OVERVIEW

The Company is a diversified energy company engaged principally in the
production, gathering, transportation, storage 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 reports financial results for four business
segments: Exploration and Production, Pipeline and Storage, Gathering, and
Utility.

Corporate responsibility

The Board of Directors and management recognize that the long-term interests of
stockholders are served by considering the interests of customers, employees and
the communities in which the Company operates. The Board retains risk oversight
and general oversight of corporate responsibility, including environmental,
social and governance ("ESG") concerns, and any related health and safety issues
that might arise from the Company's operations. The Board's Nominating/Corporate
Governance Committee oversees and provides guidance concerning the Company's
practices and reporting with respect to corporate responsibility and ESG factors
that are of significance to the Company and its stakeholders, and may also make
recommendations to the Board regarding ESG initiatives and strategies, including
the Company's progress on integrating ESG factors into business strategy and
decision-making.

Part of the Board and management's strategic and capital spending decision
process includes identifying and assessing climate-related risks and
opportunities. Management reports quarterly to the Board on critical and
potentially emerging risks, including climate-related risks, as part of the
Enterprise Risk Management process. Since the Company operates an integrated
business with assets being utilized for, and benefiting from, the production,
transportation and consumption of natural gas, the Board and management consider
physical and transitional climate risks, including policy and legal risks,
technological developments, shifts in market conditions, including future
natural gas usage, and reputational risks, and the impact of those risks on the
Company's business. In March 2022, the Company published its inaugural Climate
Report, analyzing climate-related transitional and physical risks, and
describing our strategy for addressing those risks, as well as the resiliency of
that strategy under a carbon constrained scenario. The Company reviews and
considers adjustments to its approach to capital investment in response to these
transitional developments, with its long-term, returns-focused approach.

The Company recognizes the important role of ongoing system modernization and
efficiency in reducing greenhouse gas emissions and remains focused on reducing
the Company's carbon footprint, with these efforts positioning natural gas, and
the Company's related infrastructure, to remain an important part of the energy
complex. In 2021, the Company set methane intensity reduction targets at each of
its businesses, an absolute greenhouse gas emissions reduction target for the
consolidated Company, and greenhouse gas reduction targets associated with the
Company's utility delivery system. In 2022, the Company began measuring progress
against these reduction targets. The Company also incorporated short-term and
long-term executive compensation goals designed to incentivize and reward
performance if reduction targets are met or exceeded. The Company's ability to
estimate accurately the time, costs and resources necessary to meet these
emissions reduction targets may change as environmental exposures and
opportunities change, technology advances, and legislative and regulatory
updates are issued.
                                      -32-
--------------------------------------------------------------------------------

Fiscal 2022 Highlights

This Section 7, MD&A, provides information regarding:

1. The Company’s critical accounting estimates;

2. Changes in the revenues and profits of the Company under the heading “Results of Operations”;

3. Operating, investing and financing cash flows under “Capital resources and liquidity” and;

4.Other Matters, including: (a) 2022 and projected 2023 funding for the
Company's pension and other post-retirement benefits; (b) disclosures and tables
concerning market risk sensitive instruments; (c) rate matters in the Company's
New York, Pennsylvania and FERC-regulated jurisdictions; (d) environmental
matters; and (e) effects of inflation.

The information in MD&A should be read in conjunction with the Company's
financial statements in Item 8 of this report, which includes a comparison of
our Results of Operations and Capital Resources and Liquidity for fiscal 2022
and fiscal 2021. For a discussion of the Company's earnings, refer to the
Results of Operations section below. A discussion of changes in the Company's
results of operations from fiscal 2020 to fiscal 2021 has been omitted from this
Form 10-K, but may be found in Item 7, MD&A, of the Company's Form 10-K for the
fiscal year ended September 30, 2021, filed with the SEC on November 19, 2021.

On June 30, 2022, the Company completed the sale of Seneca's California assets
to Sentinel Peak Resources California LLC for a total sale price of $253.5
million, consisting of $240.9 million in cash and contingent consideration
valued at $12.6 million at closing. The Company pursued this sale given the
strong commodity price environment and the Company's strategic focus in the
Appalachian Basin. Under the terms of the purchase and sale agreement, the
Company can receive up to three annual contingent payments between calendar year
2023 and calendar year 2025, not to exceed $10 million per year, with the amount
of each annual payment calculated as $1.0 million for each $1 per barrel that
the ICE Brent Average for each calendar year exceeds $95 per barrel up to $105
per barrel. The sale price, which reflected an effective date of April 1, 2022,
was reduced for production revenues less expenses that were retained by Seneca
from the effective date to the closing date. Under the full cost method of
accounting for oil and natural gas properties, $220.7 million of the sale price
at closing was accounted for as a reduction of capitalized costs since the
disposition did not alter the relationship between capitalized costs and proved
reserves of oil and gas attributable to the cost center. The remainder of the
sale price ($32.8 million) was applied against assets that are not subject to
the full cost method of accounting, with the Company recognizing a gain of $12.7
million on the sale of such assets. The majority of this gain related to the
sale of emission allowances.

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
into service in December 2021. This project will 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.

The Company's Exploration and Production segment continues to grow, as evidenced
by an 8% growth in proved reserves from the prior year to a total of 4,172 Bcfe
at September 30, 2022. Production increased 25.1 Bcfe during the fiscal year
ended September 30, 2022 to a total of 352.5 Bcfe, and is expected to increase
again in fiscal 2023. The December 2021 commencement of service for Seneca's
330,000 Dth per day of incremental pipeline capacity on the Leidy South Project,
which was the companion project of the Company's FM100 Project, contributed to
the production growth in fiscal 2022. This incremental pipeline capacity
provides Seneca with the ability to reach premium Transco Zone 6 (Non-New York)
markets.

                                      -33-
--------------------------------------------------------------------------------

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

On June 30, 2022, the Company entered into a new 364-Day Credit Agreement (the
"364-Day Credit Agreement") with a syndicate of five banks, all of which are
also lenders under the Credit Agreement. The 364-Day Credit Agreement provides
an additional $250.0 million unsecured committed delayed draw term loan credit
facility with a maturity date of June 29, 2023. The Company elected to draw
$250.0 million under the facility on October 27, 2022. The Company is using the
proceeds for general corporate purposes, which will include the redemption in
November of a portion of the Company's outstanding long-term debt maturing in
March 2023. The Company does not anticipate long-term refinancing for the $250.0
million drawn under the facility or the maturing long-term debt in March 2023.

                         CRITICAL ACCOUNTING ESTIMATES

The Company has prepared its consolidated financial statements in conformity
with GAAP. The preparation of these financial statements requires management to
make estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at the date of
the financial statements and the reported amounts of revenues and expenses
during the reporting period. Actual results could differ from those estimates.
In the event estimates or assumptions prove to be different from actual results,
adjustments are made in subsequent periods to reflect more current information.
The following is a summary of the Company's most critical accounting estimates,
which are defined as those estimates whereby judgments or uncertainties could
affect the application of accounting policies and materially different amounts
could be reported under different conditions or using different assumptions. For
a complete discussion of the Company's significant accounting policies, refer to
Item 8 at Note A - Summary of Significant Accounting Policies.

Oil and Gas Exploration and Development Costs. In the Company's Exploration and
Production segment, gas and oil property acquisition, exploration and
development costs are capitalized under the full cost method of accounting, with
natural gas properties in the Appalachian region being the primary component of
these capitalized costs after the June 30, 2022 sale of the Company's California
oil and natural gas properties. That sale is discussed in more detail in Item 8
at Note B - Asset Acquisitions and Divestitures. Under this accounting
methodology, all costs associated with property acquisition, exploration and
development activities are capitalized, including internal costs directly
identified with acquisition, exploration and development activities. The
internal costs that are capitalized do not include any costs related to
production, general corporate overhead, or similar activities. The Company does
not recognize any gain or loss on the sale or other disposition of oil and gas
properties unless the gain or loss would significantly alter the relationship
between capitalized costs and proved reserves of oil and gas attributable to a
cost center.

Proved reserves are estimated quantities of reserves that, based on geologic and
engineering data, appear with reasonable certainty to be producible under
existing economic and operating conditions. Such estimates of proved reserves
are inherently imprecise and may be subject to substantial revisions as a result
of numerous factors including, but not limited to, additional development
activity, evolving production history and continual reassessment of the
viability of production under varying economic conditions. The estimates
involved in determining proved reserves are critical accounting estimates
because they serve as the basis over which capitalized costs are depleted under
the full cost method of accounting (on a units-of-production basis). Unproved
properties are excluded from the depletion calculation until proved reserves are
found or it is determined that the unproved properties are impaired. All costs
related to unproved properties are reviewed quarterly to determine if impairment
has occurred. The amount of any impairment is transferred to the pool of
capitalized costs being amortized.

In addition to depletion under the units-of-production method, proved reserves
are a major component in the SEC full cost ceiling test. The full cost ceiling
test is an impairment test prescribed by SEC Regulation S-X Rule 4-10. The
ceiling test, which is performed each quarter, determines a limit, or ceiling,
on the amount of property acquisition, exploration and development costs that
can be capitalized. The ceiling under this test
                                      -34-
--------------------------------------------------------------------------------

represents (a) the present value of estimated future net cash flows, excluding
future cash outflows associated with settling asset retirement obligations that
have been accrued on the balance sheet, using a discount factor of 10%, which is
computed by applying 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 (as adjusted for hedging) to estimated future
production of proved oil and gas reserves as of the date of the latest balance
sheet, less estimated future expenditures, plus (b) the cost of unproved
properties not being depleted, less (c) income tax effects related to the
differences between the book and tax basis of the properties. The estimates of
future production and future expenditures are based on internal budgets that
reflect planned production from current wells and expenditures necessary to
sustain such future production. The amount of the ceiling can fluctuate
significantly from period to period because of additions to or subtractions from
proved reserves and significant fluctuations in natural gas prices. The ceiling
is then compared to the capitalized cost of oil and gas properties less
accumulated depletion and related deferred income taxes. If the capitalized
costs of oil and gas properties less accumulated depletion and related deferred
taxes exceeds the ceiling at the end of any fiscal quarter, a non-cash
impairment charge must be recorded to write down the book value of the reserves
to their present value. This non-cash impairment cannot be reversed at a later
date if the ceiling increases. It should also be noted that a non-cash
impairment to write down the book value of the reserves to their present value
in any given period causes a reduction in future depletion expense. At September
30, 2022, the ceiling exceeded the book value of the oil and gas properties by
approximately $3.2 billion. The 12-month average of the first day of the month
price for natural gas for each month during 2022, based on the quoted Henry Hub
spot price for natural gas, was $6.13 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 Henry Hub
price, which is only indicative of 12-month average prices for 2022. Actual
realized pricing includes adjustments for regional market differentials,
transportation fees and contractual arrangements.)  In regard to the sensitivity
of the ceiling test calculation to commodity price changes, if natural gas
prices were $0.25 per MMBtu lower than the average prices used at September 30,
2022 in the ceiling test calculation, the ceiling would have exceeded the book
value of the Company's oil and gas properties by approximately $2.9 billion
(after-tax), which would not have resulted in an impairment charge. This
calculated amount is based solely on price changes and does not take into
account any other changes to the ceiling test calculation, including, among
others, changes in reserve quantities and future cost estimates.

It is difficult to predict what factors could lead to future impairments under
the SEC's full cost ceiling test. As discussed above, fluctuations in or
subtractions from proved reserves, increases in development costs for
undeveloped reserves and significant fluctuations in natural gas prices have an
impact on the amount of the ceiling at any point in time.

As discussed above, the full cost method of accounting provides a ceiling to the
amount of costs that can be capitalized in the full cost pool. In accordance
with current authoritative guidance, the future cash outflows associated with
plugging and abandoning wells are excluded from the computation of the present
value of estimated future net revenues for purposes of the full cost ceiling
calculation.

Regulation. The Company is subject to regulation by certain state and federal
authorities. The Company, in its Utility and Pipeline and Storage segments, has
accounting policies which conform to the FASB authoritative guidance regarding
accounting for certain types of regulations, and which are in accordance with
the accounting requirements and ratemaking practices of the regulatory
authorities. The application of these accounting principles for certain types of
rate-regulated activities provide that certain actual or anticipated costs that
would otherwise be charged to expense can be deferred as regulatory assets,
based on the expected recovery from customers in future rates. Likewise, certain
actual or anticipated credits that would otherwise reduce expense can be
deferred as regulatory liabilities, based on the expected flowback to customers
in future rates. Management's assessment of the probability of recovery or pass
through of regulatory assets and liabilities requires judgment and
interpretation of laws and regulatory commission orders. If, for any reason, the
Company ceases to meet the criteria for application of regulatory accounting
treatment for all or part of its operations, the regulatory assets and
liabilities related to those portions ceasing to meet such criteria would be
eliminated from the balance sheet and included in the income statement for the
period in which the discontinuance of regulatory
                                      -35-
--------------------------------------------------------------------------------

accounting treatment takes place. These amounts would be classified as an extraordinary item. For more details on the Company’s regulatory assets and liabilities, refer to section 8 of note F – Regulatory matters.

                             RESULTS OF OPERATIONS

EARNINGS

2022 Compared with 2021

The Company's earnings were $566.0 million in 2022 compared with earnings of
$363.6 million in 2021. The increase in earnings of $202.4 million was primarily
a result of higher earnings in all reportable segments, slightly offset by
losses in the Corporate and All Other categories. In the discussion that
follows, all amounts used in the earnings discussions are after-tax amounts,
unless otherwise noted. Earnings were impacted by the following events in 2022
and 2021:

2022 Events

• The reversal of a provision for deferred tax loss of $24.9 million recorded in the Exploration and Production and Gathering segments.

•A $28.4 million remeasurement of accumulated deferred income taxes, primarily
in the Exploration and Production and Gathering segments, related to a reduction
in the Pennsylvania state corporate income tax rate that was signed into law in
July 2022.

•A gain recognized on the sale of Seneca's California assets of $12.7 million
($9.5 million after-tax) recorded during 2022 in the Exploration and Production
segment related to a portion of the sale price that was applied to assets that
were not subject to the full cost method of accounting.

•A loss of $44.6 million ($33.3 million after-tax) recorded during 2022 in the
Exploration and Production segment related to the termination of this segment's
remaining crude oil derivative contracts as a result of the sale of Seneca's
California assets.

• Transaction and dismissal costs of $9.7 million ($7.2 million net of tax) incurred during 2022 in the Exploration and Production segment related to the disposal of by Seneca California assets.

•The reduction of an OPEB regulatory liability that increased earnings by $18.5
million ($14.6 million after-tax) recorded during 2022 in the Utility segment in
accordance with a regulatory proceeding in Distribution Corporation's
Pennsylvania service territory.

Events 2021

•Non-cash impairment charges of $76.2 million ($55.2 million after-tax) recorded
during 2021 for the Exploration and Production segment's oil and gas producing
properties.

•A gain recognized on the sale of forest properties of $51.1 million ($37.0 million after tax) recognized in 2021 in the All other Company category.

•A loss of $15.7 million ($11.4. million after-tax) recorded in the Exploration
and Production and Gathering segments during 2021 for the premium paid on early
redemption of long-term debt.
                                      -36-
--------------------------------------------------------------------------------
Earnings (Loss) by Segment

                                      Year Ended September 30
                                2022           2021            2020
                                            (Thousands)
Exploration and Production   $ 306,064      $ 101,916      $ (326,904)
Pipeline and Storage           102,557         92,542          78,860
Gathering                      101,111         80,274          68,631
Utility                         68,948         54,335          57,366
Total Reported Segments        578,680        329,067        (122,047)
All Other                           (9)        37,645            (269)
Corporate                      (12,650)        (3,065)         (1,456)
Total Consolidated           $ 566,021      $ 363,647      $ (123,772)


EXPLORATION AND PRODUCTION

Revenues

Operating revenue from exploration and production

                             Year Ended September 30
                               2022             2021
                                   (Thousands)
Gas (after Hedging)      $      930,130      $ 705,326
Oil (after Hedging)(1)          113,588        126,369
Gas Processing Plant              3,511          2,960
Other                           (36,765)         2,042
Operating Revenues       $    1,010,464      $ 836,697


Production

                              Year Ended September 30
                            2022                     2021
Gas Production (MMcf)
Appalachia               341,700                   312,300
West Coast                 1,211                     1,720
Total Production         342,911                   314,020
Oil Production (Mbbl)
Appalachia                    16                         2
West Coast                 1,588                     2,233
Total Production           1,604                     2,235


                                      -37-
--------------------------------------------------------------------------------
Average Prices
                                             Year Ended September 30
                                                2022                2021
Average Gas Price/Mcf
Appalachia                             $       5.03               $  2.46
West Coast                             $      10.03               $  6.34
Weighted Average                       $       5.05               $  2.49
Weighted Average After Hedging(2)      $       2.71               $  2.25
Average Oil Price/Barrel (Bbl)
Appalachia                             $      97.82               $ 48.02
West Coast                             $      94.06               $ 60.50
Weighted Average                       $      94.10               $ 60.49
Weighted Average After Hedging(1)(2)   $      70.80               $ 56.54




(1)Oil revenue and weighted average oil price after hedging for the year ended
September 30, 2022 excludes a loss on discontinuance of crude oil cash flow
hedges of $44.6 million. This loss is presented in other revenue in the table
above.
(2)Refer to further discussion of hedging activities below under "Market Risk
Sensitive Instruments" and in Note J - Financial Instruments in Item 8 of this
report.

2022 Compared with 2021

Operating revenues for the Exploration and Production segment increased $173.8
million in 2022 as compared with 2021. Gas production revenue after hedging
increased $224.8 million primarily due to a $0.46 per Mcf increase in the
weighted average price of gas after hedging coupled with a 28.9 Bcf increase in
gas production. The increase in gas production was largely due to new Marcellus
and Utica wells in the Appalachian region. Oil production revenue after hedging
decreased $12.8 million primarily due to a 631 Mbbl decrease in crude oil
production, partially offset by a $14.26 per Bbl increase in the weighted
average price of oil after hedging. The decrease in oil production is mainly
attributed to the sale of California assets at June 30, 2022. In addition, other
revenue decreased $38.8 million and plant revenue increased $0.6 million. The
decrease in other revenue was primarily attributed to a loss on the
discontinuance of crude oil cash flow hedges related to the sale of California
assets combined with royalty shut-in payments made in accordance with lease
agreements. These were partially offset by a temporary capacity release of Leidy
South and TC Pipeline transportation contracts. Finally, other revenue also
increased from Highland Field Services water treatment plants acquired at the
end of fiscal 2021.

Refer to further discussion of derivative financial instruments in the "Market
Risk Sensitive Instruments" section that follows. Refer to the tables above for
production and price information.

Earnings

2022 vs. 2021

The Exploration and Production segment's earnings for 2022 were $306.1 million,
an increase of $204.2 million when compared with earnings of $101.9 million for
2021. The increase in earnings was primarily attributable to higher natural gas
prices after hedging ($126.3 million), higher natural gas production ($51.3
million), and higher oil prices after hedging ($18.1 million). Additionally, a
$55.2 million impairment was recorded during 2021 that did not recur during
2022. Certain deferred tax adjustments during 2022 also contributed to the
earnings increase. The Exploration and Production segment reversed a valuation
allowance ($28.6 million) on deferred tax assets related to certain state net
operating loss and credit carryforwards as these deferred tax assets are now
expected to be realized in the future. The Exploration and Production segment
also recorded an income tax benefit ($16.2 million) from the remeasurement of
deferred income taxes related to a state corporate income tax rate reduction in
Pennsylvania that was signed into law in July 2022. The law
                                      -38-
--------------------------------------------------------------------------------

reduces the Pennsylvania corporate income tax rate to 8.99% for fiscal 2024, and
starting with fiscal 2025, the rate is further reduced by 0.5% annually until it
reaches 4.99% for fiscal 2032.

In addition to the factors discussed above, the Exploration and Production
segment's earnings were also impacted by the following factors. Factors that
increased earnings included a 2022 gain ($9.5 million) that was recognized on
the sale of the Exploration and Production segment's California non-full cost
pool assets as well as a 2021 loss ($10.7 million) recognized for this segment's
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. Factors that reduced
earnings included a loss related to the discontinuance of this segment's crude
oil cash flow hedges ($33.3 million), which was driven by the sale of the
California assets, lower crude oil production ($28.2 million), higher lease
operating and transportation expenses ($13.1 million), higher depletion expense
($20.3 million), higher other operating expenses ($5.4 million), an unrealized
loss on a derivative asset ($3.2 million), higher other taxes ($2.5 million) and
a higher effective tax rate ($6.3 million). The Company also recorded
transaction and severance costs ($7.2 million) during 2022 associated with the
sale of the California assets. The increase in lease operating and
transportation expenses was primarily due to increased gathering and
transportation costs in the Appalachian region offset by lower costs in the West
Coast region due to selling the assets on June 30, 2022. The increase in
depletion expense was primarily due to the increase in production, combined with
a $0.03 per Mcfe increase in the depletion rate. The increase in other operating
expenses was primarily attributed to abandonment costs related to certain
offshore Gulf of Mexico wells formally owned by the Company. In addition, the
increase in other operating expenses was attributed to operating costs
associated with the Highland Field Services water treatment plants acquired at
the end of fiscal 2021. The unrealized loss on a derivative asset represents an
adjustment to the contingent consideration received for the sale of the
California assets. 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 increase in the effective tax rate was
primarily driven by a reduction to the valuation allowance recorded in fiscal
2021.

PIPELINE AND STORAGE

Revenues

Pipeline and storage operating revenues

                                      Year Ended September 30
                                        2022               2021
                                            (Thousands)
Firm Transportation             $     287,486           $ 254,853
Interruptible Transportation            2,481                 996
                                      289,967             255,849
Firm Storage Service                   84,565              83,032
Interruptible Storage Service               -                  48
                                       84,565              83,080
Other                                   2,512               4,628
                                $     377,044           $ 343,557

Pipeline and Storage Throughput – (MMcf)

                                     Year Ended September 30
                                   2022                     2021
Firm Transportation             790,417                   770,284
Interruptible Transportation      5,612                     1,460
                                796,029                   771,744


                                      -39-
--------------------------------------------------------------------------------

2022 vs. 2021

Operating revenues for the Pipeline and Storage segment increased $33.5 million
in 2022 as compared with 2021. The increase in operating revenues was primarily
due to an increase in transportation revenues of $34.1 million and an increase
in storage revenues of $1.5 million, partially offset by a decrease in other
revenue of $2.1 million. The increase in transportation revenues was primarily
attributable to new demand charges for transportation service from Supply
Corporation's FM100 Project, which was placed into service in December 2021. The
increase from the FM100 Project includes the impact of a negotiated revenue
step-up to Period 2 Rates that went into effect April 1, 2022, as specified in
Supply Corporation's 2020 rate case settlement. This increase was partially
offset by a decline in revenues associated with miscellaneous contract
terminations and revisions. The increase in storage revenues was partially due
to the Period 2 Rates that went into effect April 1, 2022 related to the FM100
Project, as discussed above. In addition, the Pipeline Safety and Greenhouse Gas
Regulatory Costs (PS/GHG Regulatory Costs) surcharge that went into effect in
November 2020 associated with Supply Corporation's 2020 rate case settlement
also contributed to the increase in both transportation and 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, combined with lower electric surcharge true-up revenues,
partially offset by higher cashout revenues. Revenues collected through the
electric surcharge mechanism are completely offset by electric power costs
recorded in operation and maintenance expense. Cashout revenues are completely
offset by purchased gas expense.

Transportation volume increased by 24.3 Bcf in 2022 as compared with 2021,
primarily due to incremental volume from the FM100 Project, which was brought
online in December 2021, as well as an increase in short-term contracts. These
were partially offset by lower capacity utilization with certain contract
shippers. Volume fluctuations, other than those caused by the addition or
termination of contracts, generally do not have a significant impact on revenues
as a result of the straight fixed-variable rate design utilized by Supply
Corporation and Empire.

The majority of Supply Corporation's and Empire's transportation and storage
contracts allow either party to terminate the contract upon six or twelve
months' notice effective at the end of the primary term and include "evergreen"
language that allows for annual term extension(s). The amount of firm
transportation capacity contracted on the Pipeline and Storage segment's
facilities is expected to decrease in fiscal 2023, primarily due to the
termination of two long-term contracts with a nonaffiliated party totaling 300
MDth per day. Lower contracted quantities at the time of a future rate
proceeding would be taken into account and would be the basis for setting new
rates. The timing of Supply Corporation's next rate filing is discussed below
under Rate Matters.

Earnings

2022 Compared with 2021

The profits of the Pipeline and Storage segment in 2022 were $102.6 millionan augmentation of $10.1 million compared to the gains of $92.5 million in 2021.

 The increase in earnings was primarily due to the impact of higher operating
revenues of $26.5 million, as discussed above, which was partially offset by an
increase in depreciation expense ($4.2 million), higher property taxes ($0.8
million), an increase in operating expenses ($7.6 million) and higher income tax
expense ($2.3 million). The increase in depreciation expense was primarily due
to incremental depreciation from the FM100 Project going into service in
December 2021. The increase in property taxes was primarily due to the
first-time assessment of property taxes for the Empire North project's
Farmington compressor station. The increase in operating expenses was primarily
due to a decrease in the reserve for preliminary project costs recorded during
fiscal 2021 that did not recur in fiscal 2022, as well as an increase in
personnel and technology-related costs and higher 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 ($0.7 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
income tax expense was mainly due to a reduction in benefits associated with the
tax sharing agreement with affiliated companies combined with higher state
income tax expense due to higher pre-tax earnings for fiscal 2022.
                                      -40-
--------------------------------------------------------------------------------
GATHERING

Revenues

Gathering Operating Revenues
                  Year Ended September 30
                    2022               2021
                        (Thousands)
Gathering   $     214,843           $ 193,264


Gathering Volume - (MMcf)

                        Year Ended September 30
                      2022                     2021
Gathered Volume    419,332                   366,033


2022 Compared with 2021

Operating revenues for the Gathering segment increased $21.6 million in 2022 as
compared with 2021, which was driven primarily by a 53.3 Bcf increase in
gathered volume. The increase in gathered volume can be attributed primarily to
an increase in natural gas production on the Covington, Wellsboro, Clermont and
Trout Run gathering systems, which recorded increases of 17.9 Bcf, 11.7 Bcf,
10.1 Bcf and 13.6 Bcf, respectively. The increase in gathered volume can be
attributed to the increase in gross natural gas production in the Appalachian
region by producers connected to the aforementioned gathering systems.

Earnings

2022 vs. 2021

The Gathering segment's earnings in 2022 were $101.1 million, an increase of
$20.8 million when compared with earnings of $80.3 million in 2021. The increase
in earnings was primarily attributable to higher gathering revenues ($17.0
million) driven by the increase in gathered volume (discussed above).
Additionally, the Gathering segment recorded an income tax benefit ($11.9
million) from the remeasurement of deferred income taxes related to a state
corporate income tax rate reduction in Pennsylvania that was signed into law in
July 2022 (as discussed above, in the Exploration and Production segment).
Earnings also increased 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. However, the Gathering segment's
earnings were negatively impacted by the recording of deferred income tax
expense ($3.7 million) as an offset to the reversal of the valuation allowance
recorded by the Exploration and Production segment during the quarter ended
September 30, 2022. This offset is a result of the Gathering and Exploration and
Production segments' subsidiaries filing a combined state tax return. Earnings
also decreased due to higher operating expenses ($3.2 million), higher
depreciation expense ($1.3 million) and higher income tax expense ($0.6
million). The increase in operating expenses was largely due to higher costs for
labor, major overhaul maintenance of compressor units at Trout Run gathering
system compressor stations during fiscal 2022 and higher costs for material used
to operate the compressor stations at the Trout Run, Covington and Clermont
gathering systems. The increase in depreciation expense was largely due to
higher plant balances associated with the Clermont and Covington gathering
systems. The increase in income tax expense was primarily driven by a higher
effective state income tax rate.
                                      -41-
--------------------------------------------------------------------------------
UTILITY

Revenues

Utility Operating Revenues
                         Year Ended September 30
                           2022               2021
                               (Thousands)
Retail Revenues:
Residential        $     691,034           $ 497,244
Commercial                95,120              63,954
Industrial                 4,913               3,089
                         791,067             564,287

Transportation           111,072             108,213
Other                     (3,918)             (5,249)
                   $     898,221           $ 667,251

Utility throughput – million cubic feet (MMcf)

                       Year Ended September 30
                     2022                     2021
Retail Sales:
Residential        64,011                    61,038
Commercial          9,621                     8,741
Industrial            541                       475
                   74,173                    70,254

Transportation     65,993                    66,012
                  140,166                   136,266


Degree Days

                                                                             Percent (Warmer)
                                                                               Colder Than
Year Ended September 30                     Normal      Actual        
Normal(1)         Prior Year(1)
2022                        Buffalo, NY     6,617       5,769               (12.8) %             0.7  %
                               Erie, PA     6,147       5,368               (12.7) %             2.8  %
2021                        Buffalo, NY     6,617       5,731               (13.4) %            (6.1) %
                               Erie, PA     6,147       5,221               (15.1) %            (4.2) %




(1)The percentages compare actual degree-days to normal degree-days and actual degree-days to actual degree-days of the previous year.

2022 vs. 2021

Operating revenues for the Utility segment increased $231.0 million in 2022
compared with 2021. The increase resulted from a $226.8 million increase in
retail gas sales revenues, which was primarily due to a significant increase in
the cost of gas sold (per Mcf). In addition, there was a $2.9 million increase
in transportation revenues and a $1.3 million increase in other revenues. The
increase in transportation revenues, despite a small decrease in throughput, was
largely due to an increase in marketer sales cashouts and an increase in the
system modernization tracker allocation to transportation customers, which was
partially offset by the migration of residential transportation customers
previously served by marketers to retail service provided by the Utility
segment. The increase in other revenues was primarily due to higher capacity
release revenues and higher late payment charges billed to customers.
                                      -42-
--------------------------------------------------------------------------------

Gas purchased

The cost of purchased gas is one of the Company's largest operating expenses.
Annual variations in purchased gas costs are attributed directly to changes in
gas sales volume, the price of gas purchased and the operation of purchased gas
adjustment clauses. Distribution Corporation recorded $498.0 million and
$274.8 million of Purchased Gas expense during 2022 and 2021, respectively.
Under its purchased gas adjustment clauses in New York and Pennsylvania,
Distribution Corporation is not allowed to profit from fluctuations in gas
costs. Purchased Gas expense recorded on the consolidated income statement
matches the revenues collected from customers, a component of Operating Revenues
on the consolidated income statement. Under mechanisms approved by the NYPSC in
New York and the PaPUC in Pennsylvania, any difference between actual purchased
gas costs and what has been collected from the customer is deferred on the
consolidated balance sheet as either an asset, Unrecovered Purchased Gas Costs,
or a liability, Amounts Payable to Customers. These deferrals are subsequently
collected from the customer or passed back to the customer, subject to review by
the NYPSC and the PaPUC. Absent disallowance of full recovery of Distribution
Corporation's purchased gas costs, such costs do not impact the profitability of
the Company. Purchased gas costs impact cash flow from operations due to the
timing of recovery of such costs versus the actual purchased gas costs incurred
during a particular period. Distribution Corporation's purchased gas adjustment
clauses seek to mitigate this impact by adjusting revenues on either a quarterly
or monthly basis.

Distribution Corporation contracts for firm long-term transportation and storage
capacity with rights-of-first-refusal from ten upstream pipeline companies
including Supply Corporation for transportation and storage and Empire for
transportation. Distribution Corporation contracts for firm gas supplies on term
and spot bases with various producers, marketers and two local distribution
companies to meet its gas purchase requirements. Additional discussion of the
Utility segment's gas purchases appears under the heading "Sources and
Availability of Raw Materials" in Item 1.

Earnings

2022 vs. 2021

The Utility segment's earnings in 2022 were $68.9 million, an increase of $14.6
million when compared with earnings of $54.3 million in 2021. The increase was
primarily attributable to the conclusion of a regulatory proceeding by the PaPUC
in February 2022, which resulted in the reduction of an OPEB-related regulatory
liability that increased earnings ($14.6 million). While the regulatory
proceeding reduced base rates in Pennsylvania by $5.6 million, this impact was
more than offset by a decrease in non-service post-retirement benefit costs
($11.5 million) as Distribution Corporation's Pennsylvania service territory
recognized OPEB income during fiscal 2022, compared to the prior year when it
recognized OPEB expenses to match against the OPEB amounts collected in base
rates. Additional details related to the regulatory proceeding are discussed in
Note F - Regulatory Matters.

Other factors contributing to the increase in earnings included the positive
earnings impact of a system modernization tracker in New York ($3.6 million),
which is a rate mechanism that provides recovery of qualified leak prone pipe
replacement costs, higher usage and the impact of weather on customer margins
($2.9 million), and a decrease in income tax expense ($0.6 million). These
increases were partially offset by higher operating expenses ($9.5 million),
which were primarily the result of higher personnel costs, transportation fuel
costs, and outside services partially offset by a decrease in the provision for
uncollectible accounts. The decrease in the provision for uncollectible accounts
reflects the recording of incremental expense in 2021 due to the potential for
future customer non-payment as a result of the COVID-19 pandemic. In addition,
earnings were negatively impacted by higher interest expense ($2.0 million),
which was largely the result of a higher weighted average interest rate on
intercompany short-term borrowings, and higher depreciation expense ($1.8
million), primarily due to higher plant balances.

The impact of weather variations on earnings in the Utility segment's New York
rate jurisdiction is largely 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 2022,
the WNC contributed approximately $4.8 million to earnings, as the weather was
                                      -43-
--------------------------------------------------------------------------------

warmer than normal. In 2021, the WNC contributed approximately $4.5 million to profits, as the weather was warmer than normal.

ALL OTHER OPERATIONS AND CORPORATE OPERATIONS

All Other and Corporate operations primarily includes the operations of Seneca's
Northeast Division and corporate operations. Seneca's Northeast Division
previously marketed timber from its New York and Pennsylvania land holdings. On
December 10, 2020, the Company completed the sale of substantially all timber
properties. Please refer to Item 8 at Note B - Asset Acquisitions and
Divestitures for further discussion of the sale of timber properties.

Earnings

2022 vs. 2021

All Other and Corporate operations recorded a loss of $12.7 million in 2022, a
decrease of $47.3 million when compared with earnings of $34.6 million in 2021.
The decrease was primarily attributable to the non-recurrence of a $51.1 million
gain ($37.0 million gain after-tax) on the sale of timber properties recorded by
Seneca's Northeast Division in 2021. Changes in unrealized gains and losses on
investments in equity securities also contributed to the decrease. In 2022, the
Company recorded unrealized losses of $9.2 million, while in 2021, the Company
recorded unrealized gains of $0.1 million.

OTHER INCOME (DEDUCTIONS)

Although most of the variances in other income (deductions) are discussed in the discussion of earnings by segment above, the following is a summary on a consolidated basis (amounts below are pre-tax amounts):

Net other deductions on the Consolidated Statement of Income decreased $13.7
million in 2022 as compared to 2021. This change is primarily attributable to
non-service pension and post-retirement benefit income of $3.6 million for 2022
compared to non-service pension and post-retirement benefit costs of $31.3
million for 2021. As discussed above in the Utility segment, 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. In addition, there was an
increase in other interest income of $1.7 million. This was partially offset by
changes in unrealized gains and losses on investments in equity securities.
During 2022, the Company recorded pre-tax unrealized losses of $13.8 million.
During 2021, the Company recorded pre-tax unrealized gains of $0.2 million.
Other income (deductions) was also impacted by a decrease in the cash surrender
value of life insurance policies of $1.9 million, as well as a decrease in
allowance for funds used during construction (equity component) of $2.5 million
primarily as a result of the FM100 Project being placed into service in December
2021. There was also a mark-to-market revaluation that decreased contingent
consideration by $4.4 million from the sale of Seneca's California assets. For
further discussion, refer to Note J - Financial Instruments.

INTEREST EXPENSES

Although most of the variances in Interest Charges are discussed in the earnings
discussion by segment above, the following is a summary on a consolidated basis
(amounts below are pre-tax amounts):

Interest on long-term debt decreased $21.0 million in 2022 as compared to 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.

Other interest expense increased $5.0 million in 2022 as compared to 2021. The
increase was primarily due to higher average interest rates for 2022 combined
with higher average short-term debt balances in 2022 compared to 2021.
                                      -44-
--------------------------------------------------------------------------------

                        CAPITAL RESOURCES AND LIQUIDITY

The main sources and uses of cash over the past two years are summarized in the following condensed cash flow statement:

                                                                               Year Ended September 30
                                                                               2022                2021
                                                                                     (Millions)
Provided by Operating Activities                                          $      812.5          $  791.6
Capital Expenditures                                                            (811.8)           (751.7)
Net Proceeds from Sale of Oil and Gas Producing Properties                       254.4                 -
Net Proceeds from Sale of Timber Properties                                          -             104.6
Sale of Fixed Income Mutual Fund Shares in Grantor Trust                          30.0                 -
Other Investing Activities                                                         8.7              13.8
Reduction of Long-Term Debt                                                          -            (515.7)
Change in Notes Payable to Banks and Commercial Paper                            (98.5)            128.5
Net Proceeds from Issuance of Long-Term Debt                                         -             495.3
Net Repurchases of Common Stock                                                   (9.6)             (3.7)
Dividends Paid on Common Stock                                                  (168.1)           (163.1)

Net Increase in Cash, Cash Equivalents, and Restricted Cash               $ 

17.6 $99.6


The Company expects to have adequate amounts of cash available to meet both its
short-term and long-term cash requirements for at least the next twelve months
and for the foreseeable future thereafter. During 2023, cash provided by
operating activities is expected to increase over the amount of cash provided by
operating activities during 2022 and will be used to fund the Company's capital
expenditures. There are two long-term debt maturities in March 2023, totaling
$549 million. The Company expects to repay those securities through the use of
cash on hand at the date of maturity and short-term borrowings. Looking at 2023
and 2024, based on current commodity prices, cash provided by operating
activities is expected to exceed capital expenditures in each of those years.
This is expected to provide the Company with the option to consider additional
growth investments, further reductions in short-term or long-term debt, and
increasing the amount of cash flow returned to shareholders, either through
increases to the Company's dividend or via repurchases of common stock. 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 year to year 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.

Cash provided by operating activities in the Exploration and Production segment
may vary from year to year as a result of changes in the commodity prices of
natural gas 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.

The Company, in its Utility segment and Exploration and Production segment, has
entered into contractual commitments in the ordinary course of business,
including commitments to purchase gas, transportation, and storage service to
meet customer gas supply needs. Refer to Item 8 at Note L -
                                      -45-
--------------------------------------------------------------------------------

Commitments and Contingencies under the heading "Other" for additional
discussion concerning these contractual commitments as well as the amounts of
future gas purchase, transportation and storage contract commitments expected to
be incurred during the next five years and thereafter. Also refer to Item 8 at
Note D - Leases for a discussion of the Company's operating lease arrangements
and a schedule of lease payments during the next five years and thereafter.

Net cash provided by operating activities totaled $812.5 million in 2022, an
increase of $20.9 million compared with the $791.6 million provided by operating
activities in 2021. The increase in cash provided by operating activities
primarily reflects higher cash provided by operating activities in the
Exploration and Production segment and the Gathering segment, partially offset
by lower cash provided by operating activities in the Utility segment. The
increase in the Exploration and Production segment and the Gathering segment was
primarily due to higher cash receipts from natural gas production and gathering
services in the Appalachian region. The decrease in 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 on long-lived assets, including non-cash capital expenditures, totaled $829.4 million and $769.9 million in 2022 and 2021, respectively. The table below presents these expenses:

                                       Year Ended September 30
                                       2022                      2021
                                                 (Millions)
Exploration and Production:
Capital Expenditures          $      565.8            (1)      $ 381.4   (2)
Pipeline and Storage:
Capital Expenditures                  95.8            (1)        252.3   (2)
Gathering:
Capital Expenditures                  55.5            (1)         34.7   (2)
Utility:
Capital Expenditures                 111.0            (1)        100.8   (2)
All Other and Corporate:
Capital Expenditures                   1.3                         0.5
Eliminations                             -                         0.2
Total Expenditures            $      829.4                     $ 769.9



(1) 2022 capital expenditures for Exploration & Production segment, Pipeline & Storage segment, Gathering segment and Utilities segment include $83.0 million, $15.2 million, $10.7 million and $11.4 millionrespectively, non-cash capital expenditures.

(2) 2021 capital expenditures for Exploration & Production segment, Pipeline & Storage segment, Gathering segment and Utilities segment include $47.9 million, $39.4 million, $4.8 million and $10.6 millionrespectively, non-cash capital expenditures.

exploration and production

In 2022, the Exploration and Production segment capital expenditures were
primarily well drilling and completion expenditures and included approximately
$547.1 million for the Appalachian region (including $161.4 million in the
Marcellus Shale area and $370.6 million in the Utica Shale area) and $18.7
million for the West Coast region. These amounts included approximately $154.3
million spent to develop proved undeveloped reserves.
                                      -46-
--------------------------------------------------------------------------------

In 2021, the majority of Exploration & Production capital expenditures were primarily expenditures for drilling and well completions and included approximately $368.1 million for the Appalachian region (including
$117.2 million in the Marcellus Shale region and $213.8 million in the Utica Shale
region) and $13.3 million for the Western coast Region. These sums included approximately $81.2 million spent to develop proven undeveloped reserves.

Pipeline and storage

The Pipeline and Storage segment's capital expenditures for 2022 were primarily
for additions, improvements and replacements to this segment's transmission and
gas storage systems, which included system modernization expenditures that
enhance the reliability and safety of the systems and reduce emissions. In
addition, the Pipeline and Storage segment capital expenditures for 2022 include
expenditures related to Supply Corporation's FM100 Project ($25.2 million). 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 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 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 continue in calendar year 2022. As
of September 30, 2022, approximately $211.3 million has been spent on the FM100
Project, all of which is included in Property, Plant and Equipment on the
Consolidated Balance Sheet at September 30, 2022.

The Pipeline and Storage segment's capital expenditures for 2021 were primarily
for expenditures related to Supply Corporation's FM100 Project ($179.0 million).
In addition, the Pipeline and Storage segment capital expenditures for 2021
included additions, improvements and replacements to this segment's transmission
and gas storage systems.

Gathering

The majority of the Gathering segment's capital expenditures for 2022 included
expenditures related to the continued expansion of Midstream Company's Clermont,
Covington, Trout Run and Wellsboro gathering systems, as discussed below.
Midstream Company spent $20.9 million, $27.0 million, $4.9 million and $2.3
million in 2022 on the development of the Clermont, Covington, Trout Run and
Wellsboro gathering systems, respectively. These expenditures were largely
attributable to the installation of new in-field gathering pipelines in the
Clermont gathering system, as well as the continued expansion of centralized
station facilities, including increased compression horsepower at the Clermont,
Trout Run, and Wellsboro gathering systems. In the Tioga gathering system, which
is part of Midstream Covington, expenditures were largely attributable to the
installation of in-field gathering pipelines and upgraded station facilities
related to new development.

The majority of the Gathering segment's capital expenditures for 2021 included
expenditures related to the continued expansion of Midstream Company's Clermont,
Covington and Wellsboro gathering systems. Midstream Company spent $23.1
million, $4.4 million and $3.7 million in 2021 on the development of the
Clermont, Covington and Wellsboro gathering systems, respectively. These
expenditures were largely attributable to new Clermont gathering pipelines, a
new tie-in between the legacy Covington gathering system and the midstream
gathering assets acquired from SWEPI LP, a subsidiary of Royal Dutch Shell plc
("Shell"), which is now referred to as the Tioga gathering system, 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.

Utility

The majority of the Utility segment's capital expenditures for 2022 and 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.
                                      -47-
--------------------------------------------------------------------------------

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 at Note B - Asset Acquisitions
and Divestitures 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.

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.

On June 30, 2022, the Company completed the sale of Seneca's California assets
to Sentinel Peak Resources California LLC for a total sale price of $253.5
million, consisting of $240.9 million in cash and contingent consideration
valued at $12.6 million at closing. The Company pursued this sale given the
strong commodity price environment and the Company's strategic focus in the
Appalachian Basin. Under the terms of the purchase and sale agreement, the
Company can receive up to three annual contingent payments between calendar year
2023 and calendar year 2025, not to exceed $10 million per year, with the amount
of each annual payment calculated as $1.0 million for each $1 per barrel that
the ICE Brent Average for each calendar year exceeds $95 per barrel up to $105
per barrel. The sale price, which reflected an effective date of April 1, 2022,
was reduced for production revenues less expenses that were retained by Seneca
from the effective date to the closing date. Under the full cost method of
accounting for oil and natural gas properties, $220.7 million of the sale price
at closing was accounted for as a reduction of capitalized costs since the
disposition did not alter the relationship between capitalized costs and proved
reserves of oil and gas attributable to the cost center. The remainder of the
sale price ($32.8 million) was applied against assets that are not subject to
the full cost method of accounting, with the Company recognizing a gain of $12.7
million on the sale of such assets. The majority of this gain related to the
sale of emission allowances.
                                      -48-
--------------------------------------------------------------------------------

Estimated capital expenditure

The Company’s estimated capital expenditures for the next three years are:

                                         Year Ended September 30
                                       2023             2024       2025
                                               (Millions)
Exploration and Production(1)   $     550              $ 525      $ 515
Pipeline and Storage                  120                105         90
Gathering                              95                110         95
Utility(2)                            120                135        135
All Other                               -                  -          -
                                $     885              $ 875      $ 835




(1)Includes estimated expenditures for the years ended September 30, 2023, 2024
and 2025 of approximately $308 million, $95 million and $82 million,
respectively, to develop proved undeveloped reserves. The Company is committed
to developing its proved undeveloped reserves within five years as required by
the SEC's final rule on Modernization of Oil and Gas Reporting.

(2)Includes estimated expenditures for the years ended September 30, 2023, 2024,
and 2025 of approximately $95 million, $100 million and $100 million,
respectively, for system modernization and safety to enhance the reliability and
safety of the system and reduce emissions.

exploration and production

Capital expenditures for the Exploration and Production segment in 2023 through
2025 are expected to be primarily well drilling and completion expenditures in
the Appalachian region.

Pipeline and Storage

Capital expenditures for the Pipeline and Storage segment in 2023 through 2025
are expected to include: the replacement and modernization of transmission and
storage facilities, the reconditioning of storage wells, improvements of
compressor stations and emissions reduction initiatives.

  In addition, due to 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. Capital expenditures in 2023 through 2025 include minimal capital
expenditures related to system expansion and forecasted amounts will be adjusted
in the future to incorporate any new projects that are expected to be developed
by the Company.

Gathering

The majority of the Gathering segment capital expenditures in 2023 through 2025,
included in the table above, are expected to be for construction and expansion
of gathering systems, as discussed below. The Gathering segment primarily
invests capital to support Seneca's drilling and completion activity in their
long-term development plan. Seneca has been in the process of shifting a larger
share of its activity from its Western Development Area to Tioga County,
Pennsylvania. As a result, the Gathering segment is expecting to see near-term
increases in capital expenditures as it constructs the necessary infrastructure
to support Seneca's activity in the region.

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 16 compressor stations and backbone and in-field gathering pipelines.
Estimated capital expenditures in 2023 through 2025 include anticipated
expenditures in the range of $150 million to $180 million for continued
expansion of the Tioga gathering system.
                                      -49-
--------------------------------------------------------------------------------

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. Estimated capital expenditures in 2023
through 2025 include anticipated expenditures in the range of $50 million to $70
million for the continued expansion of the Clermont gathering system.

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. Estimated capital expenditures in 2023 through
2025 include anticipated expenditures in the range of $50 million to $60 million
for the continued expansion of the Wellsboro gathering system.

NFG Midstream Trout Run, LLC, a wholly-owned subsidiary of Midstream Company,
continues to develop its Trout Run gathering system in Lycoming County,
Pennsylvania. The Trout Run gathering system was initially placed in service in
May 2012. The current system consists of three compressor stations and backbone
and in-field gathering pipelines. Estimated capital expenditures in 2023 through
2025 include anticipated expenditures in the range of $15 million to $25 million
for the continued expansion of the Trout Run gathering system.

Utility

Capital expenditures for the Utility segment in 2023 through 2025 are expected
to be concentrated in the areas of main and service line improvements and
replacements and, to a lesser extent, the purchase of new equipment.
Additionally, capital expenditures are expected to increase after 2023 largely
due to the anticipated implementation of a Distribution System Improvement
Charge (DSIC) mechanism in the Utility's Pennsylvania Division upon completion
of the rate proceeding initiated on October 28, 2022.

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 and the Company's California assets.
During fiscal 2022, capital expenditures were funded with cash from operations,
short-term debt and proceeds from the sale of the Company's California assets.
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 production, and the
associated commodity price realizations, as well as the level of hedging
collateral deposits in the Exploration and Production segment.

In the Exploration and Production segment, the Company has entered into
contractual obligations to support its development activities and operations in
Pennsylvania, including hydraulic fracturing and other well completion services,
well tending services, well workover activities, tubing and casing purchases,
production equipment purchases, water hauling services and contracts for
drilling rig services. Refer to Item 8 at Note L - Commitments and Contingencies
under the heading "Other" for the amounts of contractual obligations expected to
be incurred during the next five years and thereafter to support the Company's
exploration and development activities. These amounts are largely a subset of
the estimated capital expenditures for the Exploration and Production segment
shown above.

The Company, in its Pipeline and Storage segment, Gathering segment and Utility
segment, has entered into several contractual commitments associated with
various pipeline, compressor and gathering system modernization and expansion
projects. Refer to Item 8 at Note L - Commitments and Contingencies under the
heading "Other" for the amounts of contractual commitments expected to be
incurred during the next five years
                                      -50-
--------------------------------------------------------------------------------

and thereafter associated with the Company's pipeline, compressor and gathering
system modernization and expansion projects. These amounts are a subset of the
estimated capital expenditures for the Pipeline and Storage segment, Gathering
segment and Utility segment that are shown above.

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 natural gas properties, quicker development of existing natural 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 as well as legislative actions.

FINANCING CASH FLOW

Consolidated short-term debt decreased $98.5 million, to a total of $60.0
million, when comparing the balance sheet at September 30, 2022 to the balance
sheet at September 30, 2021. The maximum amount of short-term debt outstanding
during the year ended September 30, 2022 was $675.4 million. In addition to cash
provided by operating activities, 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 $91.7 million with a number of its derivative
counterparties as of September 30, 2022. The maximum amount of margin posted
during the year ended September 30, 2022 was $430.6 million. 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. At
September 30, 2022, the Company had outstanding short-term notes payable to
banks of $60.0 million. The Company did not have any commercial paper
outstanding at September 30, 2022.

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

On June 30, 2022, the Company entered into the 364-Day Credit Agreement with a
syndicate of five banks, all of which are also lenders under the Credit
Agreement. The 364-Day Credit Agreement provides an additional $250.0 million
unsecured committed delayed draw term loan credit facility with a maturity date
of June 29, 2023. The Company elected to draw $250.0 million under the facility
on October 27, 2022. The Company is using the proceeds for general corporate
purposes, which will include the redemption in November of a portion of the
Company's outstanding long-term debt maturing in March 2023.

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
                                      -51-
--------------------------------------------------------------------------------

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 September 30, 2022, $190.7 million was added
back to the Company's total capitalization for purposes of the calculation under
the Credit Agreement and 364-Day Credit Agreement. On May 3, 2022, the Company
entered into Amendment No. 1 to the Credit Agreement with the same twelve banks
under the initial Credit Agreement. The amendment further modified the
definition of consolidated capitalization, for purposes of calculating the debt
to capitalization ratio under the Credit Agreement, to exclude, beginning with
the quarter ended 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 consolidated balance sheet. Under the
Credit Agreement, 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. The 364-Day Credit Agreement includes the
same debt to capitalization covenant and the same exclusions of unrealized gains
or losses on derivative financial instruments as the Credit Agreement. At
September 30, 2022, the Company's debt to capitalization ratio, as calculated
under the Credit Agreement and 364-Day Credit Agreement, was .49. The
constraints specified in the Credit Agreement and 364-Day Credit Agreement would
have permitted an additional $2.56 billion in short-term and/or long-term debt
to be outstanding at September 30, 2022 (further limited by the indenture
covenants discussed below) before the Company's debt to capitalization ratio
exceeded .65.

A downgrade in the Company's credit ratings could increase borrowing costs,
negatively impact the availability of capital from banks, commercial paper
purchasers and other sources, and require the Company's subsidiaries to post
letters of credit, cash or other assets as collateral with certain
counterparties. If the Company is not able to maintain investment-grade credit
ratings, it may not be able to access commercial paper markets. However, the
Company expects that it could borrow under its credit facilities or rely upon
other liquidity sources.

The Credit Agreement and 364-Day Credit Agreement contain a cross-default
provision whereby the failure by the Company or its significant subsidiaries to
make payments under other borrowing arrangements, or the occurrence of certain
events affecting those other borrowing arrangements, could trigger an obligation
to repay any amounts outstanding under the Credit Agreement and 364-Day Credit
Agreement. In particular, a repayment obligation could be triggered if (i) the
Company or any of its significant subsidiaries fails to make a payment when due
of any principal or interest on any other indebtedness aggregating $40.0 million
or more or (ii) an event occurs that causes, or would permit the holders of any
other indebtedness aggregating $40.0 million or more to cause, such indebtedness
to become due prior to its stated maturity.

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 September 30, 2022 consists of $500.0
million of 3.75% notes and $49.0 million of 7.395% notes, that each mature in
March 2023. The Company does not anticipate long-term refinancing for these
maturities. None of the Company's long-term debt as of September 30, 2021 had a
maturity date within the following twelve-month period. As of September 30,
2022, the future contractual obligations related to aggregate principal amounts
of long-term debt, including interest expense, maturing during the next five
years and thereafter are as follows: $654.1 million in 2023, $95.4 million in
2024, $589.4 million in 2025, $548.9 million in 2026, $340.4 million in 2027,
and $863.5 million thereafter. Refer to Item 8
                                      -52-
--------------------------------------------------------------------------------

at Note H - Capitalization and Short-Term Borrowings, as well as the table under
Interest Rate Risk in the Market Risk Sensitive Instruments section below, for
the amounts excluding interest expense. Principal payments of long-term debt are
a component of cash used in financing activities while interest payments on
long-term debt are a component of cash used in operating activities.

The Company's embedded cost of long-term debt was 4.48% at both September 30,
2022 and September 30, 2021. Refer to "Interest Rate Risk" in this Item for a
more detailed breakdown of the Company's embedded cost of long-term debt.

Under the Company's existing indenture covenants at September 30, 2022, the
Company would have been permitted to issue up to a maximum of approximately $2.0
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. The Company's present liquidity position is believed to
be adequate to satisfy known demands. It is possible, depending on amounts
reported in various income statement and balance sheet line items, that the
indenture covenants could, for a period of time, prevent the Company from
issuing incremental unsubordinated long-term debt, or significantly limit the
amount of such debt that could be issued. Losses incurred as a result of
significant impairments of oil and gas properties have in the past resulted in
such temporary restrictions. The indenture covenants would not preclude the
Company from issuing new long-term debt to replace existing long-term debt, or
from issuing additional short-term debt. Please refer to the Critical Accounting
Estimates section above for a sensitivity analysis concerning commodity price
changes and their impact on the ceiling test.

The Company's 1974 indenture pursuant to which $99.0 million (or 3.7%) of the
Company's long-term debt (as of September 30, 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 environmental and other matters discussed in this Item 7 and
in Item 8 at Note L - Commitments and Contingencies, 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.

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. The Company remains committed to the project and, on June 29, 2022,
received an extension of time from FERC, until December 31, 2024, 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 September 30,
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
                                      -53-
--------------------------------------------------------------------------------

spent on the project are included in property, plant and equipment on the consolidated balance sheet at September 30, 2022.

The Company has a tax-qualified, noncontributory defined-benefit retirement plan
(Retirement Plan). The Company has been making contributions to the Retirement
Plan over the last several years and anticipates that it may continue making
contributions to the Retirement Plan in the future. During 2022, the Company
contributed $20.4 million to the Retirement Plan. The Company anticipates that
the annual contribution to the Retirement Plan in 2023 will be in the range of
zero to $8.0 million. For further discussion of the Company's Retirement Plan,
including actuarial assumptions, refer to Item 8 at Note K - Retirement Plan and
Other Post-Retirement Benefits. As noted in that footnote, the Retirement Plan
has been closed to new participants since 2003. In that regard, the average
remaining service life of active participants in the Retirement Plan is
approximately 6 years.

The Company provides health care and life insurance benefits (other
post-retirement benefits) for a majority of its retired employees. The Company
has established VEBA trusts and 401(h) accounts for its other post-retirement
benefits. The Company has been making contributions to its VEBA trusts and/or
401(h) accounts over the last several years and does not anticipate making
contributions to the VEBA trusts and/or 401(h) accounts in the near term.
However, this will be subject to future review. During 2022, the Company
contributed $2.8 million to its VEBA trusts. In addition, the Company made
direct payments of $0.3 million to retirees not covered by the VEBA trusts and
401(h) accounts during 2022. The Company does not expect to make any
contributions to its VEBA trusts in 2023. For further discussion of the
Company's other post-retirement benefits, including actuarial assumptions, refer
to Item 8 at Note K - Retirement Plan and Other Post-Retirement Benefits. As
noted in that footnote, the other post-retirement benefits provided by the
Company have been closed to new participants since 2003. In that regard, the
average remaining service life of active participants is approximately 4 years
for those eligible for other post-retirement benefits.

The Company has made certain guarantees on behalf of its subsidiaries. The
guarantees relate primarily to: (i) obligations under derivative financial
instruments, which are included on the Consolidated Balance Sheets in accordance
with the authoritative guidance (see Item 7, MD&A under the heading "Critical
Accounting Estimates - Accounting for Derivative Financial Instruments"); and
(ii) other obligations which are reflected on the Consolidated Balance Sheets.
The Company believes that the likelihood it would be required to make payments
under the guarantees is remote.

INSTRUMENTS SENSITIVE TO MARKET RISK

Risk related to the price of energy raw materials

The Company uses various derivative financial instruments (derivatives),
including price swap agreements and no cost collars, as part of the Company's
overall energy commodity price risk management strategy in its Exploration and
Production segment. Under this strategy, the Company manages a portion of the
market risk associated with fluctuations in the price of natural gas, thereby
attempting to provide more stability to operating results. The Company has
operating procedures in place that are administered by experienced management to
monitor compliance with the Company's risk management policies. The derivatives
are not held for trading purposes. The fair value of these derivatives, as shown
below, represents the amount that the Company would receive from, or pay to, the
respective counterparties at September 30, 2022 to terminate the derivatives.
However, the tables below and the fair value that is disclosed do not consider
the physical side of the natural gas transactions that are related to the
financial instruments.

On July 21, 2010, the Dodd-Frank Act was signed into law. The Dodd-Frank Act
required the CFTC, SEC and other regulatory agencies to promulgate rules and
regulations implementing the legislation, and includes provisions related to the
swaps and over-the-counter derivatives markets that are designed to promote
transparency, mitigate systemic risk and protect against market abuse. Although
regulators have issued certain regulations, other rules that may impact the
Company have yet to be finalized. Rules developed by the CFTC and other
regulators could impact the Company.  While many of those rules place specific
conditions on the operations of swap dealers and major swap participants,
concern remains that swap dealers and major swap participants will pass along
their increased costs stemming from final rules through higher transaction costs
and prices or other direct or indirect costs. Additionally, given the
enforcement authority granted to the CFTC on anti-market manipulation,
anti-fraud and disruptive trading practices, it is difficult to predict how the
evolving
                                      -54-
--------------------------------------------------------------------------------

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 September 30, 2022, the Company determined that
nonperformance risk associated with the price swap agreements, no cost collars
and foreign currency contracts 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.

The following tables disclose natural gas price swap information by expected
maturity dates for agreements in which the Company receives a fixed price in
exchange for paying a variable price as quoted in various national natural gas
publications or on the NYMEX. Notional amounts (quantities) are used to
calculate the contractual payments to be exchanged under the contract. The
weighted average variable prices represent the weighted average settlement
prices by expected maturity date as of September 30, 2022. At September 30,
2022, the Company had not entered into any natural gas price swap agreements
extending beyond 2026.

Natural Gas Price Swap Agreements

                                                        Expected Maturity 

Appointment

                                             2023        2024        2025        2026             Total

Notional quantities (Bcf equivalent) 112.8 65.7 26.8

       2.0             207.3

Weighted average fixed rate (per Mcf) $2.88 $3.07 $3.16

    $ 3.18            $ 2.98

Weighted average floating rate (per Mcf) $6.02 $4.86 $4.55

    $ 4.32            $ 5.45


At September 30, 2022, the Company would have paid its respective counterparties
an aggregate of approximately $512.3 million to terminate the natural gas price
swap agreements outstanding at that date.

To September 30, 2021the Company had entered into natural gas price swaps covering 398.8 Bcf at a weighted average fixed rate of $2.84 by Mcf.

Free Collars

The following table discloses the notional quantities, the weighted average
ceiling price and the weighted average floor price for the no cost collars used
by the Company to manage natural gas price risk. The no cost collars provide for
the Company to receive monthly payments from (or make payments to) other parties
when a variable price falls below an established floor price (the Company
receives payment from the counterparty) or exceeds an established ceiling price
(the Company pays the counterparty). At September 30, 2022, the Company had not
entered into any natural gas no cost collars extending beyond 2027.
                                                                   Expected Maturity Dates
                                               2023        2024        2025        2026        2027       Total
  Natural Gas
  Notional Quantities (Equivalent Bcf)         68.3        57.5        42.7        41.5         3.5       213.5
  Weighted Average Ceiling Price (per Mcf)   $ 3.75      $ 3.89      $ 4.79      $ 4.90      $ 4.90      $ 4.24
  Weighted Average Floor Price (per Mcf)     $ 3.20      $ 3.30      $ 3.60      $ 3.63      $ 3.63      $ 3.40

To September 30, 2022the Company should have paid a total of approximately $270.5 million to terminate the natural gas tunnels free of charge in progress on that date.

At September 30, 2021, the Company had no cost collars agreements covering 20.9
Bcf at a weighted average ceiling price of $3.25 per Mcf and a weighted average
floor price of $2.81 per Mcf.
                                      -55-
--------------------------------------------------------------------------------

Risk of change

The Company uses forward foreign exchange contracts to manage the currency fluctuation risk associated with Canadian dollar denominated transportation costs in the Exploration and Production segment. All of these transactions are planned.

The following table discloses foreign exchange contract information by expected
maturity dates. The Company receives a fixed price in exchange for paying a
variable price as noted in the Canadian to U.S. dollar forward exchange rates.
Notional amounts (Canadian dollars) are used to calculate the contractual
payments to be exchanged under contract. The weighted average variable prices
represent the weighted average settlement prices by expected maturity date as of
September 30, 2022. At September 30, 2022, the Company had not entered into any
foreign currency exchange contracts extending beyond 2030.

                                                                            

Expected due dates

                                             2023            2024            2025            2026            2027            Thereafter           Total
Notional Quantities (Canadian Dollar in
millions)                                  $ 14.7          $ 12.9          

$10.9 $3.1 $2.4 $5.4 $49.4
Weighted average fixed rate (CAD$/USD) $1.29 $1.29 $1.28 $1.32 $1.33 $1.34 $1.29
Weighted average floating rate (CAD$/USD) $1.34 $1.33 $1.32 $1.34 $1.34 $1.34 $1.33


At September 30, 2022, absent other positions with the same counterparties, the
Company would have paid to its respective counterparties an aggregate of $1.9
million to terminate these foreign exchange contracts.

Refer to Section 8 of Note J – Financial Instruments for a discussion of the Company’s exposure to credit risk related to its derivative financial instruments.

Interest rate risk

The fair value of long-term fixed rate debt is $2.5 billion at September 30,
2022. This fair value amount is not intended to reflect principal amounts that
the Company will ultimately be required to pay. The following table presents the
principal cash repayments and related weighted average interest rates by
expected maturity date for the Company's long-term fixed rate debt:
                                                                                   Principal Amounts by Expected Maturity Dates
                                     2023                 2024                2025                 2026                 2027                 Thereafter                 Total
                                                                                               (Dollars in millions)

Long-term fixed rate debt $549.0 $ – $

      500.0       $        500.0       $        300.0       $              800.0       $        2,649.0
Weighted Average Interest Rate
Paid                                       4.1%                  -                 5.4%                 5.5%                 4.0%                       3.6%                   4.5%


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." As noted below, the
Pennsylvania division currently has 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. The order also authorized the Company to
recover approximately $15 million annually for pension and other post-employment
benefit ("OPEB") expenses from customers. Because the Company's future pension
and OPEB costs were projected to be satisfied with existing funds held in
reserve, in July, Distribution Corporation made a filing with the NYPSC to
effectuate a pension and OPEB surcredit to customers to offset these amounts
being collected in base rates effective October 1, 2022. On September 16,
                                      -56-
--------------------------------------------------------------------------------

2022, the NYPSC issued an order approving the filing. With the implementation of
this surcredit, Distribution Corporation will no longer be funding the pension
from its New York jurisdiction and it will not be funding its VEBA trusts in its
New York jurisdiction.

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.

Pennsylvania jurisdiction

Distribution Corporation's current delivery rates in its Pennsylvania
jurisdiction were approved by the PaPUC on November 30, 2006 as part of a
settlement agreement that became effective January 1, 2007. On October 28, 2022,
Distribution Corporation made a filing with the PaPUC seeking an increase in its
annual base rate operating revenues of $28.1 million with a proposed effective
date of December 27, 2022. The Company is also proposing, among other things, to
implement a weather normalization adjustment mechanism and a new energy
efficiency and conservation pilot program for residential customers. The filing
will be suspended for seven months by operation of law unless directed otherwise
by the PaPUC.

Effective October 1, 2021, pursuant to a tariff supplement filed with the PaPUC,
Distribution Corporation reduced base rates by $7.7 million in order to stop
collecting OPEB expenses from customers. It also began to refund to customers
overcollected OPEB expenses in the amount of $50.0 million. Certain other
matters in the tariff supplement were unresolved. These matters were resolved
with the PaPUC's approval of an Administrative Law Judge's Recommended Decision
on February 24, 2022. Concurrent with that decision, the Company discontinued
regulatory accounting for OPEB expenses 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 Company also increased customer refunds of overcollected OPEB
expenses from $50.0 million to 54.0 million. All refunds specified in the tariff
supplement are being 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 is no
longer funding the grantor trust or its VEBA trusts in its Pennsylvania
jurisdiction.

Pipeline and storage

Supply Corporation's 2020 rate settlement provides that no party may make a rate
filing for new rates to be effective before February 1, 2024, except that Supply
Corporation may file an NGA general Section 4 rate case to change rates if the
corporate federal income tax rate is increased. If no case has been filed,
Supply Corporation must file for rates to be effective February 1, 2025.

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

ENVIRONMENTAL MATTERS

The Company is subject to various federal, state and local laws and regulations
relating to the protection of the environment. The Company has established
procedures for the ongoing evaluation of its operations to identify potential
environmental exposures and comply with regulatory requirements. In 2021, the
Company set methane intensity reduction targets at each of its businesses, an
absolute greenhouse gas emissions reduction target for the consolidated Company,
and greenhouse gas reduction targets associated with the Company's utility
delivery system. In 2022, the Company began measuring progress against these
reduction targets. 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 information on the Company’s environmental exposures, refer to Note L – Commitments and contingencies, section 8 under the heading “Environmental matters”.

                                      -57-
--------------------------------------------------------------------------------

While changes in environmental laws and regulations could have an adverse
financial impact on the Company, legislation or regulation that sets a price on
or otherwise restricts carbon emissions could also benefit the Company by
increasing demand for natural gas, because substantially fewer carbon emissions
per Btu of heat generated are associated with the use of natural gas than with
certain alternate fuels such as coal and oil. The effect (material or not) on
the Company of any new legislative or regulatory measures will depend on the
particular provisions that are ultimately adopted.

Environmental regulations

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. 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. For example, the Inflation Reduction Act of 2022 (IRA) legislation was
signed into law on August 16, 2022. The IRA includes a methane charge that is
expected to be applicable to the reported annual methane emissions of certain
oil and gas facilities, above specified methane intensity thresholds, starting
in calendar year 2024. This portion of the IRA is to be administered by the EPA
and potential fees will begin with emissions reported for calendar year 2024.
The EPA regulates greenhouse gas emissions pursuant to the Clean Air Act. The
regulations implemented by the EPA impose more 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, a number of states have adopted energy
strategies or plans with aggressive goals for the reduction of greenhouse gas
emissions. Pennsylvania has a methane reduction framework with the stated goal
of reducing methane emissions from well sites, compressor stations and
pipelines. Pennsylvania's Governor also entered the Commonwealth into a
cap-and-trade program known as the Regional Greenhouse Gas Initiative, however,
the Commonwealth's participation is currently stayed due to ongoing litigation.
Federal, state or local governments may provide tax advantages and other
subsidies to support alternative energy sources, mandate the use of specific
fuels or technologies, or promote research into new technologies to reduce the
cost and increase the scalability of alternative energy sources. 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.
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.

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.
                                      -58-
--------------------------------------------------------------------------------

SAFETY PORT FOR FORWARD-LOOKING STATEMENTS

The Company is including the following cautionary statement in this Form 10-K 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 dependence on natural gas;

5.Changes in economic conditions, including inflationary pressures, supply chain
issues, liquidity challenges, and global, national or regional recessions, and
their effect on the demand for, and customers' ability to pay for, the Company's
products and services;

6. The evolution of the price of natural gas;

7. The creditworthiness or performance of the Company’s main suppliers, customers and counterparties;

8.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;

9. Deficiencies under the DRY test of the total cost cap for natural gas reserves;

10.Increased costs or delays or changes in plans with respect to the Company’s projects or related projects of other companies, as well as difficulties or delays in obtaining any necessary governmental approvals, permits or orders or in obtaining the cooperation of operators of interconnection facilities;

11. The ability of the Company to complete planned strategic transactions;

12. The ability of the Company to successfully integrate the acquired assets and achieve the expected cost synergies;

                                      -59-
--------------------------------------------------------------------------------

13.Changes in price differentials between similar quantities of natural gas 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;

14. The impact of information technology disruptions, cybersecurity or data security breaches;

15.Factors affecting the Company's ability to successfully identify, drill for
and produce economically viable natural gas reserves, including among others
geology, lease availability and costs, 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;

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

17.Other changes in price differentials between similar quantities of natural gas of different quality, calorific value, hydrocarbon mixture or delivery date;

18. The cost and effects of legal and administrative claims against the Company or activist shareholder campaigns to effect change within the Company;

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

20. Uncertainty of gas reserve estimates;

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

22. Changes in demographic patterns and weather patterns (including those related to climate change);

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

24.Changes in laws, actuarial assumptions, the interest rate environment and the
return on plan/trust assets related to the Company's pension and other
post-retirement benefits, which can affect future funding obligations and costs
and plan liabilities;

25. Economic disruptions or uninsured losses resulting from major accidents, fires, extreme weather conditions, natural disasters, terrorist activities or acts of war, as well as economic and operational disruptions due to power outages. third ;

26. Material differences between the Company’s projected and actual capital expenditures and operating expenditures; Where

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

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

The forward-looking statements and other statements contained in this Annual Report on Form 10-K regarding methane and greenhouse gas reduction plans and targets do not imply that such statements are necessarily material to investors or required disclosure in our documents filed with the SECOND. In addition, historical, current and forward-looking statements regarding methane and greenhouse gas emissions may be based on standards for measuring progress that are still under development, internal controls and processes that continue to evolve, and assumptions that may change in the future.

DISCLOSURE OF INDUSTRY AND MARKET DATA

The market data and certain other statistical information used throughout this
Form 10-K are based on independent industry publications, government
publications or other published independent sources. Some data is also based on
the Company's good faith estimates. Although the Company believes these
third-party sources are reliable and that the information is accurate and
complete, it has not independently verified the information.

Item 7A Quantitative and qualitative disclosures about market risk

See “Instruments Sensitive to Market Risk” in Section 7 of the MD&A.

                                      -60-

————————————————– ——————————

© Edgar Online, source Previews