NATIONAL FUEL GAS CO Management’s Discussion and Analysis of Financial Condition and Results of Operations (form 10-Q)

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 western New
York and Pennsylvania, being utilized for, and benefiting from, the production
and transportation of natural gas from the Appalachian basin. Current
development activities are focused primarily in the Marcellus and Utica 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 eastern United States
and Canada. 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 in California. 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 on Supply Corporation's system,
referred to as the FM100 Project, upgraded a 1950's era pipeline in northwestern
Pennsylvania and created approximately 330,000 Dth per day of additional
transportation capacity in Pennsylvania from a receipt point with NFG Midstream
Clermont, LLC in McKean County, Pennsylvania to the Transcontinental Gas Pipe
Line Company, LLC ("Transco") system at Leidy, Pennsylvania. Construction
activities on the expansion portion of the FM100 Project are complete and the
project was placed in service in December 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 the Leidy
South Project, which is the companion project to the Company's FM100 Project,
went in service in December 2021. The incremental pipeline capacity from this
project and associated gathering system development by Midstream Company allows
Seneca to increase its production and reach premium Transco 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. At December 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 ended December 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 ended December 31,
2021, based on the quoted Henry 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 and Henry Hub prices, which are only
indicative of 12-month average prices for the twelve months ended December 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 at December 31, 2021 if
natural gas prices were $0.25 per MMBtu lower than the average prices used at
December 31, 2021, if crude oil prices were $5 per Bbl lower than the average
prices used at December 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 at
December 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 the SEC'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 ended December 31,
2021 compared to earnings of $77.8 million for the quarter ended December 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 ended December 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 ended December 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 $ 2.52 $ 2.14 $ 0.38


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 $ 64.29 $ 49.91 $ 14.38

2021 Compared with 2020


  Operating revenues for the Exploration and Production segment increased $52.8
million for the quarter ended December 31, 2021 as compared with the quarter
ended December 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 new Marcellus and Utica 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 ended
December 31, 2021 were $62.4 million, an increase of $92.0 million when compared
with a loss of $29.6 million for the quarter ended December 31, 2020. The
increase in earnings was due to a quarter ended December 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 the
West 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 ended December 31, 2021 as compared with the quarter ended December 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 in New York and
Pennsylvania, 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 ended December 31, 2021 were
$22.1 million, a decrease of $0.9 million when compared with earnings of $23.0
million for the quarter ended December 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 in
Distribution Corporation's Pennsylvania service territory in accordance with a
regulatory proceeding that became effective October 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 in New York ($0.8 million).

  The impact of weather variations on earnings in the Utility segment's New York
rate jurisdiction is mitigated by that jurisdiction's weather normalization
clause (WNC). The WNC in New York, which covers the eight-month period from
October through May, has had a stabilizing effect on earnings for the New York
rate jurisdiction. In addition, in periods of colder than normal weather, the
WNC benefits the Utility segment's New York customers. For the quarter ended
December 31, 2021, the WNC increased earnings by approximately $2.6 million, as
the weather was warmer than normal. For the quarter ended December 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
ended December 31, 2021, a decrease of $40.0 million when compared with earnings
of $39.6 million for the quarter ended December 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 by
Seneca's Northeast Division during the quarter ended December 31, 2020. The
decrease can also be attributed to changes in unrealized losses on investments
in equity securities. During the quarter ended December 31, 2021, the Company
recorded unrealized losses of $3.5 million. During the quarter ended December
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 ended December 31, 2021, compared to net other deductions of
$2.2 million for the quarter ended December 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's Pennsylvania service
territory in accordance with a tariff supplement that became effective October
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 ended
December 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 ended
December 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 ended December 31, 2021 as compared to
the quarter ended December 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 in February 2021, which replaced $500.0 million of 4.90%
notes that were retired in March 2021.

                        CAPITAL RESOURCES AND LIQUIDITY

  The Company's primary sources of cash during the three-month period ended
December 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 ended December
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's New York
rate jurisdiction by its WNC and in the Pipeline and Storage segment by the
straight fixed-variable rate design used by Supply 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
at September 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 ended December 31, 2021, a decrease of $33.2 million compared with $204.7
million provided by operating activities for the three months ended December 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's Pennsylvania service territory that went
into effect October 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 in October 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 ended December 31, 2021 and $150.9 million during the three
months ended December 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)At December 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. At September 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)At December 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. At September 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 ended December 31, 2021 were primarily well drilling and completion
expenditures and included approximately $132.1 million for the Appalachian
region (including $45.1 million in the Marcellus Shale area and $83.3 million in
the Utica Shale area) and $7.1 million for the West 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 ended December 31, 2020 were primarily well drilling and completion
expenditures and included approximately $79.9 million for the Appalachian region
(including $30.5 million in the Marcellus Shale area and $43.9 million in the
Utica Shale area) and $1.4 million for the West 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
ended December 31, 2021 were primarily for expenditures related to Supply
Corporation's FM100 Project ($15.7 million), which is discussed below. In
addition, the Pipeline and Storage segment capital expenditures for the three
months ended December 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 ended December 31, 2020 were
primarily for expenditures related to Supply Corporation's FM100 Project ($30.4
million). In addition, the Pipeline and Storage segment capital expenditures for
the three months ended December 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 the Marcellus and
Utica Shale producing areas, Supply Corporation and Empire have completed and
continue to pursue expansion projects designed to move anticipated Marcellus and
Utica production gas to other interstate pipelines and to on-system markets, and
markets beyond the Supply Corporation and Empire pipeline systems.

  Supply Corporation has developed its FM100 Project, which upgraded a 1950's
era pipeline in northwestern Pennsylvania and created approximately 330,000 Dth
per day of additional transportation capacity in Pennsylvania from a receipt
point with NFG Midstream Clermont, LLC in McKean County to the Transcontinental
Gas Pipe Line Company, LLC ("Transco") system at Leidy, Pennsylvania. Supply
Corporation and Transco executed a precedent agreement whereby Transco has
leased this additional capacity ("Lease") as part of a Transco expansion project
("Leidy South"), creating incremental transportation capacity to Transco 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 on December 1, 2021, with
full in-service on December 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 of December 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 at December 31,
2021.

  Supply Corporation and Empire have developed a project which would move
significant prospective Marcellus and Utica production from Seneca's Western
Development Area at Clermont to an Empire interconnection with the TC Energy
pipeline at Chippawa and an interconnection with TGP's 200 Line in East Aurora,
New York (the "Northern Access project"). The Northern Access project would
provide an outlet to Dawn-indexed markets in Canada and to the TGP line serving
the U.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 and
Seneca 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. On February 3, 2017, the Company received FERC 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 the New York portion of the project (the Water Quality
Certification for the Pennsylvania 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, and FERC's decisions were
appealed. The Second Circuit Court of Appeals issued an order upholding the FERC
waiver orders. In addition, in the Company's state court litigation challenging
the NYDEC's actions with regard to various state permits, the New York State
Supreme Court issued a decision finding these permits to be preempted. The
Company remains committed to the project and, on January 28, 2022, filed with
FERC 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 of December 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 at December 31, 2021.

Gathering


  The majority of the Gathering segment capital expenditures for the three
months ended December 31, 2021 included expenditures related to the continued
expansion of Midstream 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 ended December 31, 2021 on the development
of the Clermont and Covington gathering systems. These expenditures were largely
attributable to new Clermont gathering pipelines, as well as the development of
new gathering facilities, including new gathering pipelines and upgrades to
existing stations, in the Tioga gathering system, which is part of Midstream
Covington.

  The majority of the Gathering segment capital expenditures for the three
months ended December 31, 2020 were for the continued expansion of Midstream
Company's Clermont and Wellsboro gathering systems. Midstream Company spent $4.5
million and $3.1 million, respectively, during the three months ended
December 31, 2020 on the development of the Clermont and Wellsboro gathering
systems. These expenditures were largely attributable to the continued
development of centralized station facilities, including increased compression
horsepower at the Clermont and Wellsboro gathering systems and additional
dehydration on the Clermont gathering system.

  NFG Midstream Clermont, LLC, a wholly-owned subsidiary of Midstream Company,
continues to develop an extensive gathering system with compression in the
Pennsylvania counties of McKean, Elk and Cameron. The Clermont gathering system
was initially placed in service in July 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 of Seneca's long-term plans.

  NFG Midstream Covington, LLC, a wholly-owned subsidiary of Midstream Company,
operates its Covington gathering system as well as the Tioga gathering system
acquired from Shell on July 31, 2020, both in Tioga County, Pennsylvania. The
current Covington gathering system consists of two compressor stations and
backbone and in-field gathering pipelines. The Tioga gathering system consists
of 13 compressor stations and backbone and in-field gathering pipelines.

  NFG Midstream Wellsboro, LLC, a wholly-owned subsidiary of Midstream Company,
continues to develop its Wellsboro gathering system in Tioga 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
ended December 31, 2021 and December 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


  On December 10, 2020, the Company completed the sale of substantially all
timber properties in Pennsylvania to Lyme Emporium Highlands III LLC and Lyme
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"). On July 31,
2020, the Company completed its acquisition of certain upstream assets and
midstream gathering assets in Pennsylvania 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.


  In October 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's Pennsylvania service territory to fund a one-time customer bill credit
of $25 million in October 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 on October 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 ended
December 31, 2021 and December 31, 2020, capital expenditures were funded with
cash from operations. The Company issued long-term debt and common stock in June
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 in December 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 at December 31, 2021 to the balance sheet at September 30, 2021. The
maximum amount of short-term debt outstanding during the quarter ended
December 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. At September 30, 2021, the Company
had outstanding commercial paper of $158.5 million, approximately half of which
was related to the aforementioned margin requirements. At December 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 at December 31,
2021. The Company did not have any outstanding short-term notes payable to banks
at December 31, 2021.

  The Company maintains $1.0 billion of unsecured committed revolving credit
access across two facilities. On October 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 through October 25,
2023. In addition to the Credit Agreement, on February 3, 2021, the Company
amended its existing 364-Day Credit Agreement to extend the maturity date
thereof from May 3, 2021 to December 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 after July 1, 2018, not to exceed $250 million. This provision also applies
to the Amended 364-Day Credit Agreement. Since July 1, 2018, the Company
recorded non-cash, after-tax ceiling test impairments totaling $381.4 million.
As a result, at December 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 at December 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 December 31, 2021 and September 30,
2021
had a maturity date within the following twelve-month period.

The Company’s embedded cost of long-term debt was 4.48% and 4.85% at
December 31, 2021 and December 31, 2020, respectively.


  Under the Company's existing indenture covenants at December 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 of December 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 ended December 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


  On July 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. At December 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 the New York and Pennsylvania 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 the New
York or Pennsylvania 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 its New York jurisdiction
were approved by the NYPSC in an order issued on April 20, 2017 with rates
becoming effective May 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 on April 1, 2018.

  On August 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 (until March 31,
2023). The extension is contingent on the Company not filing a base rate case
that would result in new rates becoming effective prior to April 1, 2023.
                                       38

——————————————————————————–

Table of Contents



  In New York, on March 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, on June 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 on March 31, 2021, new legislation was
enacted in May 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 the New York State
COVID-19 state of emergency is lifted or expires or December 31, 2021, whichever
is earlier. On June 24, 2021, the New York State COVID-19 state of emergency
expired. Updated guidance issued by the NYPSC on July 6, 2021 confirmed that
qualified customers are protected from termination through December 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. On December 20, 2021, NYPSC Staff requested, and
the Company agreed, to refrain from terminating residential customers with a
pending application for arrears payments through the Emergency Rental Assistance
Program administered by the Office of Temporary Disability.

Pennsylvania Jurisdiction

Distribution Corporation’s current delivery rates in its Pennsylvania
jurisdiction were approved by the PaPUC on November 30, 2006 as part of a
settlement agreement that became effective January 1, 2007. The rate settlement
does not specify any requirement to file a future rate case.


  On July 22, 2021, Distribution Corporation filed a supplement to its current
Pennsylvania tariff proposing to reduce base rates effective October 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 reduce Distribution Corporation's regulatory
liability associated with OPEB expenses. The PaPUC issued an order approving
this tariff supplement on September 15, 2021 and new rates went into effect on
October 1, 2021. On September 21, 2021, a complaint was filed in this
proceeding. While new rates, including associated refunds, went into effect on
October 1, 2021, certain other adjustments called for by the tariff supplement
that allow Distribution 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, on January 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 its
Pennsylvania 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 before February 1, 2024, except that
Supply 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 effective February 1, 2025.

Empire’s 2019 rate settlement provides that Empire must make a rate case
filing no later than May 1, 2025.

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. In
March 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, in September 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 in the
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 if Congress will pass
such legislation and in what form. In the absence of such legislation, the EPA
regulates greenhouse gas emissions pursuant to the Clean Air Act. The
regulations implemented by EPA 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. In New York, the NYPSC, for example, initiated a proceeding to
consider climate-related financial disclosures at the utility operating company
level, and the New 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, effective
December 30, 2020. The NYDEC has until January 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). In
California, the Company currently complies with California cap-and-trade rules,
which increases the Company's cost of environmental compliance in its
Exploration and Production segment. On April 23, 2021, California's Governor
issued an executive order directing California 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 the
California 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 the SEC'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 Glimpses

Source link