Depreciation, Depletion and Amortization 2,383 402 327 2,458 Interest and Other Income (616) 5,678 (1,211) 6,273 Interest Expense (7,484) (2,212) (1,849) (7,847) Income Taxes 18,449 (4,765) 15,005 (1,321) Adjusted EBITDA $ (8,735) $ (1,083) $ (1,673) $ (8,145) FY19 FY18 12-Months FY 2018 FYTD FYTD Ended 12/31/18
61
Appendix
(in thousands except per share amounts) 2018 2017 Reported GAAP Earnings 102,660 $ 198,654 $ Items impacting comparability Remeasurement of deferred income taxes under 2017 Tax Reform (5,000) (111,000) Unrealized (gain) loss on hedge ineffectiveness (E&P) (6,505) 433 Tax impact of unrealized (gain) loss on hedge ineffectiveness 1,366 (106) Unrealized loss on other investments (Corporate / All Other) 6,347
(1,333)
97,535 $ 87,981 $ Reported GAAP Earnings per share 1.18 $ 2.30 $ Items impacting comparability Remeasurement of deferred income taxes under 2017 Tax Reform (0.06) (1.29) Unrealized (gain) loss on hedge ineffectiveness (E&P) (0.08) 0.01 Tax impact of unrealized (gain) loss on hedge ineffectiveness 0.02
0.07
(0.02)
0.01
1.12 $ 1.02 $ Three Months Ended December 31,
Fiscal Year Ended September 30, (in thousands except per share amounts) 2018 2017 Reported GAAP Earnings $ 391,521
$
283,482 Items impacting comparability Remeasurement of deferred income taxes under 2017 Tax Reform (103,484 ) — Premium paid on early redemption of debt (E&P) 962 — Tax impact on premium paid on early redemption of debt (235 ) — Adjusted Operating Results $ 288,764
$
283,482 Reported GAAP Earnings per share $ 4.53
$
3.30 Items impacting comparability Remeasurement of deferred income taxes under 2017 Tax Reform (1.20 ) — Premium paid on early redemption of debt, net of tax 0.01 — Adjusted Operating Results per share $ 3.34
$
3.30
62
Appendix
Reconciliation of Segment Capital Expenditures to Consolidated Capital Expenditures ($ Thousands) FY 2019 FY 2014 FY 2015 FY 2016 FY 2017 FY 2018 Forecast Capital Expenditures Exploration & Production Capital Expenditures 602,705 $ 557,313 $ 256,104 $ 253,057 $ 380,677 $ $460,000 - $495,000 Pipeline & Storage Capital Expenditures 139,821 $ 230,192 $ 114,250 $ 95,336 $ 92,832 $ $120,000 - $150,000 Gathering Segment Capital Expenditures 137,799 $ 118,166 $ 54,293 $ 32,645 $ 61,728 $ $55,000 - $65,000 Utility Capital Expenditures 88,810 $ 94,371 $ 98,007 $ 80,867 $ 85,648 $ $90,000 - $100,000 Energy Marketing, Corporate & All Other Capital Expenditures 772 $ 467 $ 397 $ 212 $ 222 $ Eliminations
(20,505) $ Total Capital Expenditures from Continuing Operations 969,907 $ 1,000,509 $ 523,051 $ 462,117 $ 600,602 $ $725,000 - $810,000 Plus (Minus) Accrued Capital Expenditures Exploration & Production FY 2018 Accrued Capital Expenditures (51,343) $ Exploration & Production FY 2017 Accrued Capital Expenditures (36,465) $ 36,465 $ Exploration & Production FY 2016 Accrued Capital Expenditures
25,215 Exploration & Production FY 2015 Accrued Capital Expenditures
46,173
(80,108) 80,108
58,478
(21,861) $ Pipeline & Storage FY 2017 Accrued Capital Expenditures (25,077) 25,077 $ Pipeline & Storage FY 2016 Accrued Capital Expenditures
18,661 Pipeline & Storage FY 2015 Accrued Capital Expenditures
33,925
(28,122) 28,122
5,633
(6,084) $ Gathering FY 2017 Accrued Capital Expenditures (3,925) 3,925 $ Gathering FY 2016 Accrued Capital Expenditures
5,355 Gathering FY 2015 Accrued Capital Expenditures
22,416
(20,084) 20,084
6,700
(9,525) $ Utility FY 2017 Accrued Capital Expenditures (6,748) 6,748 $ Utility FY 2016 Accrued Capital Expenditures
11,203 Utility FY 2015 Accrued Capital Expenditures
16,445
(8,315) 8,315
10,328
(55,490) $ 17,670 $ 58,525 $ (11,782) $ (16,597) $ Total Capital Expenditures per Statement of Cash Flows 914,417 $ 1,018,179 $ 581,576 $ 450,335 $ 584,004 $ $725,000 - $810,000
63
Appendix
Reconciliation of Exploration & Production Segment Operating Expenses by Division ($000s unless noted otherwise) Appalachia West Coast(2) Total E&P Appalachia West Coast(2) Total E&P Appalachia West Coast(2) Total E&P Appalachia West Coast(2) Total E&P $/ Mcfe $ / Boe $ / Mcfe $/ Mcfe $ / Boe $ / Mcfe Operating Expenses: Gathering & Transportation Expense (1) $95,611 $46 $95,657 $0.60 $0.02 $0.54 $92,874 $502 $93,376 $0.60 $0.16 $0.54 Other Lease Operating Expense $14,604 $52,461 $67,065 $0.09 $17.89 $0.38 $16,625 $55,990 $72,615 $0.11 $17.31 $0.42 Lease Operating and Transportation Expense $110,215 $52,507 $162,721 $0.69 $17.91 $0.91 $109,499 $56,492 $165,991 $0.71 $17.46 $0.96 General & Administrative Expense $60,596 $0.34 $58,734 $0.34 All Other Operating and Maintenance Expense $11,077 $0.06 $13,469 $0.08 Property, Franchise and Other Taxes $14,400 $0.08 $15,426 $0.09 Total Taxes & Other $25,477 $0.14 $28,895 $0.17 Depreciation, Depletion & Amortization $124,274 $0.70 $112,565 $0.65 Production: Gas Production (MMcf) 160,499 2,407 162,906 154,093 2,995 157,088 Oil Production (MBbl) 4 2,531 2,535 4 2,736 2,740 Total Production (Mmcfe) 160,523 17,592 178,114 154,117 19,411 173,528 Total Production (Mboe) 26,754 2,932 29,686 25,686 3,235 28,921 (1) Gathering and Transportation expense is net of any payments received from JDA partner for the partner's share of gathering cost (2) Seneca West Coast division includes Seneca corporate and eliminations. Twelve Months Ended September 30, 2018 Twelve Months Ended September 30, 2017
64
Appendix
Reconciliation of Adjusted Operation and Maintenance Expense to Operation and Maintenance Expense, By Segment ($ Thousands) Exploration and Production Segment Operation and Maintenance: General and Administrative Expense $ 59,425 $ 15,198 $ 13,602 $ 61,021 Lease Operating and Transportation Expense 162,721 42,562 39,647 165,636 All Other Operation and Maintenance Expense 11,077 2,353 2,535 10,895 Operation and Maintenance Expense $ 233,223 60,113 55,784 237,552 Plus: Non-Service Pension Costs 1,171 4 293 882 Adjusted Operation and Maintenance Expense $ 234,394 $ 60,117 $ 56,077 $ 238,434 Pipeline and Storage Segment Operation and Maintenance Expense $ 86,876 $ 21,633 $ 17,672 $ 90,837 Plus: Non-Service Pension Costs (1,420) (467) (356) (1,531) Adjusted Operation and Maintenance Expense $ 85,456 $ 21,166 $ 17,316 $ 89,306 Gathering Segment Operation and Maintenance Expense $ 15,862 $ 3,711 $ 2,984 $ 16,589 Plus: Non-Service Pension Cots 328 82 82 328 Adjusted Operation and Maintenance Expense $ 16,190 $ 3,793 $ 3,066 $ 16,917 Utility Segment Operation and Maintenance Expense $ 165,857 $ 43,155 $ 43,317 $ 165,695 Plus: Non-Service Pension Costs 31,400 6,928 7,165 31,163 Adjusted Operation and Maintenance Expense $ 197,257 $ 50,083 $ 50,482 $ 196,858 Energy Marketing Segment Operation and Maintenance Expense $ 6,057 $ 1,617 $ 1,513 $ 6,161 Plus: Non-Service Pension Costs 497 123 124 496 Adjusted Operation and Maintenance Expense $ 6,554 $ 1,740 $ 1,637 $ 6,657 Corporate and All Other Operation and Maintenance Expense $ 17,003 $ 3,058 $ 3,721 $ 16,340 Plus: Non-Service Pension Costs 664 737 167 1,234 Adjusted Operation and Maintenance Expense $ 17,667 $ 3,795 $ 3,888 $ 17,574 Intersegment Eliminations $ (115,112) $ (31,643) $ (25,517) $ (121,238) Consolidated Operation and Maintenance Expense $ 409,766 $ 101,644 $ 99,474 $ 411,936 Plus: Non-Service Pension Costs 32,640 7,407 7,475 32,572 Adjusted Operation and Maintenance Expense $ 442,406 $ 109,051 $ 106,949 $ 444,508 FY19 FY18 12-Months FY 2018 FYTD FYTD Ended 12/31/18