NATIONAL FUEL GAS COMPANY OVERVIEW
Please note that this overview is a high-level summary of items that are discussed in greater detail in subsequent sections of this report.
The Company is a diversified energy company engaged principally in the production, gathering, transportation and distribution of natural gas. The Company operates an integrated business, with assets centered in westernNew York andPennsylvania , being utilized for, and benefiting from, the production and transportation of natural gas from the Appalachian basin. Current development activities are focused primarily in theMarcellus andUtica shales. The common geographic footprint of the Company's subsidiaries enables them to share management, labor, facilities and support services across various businesses and pursue coordinated projects designed to produce and transport natural gas from the Appalachian basin to markets in the easternUnited States andCanada . The Company's efforts in this regard are not limited to affiliated projects. The Company has also been designing and building pipeline projects for the transportation of natural gas for non-affiliated natural gas customers in the Appalachian basin. The Company also develops and produces oil reserves, primarily inCalifornia . The Company reports financial results for four business segments. For a discussion of the Company's earnings, refer to the Results of Operations section below. The Company is closely monitoring and responding to developments related to the novel coronavirus (COVID-19) and is taking steps to limit operational impacts and the potential exposure for our workforce and customers. Refer to Risk Factors in Part I, Item 1A, Risk Factors, under Operational Risks in the Company's 2021 Form 10-K for a more complete discussion of the risks to the Company associated with the COVID-19 pandemic. The Company has continued to pursue development projects to expand its Pipeline and Storage segment. One project onSupply Corporation's system, referred to as theFM100 Project , upgraded a 1950's era pipeline in northwesternPennsylvania and created approximately 330,000 Dth per day of additional transportation capacity inPennsylvania from a receipt point withNFG Midstream Clermont, LLC inMcKean County, Pennsylvania to theTranscontinental Gas Pipe Line Company, LLC ("Transco") system atLeidy, Pennsylvania . Construction activities on the expansion portion of theFM100 Project are complete and the project was placed in service inDecember 2021 . The final project cost is estimated to be$230 million . This project is expected to provide incremental annual transportation revenues of approximately$50 million .The FM100 Project is discussed in more detail in the Capital Resources and Liquidity section that follows. For further discussion of the Pipeline and Storage segment's revenues and earnings, refer to the Results of Operations section below.Seneca's 330,000 Dth per day of incremental pipeline capacity on theLeidy South Project , which is the companion project to theCompany's FM100 Project , went in service inDecember 2021 . The incremental pipeline capacity from this project and associated gathering system development byMidstream Company allowsSeneca to increase its production and reach premiumTransco Zone 6 (Non-New York) markets. From a financing perspective, the Company expects to use cash on hand and cash from operations, as well as short-term borrowings, to meet its financing needs for fiscal 2022. CRITICAL ACCOUNTING ESTIMATES For a complete discussion of critical accounting estimates, refer to "Critical Accounting Estimates" in Item 7 of the Company's 2021 Form 10-K. There have been no material changes to that disclosure other than as set forth below. The information presented below updates and should be read in conjunction with the critical accounting estimates in that Form 10-K. Oil and Gas Exploration and Development Costs. The Company, in its Exploration and Production segment, follows the full cost method of accounting for determining the book value of its oil and natural gas properties. In accordance with this methodology, the Company is required to perform a quarterly ceiling test. Under the ceiling test, the present value of future revenues from the Company's oil and gas reserves based on an unweighted arithmetic average of the first day of the month oil and gas prices for each month within the twelve-month period prior to the end of the reporting period (the "ceiling") is compared with the book value of the Company's oil and gas properties at the balance sheet date. The present value of future revenues is calculated using a 10% discount factor. If the book value of the oil and gas properties exceeds the ceiling, a non-cash impairment charge must be recorded to reduce the book value of the oil and gas properties to the calculated ceiling. AtDecember 31, 2021 , the ceiling exceeded the book value of the oil and gas properties by approximately$1.3 billion . The 12- 25
--------------------------------------------------------------------------------
Table of Contents
month average of the first day of the month price for crude oil for each month during the twelve months endedDecember 31, 2021 , based on posted Midway Sunset prices, was$65.70 per Bbl. The 12-month average of the first day of the month price for natural gas for each month during the twelve months endedDecember 31, 2021 , based on the quotedHenry Hub spot price for natural gas, was$3.60 per MMBtu. (Note: Because actual pricing of the Company's producing properties vary depending on their location and hedging, the prices used to calculate the ceiling may differ from the Midway Sunset andHenry Hub prices, which are only indicative of 12-month average prices for the twelve months endedDecember 31, 2021 . Actual realized pricing includes adjustments for regional market differentials, transportation fees and contractual arrangements.) The following table illustrates the sensitivity of the ceiling test calculation to commodity price changes, specifically showing the amounts the ceiling would have exceeded the book value of the Company's oil and gas properties atDecember 31, 2021 if natural gas prices were$0.25 per MMBtu lower than the average prices used atDecember 31, 2021 , if crude oil prices were$5 per Bbl lower than the average prices used atDecember 31, 2021 , and if both natural gas prices and crude oil prices were$0.25 per MMBtu and$5 per Bbl lower than the average prices used atDecember 31, 2021 (all amounts are presented after-tax). In all cases, these price decreases would not have resulted in an impairment charge. These calculated amounts are based solely on price changes and do not take into account any other changes to the ceiling test calculation, including, among others, changes in reserve quantities and future cost estimates.
Ceiling Testing Sensitivity to Commodity Price Changes
$0.25 /MMBtu Decrease in Natural Gas Prices$0.25 /MMBtu$5.00 /Bbl and$5.00 /Bbl Decrease in Decrease in Decrease in (Millions) Natural Gas Prices Crude Oil Prices Crude Oil Prices Excess of Ceiling over Book Value under Sensitivity Analysis $ 1,004.0 $ 1,249.0 $ 968.4 It is difficult to predict what factors could lead to future non-cash impairments under theSEC's full cost ceiling test. Fluctuations in or subtractions from proved reserves, increases in development costs for undeveloped reserves and significant fluctuations in oil and gas prices have an impact on the amount of the ceiling at any point in time. For a more complete discussion of the full cost method of accounting, refer to "Oil and Gas Exploration and Development Costs" under "Critical Accounting Estimates" in Item 7 of the Company's 2021 Form 10-K. RESULTS OF OPERATIONS
Earnings
The Company's earnings were$132.4 million for the quarter endedDecember 31, 2021 compared to earnings of$77.8 million for the quarter endedDecember 31, 2020 . The increase in earnings of$54.6 million is primarily the result of higher earnings in the Exploration and Production segment, Gathering segment and Pipeline and Storage segment. Lower earnings in the Utility segment, as well as losses in the Corporate and All Other categories, partially offset these increases. The Company's earnings for the quarter endedDecember 31, 2020 included a non-cash impairment charge of$76.2 million ($55.2 million after-tax) for the Exploration and Production segment's oil and gas producing properties. The Company's earnings for the quarter endedDecember 31, 2020 also included a gain recognized on the sale of timber properties of$51.1 million ($37.0 million after-tax) in the Company's All Other category. Additional discussion of earnings in each of the business segments can be found in the business segment information that follows. Note that all amounts used in the earnings discussions are after-tax amounts, unless otherwise noted. 26
--------------------------------------------------------------------------------
Table of Contents
Earnings (Loss) by Segment
Three Months Ended
December 31,
Increase
(Thousands) 2021 2020 (Decrease)
Exploration and Production $ 62,369 $ (29,623) $ 91,992
Pipeline and Storage 25,168 24,183 985
Gathering 23,137 20,550 2,587
Utility 22,130 23,037 (907)
Total Reportable Segments 132,804 38,147 94,657
All Other (7) 37,560 (37,567)
Corporate (405) 2,067 (2,472)
Total Consolidated $ 132,392 $ 77,774 $ 54,618
Exploration and Production
Exploration and Production Operating Revenues
Three Months Ended
December 31,
Increase
(Thousands) 2021 2020 (Decrease)
Gas (after Hedging) $ 205,801 $ 162,507 $ 43,294
Oil (after Hedging) 35,223 28,124 7,099
Gas Processing Plant 1,029 553 476
Other 2,145 211 1,934
$ 244,198 $ 191,395 $ 52,803
Production Volumes
Three Months Ended
December 31,
Increase
2021 2020 (Decrease)
Gas Production (MMcf)
Appalachia 81,389 75,669 5,720
West Coast 408 441 (33)
Total Production 81,797 76,110 5,687
Oil Production (Mbbl)
Appalachia - - -
West Coast 548 563 (15)
Total Production 548 563 (15)
27--------------------------------------------------------------------------------
Table of Contents
Average Prices
Three Months Ended
December 31,
Increase
2021 2020 (Decrease)
Average Gas Price/Mcf
Appalachia $ 4.39 $ 2.17 $ 2.22
West Coast $ 9.79 $ 5.03 $ 4.76
Weighted Average $ 4.42 $ 2.19 $ 2.23
Weighted Average After Hedging
Average Oil Price/Bbl Appalachia$ 70.86 $ 38.53 $ 32.33 West Coast$ 77.34 $ 43.48 $ 33.86 Weighted Average$ 77.34 $ 43.48 $ 33.86
Weighted Average After Hedging
2021 Compared with 2020
Operating revenues for the Exploration and Production segment increased$52.8 million for the quarter endedDecember 31, 2021 as compared with the quarter endedDecember 31, 2020 . Gas production revenue after hedging increased$43.3 million due to the impact of a 5.7 Bcf increase in natural gas production, together with a$0.38 per Mcf increase in the weighted average price of natural gas after hedging. Natural gas production increased largely due to additional production from the Company's newMarcellus andUtica wells in the Appalachian region. Oil production revenue after hedging increased$7.1 million due to an increase in the weighted average price of oil after hedging of$14.38 per Bbl, offset by the impact of a 15 Mbbl decrease in oil production. The decrease in oil production was largely due to natural production declines. In addition, other revenue increased$1.9 million and gas processing plant revenue increased$0.5 million . The increase in other revenue is primarily attributed to a temporary capacity release for a small portion of this segment's Leidy South transportation contract combined with operating revenue for the Highland Field Services water treatment plants acquired at the end of fiscal year 2021. The Exploration and Production segment's earnings for the quarter endedDecember 31, 2021 were$62.4 million , an increase of$92.0 million when compared with a loss of$29.6 million for the quarter endedDecember 31, 2020 . The increase in earnings was due to a quarter endedDecember 31, 2020 non-cash impairment of oil and gas properties ($55.2 million ), higher natural gas production ($9.6 million ), higher natural gas prices after hedging ($24.6 million ), higher oil prices after hedging ($6.2 million ), higher other operating revenue ($1.5 million ), lower interest expense ($2.7 million ) and lower income tax expense ($0.9 million ). The positive earnings impact of these items was partially offset by lower oil production ($0.6 million ), higher lease operating and transportation expenses ($2.8 million ), higher depletion expense ($3.3 million ), higher other operating expenses ($1.3 million ) and higher other taxes ($1.0 million ). The decrease in interest expense can largely be attributed to lower intercompany long-term and short-term borrowings combined with lower rates. The increase in lease operating and transportation expenses was primarily the result of increased gathering and transportation costs in the Appalachian region due to increased production combined with higher steam fuel costs in theWest Coast region due to higher nature gas prices. The increase in depletion expense was primarily due to the net increase in production. The increase in other operating expense was partially attributed to an increase in personnel costs combined with an increase in operating costs associated with the Highland Field Services water treatment plants acquired at the end of fiscal year 2021. The increase in other taxes was mainly attributed to increased Impact Fees in the Appalachian region. Impact Fees are variable fees that move based on calendar year NYMEX prices. 28
--------------------------------------------------------------------------------
Table of Contents
Pipeline and Storage
Pipeline and Storage Operating Revenues
Three Months Ended
December 31,
Increase
(Thousands) 2021 2020 (Decrease)
Firm Transportation $ 65,825 $ 64,599 $ 1,226
Interruptible Transportation 444 226 218
66,269 64,825 1,444
Firm Storage Service 20,800 20,485 315
Interruptible Storage Service - 32 (32)
Other 1,281 2,422 (1,141)
$ 88,350 $ 87,764 $ 586 Pipeline and Storage Throughput
Three Months Ended
December 31,
Increase
(MMcf) 2021 2020 (Decrease)
Firm Transportation 193,594 203,028 (9,434)
Interruptible Transportation 767 590 177
194,361 203,618 (9,257)
2021 Compared with 2020
Operating revenues for the Pipeline and Storage segment increased $0.6 million
for the quarter ended December 31, 2021 as compared with the quarter ended
December 31, 2020 . The increase in operating revenues was primarily due to an
increase in transportation revenues of $1.4 million and an increase in storage
revenues of $0.3 million , partially offset by a decrease in other revenue of
$1.1 million . The increase in transportation revenues was primarily attributable
to new demand charges for transportation service from Supply Corporation's FM100
Project , which was placed into service in December 2021 , partially offset by
revenue decreases associated with miscellaneous contract terminations and
revisions. In addition, a surcharge for Pipeline Safety and Greenhouse Gas
Regulatory Costs (PS/GHG Regulatory Costs) that went into effect in November
2020 associated with Supply Corporation's 2020 rate case settlement also
contributed to the increase in transportation revenues and was primarily
responsible for the increase in storage revenues. The decrease in other revenue
primarily reflects the non-recurrence of revenue associated with a contract
buyout that occurred during the quarter ended December 31, 2020 , partially
offset by higher revenues recorded under surcharge mechanisms to match higher
purchased gas and electric power costs for Empire's compressor stations.
Transportation volume for the quarter ended December 31, 2021 decreased by 9.3
Bcf from the prior year's quarter, primarily due to lower throughput related to
warmer weather than the prior year, partially offset by an increase in volume
from the FM100 Project , which was brought online in December 2021 . Volume
fluctuations, other than those caused by the addition or termination of
contracts, generally do not have a significant impact on revenues as a result of
the straight fixed-variable rate design utilized by Supply Corporation and
Empire.
The Pipeline and Storage segment's earnings for the quarter ended December 31,
2021 were $25.2 million , an increase of $1.0 million when compared with earnings
of $24.2 million for the quarter ended December 31, 2020 . The increase in
earnings was primarily due to the earnings impact of higher operating revenues
of $0.5 million , as discussed above, and an increase in other income ($1.2
million ). The increase in other income was mainly due to an increase in
allowance for funds used during construction (equity component) related to the
construction of the FM100 Project . These earnings increases were partially
offset by an increase in operating expenses ($0.8 million ) primarily due to an
increase in personnel costs and higher power costs, related to Empire's electric
motor drive compressor station. Empire also experienced higher purchased gas
costs ($0.3 million ) related to its natural gas driven compressor stations. The
power costs and purchased gas costs are offset by an equal amount of revenue due
to surcharge mechanisms.
29--------------------------------------------------------------------------------
Table of Contents
Gathering
Gathering Operating Revenues
Three Months Ended
December 31,
Increase
(Thousands) 2021 2020 (Decrease)
Gathering Revenues $ 52,225 $ 47,009 $ 5,216
Gathering Volume
Three Months Ended
December 31,
Increase
2021 2020 (Decrease)
Gathered Volume - (MMcf) 101,094 88,345 12,749
2021 Compared with 2020
Operating revenues for the Gathering segment increased $5.2 million for the
quarter ended December 31, 2021 as compared with the quarter ended December 31,
2020 , which was driven primarily by a 12.7 Bcf increase in gathered volume.
Contributors to the increase included the Trout Run , Clermont and Wellsboro
gathering systems, which recorded increases of 11.3 Bcf, 4.0 Bcf and 1.3 Bcf,
respectively, partially offset by the Covington gathering system, which recorded
a decrease of 3.9 Bcf. The net increase in gathered volume can be attributed
primarily to an increase in non-affiliated natural gas production on the Trout
Run gathering system in the Appalachian region and, to a lesser extent, an
increase in Seneca's gross natural gas production in the Appalachian region.
The Gathering segment's earnings for the quarter ended December 31, 2021 were
$23.1 million , an increase of $2.5 million when compared with earnings of $20.6
million for the quarter ended December 31, 2020 . The increase in earnings was
mainly due to higher gathering revenues ($4.1 million ) driven by the increase in
gathered volume, as discussed above. This earnings increase was partially offset
by higher operating expenses ($0.8 million ) and higher depreciation expense
($0.4 million ). The increase in operating expenses was largely attributable to
higher outside services costs associated with preventative maintenance overhauls
on the Trout Run gathering system. The increase in depreciation expense was
largely due to higher plant balances associated with the Clermont gathering
system. Earnings also decreased due to higher income tax expense ($0.2 million ).
Utility
Utility Operating Revenues
Three Months Ended
December 31,
Increase
(Thousands) 2021 2020 (Decrease)
Retail Sales Revenues:
Residential $ 182,708 $ 140,844 $ 41,864
Commercial 25,242 18,207 7,035
Industrial 1,157 931 226
209,107 159,982 49,125
Transportation 29,652 30,631 (979)
Other (2,000) (1,612) (388)
$ 236,759 $ 189,001 $ 47,758
30--------------------------------------------------------------------------------
Table of Contents
Utility Throughput
Three Months Ended
December 31,
Increase
(MMcf) 2021 2020 (Decrease)
Retail Sales:
Residential 17,496 18,412 (916)
Commercial 2,543 2,528 15
Industrial 123 153 (30)
20,162 21,093 (931)
Transportation 17,593 17,935 (342)
37,755 39,028 (1,273)
Degree Days
Percent Colder (Warmer) Than
Three Months Ended December 31, Normal 2021 2020 Normal(1) Prior Year(1)
Buffalo, NY 2,253 1,704 1,921 (24.4) % (11.3) %
Erie, PA 2,044 1,560 1,697 (23.7) % (8.1) %
(1)Percents compare actual 2021 degree days to normal degree days and actual 2021 degree days to actual 2020 degree days.
2021 Compared with 2020
Operating revenues for the Utility segment increased$47.8 million for the quarter endedDecember 31, 2021 as compared with the quarter endedDecember 31, 2020 . The increase resulted from a$49.1 million increase in retail gas sales revenue, which was primarily due to a significant increase in the cost of gas sold (per Mcf). Under its purchased gas adjustment clauses inNew York andPennsylvania ,Distribution Corporation is not allowed to profit from fluctuations in gas costs. This increase was partially offset by a$1.0 million decrease in transportation revenues and a$0.4 million decrease in other revenues. The decline in transportation revenues was largely the result of a 0.3 Bcf decrease in transportation throughput due to warmer weather and the migration of residential transportation customers to retail. The decrease in other revenues was mainly the result of a regulatory adjustment ($0.9 million ) and lower late payment charges billed to customers ($0.5 million ), partially offset by a smaller estimated refund provision for the income tax benefits resulting from the 2017 Tax Reform Act ($0.7 million ) and an increase in capacity release revenues ($0.3 million ). The Utility segment's earnings for the quarter endedDecember 31, 2021 were$22.1 million , a decrease of$0.9 million when compared with earnings of$23.0 million for the quarter endedDecember 31, 2020 . The decrease in earnings was largely attributable to a decrease in base rates that reflects the elimination of other post-employment benefit ("OPEB") expenses from customer rates inDistribution Corporation's Pennsylvania service territory in accordance with a regulatory proceeding that became effectiveOctober 1, 2021 ($1.8 million ) combined with higher operating expenses ($1.4 million ), primarily the result of higher personnel costs and outside services that were partially offset by a decrease in the allowance for uncollectible accounts. The impact of regulatory revenue adjustments ($0.9 million ) and higher depreciation expense ($0.7 million ) due to higher plant balances also contributed to the decrease in earnings. These decreases were partially offset by a lower effective tax rate ($2.0 million ), lower other deductions ($1.7 million ) largely related to the elimination of OPEB expenses from customer rates, as discussed above, and the impact of a system modernization tracker inNew York ($0.8 million ). The impact of weather variations on earnings in the Utility segment'sNew York rate jurisdiction is mitigated by that jurisdiction's weather normalization clause (WNC). The WNC inNew York , which covers the eight-month period from October through May, has had a stabilizing effect on earnings for theNew York rate jurisdiction. In addition, in periods of colder than normal weather, the WNC benefits the Utility segment'sNew York customers. For the quarter endedDecember 31, 2021 , the WNC increased earnings by approximately$2.6 million , as the weather was warmer than normal. For the quarter endedDecember 31, 2020 , the WNC increased earnings by approximately$1.6 million , as the weather was warmer than normal. 31
--------------------------------------------------------------------------------
Table of Contents Corporate and All Other 2021 Compared with 2020 Corporate and All Other operations had a loss of$0.4 million for the quarter endedDecember 31, 2021 , a decrease of$40.0 million when compared with earnings of$39.6 million for the quarter endedDecember 31, 2020 . The decrease in earnings was primarily attributable to the non-recurrence of a$51.1 million gain ($37.0 million gain after-tax) on sale of timber properties recorded bySeneca's Northeast Division during the quarter endedDecember 31, 2020 . The decrease can also be attributed to changes in unrealized losses on investments in equity securities. During the quarter endedDecember 31, 2021 , the Company recorded unrealized losses of$3.5 million . During the quarter endedDecember 31, 2020 , the Company recorded unrealized losses of$1.0 million .
Other Income (Deductions)
Net other deductions on the Consolidated Statement of Income were$1.1 million for the quarter endedDecember 31, 2021 , compared to net other deductions of$2.2 million for the quarter endedDecember 31, 2020 . This change is primarily attributable to a decrease in the pension and post-retirement non-service benefit cost expense of$3.0 million largely relating to the elimination of OPEB expenses from customer rates in the Utility segment'sPennsylvania service territory in accordance with a tariff supplement that became effectiveOctober 1, 2021 . Also contributing to the decrease in other deductions is an increase in allowance for funds used during construction (equity component) of$1.1 million . These were partially offset by changes in realized and unrealized gains and losses on investments in equity securities. During the quarter endedDecember 31, 2021 , the Company recorded pre-tax realized gains of$4.4 million and pre-tax unrealized losses of$5.2 million . During the quarter endedDecember 31, 2020 , the Company recorded pre-tax realized gains of$3.3 million and pre-tax unrealized losses of$1.1 million .
Interest Expense on Long-Term Debt
Interest expense on long-term debt on the Consolidated Statement of Income decreased$2.1 million for the quarter endedDecember 31, 2021 as compared to the quarter endedDecember 31, 2020 primarily due to a lower weighted average interest rate on long-term debt, stemming from the Company's issuance of$500.0 million of 2.95% notes inFebruary 2021 , which replaced$500.0 million of 4.90% notes that were retired inMarch 2021 . CAPITAL RESOURCES AND LIQUIDITY The Company's primary sources of cash during the three-month period endedDecember 31, 2021 consisted of cash provided by operating activities and proceeds from the sale of a fixed income mutual fund in a grantor trust. The Company's primary sources of cash during the three-month period endedDecember 31, 2020 consisted of cash provided by operating activities and net proceeds from the sale of timber properties. The Company expects to have adequate amounts of cash to meet both its short-term and long-term cash requirements. During the remainder of 2022, cash provided by operating activities is expected to increase over the amount of cash provided by operating activities during 2021 and will be used to meet the Company's dividend requirements and reduce short-term borrowings. Capital expenditures for 2022 are expected to be lower than 2021. There are no scheduled repayments of long-term debt in the remainder of 2022. Looking at 2023 through 2024, based on current commodity prices, cash provided by operating activities is expected to exceed capital expenditures in each of those years, which could lead to further capital investments in the business or reductions in short-term borrowings and a net reduction in long-term debt in 2023 while still allowing the Company to meet its dividend requirements. These cash flow projections do not reflect the impact of acquisitions or divestitures that may arise in the future. Operating Cash Flow Internally generated cash from operating activities consists of net income available for common stock, adjusted for non-cash expenses, non-cash income, gains and losses associated with investing and financing activities, and changes in operating assets and liabilities. Non-cash items include depreciation, depletion and amortization, impairment of oil and gas producing properties, deferred income taxes and stock-based compensation. Cash provided by operating activities in the Utility and Pipeline and Storage segments may vary substantially from period to period because of the impact of rate cases. In the Utility segment, supplier refunds, over- or under-recovered 32
--------------------------------------------------------------------------------
Table of Contents
purchased gas costs and weather may also significantly impact cash flow. The impact of weather on cash flow is tempered in the Utility segment'sNew York rate jurisdiction by its WNC and in the Pipeline and Storage segment by the straight fixed-variable rate design used bySupply Corporation and Empire. Because of the seasonal nature of the heating business in the Utility segment, revenues in this business are relatively high during the heating season, primarily the first and second quarters of the fiscal year, and receivable balances historically increase during these periods from the receivable balances atSeptember 30 . The storage gas inventory normally declines during the first and second quarters of the fiscal year and is replenished during the third and fourth quarters. For storage gas inventory accounted for under the LIFO method, the current cost of replacing gas withdrawn from storage is recorded in the Consolidated Statements of Income and a reserve for gas replacement is recorded in the Consolidated Balance Sheets under the caption "Other Accruals and Current Liabilities." Such reserve is reduced as the inventory is replenished. Cash provided by operating activities in the Exploration and Production segment may vary from period to period as a result of changes in the commodity prices of natural gas and crude oil as well as changes in production. The Company uses various derivative financial instruments, including price swap agreements and no cost collars, in an attempt to manage this energy commodity price risk. Net cash provided by operating activities totaled$171.5 million for the three months endedDecember 31, 2021 , a decrease of$33.2 million compared with$204.7 million provided by operating activities for the three months endedDecember 31, 2020 . The decrease in cash provided by operating activities primarily reflects lower cash provided by operating activities in the Utility segment, slightly offset by higher cash provided by operating activities in the Exploration and Production segment. The decrease in the Utility segment is primarily due to lower rates in the Utility segment'sPennsylvania service territory that went into effectOctober 1, 2021 combined with the timing of gas cost recovery and other regulatory true-ups. The rates that went into effect included a one-time customer bill credit of$25 million inOctober 2021 for previously overcollected OPEB expenses and the beginning of a 5-year pass back of an additional$25 million in previously overcollected OPEB expenses. Please refer to the Rate Matters section that follows for additional discussion of this matter. The increase in the Exploration and Production segment was primarily due to higher cash receipts from natural gas production.
Investing Cash Flow
Expenditures for Long-Lived Assets
The Company's expenditures for long-lived assets totaled$191.8 million during the three months endedDecember 31, 2021 and$150.9 million during the three months endedDecember 31, 2020 . The table below presents these expenditures: Total Expenditures for Long-Lived Assets Three Months Ended December 31, Increase (Millions) 2021 2020 (Decrease) Exploration and Production: Capital Expenditures$ 139.2 (1)$ 81.3 (2)$ 57.9 Pipeline and Storage: Capital Expenditures 24.1 (1) 43.7 (2) (19.6) Gathering: Capital Expenditures 8.9 (1) 8.3 (2) 0.6 Utility: Capital Expenditures 19.4 (1) 17.3 (2) 2.1 All Other: Capital Expenditures 0.2 0.1 0.1 Eliminations - 0.2 (0.2)$ 191.8 $ 150.9 $ 40.9 (1)AtDecember 31, 2021 , capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment include$69.9 million ,$5.4 million ,$2.6 million and$3.1 million , respectively, of non-cash capital expenditures. AtSeptember 30 , 33
--------------------------------------------------------------------------------
Table of Contents
2021, capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment included$47.9 million ,$39.4 million ,$4.8 million and$10.6 million , respectively, of non-cash capital expenditures. (2)AtDecember 31, 2020 , capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment included$35.1 million ,$11.2 million ,$2.3 million and$3.5 million , respectively, of non-cash capital expenditures. AtSeptember 30, 2020 , capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment included$45.8 million ,$17.3 million ,$13.5 million and$10.7 million , respectively, of non-cash capital expenditures.
Exploration and Production
The Exploration and Production segment capital expenditures for the three months endedDecember 31, 2021 were primarily well drilling and completion expenditures and included approximately$132.1 million for the Appalachian region (including$45.1 million in theMarcellus Shale area and$83.3 million in theUtica Shale area) and$7.1 million for theWest Coast region. These amounts included approximately$54.2 million spent to develop proved undeveloped reserves. The Exploration and Production segment capital expenditures for the three months endedDecember 31, 2020 were primarily well drilling and completion expenditures and included approximately$79.9 million for the Appalachian region (including$30.5 million in theMarcellus Shale area and$43.9 million in theUtica Shale area) and$1.4 million for theWest Coast region. These amounts included approximately$34.3 million spent to develop proved undeveloped reserves.
Pipeline and Storage
The Pipeline and Storage segment capital expenditures for the three months endedDecember 31, 2021 were primarily for expenditures related toSupply Corporation's FM100 Project ($15.7 million ), which is discussed below. In addition, the Pipeline and Storage segment capital expenditures for the three months endedDecember 31, 2021 included additions, improvements and replacements to this segment's transmission and gas storage systems. The Pipeline and Storage segment capital expenditures for the three months endedDecember 31, 2020 were primarily for expenditures related toSupply Corporation's FM100 Project ($30.4 million ). In addition, the Pipeline and Storage segment capital expenditures for the three months endedDecember 31, 2020 included additions, improvements and replacements to this segment's transmission and gas storage systems. In light of the continuing demand for pipeline capacity to move natural gas from new wells being drilled in Appalachia, specifically in theMarcellus andUtica Shale producing areas,Supply Corporation and Empire have completed and continue to pursue expansion projects designed to move anticipatedMarcellus andUtica production gas to other interstate pipelines and to on-system markets, and markets beyond theSupply Corporation and Empire pipeline systems.Supply Corporation has developed itsFM100 Project , which upgraded a 1950's era pipeline in northwesternPennsylvania and created approximately 330,000 Dth per day of additional transportation capacity inPennsylvania from a receipt point withNFG Midstream Clermont, LLC inMcKean County to theTranscontinental Gas Pipe Line Company, LLC ("Transco") system atLeidy, Pennsylvania .Supply Corporation andTransco executed a precedent agreement wherebyTransco has leased this additional capacity ("Lease") as part of aTransco expansion project ("Leidy South"), creating incremental transportation capacity toTransco Zone 6 markets.Seneca is an anchor shipper on Leidy South, which provides it with an outlet to premium markets from both its Eastern and Western development areas. Construction activities on the expansion portion of the FM100 project are complete and the project commenced partial in-service onDecember 1, 2021 , with full in-service onDecember 19, 2021 . Abandonment activities on the project will continue in calendar year 2022. The estimated capital cost of the project is approximately$230 million . As ofDecember 31, 2021 , approximately$201.8 million has been spent on the FM100 project, all of which is included in Property, Plant and Equipment on the Consolidated Balance Sheet atDecember 31, 2021 .Supply Corporation and Empire have developed a project which would move significant prospectiveMarcellus andUtica production fromSeneca's Western Development Area atClermont to an Empire interconnection with the TC Energy pipeline at Chippawa and an interconnection with TGP's 200 Line inEast Aurora, New York (the "Northern Access project"). The Northern Access project would provide an outlet to Dawn-indexed markets inCanada and to the TGP line serving theU.S. Northeast. The Northern Access project involves the construction of approximately 99 miles of largely 24" pipeline and approximately 27,500 horsepower of compression on the two systems.Supply Corporation , Empire andSeneca executed anchor shipper agreements for 350,000 Dth per day of firm transportation delivery capacity to Chippawa and 140,000 Dth per day of firm transportation capacity to a new interconnection with TGP's 200 Line on this project. OnFebruary 3, 2017 , the Company receivedFERC approval of the project. Shortly thereafter, the NYDEC issued a Notice of Denial of the federal Clean Water Act Section 401 Water Quality Certification and other state stream and wetland permits for theNew York portion of the project (the Water Quality Certification for thePennsylvania portion of the project was received in January of 2017). 34
--------------------------------------------------------------------------------
Table of Contents
Subsequently,FERC issued an Order finding that the NYDEC exceeded the statutory time frame to take action under the Clean Water Act and, therefore, waived its opportunity to approve or deny the Water Quality Certification.FERC denied rehearing requests associated with its Order, andFERC's decisions were appealed.The Second Circuit Court of Appeals issued an order upholding theFERC waiver orders. In addition, in the Company's state court litigation challenging the NYDEC's actions with regard to various state permits, theNew York State Supreme Court issued a decision finding these permits to be preempted. The Company remains committed to the project and, onJanuary 28, 2022 , filed withFERC a request for an extension of time to construct the project. The Company will update the$500 million preliminary cost estimate and expected in-service date for the project when there is further clarity on the timing of receipt of necessary regulatory approvals. As ofDecember 31, 2021 , approximately$55.7 million has been spent on the Northern Access project, including$24.1 million that has been spent to study the project. The remaining$31.6 million spent on the project is included in Property, Plant and Equipment on the Consolidated Balance Sheet atDecember 31, 2021 .
Gathering
The majority of the Gathering segment capital expenditures for the three months endedDecember 31, 2021 included expenditures related to the continued expansion ofMidstream Company's Clermont and Covington gathering systems, as discussed below.Midstream Company spent$4.0 million and$4.5 million , respectively, during the three months endedDecember 31, 2021 on the development of theClermont and Covington gathering systems. These expenditures were largely attributable to newClermont gathering pipelines, as well as the development of new gathering facilities, including new gathering pipelines and upgrades to existing stations, in theTioga gathering system, which is part of Midstream Covington. The majority of the Gathering segment capital expenditures for the three months endedDecember 31, 2020 were for the continued expansion ofMidstream Company's Clermont andWellsboro gathering systems.Midstream Company spent$4.5 million and$3.1 million , respectively, during the three months endedDecember 31, 2020 on the development of theClermont andWellsboro gathering systems. These expenditures were largely attributable to the continued development of centralized station facilities, including increased compression horsepower at theClermont andWellsboro gathering systems and additional dehydration on theClermont gathering system.NFG Midstream Clermont, LLC , a wholly-owned subsidiary ofMidstream Company , continues to develop an extensive gathering system with compression in thePennsylvania counties ofMcKean ,Elk andCameron . TheClermont gathering system was initially placed in service inJuly 2014 . The current system consists of three compressor stations and backbone and in-field gathering pipelines. The total cost estimate for the continued buildout will be dependent on the nature and timing ofSeneca's long-term plans.NFG Midstream Covington, LLC , a wholly-owned subsidiary ofMidstream Company , operates its Covington gathering system as well as theTioga gathering system acquired from Shell onJuly 31, 2020 , both inTioga County, Pennsylvania . The current Covington gathering system consists of two compressor stations and backbone and in-field gathering pipelines. TheTioga gathering system consists of 13 compressor stations and backbone and in-field gathering pipelines.NFG Midstream Wellsboro, LLC , a wholly-owned subsidiary ofMidstream Company , continues to develop itsWellsboro gathering system inTioga County, Pennsylvania . The current system consists of one compressor station and backbone and in-field gathering pipelines.
Utility
The majority of the Utility segment capital expenditures for the three months endedDecember 31, 2021 andDecember 31, 2020 were made for main and service line improvements and replacements that enhance the reliability and safety of the system and reduce emissions. Expenditures were also made for main extensions.
Other Investing Activities
OnDecember 10, 2020 , the Company completed the sale of substantially all timber properties inPennsylvania toLyme Emporium Highlands III LLC andLyme Allegheny Land Company II LLC for net proceeds of$104.6 million . After purchase price adjustments and transaction costs, a gain of$51.1 million was recognized on the sale of these assets ($37.0 million after-tax). The sale of the timber properties completed a reverse like-kind exchange pursuant to Section 1031 of the Internal Revenue Code, as amended ("Reverse 1031 Exchange"). OnJuly 31, 2020 , the Company completed its acquisition of certain upstream assets and midstream gathering assets inPennsylvania from Shell for total consideration of$506.3 million . The purchase and sale agreement with Shell was structured, in part, as a Reverse 1031 Exchange. Refer to Item 8, Note B - 35
--------------------------------------------------------------------------------
Table of Contents
Asset Acquisitions and Divestitures, of the Company's 2021 Form 10-K for additional information concerning the Company's acquisition of certain upstream assets and midstream gathering assets from Shell.
InOctober 2021 , the Company sold fixed income mutual fund shares held in a grantor trust for proceeds of$30 million . The proceeds were used in the Utility segment'sPennsylvania service territory to fund a one-time customer bill credit of$25 million inOctober 2021 for previously overcollected OPEB expenses and the first year installment of a 5-year pass back of an additional$25 million in previously overcollected OPEB expenses in accordance with new rates that went into effect onOctober 1, 2021 . Please refer to the Rate Matters section that follows for additional discussion of this matter.
Project Funding
Over the past two years, the Company has been financing capital expenditures with cash from operations, short-term and long-term debt, common stock, and proceeds from the sale of timber properties. During the quarters endedDecember 31, 2021 andDecember 31, 2020 , capital expenditures were funded with cash from operations. The Company issued long-term debt and common stock inJune 2020 to help finance the acquisition of upstream assets and midstream gathering assets from Shell. The financing of the asset acquisition from Shell was completed inDecember 2020 when the Company completed the sale of substantially all of its timber properties, through the completion of the Reverse 1031 Exchange discussed above. Going forward, the Company expects to use cash on hand, cash from operations and short-term borrowings to finance capital expenditures. The level of short-term borrowings will depend upon the amount of cash provided by operations, which, in turn, will likely be most impacted by the timing of gas cost recovery in the Utility segment and by natural gas and crude oil production, and the associated commodity price realizations, in the Exploration and Production segment. The Company continuously evaluates capital expenditures and potential investments in corporations, partnerships, and other business entities. The amounts are subject to modification for opportunities such as the acquisition of attractive oil and gas properties, quicker development of existing oil and gas properties, natural gas storage and transmission facilities, natural gas gathering and compression facilities and the expansion of natural gas transmission line capacities, regulated utility assets and other opportunities as they may arise. While the majority of capital expenditures in the Utility segment are necessitated by the continued need for replacement and upgrading of mains and service lines, the magnitude of future capital expenditures or other investments in the Company's other business segments depends, to a large degree, upon market and regulatory conditions.
Financing Cash Flow
Consolidated short-term debt increased$7.5 million when comparing the balance sheet atDecember 31, 2021 to the balance sheet atSeptember 30, 2021 . The maximum amount of short-term debt outstanding during the quarter endedDecember 31, 2021 was$288.3 million . The Company continues to consider short-term debt (consisting of short-term notes payable to banks and commercial paper) an important source of cash for temporarily financing capital expenditures, gas-in-storage inventory, unrecovered purchased gas costs, margin calls on derivative financial instruments, exploration and development expenditures, other working capital needs and repayment of long-term debt. Fluctuations in these items can have a significant impact on the amount and timing of short-term debt. Given the significant rise in gas prices toward the end of fiscal 2021, the Company was required to post margin on some of its outstanding derivative financial instruments. AtSeptember 30, 2021 , the Company had outstanding commercial paper of$158.5 million , approximately half of which was related to the aforementioned margin requirements. AtDecember 31, 2021 , the Company had outstanding commercial paper of$166.0 million , all of which was related to actual operating cash requirements. The Company was not required to post margin on its outstanding derivative financial instruments atDecember 31, 2021 . The Company did not have any outstanding short-term notes payable to banks atDecember 31, 2021 . The Company maintains$1.0 billion of unsecured committed revolving credit access across two facilities. OnOctober 25, 2018 , the Company entered into a Fourth Amended and Restated Credit Agreement ("Credit Agreement") with a syndicate of twelve banks. This Credit Agreement provides a$750.0 million multi-year unsecured committed revolving credit facility throughOctober 25, 2023 . In addition to the Credit Agreement, onFebruary 3, 2021 , the Company amended its existing 364-Day Credit Agreement to extend the maturity date thereof fromMay 3, 2021 toDecember 30, 2022 , and to increase the lenders' commitments thereunder from$200.0 million to$250.0 million , among other changes (as amended, the "Amended 364-Day Credit Agreement"). Twelve banks are parties to the Amended 364-Day Credit Agreement, all of which are also lenders under the Credit Agreement. The Company also has uncommitted lines of credit with financial institutions for general corporate purposes. Borrowings under these uncommitted lines of credit would be made at competitive market rates. The uncommitted credit lines are revocable at the option of the financial institution and are reviewed on an annual basis. The Company anticipates that its uncommitted lines of credit generally will be renewed or substantially replaced by similar lines. Other financial institutions may also provide the Company with uncommitted or discretionary lines of credit in the future. 36
--------------------------------------------------------------------------------
Table of Contents
The total amount available to be issued under the Company's commercial paper program is$500.0 million . The commercial paper program is backed by the Credit Agreement, which provides that the Company's debt to capitalization ratio will not exceed .65 at the last day of any fiscal quarter. For purposes of calculating the debt to capitalization ratio, the Company's total capitalization will be increased by adding back 50% of the aggregate after-tax amount of non-cash charges directly arising from any ceiling test impairment occurring on or afterJuly 1, 2018 , not to exceed$250 million . This provision also applies to the Amended 364-Day Credit Agreement. SinceJuly 1, 2018 , the Company recorded non-cash, after-tax ceiling test impairments totaling$381.4 million . As a result, atDecember 31, 2021 ,$190.7 million was added back to the Company's total capitalization for purposes of the facility, and the Company's debt to capitalization ratio, as calculated under the facility, was .55. The constraints specified in both the Credit Agreement and Amended 364-Day Credit Agreement would have permitted an additional$1.47 billion in short-term and/or long-term debt to be outstanding atDecember 31, 2021 before the Company's debt to capitalization ratio exceeded .65. A downgrade in the Company's credit ratings could increase borrowing costs, negatively impact the availability of capital from banks, commercial paper purchasers and other sources, and require the Company's subsidiaries to post letters of credit, cash or other assets as collateral with certain counterparties. If the Company is not able to maintain investment-grade credit ratings, it may not be able to access commercial paper markets. However, the Company expects that it could borrow under its credit facilities or rely upon other liquidity sources. The Credit Agreement and Amended 364-Day Credit Agreement contain a cross-default provision whereby the failure by the Company or its significant subsidiaries to make payments under other borrowing arrangements, or the occurrence of certain events affecting those other borrowing arrangements, could trigger an obligation to repay any amounts outstanding under the Credit Agreement and the Amended 364-Day Credit Agreement. In particular, a repayment obligation could be triggered if (i) the Company or any of its significant subsidiaries fails to make a payment when due of any principal or interest on any other indebtedness aggregating$40.0 million or more or (ii) an event occurs that causes, or would permit the holders of any other indebtedness aggregating$40.0 million or more to cause, such indebtedness to become due prior to its stated maturity.
None of the Company's long-term debt as of
The Company's embedded cost of long-term debt was 4.48% and 4.85% at
Under the Company's existing indenture covenants atDecember 31, 2021 , the Company would have been permitted to issue up to a maximum of approximately$2.16 billion in additional unsubordinated long-term indebtedness at then current market interest rates, in addition to being able to issue new indebtedness to replace existing debt (further limited by debt to capitalization ratio constraints under the Company's Credit Agreement and Amended 364-Day Credit Agreement, as discussed above). The Company's present liquidity position is believed to be adequate to satisfy known demands. It is possible, depending on amounts reported in various income statement and balance sheet line items, that the indenture covenants could, for a period of time, prevent the Company from issuing incremental unsubordinated long-term debt, or significantly limit the amount of such debt that could be issued. Losses incurred as a result of significant impairments of oil and gas properties have in the past resulted in such temporary restrictions. The indenture covenants would not preclude the Company from issuing new long-term debt to replace existing long-term debt, or from issuing additional short-term debt. Please refer to the Critical Accounting Estimates section above for a sensitivity analysis concerning commodity price changes and their impact on the ceiling test. The Company's 1974 indenture pursuant to which$99.0 million (or 3.7%) of the Company's long-term debt (as ofDecember 31, 2021 ) was issued, contains a cross-default provision whereby the failure by the Company to perform certain obligations under other borrowing arrangements could trigger an obligation to repay the debt outstanding under the indenture. In particular, a repayment obligation could be triggered if the Company fails (i) to pay any scheduled principal or interest on any debt under any other indenture or agreement or (ii) to perform any other term in any other such indenture or agreement, and the effect of the failure causes, or would permit the holders of the debt to cause, the debt under such indenture or agreement to become due prior to its stated maturity, unless cured or waived. OTHER MATTERS In addition to the legal proceedings disclosed in Part II, Item 1 of this report, the Company is involved in other litigation and regulatory matters arising in the normal course of business. These other matters may include, for example, negligence claims and tax, regulatory or other governmental audits, inspections, investigations or other proceedings. These 37
--------------------------------------------------------------------------------
Table of Contents
matters may involve state and federal taxes, safety, compliance with regulations, rate base, cost of service and purchased gas cost issues, among other things. While these normal-course matters could have a material effect on earnings and cash flows in the period in which they are resolved, they are not expected to change materially the Company's present liquidity position, nor are they expected to have a material adverse effect on the financial condition of the Company. During the three months endedDecember 31, 2021 , the Company contributed$5.2 million to its tax-qualified, noncontributory defined-benefit retirement plan (Retirement Plan) and$0.7 million to its VEBA trusts for its other post-retirement benefits. In the remainder of 2022, the Company expects its contributions to the Retirement Plan to be in the range of$15.0 million to$20.0 million . In the remainder of 2022, the Company expects its contributions to its VEBA trusts to be in the range of$2.0 million to$2.5 million .
Market Risk Sensitive Instruments
OnJuly 21, 2010 , the Dodd-Frank Act was signed into law. The Dodd-Frank Act required the CFTC,SEC and other regulatory agencies to promulgate rules and regulations implementing the legislation, and includes provisions related to the swaps and over-the-counter derivatives markets that are designed to promote transparency, mitigate systemic risk and protect against market abuse. Although regulators have issued certain regulations, other rules that may impact the Company have yet to be finalized. Rules developed by the CFTC and other regulators could impact the Company. While many of those rules place specific conditions on the operations of swap dealers and major swap participants, concern remains that swap dealers and major swap participants will pass along their increased costs stemming from final rules through higher transaction costs and prices or other direct or indirect costs. Additionally, given the enforcement authority granted to the CFTC on anti-market manipulation, anti-fraud and disruptive trading practices, it is difficult to predict how the evolving enforcement priorities of the CFTC will impact our business. Should the Company violate any laws or regulations applicable to our hedging activities, it could be subject to CFTC enforcement action and material penalties and sanctions. The Company continues to monitor these enforcement and other regulatory developments, but cannot predict the impact that evolving application of the Dodd-Frank Act may have on its operations. The authoritative guidance for fair value measurements and disclosures require consideration of the impact of nonperformance risk (including credit risk) from a market participant perspective in the measurement of the fair value of assets and liabilities. AtDecember 31, 2021 , the Company determined that nonperformance risk would have no material impact on its financial position or results of operation. To assess nonperformance risk, the Company considered information such as any applicable collateral posted, master netting arrangements, and applied a market-based method by using the counterparty's (assuming the derivative is in a gain position) or the Company's (assuming the derivative is in a loss position) credit default swaps rates. For a complete discussion of all other market risk sensitive instruments used by the Company, refer to "Market Risk Sensitive Instruments" in Item 7 of the Company's 2021 Form 10-K. Rate Matters Utility Operation Delivery rates for both theNew York andPennsylvania divisions are regulated by the states' respective public utility commissions and typically are changed only when approved through a procedure known as a "rate case." Neither theNew York orPennsylvania divisions currently have a rate case on file. In both jurisdictions, delivery rates do not reflect the recovery of purchased gas costs. Prudently-incurred gas costs are recovered through operation of automatic adjustment clauses, and are collected primarily through a separately-stated "supply charge" on the customer bill.
New York Jurisdiction
Distribution Corporation's current delivery rates in itsNew York jurisdiction were approved by the NYPSC in an order issued onApril 20, 2017 with rates becoming effectiveMay 1, 2017 . The order provided for a return on equity of 8.7%. The order also directed the implementation of an earnings sharing mechanism to be in place beginning onApril 1, 2018 . OnAugust 13, 2021 , the NYPSC issued an order extending the date through which qualified pipeline replacement costs incurred by the Company can be recovered using the existing system modernization tracker for two years (untilMarch 31, 2023 ). The extension is contingent on the Company not filing a base rate case that would result in new rates becoming effective prior toApril 1, 2023 . 38
--------------------------------------------------------------------------------
Table of Contents
InNew York , onMarch 13, 2020 , in response to the COVID-19 pandemic, the Company agreed to NYPSC Staff's request that the Company suspend service terminations and disconnections. Thereafter, onJune 17, 2020 ,New York enacted a law that prohibited utilities from terminating or disconnecting services to any residential customer for non-payment for the duration of the state disaster emergency. While that legislation expired onMarch 31, 2021 , new legislation was enacted inMay 2021 that prohibited utility terminations for non-payment for residential and small commercial customers who experienced a change in financial circumstances due to the COVID-19 state of emergency, with such prohibition running for a period of one hundred eighty days after either theNew York State COVID-19 state of emergency is lifted or expires orDecember 31, 2021 , whichever is earlier. OnJune 24, 2021 , theNew York State COVID-19 state of emergency expired. Updated guidance issued by the NYPSC onJuly 6, 2021 confirmed that qualified customers are protected from termination throughDecember 21, 2021 and are eligible for a deferred payment agreement without the requirement of a down payment, late fees, penalties or interest on arrears incurred during the COVID-19 state of emergency. OnDecember 20, 2021 , NYPSC Staff requested, and the Company agreed, to refrain from terminating residential customers with a pending application for arrears payments through theEmergency Rental Assistance Program administered by theOffice of Temporary Disability .
Pennsylvania Jurisdiction
OnJuly 22, 2021 ,Distribution Corporation filed a supplement to its currentPennsylvania tariff proposing to reduce base rates effectiveOctober 1, 2021 by$7.7 million in order to stop collecting other post-employment benefit ("OPEB") expenses from customers at this time, to begin to refund to customers overcollected OPEB expenses in the amount of$50.0 million , and to make certain other adjustments to further reduceDistribution Corporation's regulatory liability associated with OPEB expenses. The PaPUC issued an order approving this tariff supplement onSeptember 15, 2021 and new rates went into effect onOctober 1, 2021 . OnSeptember 21, 2021 , a complaint was filed in this proceeding. While new rates, including associated refunds, went into effect onOctober 1, 2021 , certain other adjustments called for by the tariff supplement that allowDistribution Corporation to reduce its regulatory liability and its OPEB expenses will not be recorded in the Company's consolidated financial statements until the complaint is resolved. The PaPUC assigned the matter to an Administrative Law Judge who, onJanuary 6, 2022 , issued a Recommended Decision approving a settlement reached by parties to the complaint proceeding. The matter currently sits with the PaPUC for final determination. The refunds specified in the tariff supplement will be funded entirely by grantor trust assets held by the Company, most of which are included in a fixed income mutual fund that is a component of Other Investments on the Company's Consolidated Balance Sheet. With the elimination of OPEB expenses in base rates,Distribution Corporation will no longer fund the grantor trust or its VEBA trusts in itsPennsylvania jurisdiction.
Pipeline and Storage
Supply Corporation's 2020 rate settlement provides that no party may make a rate filing for new rates to be effective beforeFebruary 1, 2024 , except thatSupply Corporation may file an NGA general Section 4 rate case to change rates if the corporate federal income tax rate is increased. If no case has been filed,Supply Corporation must file for rates to be effectiveFebruary 1, 2025 .
Empire's 2019 rate settlement provides that Empire must make a rate case
filing no later than
Environmental Matters
The Company is subject to various federal, state and local laws and regulations relating to the protection of the environment. The Company has established procedures for the ongoing evaluation of its operations to identify potential environmental exposures and comply with regulatory requirements. InMarch 2021 , the Company set greenhouse gas reduction targets associated with the Company's utility delivery system. To further our ongoing efforts to lower the Company's emissions profile, inSeptember 2021 the Company also established methane intensity reduction targets at each of its businesses, as well as an absolute greenhouse gas emissions reduction target for the consolidated Company. The Company's ability to estimate accurately the time, costs and resources necessary to meet emissions targets may change as environmental exposures and opportunities change and regulatory updates are issued. 39
--------------------------------------------------------------------------------
Table of Contents
For further discussion of the Company's environmental exposures, refer to Item 1 at Note 8 - Commitments and Contingencies under the heading "Environmental Matters."
Legislative and regulatory measures to address climate change and greenhouse gas emissions are in various phases of discussion or implementation inthe United States . These efforts include legislation, legislative proposals and new regulations at the state and federal level, and private party litigation related to greenhouse gas emissions.The U.S. Congress has not yet passed any federal climate change legislation and we cannot predict when or ifCongress will pass such legislation and in what form. In the absence of such legislation, theEPA regulates greenhouse gas emissions pursuant to the Clean Air Act. The regulations implemented byEPA impose stringent leak detection and repair requirements, and further address reporting and control of methane and volatile organic compound emissions. The Company must continue to comply with all applicable regulations. Additionally, other federal regulatory agencies are beginning to address greenhouse gas emissions through changes in their regulatory oversight approach and policies. A number of states have adopted energy strategies or plans with aggressive goals for the reduction of greenhouse gas emissions. InNew York , the NYPSC, for example, initiated a proceeding to consider climate-related financial disclosures at the utility operating company level, and theNew York State legislature passed the CLCPA that mandates reducing greenhouse gas emissions by 40% from 1990 levels by 2030, and by 85% from 1990 levels by 2050, with the remaining emission reduction achieved by controlled offsets. The CLCPA also requires electric generators to meet 70% of demand with renewable energy by 2030 and 100% with zero emissions generation by 2040. These climate change and greenhouse gas initiatives could impact the Company's customer base and assets depending on the promulgation of final regulations and on regulatory treatment afforded in the process. Thus far, the only regulations promulgated in connection with the CLCPA are greenhouse gas emissions limits established by the NYDEC in 6 NYCRR Part 496, effectiveDecember 30, 2020 . The NYDEC has untilJanuary 1, 2024 to issue further rules and regulations implementing the statute.Pennsylvania has a methane reduction framework with the stated goal of reducing methane emissions from well sites, compressor stations and pipelines and is in the process of evaluating cap-and-trade programs (e.g., Regional Greenhouse Gas Initiative). InCalifornia , the Company currently complies withCalifornia cap-and-trade rules, which increases the Company's cost of environmental compliance in its Exploration and Production segment. OnApril 23, 2021 ,California's Governor issued an executive order directingCalifornia Geologic Energy Management Division to stop issuing hydraulic fracturing permits by 2024, which does not have a direct impact on the plans of the Exploration and Production segment as those plans do not involve fracking. The executive order also directed theCalifornia Air Resources Board to investigate phasing out oil extraction by 2045, which may result in permitting delays and new legislative action in support of the directive. Legislation or regulation that aims to reduce greenhouse gas emissions could also include emissions limits, reporting requirements, carbon taxes, restrictive permitting, increased efficiency standards, and incentives or mandates to conserve energy or use renewable energy sources. The above-enumerated initiatives could also increase the Company's cost of environmental compliance by increasing reporting requirements, requiring retrofitting of existing equipment, requiring installation of new equipment, and/or requiring the purchase of emission allowances. They could also delay or otherwise negatively affect efforts to obtain permits and other regulatory approvals. Changing market conditions and new regulatory requirements, as well as unanticipated or inconsistent application of existing laws and regulations by administrative agencies, make it difficult to predict a long-term business impact across twenty or more years. Federal, state or local governments may provide tax advantages and other subsidies to support alternative energy sources, mandate the use of specific fuels or technologies, or promote research into new technologies to reduce the cost and increase the scalability of alternative energy sources.
Safe Harbor for Forward-Looking Statements
The Company is including the following cautionary statement in this Form 10-Q
to make applicable and take advantage of the safe harbor provisions of the
Private Securities Litigation Reform Act of 1995 for any forward-looking
statements made by, or on behalf of, the Company. Forward-looking statements
include statements concerning plans, objectives, goals, projections, strategies,
future events or performance, and underlying assumptions and other statements
which are other than statements of historical facts. From time to time, the
Company may publish or otherwise make available forward-looking statements of
this nature. All such subsequent forward-looking statements, whether written or
oral and whether made by or on behalf of the Company, are also expressly
qualified by these cautionary statements. Certain statements contained in this
report, including, without limitation, 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 authoritative accounting and reporting guidance,
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, are
"forward-looking statements" as defined in the Private Securities Litigation
Reform Act of 1995 and accordingly 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
40--------------------------------------------------------------------------------
Table of Contents
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 and matters discussed elsewhere herein, 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: 1.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; 2.Governmental/regulatory actions, initiatives and proceedings, including those involving rate cases (which address, among other things, target rates of return, rate design, retained natural gas and system modernization), environmental/safety requirements, affiliate relationships, industry structure, and franchise renewal; 3.The Company's ability to estimate accurately the time and resources necessary to meet emissions targets; 4.Governmental/regulatory actions and/or market pressures to reduce or eliminate reliance on natural gas; 5.The length and severity of the ongoing COVID-19 pandemic, including its impacts across our businesses on demand, operations, global supply chains and liquidity; 6.Changes in economic conditions, including inflationary pressures and global, national or regional recessions, and their effect on the demand for, and customers' ability to pay for, the Company's products and services; 7.Changes in the price of natural gas or oil; 8.The creditworthiness or performance of the Company's key suppliers, customers and counterparties; 9.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; 10.Impairments under theSEC's full cost ceiling test for natural gas and oil reserves; 11.Increased costs or delays or changes in plans with respect to Company projects or related projects of other companies, including disruptions due to the COVID-19 pandemic, as well as difficulties or delays in obtaining necessary governmental approvals, permits or orders or in obtaining the cooperation of interconnecting facility operators; 12.The Company's ability to complete planned strategic transactions; 13.The Company's ability to successfully integrate acquired assets and achieve expected cost synergies; 14.Changes in price differentials between similar quantities of natural gas or oil at different geographic locations, and the effect of such changes on commodity production, revenues and demand for pipeline transportation capacity to or from such locations; 15.The impact of information technology disruptions, cybersecurity or data security breaches; 16.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; 17.Increasing health care costs and the resulting effect on health insurance premiums and on the obligation to provide other post-retirement benefits; 18.Other changes in price differentials between similar quantities of natural gas or oil having different quality, heating value, hydrocarbon mix or delivery date; 19.The cost and effects of legal and administrative claims against the Company or activist shareholder campaigns to effect changes at the Company; 20.Uncertainty of oil and gas reserve estimates; 21.Significant differences between the Company's projected and actual production levels for natural gas or oil; 22.Changes in demographic patterns and weather conditions; 41
--------------------------------------------------------------------------------
Table of Contents
23.Changes in the availability, price or accounting treatment of derivative financial instruments; 24.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; 25.Economic disruptions or uninsured losses resulting from major accidents, fires, severe weather, natural disasters, terrorist activities or acts of war; 26.Significant differences between the Company's projected and actual capital expenditures and operating expenses; or 27.Increasing costs of insurance, changes in coverage and the ability to obtain insurance.
The Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date hereof.
© Edgar Online, source
