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

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PREVIEW

Please note that this overview is a high-level summary of items that are discussed in more detail in the following 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.

  On May 1, 2022, the Company entered into a purchase and sale agreement to sell
Seneca's California oil and gas assets to Sentinel Peak Resources California LLC
for total consideration between $280 million and $310 million, depending on oil
prices. This consideration consists of $280 million in cash at closing, plus up
to three annual contingent payments between calendar 2023 and 2025 that can
total $30 million in aggregate. The transaction has an effective date of April
1, 2022 and is expected to close on June 30, 2022, subject to customary closing
conditions (including waivers of certain transfer restrictions). The Company
pursued this sale given the strong commodity price environment and the Company's
strategic focus in the Appalachian Basin. Under the full cost method of
accounting for oil and natural gas properties, it is expected that substantially
all of the sale proceeds received at closing will be accounted for as a
reduction of capitalized costs since the disposition will not significantly
alter the relationship between capitalized costs and proved reserves of oil and
gas attributable to the cost center. A portion of the sales proceeds will be
applied to assets that are not subject to the full cost method of accounting.

  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. 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.

  On February 28, 2022, the Company entered into a Credit Agreement (the "Credit
Agreement") with a syndicate of twelve banks. The Credit Agreement replaces the
previous Fourth Amended and Restated Credit Agreement and 364-Day Credit
Agreement. The Credit Agreement provides a $1.0 billion unsecured committed
revolving credit facility with an initial maturity date of February 26, 2027.

  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. The Company may issue long-term debt during fiscal 2022 to
replace all or a portion of its March 2023 debt maturities.

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                         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 March 31, 2022, the ceiling
exceeded the book value of the oil and gas properties by approximately $1.8
billion. The 12-month average of the first day of the month price for crude oil
for each month during the twelve months ended March 31, 2022, based on posted
Midway Sunset prices, was $74.02 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
March 31, 2022, based on the quoted Henry Hub spot price for natural gas, was
$4.09 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
March 31, 2022. 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 March 31, 2022 if
natural gas prices were $0.25 per MMBtu lower than the average prices used at
March 31, 2022, if crude oil prices were $5 per Bbl lower than the average
prices used at March 31, 2022, 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
March 31, 2022 (all amounts are presented after-tax). In all such 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.

Sensitivity of cap tests to changes in commodity prices

                                                                                                         $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                         $          1,485.0          $         1,724.6          $          1,450.5



  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 $167.3 million for the quarter ended March 31,
2022 compared to earnings of $112.4 million for the quarter ended March 31,
2021. The increase in earnings of $54.9 million is primarily the result of
higher earnings in all reportable segments, partially offset by losses in the
Corporate category.

  The Company's earnings were $299.7 million for the six months ended March 31,
2022 compared to earnings of $190.2 million for the six months ended March 31,
2021. The increase in earnings of $109.5 million is primarily the result of
higher earnings in all reportable segments, partially offset by losses in the
Corporate and All Other categories.
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Contents

  The Company's earnings for the quarter and six months ended March 31, 2022
include the reduction of an OPEB regulatory liability that increased earnings by
$18.5 million ($14.6 million after-tax) recorded in the Utility segment in
accordance with a regulatory proceeding in Distribution Corporation's
Pennsylvania service territory. The Company's earnings for the six months ended
March 31, 2021 included a non-cash impairment charge of $76.2 million ($55.2
million after-tax) recorded during the quarter ended December 31, 2020 for the
Exploration and Production segment's oil and gas producing properties. The
Company's earnings for the six months ended March 31, 2021 also included a gain
recognized on the sale of timber properties of $51.1 million ($37.0 million
after-tax) recorded during the quarter ended December 31, 2020 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.

Earnings (Loss) by Segment

                                                       Three Months Ended                       Six Months Ended
                                                           March 31,                                March 31,
                                                                         Increase                                Increase
(Thousands)                                     2022         2021       (Decrease)       2022         2021      (Decrease)
Exploration and Production                  $  71,121    $  36,822    $    34,299    $ 133,490    $   7,199    $  126,291
Pipeline and Storage                           25,470       24,928            542       50,637       49,112         1,525
Gathering                                      22,092       20,700          1,392       45,229       41,250         3,979
Utility                                        53,048       32,044         21,004       75,178       55,081        20,097
Total Reportable Segments                     171,731      114,494         57,237      304,534      152,642       151,892
All Other                                           -         (983)           983           (7)      36,577       (36,584)
Corporate                                      (4,403)      (1,075)        (3,328)      (4,807)         991        (5,798)
Total Consolidated                          $ 167,328    $ 112,436    $    54,892    $ 299,720    $ 190,210    $  109,510


exploration and production

Operating revenue from exploration and production

                                Three Months Ended                     Six Months Ended
                                     March 31,                             March 31,
                                                 Increase                              Increase
(Thousands)               2022        2021      (Decrease)      2022        2021      (Decrease)
Gas (after Hedging)    $ 218,486   $ 186,530   $    31,956   $ 424,287   $ 349,038   $    75,249
Oil (after Hedging)       36,817      32,067         4,750      72,040      60,191        11,849
Gas Processing Plant         985         772           213       2,013       1,324           689
Other                      5,305         818         4,487       7,451       1,029         6,422
                       $ 261,593   $ 220,187   $    41,406   $ 505,791   $ 411,582   $    94,209



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Production Volumes

                                                                     Three Months Ended                                     Six Months Ended
                                                                          March 31,                                             March 31,
                                                                                           Increase                                               Increase
                                                           2022             2021          (Decrease)           2022              2021            (Decrease)
Gas Production (MMcf)
Appalachia                                                 83,565           81,446           2,119             164,954           157,115            7,839
West Coast                                                    397              428             (31)                805               869              (64)
Total Production                                           83,962           81,874           2,088             165,759           157,984            7,775

Oil Production (Mbbl)
Appalachia                                                      1                1               -                   1                 1                -
West Coast                                                    522              561             (39)              1,070             1,124              (54)
Total Production                                              523              562             (39)              1,071             1,125              (54)



Average Prices

                                                    Three Months Ended                      Six Months Ended
                                                        March 31,                               March 31,
                                                                     Increase                               Increase
                                             2022        2021       (Decrease)      2022        2021       (Decrease)
Average Gas Price/Mcf
Appalachia                                $   3.97    $   2.28    $      1.69    $   4.18    $   2.23    $      1.95
West Coast                                $  10.04    $   7.14    $      2.90    $   9.91    $   6.07    $      3.84
Weighted Average                          $   4.00    $   2.31    $      1.69    $   4.21    $   2.25    $      1.96
Weighted Average After Hedging            $   2.60    $   2.28    $      

0.32 $2.56 $2.21 $0.35

Average Oil Price/Bbl
Appalachia                                $  78.32    $  48.47    $     29.85    $  75.38    $  43.83    $     31.55
West Coast                                $  94.95    $  59.83    $     35.12    $  85.93    $  51.64    $     34.29
Weighted Average                          $  94.93    $  59.82    $     35.11    $  85.93    $  51.63    $     34.30
Weighted Average After Hedging            $  70.45    $  57.11    $     

13.34 $67.30 $53.50 $13.80

2022 vs. 2021

  Operating revenues for the Exploration and Production segment increased $41.4
million for the quarter ended March 31, 2022 as compared with the quarter ended
March 31, 2021. Gas production revenue after hedging increased $32.0 million due
to the impact of a 2.1 Bcf increase in natural gas production, together with a
$0.32 per Mcf increase in the weighted average price of natural gas after
hedging. Natural gas production increased largely due to additional production
from new Marcellus and Utica wells in the Appalachian region. Oil production
revenue after hedging increased $4.8 million due to an increase in the weighted
average price of oil after hedging of $13.34 per Bbl, partially offset by the
impact of a 39 Mbbl decrease in oil production. The decrease in oil production
was largely due to natural production declines. In addition, other revenue
increased $4.5 million and gas processing plant revenue increased $0.2 million.
The increase in other revenue is primarily attributed to a temporary capacity
release through March 2022 for a small portion of this segment's Leidy South
transportation contract combined with operating revenue from Highland Field
Services water treatment plants acquired at the end of fiscal 2021.

  Operating revenues for the Exploration and Production segment increased $94.2
million for the six months ended March 31, 2022 as compared with the six months
ended March 31, 2021. Gas production revenue after hedging increased $75.2
million due to the impact of a 7.8 Bcf increase in natural gas production
combined with a $0.35 per Mcf increase in the weighted average price of natural
gas after hedging. The increase in natural gas production was largely due to
additional production from new Marcellus and Utica wells in the Appalachian
region during the six months ended March 31, 2022 as
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compared with the six months ended March 31, 2021. Oil production revenue after
hedging increased $11.8 million due to a $13.80 per Bbl increase in the weighted
average price of oil after hedging, offset by the impact of a 54 Mbbl decrease
in oil production. The decrease in oil production was largely due to natural
production declines. In addition, other revenue increased $6.4 million and gas
processing plant revenue increased $0.7 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 from Highland Field Services water treatment plants acquired at the end
of fiscal 2021.

  The Exploration and Production segment's earnings for the quarter ended
March 31, 2022 were $71.1 million, an increase of $34.3 million when compared
with earnings of $36.8 million for the quarter ended March 31, 2021. The
increase in earnings was due to higher natural gas production ($3.8 million),
higher natural gas prices after hedging ($21.5 million), higher oil prices after
hedging ($5.5 million), higher other revenue ($3.5 million) and lower interest
expense ($2.6 million). The Exploration and Production segment also recognized a
loss in March 2021 ($10.7 million) for its share of the premium paid by the
Company to redeem $500 million of the Company's 4.90% notes that were scheduled
to mature in December 2021. The positive earnings impact of these items was
partially offset by lower oil production ($1.8 million), higher lease operating
and transportation expenses ($4.4 million), higher depletion expense ($3.5
million), higher other operating expenses ($1.7 million), higher other taxes
($1.9 million) and higher income tax expense ($0.3 million). The decrease in
interest expense can largely be attributed to a lower average amount of
intercompany long-term borrowings outstanding combined with a lower average
interest rate on such borrowings. The increase in lease operating and
transportation expenses was primarily the result of increased well workover
costs and higher steam fuel costs in the West Coast region. The increase in
depletion expense was primarily due to the net increase in production combined
with a $0.04 per Mcf increase in the depletion rate. The increase in other
operating expenses was partially attributed to an increase in operating costs
associated with the Highland Field Services water treatment plants acquired at
the end of fiscal 2021, as well as higher consulting services and
technology-related expenses. The increase in other taxes was mainly attributed
to increased Impact Fees in the Appalachian region as a result of an increase in
natural gas prices. The Impact Fees are calculated annually based on calendar
year NYMEX natural gas prices.

  The Exploration and Production segment's earnings for the six months ended
March 31, 2022 were $133.5 million, an increase of $126.3 million when compared
with earnings of $7.2 million for the six months ended March 31, 2021. The
increase in earnings was primarily attributable to an impairment of oil and gas
properties ($55.2 million) recorded during the six months ended March 31, 2021,
higher natural gas production ($13.6 million), higher natural gas prices after
hedging ($45.9 million), higher oil prices after hedging ($11.7 million), higher
other revenue ($5.1 million), higher gas processing plant revenue ($0.5
million), lower interest expense ($5.2 million) and lower income tax expense
($0.6 million). The Exploration and Production segment also recognized a loss in
March 2021 ($10.7 million) for its share of the premium paid by the Company to
redeem $500 million of the Company's 4.90% notes that were scheduled to mature
in December 2021. These increases in earnings were partially offset by lower oil
production ($2.3 million), higher lease operating and transportation expenses
($7.2 million), higher depletion expense ($6.8 million), higher other operating
expenses ($3.0 million) and higher other taxes ($2.9 million). The decrease in
interest expense can largely be attributed to a lower average amount of
intercompany long-term borrowings outstanding combined with a lower average
interest rate on such borrowings. The increase in lease operating and
transportation expenses was primarily the result of increased well workover
costs and higher steam fuel costs in the West Coast region combined with
gathering and transportation costs in the Appalachian region due to increased
production. The increase in depletion expense was primarily due to the net
increase in production combined with a $0.03 per Mcf increase in the depletion
rate. The increase in other operating expenses was partially attributed to an
increase in operating costs associated with the Highland Field Services water
treatment plants acquired at the end of fiscal 2021, as well as higher
consulting services, personnel costs and technology-related expenses. The
increase in other taxes was mainly attributed to increased Impact Fees in the
Appalachian region, as discussed above.

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Pipeline and Storage

Pipeline and storage operating revenues

                                                        Three Months Ended                       Six Months Ended
                                                            March 31,                                March 31,
                                                                         Increase                                 Increase
(Thousands)                                      2022        2021       (Decrease)       2022         2021       (Decrease)
Firm Transportation                           $ 72,259    $ 64,405    $     7,854    $ 138,084    $ 129,004    $     9,080
Interruptible Transportation                       412         243            169          856          469            387
                                                72,671      64,648          8,023      138,940      129,473          9,467
Firm Storage Service                            21,451      21,220            231       42,251       41,705            546
Interruptible Storage Service                        -          11            (11)           -           43            (43)
Other                                            1,275         825            450        2,556        3,248           (692)
                                              $ 95,397    $ 86,704    $     8,693    $ 183,747    $ 174,469    $     9,278


Pipeline and storage throughput

                                                               Three Months Ended                                      Six Months Ended
                                                                    March 31,                                              March 31,
                                                                                      Increase                                               Increase
(MMcf)                                              2022              2021           (Decrease)           2022              2021            (Decrease)
Firm Transportation                                 232,030           209,496          22,534             425,623           412,524           13,099
Interruptible Transportation                            752               435             317               1,520             1,024              496
                                                    232,782           209,931          22,851             427,143           413,548           13,595



2022 Compared with 2021

  Operating revenues for the Pipeline and Storage segment increased $8.7 million
for the quarter ended March 31, 2022 as compared with the quarter ended
March 31, 2021. The increase in operating revenues was primarily due to an
increase in transportation revenues of $8.0 million and an increase in other
revenue of $0.5 million. The increase in transportation revenues was primarily
attributable to new demand charges for transportation service from the expansion
portion of 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. The increase in other revenue
primarily reflects higher cashout revenues partially offset by lower electric
surcharge true-up revenues. Cashout revenues are completely offset by purchased
gas expense. Revenues collected through the electric surcharge mechanism are
completely offset by electric power costs recorded in operation and maintenance
expense.

  Operating revenues for the Pipeline and Storage segment increased $9.3 million
for the six months ended March 31, 2022 as compared with the six months ended
March 31, 2021. The increase in operating revenues was primarily due to an
increase in transportation revenues of $9.5 million and an increase in storage
revenues of $0.5 million, partially offset by a decrease in other revenues of
$0.7 million. The increase in transportation revenues was primarily attributable
to new demand charges for transportation service from Supply Corporation's FM100
Project being placed into service as mentioned above, 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 cashout revenues.

  Transportation volume for the quarter ended March 31, 2022 increased by 22.9
Bcf from the prior year's quarter, primarily due to an increase in volume from
the FM100 Project, which was brought online in December 2021, combined with an
increase in volume from colder weather and an increase in capacity utilization
by certain contract shippers. For the six months ended March 31, 2022,
transportation volume increased by 13.6 Bcf from the prior year's six-month
period ended March 31, 2021. The increase in transportation volume for the
six-month period primarily reflects an increase in volume from the FM100
Project. Volume fluctuations, other than those caused by the addition or
termination of contracts, generally do not
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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 March 31,
2022 were $25.5 million, an increase of $0.6 million when compared with earnings
of $24.9 million for the quarter ended March 31, 2021. The increase in earnings
was primarily due to the earnings impact of higher operating revenues of $6.9
million, as discussed above. These earnings increases were partially offset by
an increase in operating expenses ($3.7 million) and an increase in depreciation
expense ($1.2 million). The increase in operating expenses was primarily due to
a decrease in the reserve for preliminary project costs recorded in the quarter
ended March 31, 2021 that did not recur this fiscal year, as well as higher
pipeline integrity costs and vehicle fuel costs. This was partially offset by
lower power costs related to Empire's electric motor drive compressor station.
The Pipeline and Storage segment also experienced higher purchased gas costs
($0.6 million), largely related to Empire's natural gas driven compressor
stations. The electric power costs and purchased gas costs are offset by an
equal amount of revenue, as discussed above. The increase in depreciation
expense was primarily due to incremental depreciation from Supply's FM100
Project going into service in December 2021.

  The Pipeline and Storage segment's earnings for the six months ended March 31,
2022 were $50.6 million, an increase of $1.5 million when compared with earnings
of $49.1 million for the six months ended March 31, 2021. The increase in
earnings was primarily due to the earnings impact of higher operating revenues
of $7.3 million, as discussed above, combined with an increase in other income
($0.9 million). The increase in other income was mainly due to higher
non-service pension and post-retirement benefit income and 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 ($4.5 million) and an increase in
depreciation expense ($1.5 million). The increase in operating expenses was
primarily due to a decrease in the reserve for preliminary project costs
recorded in the six months ended March 31, 2021 that did not recur this fiscal
year, as well as an increase in vehicle fuel costs and utilities expenses. The
Pipeline and Storage segment also experienced higher purchased gas costs ($1.0
million), largely related to Empire's natural gas driven compressor stations.
Purchased gas costs are offset by an equal amount of revenue, as discussed
above. The increase in depreciation expense was primarily due to incremental
depreciation from Supply's FM100 Project going into service in December 2021.

Gathering

Gathering Operating Revenues
                             Three Months Ended                    Six Months Ended
                                  March 31,                            March 31,
                                             Increase                             Increase
(Thousands)             2022       2021     (Decrease)      2022        2021     (Decrease)
Gathering Revenues   $ 52,604   $ 50,262   $     2,342   $ 104,829   $ 97,270   $     7,559



Gathering Volume

                                                         Three Months Ended                                     Six Months Ended
                                                             March 31,                                              March 31,
                                                                               Increase                                               Increase
                                              2022              2021          (Decrease)           2022              2021            (Decrease)
Gathered Volume - (MMcf)                      103,736           95,121           8,615             204,829           183,466           21,363



2022 vs. 2021

  Operating revenues for the Gathering segment increased $2.3 million for the
quarter ended March 31, 2022 as compared with the quarter ended March 31, 2021,
which was driven primarily by an 8.6 Bcf increase in gathered volume. The
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.

  Operating revenues for the Gathering segment increased $7.6 million for the
six months ended March 31, 2022 as compared with the six months ended March 31,
2021, which was driven primarily by a 21.4 Bcf increase in gathered volume.
Contributors to the increase included the Trout Run, Clermont and Wellsboro
gathering systems, which recorded increases of 13.7 Bcf, 7.3 Bcf and 4.8 Bcf,
respectively, partially offset by the Covington gathering system, which recorded
a decrease of 4.4 Bcf. The net increase in gathered volume can be attributed
primarily to an increase in non-affiliated natural gas production
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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 March 31, 2022 were
$22.1 million, an increase of $1.4 million when compared with earnings of $20.7
million for the quarter ended March 31, 2021. The increase in earnings was
mainly due to higher gathering revenues ($1.8 million) driven by the increase in
gathered volume, as discussed above. Additionally, the Gathering segment's
earnings were positively impacted as a result of the Gathering segment's
recognition of a loss during the quarter end March 31, 2021 ($0.7 million) for
its share of the premium paid by the Company to redeem $500 million of the
Company's 4.90% notes that were scheduled to mature in December 2021. These
earnings increases were partially offset by higher operating expenses ($0.6
million) and higher income tax expense ($0.5 million). The increase in operating
expenses was largely attributable to higher outside services costs associated
with preventative maintenance overhauls on the Trout Run and Clermont gathering
systems.

  The Gathering segment's earnings for the six months ended March 31, 2022 were
$45.2 million, an increase of $3.9 million when compared with earnings of $41.3
million for the six months ended March 31, 2021.  The increase in earnings was
mainly due to higher gathering revenues ($6.0 million) driven by the increase in
gathered volume, as discussed above. Additionally, the Gathering segment's
earnings were positively impacted as a result of the Gathering segment's
recognition of a loss during the quarter end March 31, 2021 ($0.7 million) for
its share of the premium paid by the Company to redeem $500 million of the
Company's 4.90% notes that were scheduled to mature in December 2021. Earnings
also decreased due to higher operating expenses ($1.3 million), higher
depreciation expense ($0.6 million) and higher income tax expense ($0.7
million). The increase in operating expenses was largely attributable to higher
outside services costs associated with preventative maintenance overhauls on the
Trout Run and Clermont gathering systems. The increase in depreciation expense
was largely due to higher plant balances associated with the Clermont gathering
system.

Utility

Utility Operating Revenues

                                  Three Months Ended                     Six Months Ended
                                       March 31,                             March 31,
                                                   Increase                              Increase
(Thousands)                 2022        2021      (Decrease)      2022        2021      (Decrease)
Retail Sales Revenues:
Residential              $ 286,329   $ 204,398   $    81,931   $ 469,037   $ 345,241   $  123,796
Commercial                  41,668      28,196        13,472      66,910      46,404       20,506
Industrial                   2,193       1,370           823       3,350       2,301        1,049
                           330,190     233,964        96,226     539,297     393,946      145,351
Transportation              43,159      41,436         1,723      72,810      72,066          744

Other                       (4,147)     (4,519)          372      (6,147)     (6,131)         (16)
                         $ 369,202   $ 270,881   $    98,321   $ 605,960   $ 459,881   $  146,079



Utility Throughput

                                                         Three Months Ended                                    Six Months Ended
                                                              March 31,                                            March 31,
                                                                               Increase                                             Increase
(MMcf)                                         2022             2021          (Decrease)           2022             2021           (Decrease)
Retail Sales:
Residential                                    32,026           29,052           2,974             49,521           47,465            2,056
Commercial                                      4,923            4,309             614              7,466            6,836              630
Industrial                                        268              223              45                392              376               16
                                               37,217           33,584           3,633             57,379           54,677            2,702
Transportation                                 25,745           24,584           1,161             43,338           42,518              820

                                               62,962           58,168           4,794            100,717           97,195            3,522



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Degree Days

                                                                                                 Percent Colder (Warmer) Than
Three Months Ended March 31,                    Normal            2022             2021           Normal(1)       Prior Year(1)
Buffalo, NY                                        3,290            3,161            2,978               (3.9) %           6.1  %
Erie, PA                                           3,108            2,973            2,750               (4.3) %           8.1  %
Six Months Ended March 31,
Buffalo, NY                                        5,543            4,865            4,899              (12.2) %          (0.7) %
Erie, PA                                           5,152            4,533            4,447              (12.0) %           1.9  %


(1)Percentages compare actual 2022 degree-days to normal degree-days and actual 2022 degree-days to actual 2021 degree-days.

2022 vs. 2021

  Operating revenues for the Utility segment increased $98.3 million for the
quarter ended March 31, 2022 as compared with the quarter ended March 31, 2021.
The increase resulted from a $96.2 million increase in retail gas sales revenue,
which was primarily due to a significant increase in the cost of gas sold (per
Mcf) coupled with higher throughput due to colder weather. Under its purchased
gas adjustment clauses in New York and Pennsylvania, Distribution Corporation is
not allowed to profit from fluctuations in gas costs. In addition, there was a
$1.7 million increase in transportation revenues and a $0.4 million increase in
other revenues. The increase in transportation revenues was largely the result
of a 1.2 Bcf increase in transportation throughput due to colder weather. The
increase in other revenues was mainly the result of higher late payment charges
billed to customers and higher capacity release revenues, partially offset by a
larger estimated refund provision for the income tax benefits resulting from the
2017 Tax Reform Act.

  Operating revenues for the Utility segment increased $146.1 million for the
six months ended March 31, 2022 as compared with the six months ended March 31,
2021. The increase largely resulted from a $145.4 million increase in retail gas
sales revenue and a $0.7 million increase in transportation revenues. The
increase in retail gas sales revenue was primarily due to a significant increase
in the cost of gas sold (per Mcf). The increase in transportation revenues was
largely due to 0.8 Bcf increase in transportation throughput during the six
months ended March 31, 2022.

  The Utility segment's earnings for the quarter ended March 31, 2022 were $53.0
million, an increase of $21.0 million when compared with earnings of $32.0
million for the quarter ended March 31, 2021. In February 2022, the PaPUC
concluded a regulatory proceeding that addressed Distribution Corporation's
recovery of other post-employment benefit ("OPEB") expenses. As a result of that
proceeding, Distribution Corporation recorded an adjustment to an OPEB-related
regulatory liability that increased earnings ($14.6 million) and agreed to
reduce its base rates in Pennsylvania to eliminate the recovery of OPEB expenses
effective October 1, 2021, which reduced earnings for the quarter ($3.1
million). Additional details related to the regulatory proceeding are discussed
in the Rate Matters section and in Item 1 at Note 11 - Regulatory Matters. With
the elimination of OPEB expenses in customer rates, earnings benefited from a
decrease in non-service post-retirement benefit costs ($5.2 million) as
Distribution Corporation's Pennsylvania service territory recognized OPEB income
during the quarter ended March 31, 2022 compared to the prior year period when
it recognized OPEB expenses to match against the OPEB amounts collected in base
rates.

  Higher usage and the impact of weather on customer margins ($3.0 million), as
well as the impact of a system modernization tracker in New York ($1.6 million),
also contributed to the increase in earnings when comparing the quarter ended
March 31, 2022 to the quarter ended March 31, 2021. These increases were
partially offset by higher income tax expense ($1.2 million), which was
primarily attributable to state income taxes.

  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
March 31, 2022, the WNC increased earnings by approximately $1.5 million, as the
weather was warmer than normal. For the quarter ended March 31, 2021, the WNC
increased earnings by approximately $1.6 million, as the weather was warmer than
normal.

  The Utility segment's earnings for the six months ended March 31, 2022 were
$75.2 million, an increase of $20.1 million when compared with earnings of $55.1
million for the six months ended March 31, 2021. The increase is primarily
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attributable to conclusion of the regulatory proceeding in Pennsylvania, as
discussed above, which resulted in a reduction in a regulatory liability that
increased earnings ($14.6 million). The regulatory proceeding also reduced base
rates in Pennsylvania, which reduced earnings for the six-month period ($4.8
million). With the elimination of OPEB expenses in customer rates, earnings
benefited from a decrease in non-service post-retirement benefit costs ($6.9
million) as Distribution Corporation's Pennsylvania service territory recognized
OPEB income during the six months ended March 31, 2022 compared to the prior
year period when it recognized OPEB expenses to match against the OPEB amounts
collected in base rates.

  Higher usage and the impact of weather on customer margins ($3.0 million), the
impact of a system modernization tracker in New York ($2.4 million), and lower
income tax expense ($0.9 million) also contributed to the increase in earnings
when comparing the six months ended March 31, 2022 to the six months ended March
31, 2021. These increases were partially offset by higher operating expenses
($1.9 million), which were primarily the result of higher personnel costs
partially offset by a decrease in the allowance for uncollectible accounts, and
the impact of regulatory true-up adjustments ($0.8 million). The decrease in the
allowance for uncollectible accounts is related to the COVID-19 pandemic as the
Company recorded incremental expense due to the potential for customer
non-payment, given the economic environment, during 2021.

  For the six months ended March 31, 2022, the WNC increased earnings by
approximately $4.1 million, as the weather was warmer than normal. For the six
months ended March 31, 2021, the WNC increased earnings by approximately $3.2
million, as the weather was warmer than normal.

Businesses and others

2022 vs. 2021

  Corporate and All Other operations had a loss of $4.4 million for the quarter
ended March 31, 2022, which was $2.3 million higher than the loss of $2.1
million for the quarter ended March 31, 2021. The increase in loss for the
quarter is primarily attributable to changes in unrealized gains and losses on
investments in equity securities. During the quarter ended March 31, 2021, the
Company recorded unrealized gains of $0.7 million. During the quarter ended
March 31, 2022, the Company recorded unrealized losses of $1.7 million.

  For the six months ended March 31, 2022, Corporate and All Other operations
had a loss of $4.8 million, a decrease of $42.4 million when compared with
earnings of $37.6 million for the six months ended March 31, 2021. 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 six months ended March 31, 2021. The
decrease can also be attributed to changes in unrealized losses on investments
in equity securities. During the six months ended March 31, 2021, the Company
recorded unrealized losses of $0.4 million. During the six months ended March
31, 2022, the Company recorded unrealized losses of $5.3 million.

Other income (deductions)

  Net other income on the Consolidated Statement of Income was $10.0 million for
the quarter ended March 31, 2022, compared to net other deductions of $10.9
million for the quarter ended March 31, 2021. This change is primarily
attributable to non-service pension and post-retirement benefit income of $12.5
million for the quarter ended March 31, 2022 compared to non-service pension and
post-retirement benefit costs of $13.4 million for the quarter ended March 31,
2021. As discussed above in the Utility, this is largely related to the February
2022 conclusion of the regulatory proceeding in Distribution Corporation's
Pennsylvania service territory that addressed Distribution Corporation's
recovery of OPEB expenses. This was partially offset by changes in unrealized
gains and losses on investments in equity securities. During the quarter ended
March 31, 2022, the Company recorded pre-tax unrealized losses of $2.8 million.
During the quarter ended March 31, 2021, the Company recorded pre-tax unrealized
gains of $0.6 million. Other income (deductions) was also impacted by the change
in cash surrender value of life insurance policies, with the change in value for
the quarter ended March 31, 2022 decreasing $1.2 million from the change in
value for the quarter ended March 31, 2021.

  Net other income on the Consolidated Statement of Income was $8.9 million for
the six months ended March 31, 2022, compared to net other deductions of $13.1
million for the six months ended March 31, 2021. This change is primarily
attributable to non-service pension and post-retirement benefit income of $7.7
million for the six months ended March 31, 2022 compared to non-service pension
and post-retirement benefit costs of $21.2 million for the six months ended
March 31, 2021. This is largely related to the February 2022 conclusion of a
regulatory proceeding, as discussed in the previous paragraph. This was
partially offset by changes in realized and unrealized gains and losses on
investments in equity securities. During the six months ended March 31, 2022,
the Company recorded pre-tax realized gains of $4.4 million and pre-tax
unrealized losses of
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$8.0 million. During the six months ended March 31, 2021, the Company recorded
pre-tax realized gains of $3.3 million and pre-tax unrealized losses of $0.5
million. Other income (deductions) was also impacted by the change in cash
surrender value of life insurance policies, with the change in value for the six
months ended March 31, 2022 decreasing $0.8 million from the change in value for
the six months ended March 31, 2021.

Interest expense on long-term debt

  Interest expense on long-term debt on the Consolidated Statement of Income
decreased $18.7 million for the quarter ended March 31, 2022 as compared to the
quarter ended March 31, 2021. For the six months ended March 31, 2022, interest
expense on long-term debt decreased $20.9 million as compared with the six
months ended March 31, 2021. The Company redeemed $500.0 million of 4.90% notes
in March 2021 and paid an early redemption premium of $15.7 million that was
recorded as interest expense on long-term debt. The remaining decrease is due
largely 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 six-month period ended
March 31, 2022 consisted of cash provided by operating activities, net proceeds
from short-term borrowings, proceeds from the sale of a fixed income mutual fund
in a grantor trust and net proceeds from the sale of oil and gas properties. The
Company's primary sources of cash during the six-month period ended March 31,
2021 consisted of cash provided by operating activities, net proceeds from the
sale of timber properties and net proceeds from the issuance of long-term debt.

  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 when compared to the same period in 2021 and
will be used to meet the Company's capital expenditures, with any remaining cash
being used to meet the Company's dividend requirements and/or reduce short-term
borrowings. 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, the reduction of an other post-retirement regulatory
liability 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
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.

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  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 $425.6 million for the six
months ended March 31, 2022, an increase of $8.5 million compared with $417.1
million provided by operating activities for the six months ended March 31,
2021. The increase in cash provided by operating activities primarily reflects
higher cash provided by operating activities in the Exploration and Production
segment, slightly offset by lower cash provided by operating activities in the
Utility segment. The increase in the Exploration and Production segment was
primarily due to higher cash receipts from natural gas production. 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, timing of gas receivables 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 $29
million in previously overcollected OPEB expenses. Please refer to the Rate
Matters section that follows for additional discussion of this matter.

Investing cash flow

Expenses for long-lived assets

  The Company's expenditures for long-lived assets totaled $376.2 million during
the six months ended March 31, 2022 and $322.4 million during the six months
ended March 31, 2021.  The table below presents these expenditures:

Total Expenditures for Long-Lived Assets
Six Months Ended March 31,                                                                         Increase
(Millions)                                             2022                   2021                (Decrease)
Exploration and Production:
Capital Expenditures                               $   274.0    (1)       $   169.6    (2)      $      104.4
Pipeline and Storage:
Capital Expenditures                                    38.5    (1)            91.7    (2)             (53.2)
Gathering:
Capital Expenditures                                    20.0    (1)            19.4    (2)               0.6
Utility:
Capital Expenditures                                    43.3    (1)            41.8    (2)               1.5
All Other:
Capital Expenditures                                     0.4                    0.1                      0.3
Eliminations                                               -                   (0.2)                     0.2
                                                   $   376.2              $   322.4             $       53.8



(1)At March 31, 2022, capital expenditures for the Exploration and Production
segment, the Pipeline and Storage segment, the Gathering segment and the Utility
segment include $52.5 million, $3.5 million, $3.4 million and $4.1 million,
respectively, of non-cash capital expenditures. At September 30, 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 March 31, 2021, capital expenditures for the Exploration and Production
segment, the Pipeline and Storage segment, the Gathering segment and the Utility
segment included $44.5 million, $16.0 million, $2.9 million and $4.7 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 six months
ended March 31, 2022 were primarily well drilling and completion expenditures
and included approximately $258.8 million for the Appalachian region (including
$84.8 million in the Marcellus Shale area and $166.8 million in the Utica Shale
area) and $15.2 million for the West Coast region. These amounts included
approximately $93.4 million spent to develop proved undeveloped reserves. The
Exploration and Production segment's capital expenditures for fiscal 2022 are
expected to be in the range of $475 million to $550 million.

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  The Exploration and Production segment capital expenditures for the six months
ended March 31, 2021 were primarily well drilling and completion expenditures
and included approximately $167.1 million for the Appalachian region (including
$58.2 million in the Marcellus Shale area and $97.7 million in the Utica Shale
area) and $2.5 million for the West Coast region. These amounts included
approximately $62.2 million spent to develop proved undeveloped reserves.

Pipeline and storage

  The Pipeline and Storage segment capital expenditures for the six months ended
March 31, 2022 were primarily for expenditures related to Supply Corporation's
FM100 Project ($21.0 million), which is discussed below. In addition, the
Pipeline and Storage segment capital expenditures for the six months ended
March 31, 2022 included additions, improvements and replacements to this
segment's transmission and gas storage systems. The Pipeline and Storage segment
capital expenditures for the six months ended March 31, 2021 were primarily for
expenditures related to Supply Corporation's FM100 Project ($60.8 million). In
addition, the Pipeline and Storage segment capital expenditures for the six
months ended March 31, 2021 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
(Non-New York) 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. As of March 31, 2022, approximately
$207.1 million has been spent on the FM100 project, all of which is included in
Property, Plant and Equipment on the Consolidated Balance Sheet at March 31,
2022.

  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). 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
March 31, 2022, approximately $55.8 million has been spent on the Northern
Access project, including $24.2 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 March 31,
2022.

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Gathering

  The majority of the Gathering segment capital expenditures for the six months
ended March 31, 2022 included expenditures related to the continued expansion of
Midstream Company's Clermont and Covington gathering systems, as discussed
below. Midstream Company spent $8.7 million and $10.6 million, respectively,
during the six months ended March 31, 2022 on the development of the Clermont
and Covington gathering systems. These expenditures were largely attributable to
the installation of new in-field gathering pipelines in the Clermont gathering
system, as well as the development of new gathering facilities, including new
in-field gathering pipelines and station upgrades, in the Tioga gathering
system, which is part of Midstream Covington.

  The majority of the Gathering segment capital expenditures for the six months
ended March 31, 2021 were for the continued expansion of Midstream Company's
Clermont and Wellsboro gathering systems. Midstream Company spent $11.6 million
and $3.7 million, respectively, during the six months ended March 31, 2021 on
the development of the Clermont and Wellsboro gathering systems. These
expenditures were largely attributable to new Clermont gathering pipelines, as
well as 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 six months
ended March 31, 2022 and March 31, 2021 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.
The Utility segment's capital expenditures for fiscal 2022 are expected to be in
the range of $100 million to $110 million.

Other investment 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 - 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 $30 million of fixed income mutual fund
shares held in a grantor trust that was established for the benefit of
Pennsylvania ratepayers. 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 $29 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.

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  In March 2022, the Company completed the sale of certain oil and gas assets
located in Tioga County, Pennsylvania effective as of October 1, 2021. The
Company received net proceeds of $13.5 million from this sale. Under the full
cost method of accounting for oil and natural gas properties, the sale proceeds
were accounted for as a reduction of capitalized costs. Since the disposition
did not significantly alter the relationship between capitalized costs and
proved reserves of oil and gas attributable to the cost center, the Company did
not record any gain or loss from this sale.

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 six months ended
March 31, 2022 and March 31, 2021, 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. It will also depend on
natural gas and crude oil production, and the associated commodity price
realizations, as well as the level of hedging collateral deposits 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

  Consolidated short-term debt increased $59.5 million when comparing the
balance sheet at March 31, 2022 to the balance sheet at September 30, 2021. The
maximum amount of short-term debt outstanding during the six months ended
March 31, 2022 was $304.7 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, 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. For example, elevated commodity prices
relative to its existing portfolio of derivative financial instruments led to
the Company posting margin of $102.4 million with a number of its derivative
counterparties as of March 31, 2022. The Company's margin deposits are reflected
on the balance sheet as a current asset titled Hedging Collateral Deposits. To
meet these margin requirements and other near-term cash flow needs, the Company
utilized short-term debt in the form of commercial paper and borrowings under
its revolving credit facility. As of March 31, 2022, the Company had outstanding
commercial paper of $68.0 million and short-term notes payable to banks of 150.0
million.

  On February 28, 2022, the Company entered into a Credit Agreement (the "Credit
Agreement") with a syndicate of 12 banks. The Credit Agreement replaces the
previous Fourth Amended and Restated Credit Agreement and 364-Day Credit
Agreement. The Credit Agreement provides a $1.0 billion unsecured committed
revolving credit facility with an initial maturity date of February 26, 2027.
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.

  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 $400 million. Since July 1, 2018, the
Company recorded non-cash, after-tax ceiling test impairments totaling $381.4
million. As a result, at March 31,
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2022, $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 .58. The constraints specified in the Credit
Agreement would have permitted an additional $966.7 million in short-term and/or
long-term debt to be outstanding at March 31, 2022 before the Company's debt to
capitalization ratio exceeded .65.

  On May 3, 2022, the Company entered into Amendment No. 1 to the Credit
Agreement with the same 12 banks under the initial Credit Agreement. The
amendment modifies the definition of consolidated capitalization, for purposes
of calculating the debt to capitalization ratio under the Credit Agreement, to
exclude, beginning with the quarter ending June 30, 2022, all unrealized gains
or losses on commodity-related derivative financial instruments and up to $10
million in unrealized gains or losses on other derivative financial instruments
included in Accumulated Other Comprehensive Income (Loss) within Total
Comprehensive Shareholders' Equity on the Company's balance sheet. Under the
Credit Agreement as amended, such unrealized losses will not negatively affect
the calculation of the debt to capitalization ratio, and such unrealized gains
will not positively affect the calculation.

   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 contains 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. 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.

  On February 24, 2021, the Company issued $500.0 million of 2.95% notes due
March 1, 2031. After deducting underwriting discounts, commissions and other
debt issuance costs, the net proceeds to the Company amounted to $495.3 million.
The holders of the notes may require the Company to repurchase their notes at a
price equal to 101% of the principal amount in the event of both a change in
control and a ratings downgrade to a rating below investment grade.
Additionally, the interest rate payable on the notes will be subject to
adjustment from time to time, with a maximum adjustment of 2.00%, such that the
coupon will not exceed 4.95%, if certain change of control events involving a
material subsidiary result in a downgrade of the credit rating assigned to the
notes to a rating below investment grade. A downgrade with a resulting increase
to the coupon does not preclude the coupon from returning to its original rate
if the Company's credit rating is subsequently upgraded. The proceeds of this
debt issuance were used for general corporate purposes, including the redemption
of $500.0 million of the Company's 4.90% notes on March 11, 2021 that were
scheduled to mature in December 2021. The Company redeemed those notes for
$515.7 million, plus accrued interest.

  The Current Portion of Long-Term Debt at March 31, 2022 consists of $500.0
million of 3.75% notes and $49.0 million of 7.395% notes that mature in March
2023. None of the Company's long-term debt as of September 30, 2021 had a
maturity date within the following twelve-month period.

The intrinsic cost of the Company’s long-term debt was 4.48% at both March 31, 2022
and March 31, 2021.

  Under the Company's existing indenture covenants at March 31, 2022, the
Company would have been permitted to issue up to a maximum of approximately
$1.75 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, 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.

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Contents

  The Company's 1974 indenture pursuant to which $99.0 million (or 3.7%) of the
Company's long-term debt (as of March 31, 2022) 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 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 six months ended March 31, 2022, the Company contributed $15.0
million to its tax-qualified, noncontributory defined-benefit retirement plan
(Retirement Plan) and $1.6 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 $5.0 million to $10.0
million. In the remainder of 2022, the Company expects its contributions to its
VEBA trusts to be in the range of $1.0 million to $1.5 million.

  The Company, in its Exploration and Production segment, entered into
contractual obligations during the quarter ended March 31, 2022 to spend $43.1
million for hydraulic fracturing services and piping and casing work for fiscal
2022.

Instruments sensitive to market risk

  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 March 31, 2022, 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.

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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.

Jurisdiction of New York

  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%, and 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.

  In response to the COVID-19 pandemic, various legislative actions and NYPSC
Staff requests resulted in the Company suspending service terminations and
disconnections for a period of time. All legislative prohibitions have expired
and the Company has agreed to refrain from terminating residential customers (1)
with a pending application for arrears payments through the Emergency Rental
Assistance Program administered by the Office of Temporary Disability and (2)
participating in the Company's Statewide Low Income Program (EAP) through
September 1, 2022.

Pennsylvania jurisdiction

distribution company current delivery rates in its Pennsylvania
jurisdiction were approved by PaPUC on November 30, 2006 under a settlement agreement that became effective January 1, 2007. The tariff regulations do not specify any obligation to file a future tariff 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, to begin to refund to customers overcollected OPEB
expenses in the amount of $50.0 million, to suspend all regulatory accounting
for OPEB expenses and record the cumulative amount of OPEB income previously
deferred as a regulatory liability, 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 the proceeding. While new rates,
including associated refunds, went into effect on October 1, 2021, the Company
decided to wait for resolution of the complaint before suspending regulatory
accounting for OPEB expenses and recording the cumulative amount of OPEB income
previously deferred as a regulatory liability in its consolidated financial
statements. 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. Under the terms of the settlement, customer
refunds of overcollected OPEB expenses increased from $50.0 million to $54.0
million. The Recommended Decision was approved by the PaPUC on February 24,
2022. Accordingly, the Company suspended regulatory accounting for OPEB expenses
at that time and recorded an $18.5 million adjustment during the quarter ended
March 31, 2022 to reduce its regulatory liability for previously deferred OPEB
income amounts through September 30, 2021 and to increase Other Income
(Deductions) on the consolidated financial statements by a like amount. 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
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Table of Contents The federal corporate income tax rate is increased. If no file has been submitted,
supply company must file for rates to be effective February 1, 2025.

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

Environmental issues

  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.

For more details on the Company’s environmental exposures, refer to section 1 of 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. NYDEC finalized its Part 203 Oil and
Gas Sector Rule in March 2022, which establishes monitoring, operational, and
reporting requirements with respect to methane and volatile organic compound
emissions and significantly increases leak detection and repair (LDAR)
inspections, repair and replacement obligations, recordkeeping, reporting, and
notification requirements for multiple sources along natural gas metering and
regulating stations, transmission pipelines, compressor stations, storage
facilities, and gathering lines. 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
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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.

Effects of inflation

  The Company's operations are sensitive to increases in the rate of inflation
because of its operational and capital spending requirements in both its
regulated and non-regulated businesses. For the regulated businesses, recovery
of increasing costs from customers can be delayed by the regulatory process of a
rate case filing. For the non-regulated businesses, prices received for services
performed or products produced are determined by market factors that are not
necessarily correlated to the underlying costs required to provide the service
or product.

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 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 accurately estimate the time and resources needed to achieve emissions targets;

4. Government/regulatory actions and/or market pressures to reduce or eliminate reliance on natural gas;

5.The duration and severity of the ongoing COVID-19 pandemic, including its impacts on our business on demand, operations, global supply chains and liquidity;

6. Changing economic conditions, including inflationary pressures and global, national or regional recessions, and their effect on customer demand and 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 main 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. Deficiencies under the DRY testing the total cost cap for natural gas and oil reserves;

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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 ability of the Company to complete the planned strategic transactions;

13. The Company’s ability to successfully integrate the acquired assets and achieve the expected cost synergies;

14.Changes in price differentials between similar quantities of natural gas or
oil sold at different geographic locations, and the effect of such changes on
commodity production, revenues and demand for pipeline transportation capacity
to or from such locations;

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. Rising health care costs and the resulting effect on health insurance premiums and the obligation to provide other benefits after retirement;

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 change within the Company;

20. Negotiations with collective bargaining units representing the Company’s workforce, including potential work stoppages during negotiations;

21. Uncertainty of oil and gas reserve estimates;

22. Significant variances between the Company’s projected and actual production levels for natural gas or oil;

23. Changes in demographic patterns and weather conditions;

24. Changes in the availability, price or accounting treatment of derivative financial instruments;

25.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;

26. Economic disruption or uninsured loss resulting from major accidents, fires, extreme weather conditions, natural disasters, terrorist activities or acts of war;

27. Material differences between the Company’s projected and actual capital expenditures and operating expenditures; or

28. Increase in Insurance Costs, Changes in Coverage and Ability to Obtain Insurance.

The Company disclaims any obligation to update forward-looking statements to reflect events or circumstances after the date hereof.

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