What changed in this filing

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Item 2. Management’s Discussion and Analysis

2023-05-04 compared with 2023-02-03 · 279 added, 158 removed, 357 unchanged (55% of the section changed)

19 unchanged sentences

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 included the redemption in November 2022 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 long-term debt maturing in March 2023.

The Company is using the proceeds for general corporate purposes, which included using $150.0 million for the November 2022 redemption of a portion of the Company's outstanding long-term debt with a maturity date in March 2023.

In March 2023, the Company utilized short-term borrowings and cash on hand to redeem the remaining long-term debt that had maturity dates in March 2023, which included $350.0 million of 3.75% notes and $49.0 million of 7.395% notes.

From a financing perspective, the Company expects to use cash on hand, cash from operations, and short-term or long-term borrowings, as needed, to meet its financing needs for the remainder of fiscal 2023.

The Company continues to evaluate these financing needs and options to meet them.

Given the current economic conditions, which include continued inflationary pressures and rising interest rates, the cost and/or availability of capital may be impacted, but the Company continues to expect to meet its financing needs as discussed above.

Recent turmoil with certain financial institutions has created uncertainty in the economy.

While the Company has not been directly impacted, it continues to closely monitor any potential future impacts on the business.

The Company has a diverse group of twelve banks that participate in its multi-year and 364-day credit facilities.

All of these banks have solid investment grade credit ratings.

Additionally, the Company regularly reviews the credit quality of its hedging counterparties, those that provide credit support for customers, and any other material counterparties, and has not identified any material risks as a result of the current economic uncertainty.

CRITICAL ACCOUNTING ESTIMATES

7 unchanged sentences

Under the ceiling test, the present value of future revenues from the Company's oil and gas reserves based on an unweighted arithmetic average of the first day of the month oil and gas prices for each month within the twelve-month period prior to the end of the reporting period (the “ceiling”) is compared with the book value of the Company’s oil and gas properties at the balance sheet date.

The present value of future

revenues is calculated using a 10% discount factor.

The present value of future revenues is calculated using a 10% discount factor.

If the book value of the oil and gas properties exceeds the ceiling, a non-cash impairment charge must be recorded to reduce the book value of the oil and gas properties to the calculated ceiling.

At December 31, 2022, the ceiling exceeded the book value of the oil and gas properties by approximately $3.3 billion.

The 12-month average of the first day of the month price for natural gas for each month during the twelve months ended December 31, 2022, based on the quoted Henry Hub spot price for natural gas, was $6.36 per MMBtu.

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 the twelve months ended December 31, 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 December 31, 2022 in the ceiling test calculation, the ceiling would have exceeded the book value of the Company's oil and gas properties by approximately $3.0 billion (after-tax), which would not have resulted in an impairment charge.

At March 31, 2023, the ceiling exceeded the book value of the oil and gas properties by approximately $2.7 billion.

The 12-month average of the first day of the month price for natural gas for each month during the twelve months ended March 31, 2023, based on the quoted Henry Hub spot price for natural gas, was $5.96 per MMBtu.

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 March 31, 2023 in the ceiling test calculation, the ceiling would have exceeded the book value of the Company's oil and gas properties by approximately $2.4 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.

3 unchanged sentences

RESULTS OF OPERATIONS

The Company's earnings were $169.7 million for the quarter ended December 31, 2022 compared to earnings of $132.4 million for the quarter ended December 31, 2021.

The increase in earnings of $37.3 million is primarily the result of higher earnings in all reportable segments as well as in the Corporate category, slightly offset by a loss in the All Other category.

The Company's earnings were $140.9 million for the quarter ended March 31, 2023 compared to earnings of $167.3 million for the quarter ended March 31, 2022.

The decrease in earnings of $26.4 million is primarily the result of lower earnings in the Exploration and Production segment, Pipeline and Storage segment and Utility segment.

Higher earnings in the Gathering segment and the Corporate category partially offset these decreases.

The Company's earnings were $310.6 million for the six months ended March 31, 2023 compared to earnings of $299.7 million for the six months ended March 31, 2022.

The increase in earnings of $10.9 million is primarily the result of higher earnings in the Exploration and Production segment, Pipeline and Storage segment, Gathering segment and Corporate category.

Lower earnings in the Utility segment and a loss in the All Other category partially offset these increases.

The Company's earnings for the quarter and six months ended March 31, 2022 include the reduction of an OPEB regulatory liability that increased Utility segment earnings by $18.5 million ($14.6 million after-tax) in accordance with a regulatory proceeding in Distribution Corporation's Pennsylvania service territory.

Additional discussion of earnings in each of the business segments can be found in the business segment information that follows.

2 unchanged sentences

Three Months Ended

March 31, Six Months Ended

(Thousands) 2023 2022 Increase

(Decrease) 2023 2022 Increase

Exploration and Production $ 60,982 $ 71,121 $ (10,139) $ 152,174 $ 133,490 $ 18,684

9 unchanged sentences

Three Months Ended

March 31, Six Months Ended

(Thousands) 2023 2022 Increase

(Decrease) 2023 2022 Increase

Gas (after Hedging) $ 241,002 $ 218,486 $ 22,516 $ 514,199 $ 424,287 $ 89,912

5 unchanged sentences

Three Months Ended

March 31, Six Months Ended

2023 2022 Increase

(Decrease) 2023 2022 Increase

Gas Production (MMcf)

8 unchanged sentences

Three Months Ended

March 31, Six Months Ended

2023 2022 Increase

(Decrease) 2023 2022 Increase

Average Gas Price/Mcf

Appalachia $ 2.79 $ 3.97 $ (1.18) $ 3.77 $ 4.18 $ (0.41)

West Coast N/M $ 9.79 N/M

West Coast N/M $ 10.04 N/M N/M $ 9.91 N/M

Weighted Average $ 2.79 $ 4.00 $ (1.21) $ 3.77 $ 4.21 $ (0.44)

2 unchanged sentences

Appalachia $ 74.12 $ 78.32 $ (4.20) $ 78.25 $ 75.38 $ 2.87

West Coast N/M $ 77.34 N/M

West Coast N/M $ 94.95 N/M N/M $ 85.93 N/M

Weighted Average $ 74.12 $ 94.93 $ (20.81) $ 78.25 $ 85.93 $ (7.68)

2 unchanged sentences

2023 Compared with 2022

Operating revenues for the Exploration and Production seg ment increased $32.8 million for t he quarter ended December 31, 2022 as compared with the quarter en ded December 31, 2021.

Gas production revenue after hedging increased $67.4 million due to the impact of an 8.8 Bcf increase in natural gas production, together with a $0.50 per Mcf increase in the weighted average price of natural gas after hedging.

Operating revenues for the Exploration and Production segment decreased $17.0 million for the quarter ended March 31, 2023 as compared with the quarter ended March 31, 2022.

Gas production revenue after hedging increased $22.5 million due to the impact of a 9.3 Bcf increase in natural gas production, offset by a $0.02 per Mcf decrease in the weighted average price of natural gas after hedging.

Natural gas production increased largely due to additional production from new Marcellus and Utica wells in the Appalachian region.

Oil production revenue after hedging decreased $36.3 million due to the sale of the Exploration and Production segment's California assets on June 30, 2022.

In addition, other revenue increased $0.6 million and gas processing plant revenue decreased $0.7 million.

The increase in other revenue was attributed to a temporary capacity release of the TransCanada Pipeline transportation contract.

The decrease in gas processing plant revenue was attributed to the sale of the California assets.

The Exploration and Production segment's earnings for the quarter ended December 31, 2022 were $91.2 million, an increase of $28.8 million when compared with earnings of $62.4 million for the quarter ended December 31, 2021.

The increase in earnings was due to higher natural gas production ($17.4 million), higher natural gas prices after hedging ($35.8 million), lower lease operating and transportation expenses ($6.0 million), lower other operating expenses ($3.3 million) and higher other income ($1.4 million).

The positive earnings impact of these items was partially offset by lower oil production ($27.4 million), higher depletion expense ($4.8 million), higher other taxes ($1.0 million), higher interest expense ($0.9 million) and a higher income tax expense ($1.2 million).

The decrease in lease operating and transportation expenses was primarily the result of the sale of the California assets, partially offset by higher gathering and transportation costs in the Appalachian region due to increased production.

In addition, other revenue decreased $2.5 million and gas processing plant revenue decreased $0.8 million.

The decrease in other revenue was attributed to higher temporary capacity releases during the quarter ended March 31, 2022 when compared to the quarter ended March 31, 2023.

The decrease in gas processing plant revenue was mainly attributed to the sale of the California assets.

Operating revenues for the Exploration and Production segment increased $15.7 million for the six months ended March 31, 2023 as compared with the six months ended March 31, 2022.

Gas production revenue after hedging increased $89.9 million due to the impact of an 18.1 Bcf increase in natural gas production combined with a $0.24 per Mcf increase in the weighted average price of natural gas after hedging.

The increase in natural gas production was largely due to additional production from new Marcellus and Utica wells in the Appalachian region during the six months ended March 31, 2023 as compared with the six months ended March 31, 2022.

Oil production revenue after hedging decreased $70.9 million due to the sale of the California assets.

In addition, other revenue decreased $1.9 million and gas processing plant revenue decreased $1.4 million.

The decrease in other revenue was attributed to higher temporary capacity releases during the six months ended March 31, 2022 when compared to the six months ended March 31, 2023, combined with a decrease in operating revenue from this segment's water treatment plants.

The decrease in gas processing plant revenue was mainly attributed to the sale of the California assets.

The Exploration and Production segment's earnings for the quarter ended March 31, 2023 were $61.0 million, a decrease of $10.1 million when compared with earnings of $71.1 million for the quarter ended March 31, 2022.

The decrease in earnings was attributed to lower natural gas prices after hedging ($1.3 million), lower oil production ($28.7 million), higher depletion expense ($6.4 million) and an unrealized loss on contingent consideration received as part of the California asset sale ($1.8 million).

A decrease in other revenue ($2.0 million) and gas processing plant revenue ($0.6 million), both of which are discussed above, also contributed to the decrease in earnings.

These decreases were partially offset by higher natural gas production ($19.1 million), lower lease operating and transportation expenses ($5.3 million), lower other operating expenses ($3.2 million), lower other taxes ($1.9 million) and higher other income ($1.0 million).

The increase in depletion expense was primarily due to the net increase in production combined with a $0.05 per Mcf increase in the depletion rate.

The decrease in lease operating and transportation expenses was primarily the result of the sale of the California assets, partially offset by higher gathering and transportation costs combined with higher lease operating expenses in the Appalachian region.

The decrease in other operating expenses was primarily attributed to the California asset sale.

The increase in other income was attributed to interest income received on hedging collateral deposits, an unrealized gain on contingent consideration received as part of the California asset sale, as well as non-service pension and post-retirement income in the quarter ended December 31, 2022 compared to non-service pension and post-retirement benefit costs in the quarter ended December 31, 2021.

The decrease in other taxes was primarily

attributed to both the impact of the sale of Seneca's California assets as well as lower Impact Fees in the Appalachian region.

The increase in other income was attributed to higher interest income, as well as non-service pension and post-retirement benefit income in the quarter ended March 31, 2023 compared to non-service pension and post-retirement benefit costs in the quarter ended March 31, 2022.

The Exploration and Production segment's earnings for the six months ended March 31, 2023 were $152.2 million, an increase of $18.7 million when compared with earnings of $133.5 million for the six months ended March 31, 2022.

The increase in earnings was primarily attributable to higher natural gas production ($36.5 million) and higher natural gas prices after hedging ($34.5 million) as discussed above.

Other factors contributing to the earnings increase included lower lease operating and transportation expenses ($11.3 million), lower other operating expenses ($6.5 million), lower other taxes ($0.9 million) and higher other income ($2.3 million).

Partially offsetting these items, the Exploration and Production segment experienced lower oil production ($56.1 million), lower other revenue ($1.5 million) and lower gas processing plant revenue ($1.1 million), all of which are discussed above.

Other factors that decreased earnings included higher depletion expense ($11.1 million), higher interest expense ($0.9 million), higher income tax expense ($1.1 million) and an unrealized loss on contingent consideration received as part of the California asset sale ($1.7 million).

The decrease in lease operating and transportation expenses was primarily the result of the sale of the California assets, partially offset by higher gathering and transportation costs combined with higher lease operating expenses in the Appalachian region.

The decrease in other operating expenses was primarily attributed to the California asset sale.

The decrease in other taxes was attributed to the impact of the California asset sale, partially offset by higher Impact Fees in the Appalachian region.

The increase in other income was attributed to higher interest income, as well as non-service pension and post-retirement income in the six months ended March 31, 2023 compared to non-service pension and post-retirement benefit costs in the six months ended March 31, 2022.

The increase in depletion expense was primarily due to the net increase in production combined with a $0.04 per Mcf increase in the depletion rate.

The increase in other taxes was attributed to higher Impact Fees in the Appalachian region offset partially by lower production and other taxes as a result of the California asset sale.

The increase in interest expense can largely be attributed to a higher average interest rate on intercompany short-term borrowings.

The increase in income tax expense was primarily driven by a prior year first quarter benefit realized from the Enhanced Oil Recovery tax credit, which did not recur in the current year as a result of the sale of the California assets.

The increase in interest expense can largely be attributed to a higher average interest rate on intercompany short-term borrowings partially offset by lower interest on intercompany long-term borrowings due to the Company's redemption of $500.0 million of 3.75% notes during the six months ended March 31, 2023.

The increase in income tax expense was primarily driven by a prior-year benefit realized from the Enhanced Oil Recovery tax credit, which did not recur in the current year as a result of the sale of the California assets.

Pipeline and Storage

1 unchanged sentence

Three Months Ended

March 31, Six Months Ended

(Thousands) 2023 2022 Increase

(Decrease) 2023 2022 Increase

Firm Transportation $ 73,487 $ 72,259 $ 1,228 $ 148,944 $ 138,084 $ 10,860

7 unchanged sentences

Three Months Ended

March 31, Six Months Ended

(MMcf) 2023 2022 Increase

(Decrease) 2023 2022 Increase

Firm Transportation 231,081 232,030 (949) 455,705 425,623 30,082

2 unchanged sentences

2023 Compared with 2022

Operating revenues for the Pipeline and Storage segment increased $9.3 million for the quarter ended December 31, 2022 as compared with the quarter ended December 31, 2021.

The increase in operating revenues was primarily due to increases in transportation revenues of $9.9 million and storage revenues of $0.5 million, partially offset by a decrease in other revenue of $1.1 million.

Operating revenues for the Pipeline and Storage segment decreased $0.3 million for the quarter ended March 31, 2023 as compared with the quarter ended March 31, 2022.

The decrease in operating revenues was primarily due to a decrease in other revenue of $1.4 million, partially offset by an increase in transportation revenues of $1.1 million.

The decrease in other revenue primarily reflects an adjustment to electric surcharge revenues and lower cashout revenues.

All customer surcharges and related adjustments for the electric surcharge mechanism are completely offset by an equal amount of electric power costs recorded in operation and maintenance expense.

Cashout revenues are completely offset by purchased gas expense.

The increase in transportation revenues was primarily attributable to Period 2 Rates that went into effect April 1, 2022.

These Period 2 Rates were a negotiated revenue step-up as part of the FM100 Project that was placed into service in December 2021, as specified in Supply Corporation's 2020 rate case settlement.

An increase in short-term contracts also contributed to the increase in transportation revenues.

These increases were partially offset by a decline in revenues associated with miscellaneous contract terminations and revisions.

Operating revenues for the Pipeline and Storage segment increased $9.0 million for the six months ended March 31, 2023 as compared with the six months ended March 31, 2022.

The increase in operating revenues was primarily due to an increase in transportation revenues of $11.1 million and an increase in storage revenues of $0.5 million, partially offset by a decrease in other revenue of $2.5 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.

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 mentioned above.

An increase in short-term contracts also contributed to the increase in transportation revenues.

These increases were partially offset by a decline in revenues associated with miscellaneous contract terminations.

These increases were partially offset by a decline in revenues associated with miscellaneous contract terminations and revisions.

The increase in storage revenues was mainly due to the Period 2 Rates that went into effect April 1, 2022 related to the FM100 Project, as discussed above, as well as an increase in reservation charges for storage service from several new contracts that went into effect.

The decrease in other revenue primarily reflects lower electric surcharge true-up revenues.

Revenues collected through the electric surcharge mechanism are completely offset by an equal amount of electric power costs recorded in operation and maintenance expense.

Transportation volume for the quarter ended December 31, 2022 increased by 31.6 Bcf from the prior year's quarter primarily due to an increase in volume from the FM100 Project, which was brought online in December 2021, as well as an increase in short-term contracts and an increase in volume from colder weather.

These were partially offset by certain contract terminations during the quarter.

The decrease in other revenue primarily reflects an adjustment to electric surcharge revenues and lower cashout revenues.

Transportation volume for the quarter ended March 31, 2023 decreased by 1.1 Bcf from the prior year's quarter ended March 31, 2022.

For the six months ended March 31, 2023, transportation volume increased by 30.5 Bcf from the prior year's six-month period ended March 31, 2022.

The increase in transportation volume for the six-month period primarily reflects an increase in 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 certain contract terminations during the six months ended March 31, 2023.

Volume fluctuations, other than those caused by the addition or termination of contracts, generally do not have a significant impact on revenues as a result of the straight fixed-variable rate design utilized by Supply Corporation and Empire.

The Pipeline and Storage segment’s earnings for the quarter ended December 31, 2022 were $29.5 million, an increase of $4.3 million when compared with earnings of $25.2 million for the quarter ended December 31, 2021.

The increase in earnings was primarily due to the earnings impact of higher operating revenues of $7.4 million, as discussed above, combined with an increase in other income of $0.6 million.

The Pipeline and Storage segment’s earnings for the quarter ended March 31, 2023 were $23.9 million, a decrease of $1.6 million when compared with earnings of $25.5 million for the quarter ended March 31, 2022.

The decrease in earnings was primarily due to an increase in operating expenses of $2.2 million, combined with the earnings impact of lower operating revenues of $0.2 million, as discussed above.

The increase in operating expenses was primarily due to higher personnel costs, higher pipeline integrity costs and an increase in compressor maintenance costs.

This was partially offset by lower power costs related to Empire's electric motor drive compressor station.

This reduction in electric power costs is offset by an equal reduction in revenue, as discussed above.

These earnings decreases were partially offset by an increase in other income of $0.9 million, which was primarily due to a higher weighted average interest rate on intercompany short-term notes receivables along with higher non-service pension and post-retirement benefit income.

This was partially offset by a decrease in the allowance for funds used during construction (equity component) related to an annual adjustment that was recorded during the current quarter.

The Pipeline and Storage segment’s earnings for the six months ended March 31, 2023 were $53.3 million, an increase of $2.7 million when compared with earnings of $50.6 million for the six months ended March 31, 2022.

The increase in earnings was primarily due to the earnings impact of higher operating revenues of $7.1 million, as discussed above, combined with an increase in other income ($1.5 million).

The increase in other income is primarily due to a higher weighted average interest rate on intercompany short-term notes receivables along with higher non-service pension and post-retirement benefit income.

This was partially offset by a decrease in the allowance for funds used during construction (equity component) related to the construction of the FM100 Project that was placed into service in December 2021.

This was partially offset by a decrease in allowance for funds used during construction (equity component) related to the construction of the FM100 Project that was placed into service in December 2021 along with an annual adjustment that was recorded during the current fiscal year.

These earnings increases were partially offset by increases in operating expenses ($3.7 million), depreciation expense ($1.6 million) and interest expense ($0.9 million).

The increase in operating expenses was primarily due to higher personnel costs, timing of dues and memberships and higher pipeline integrity costs.

The increase in operating expenses was primarily due to higher personnel costs, higher pipeline integrity costs and an increase in compressor maintenance costs.

This was partially offset by lower power costs related to Empire's electric motor drive compressor station.

The electric power costs are offset by an equal amount of revenue, as discussed above.

The increase in depreciation expense was primarily due to incremental depreciation from Supply Corporation's FM100 Project going into service in December 2021.

The increase in interest expense is primarily due to a decrease in the allowance for funds used during construction (debt component) related to the construction of the FM100 Project, discussed above, combined with higher interest rates on security deposits.

This reduction in electric

power costs is offset by an equal reduction in revenue, as discussed above.

The increase in depreciation expense was primarily due to incremental depreciation from the FM100 Project going into service in December 2021.

The increase in interest expense was mainly due to higher interest rates on security deposits and intercompany short-term borrowings, partially offset by a decrease in interest on intercompany long-term borrowings due to the Company's redemption of $500.0 million of 3.75% notes during the six months ended March 31, 2023.

Gathering Operating Revenues

Three Months Ended

March 31, Six Months Ended

(Thousands) 2023 2022 Increase

(Decrease) 2023 2022 Increase

Gathering Revenues $ 56,981 $ 52,604 $ 4,377 $ 113,394 $ 104,829 $ 8,565

1 unchanged sentence

Three Months Ended

March 31, Six Months Ended

2023 2022 Increase

(Decrease) 2023 2022 Increase

Gathered Volume - (MMcf) 109,344 103,736 5,608 217,371 204,829 12,542

2023 Compared with 2022

Operating revenues for the Ga thering segment increased $4.2 million for the quarter ended December 31, 2022 as compared with the quarter ended December 31, 2021, which was driven primarily by a 6.9 Bcf increase in gathered volume.

Operating revenues for the Ga thering segment increased $4.4 million for the quarter ended March 31, 2023 as compared with the quarter ended March 31, 2022, which was driven primarily by a 5.6 Bcf increase in gathered volume.

The increase in gathered volume can be attributed primarily to an increase in natural gas production on the Covington and Clermont gathering systems, which recorded increases of 14.9 Bcf and 4.2 Bcf, respectively, partially offset by decreases on the Trout Run and Wellsboro gathering systems, which recorded decreases of 8.6 Bcf and 4.9 Bcf, respectively.

The net increase can be attributed to an increase in gross natural gas production in the Appalachian region by producers connected to the aforementioned gathering systems.

The Gathering segment’s earnings for the quarter ended December 31, 2022 were $24.7 million, an increase of $1.6 million when compared with earnings of $23.1 million for the quarter ended December 31, 2021.

Operating revenue s for the Gathering segment increased $8.6 million for the six months ended March 31, 2023 as compared with the six months ended March 31, 2022, which was driven primarily by a 12.5 Bcf increase in gathered volume.

Contributors to the increase included the Covington and Clermont gathering systems, which recorded increases of 31.1 Bcf and 5.7 Bcf, respectively, partially offset by the Trout Run and Wellsboro gathering systems, which recorded decreases of 18.6 Bcf and 5.7 Bcf, respectively.

The net increase can be attributed to an increase in gross natural gas production in the Appalachian region by producers connected to the aforementioned gathering systems.

The Gathering segment’s earnings for the quarter ended March 31, 2023 were $24.3 million, an increase of $2.2 million when compared with earnings of $22.1 million for the quarter ended March 31, 2022.

The increase in earnings was mainly due to higher gathering revenues ($3.5 million) driven by the increase in gathered volume, as discussed above.

This increase was partially offset by higher operating expenses ($1.2 million) and higher income tax expense ($0.6 million).

The increase in operating expenses was largely attributable to higher leased compression costs on the Trout Run and Covington gathering systems as well as higher compressor repairs and services on the Clermont and Covington gathering systems.

These increases were partially offset by higher operating expenses ($0.9 million) and higher depreciation expense ($0.4 million).

The increase in operating expenses was largely attributable to higher leased compression and material costs on the Trout Run and Covington gathering systems combined with higher labor costs across all of the gathering systems.

The increase in depreciation expense was largely due to higher plant balances associated with the Covington and Clermont gathering systems.

The Gathering segment’s earnings for the six months ended March 31, 2023 were $49.1 million, an increase of $3.9 million when compared with earnings of $45.2 million for the six months ended March 31, 2022.

The increase in earnings was mainly due to higher gathering revenues ($6.8 million) driven by the increase in gathered volume, as discussed above.

This increase was partially offset by higher operating expenses ($2.1 million) and higher depreciation expense ($0.7 million).

The increase in operating expenses was largely attributable to higher leased compression costs on the Trout Run and Covington gathering systems, higher material costs on the Clermont and Covington gathering systems and higher labor costs across all of the gathering systems.

The increase in depreciation expense was largely due to higher plant balances associated with the Covington and Clermont gathering systems.

Utility Operating Revenues

Three Months Ended

March 31, Six Months Ended

(Thousands) 2023 2022 Increase

(Decrease) 2023 2022 Increase

Retail Sales Revenues:

8 unchanged sentences

Three Months Ended

March 31, Six Months Ended

(MMcf) 2023 2022 Increase

(Decrease) 2023 2022 Increase

Retail Sales:

5 unchanged sentences

55,323 62,962 (7,639) 96,931 100,717 (3,786)

Three Months Ended December 31, Percent Colder (Warmer) Than

Three Months Ended March 31, Percent Colder (Warmer) Than

Normal 2023 2022 Normal (1)

2 unchanged sentences

Erie, PA 3,108 2,645 2,973 (14.9) % (11.0) %

Six Months Ended March 31,

Buffalo, NY 5,543 4,868 4,865 (12.2) % 0.1 %

Erie, PA 5,152 4,632 4,533 (10.1) % 2.2 %

(1) Percents compare actual 2023 degree days to normal degree days and actual 2023 degree days to actual 2022 degree days.

2023 Compared with 2022

Operating revenues for the Utility segment increased $74.9 million for the quarter ended December 31, 2022 as compared with the quarter ended December 31, 2021.

The increase resulted from a $73.3 million increase in retail gas sales revenue, which was primarily due to a significant increase in the cost of gas sold (per Mcf), as well as a 3.1 Bcf increase in throughput due to colder weather.

Under its purchased gas adjustment clauses in New York and Pennsylvania, Distribution Corporation is not allowed to profit from fluctuations in gas costs.

This increase in retail gas sales revenue was partially offset by a decrease in base rates related to a tariff filing approved by the NYPSC, which created a surcredit that temporarily eliminates pension and OPEB cost recovery from base rates effective October 1, 2022.

Operating revenues for the Utility segment increased $37.9 million for the quarter ended March 31, 2023 as compared with the quarter ended March 31, 2022.

The increase resulted largely from a $40.2 million increase in retail gas sales revenue.

This increase primarily reflects an increase in the cost of gas sold (per Mcf), partially offset by a 4.7 Bcf decrease in throughput due to warmer weather and a decrease in base rates.

It should be noted that 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.

Revenues collected in 2023 reflect not only the current cost of gas but also the collection of previously deferred under collected gas costs.

The decrease in base rates is related to a tariff filing approved by the NYPSC, which created a surcredit that temporarily eliminates pension and

OPEB cost recovery from base rates effective October 1, 2022.

Additional details related to the regulatory proceeding are discussed in the Rate Matters section and in Item 1 at Note 11 - Regulatory Matters.

In addition, there was a $0.1 million decrease in transportation revenues and a $1.7 million increase in other revenues.

The decrease in transportation revenues, in spite of a 0.7 Bcf increase in throughput, is mainly attributable to a decrease in base rates, as a result of the NYPSC tariff filing related to Pension and OPEB costs discussed above, which was partially offset by an increase in the system modernization tracker allocation to transportation customers.

The increase in other revenues is the result of a regulatory adjustment ($1.0 million), higher capacity release revenues ($0.7 million) and late payment charges billed to customers ($0.5 million).

These increases were partially offset by a larger estimated refund provision from the income tax benefits resulting from the 2017 Tax Reform Act ($0.5 million).

The Utility segment’s earnings for the quarter ended December 31, 2022 were $23.8 million, an increase of $1.7 million when compared with earnings of $22.1 million for the quarter ended December 31, 2021.

The increase in earnings was mainly attributable to an increase in usage due to colder weather ($3.3 million), higher other operating revenues ($1.0 million), and the impact of a system modernization tracker in New York ($0.9 million).

Higher other income of $0.5 million, consisting largely of interest on deferred gas costs, also contributed to the earnings increase.

These increases were partially offset by a reduction in the New York jurisdiction’s base rates resulting from the NYPSC tariff filing related to pension and OPEB costs discussed above, which temporarily eliminated the recovery of pension and OPEB expenses effective October 1, 2022 and reduced earnings for the quarter ($3.7 million).

With the elimination of pension and OPEB expenses in customer rates, earnings benefited from a decrease in non-service pension and post-retirement benefit costs ($3.6 million), as Distribution Corporation’s New York service territory recognized pension and OPEB income during the quarter ended December 31, 2022 compared to the prior year period when it recognized pension and OPEB expenses to match against the pension and OPEB amounts collected in base rates.

The Utility segment also experienced higher operating expenses ($2.4 million) and higher interest expense ($2.0 million) when comparing the quarter ended December 31, 2022 to the quarter ended December 31, 2021.

The increase in operating expenses was primarily due to higher personnel costs and an increase in the provision for uncollectible accounts, due to higher gas costs.

In addition to the overall increase in retail gas sales revenue, there was a $2.3 million increase in other revenues.

The increase in other revenues is the result of higher capacity release revenues ($1.1 million) and a smaller estimated refund provision from the income tax benefits resulting from the 2017 Tax Reform Act ($1.4 million).

Partially offsetting the impact of higher retail gas sales revenue and other revenues, there was a $4.6 million decrease in transportation revenues.

The decrease in transportation revenues is mainly attributable to a decrease in base rates, as a result of the NYPSC tariff filing related to pension and OPEB costs discussed above, as well as a 3.0 Bcf decrease in throughput due to warmer weather.

The decrease in transportation revenues was partially offset by an increase in the system modernization tracker allocation to transportation customers.

Operating revenues for the Utility segment increased $112.8 million for the six months ended March 31, 2023 as compared with the six months ended March 31, 2022.

The increase largely resulted from a $113.5 million increase in retail gas sales revenue and a $4.0 million increase in other revenues, which were partially offset by a $4.7 million decrease in transportation revenues.

The increase in retail gas sales revenue was primarily due to a considerable increase in the cost of gas sold (per Mcf) partially offset by a decrease in base rates, as a result of the NYPSC tariff filing related to pension and OPEB costs discussed above, as well as a 1.5 Bcf decrease in throughput due to warmer weather.

The increase in other revenues was largely due to higher capacity release revenues ($1.8 million), a smaller estimated refund provision from the income tax benefits resulting from the 2017 Tax Reform Act ($0.9 million), a positive regulatory adjustment ($0.9 million), and higher late payment charges billed to customers ($0.5 million).

The decrease in transportation revenues was largely due to a 2.2 Bcf decrease in transportation throughput during the six months ended March 31, 2023 and the decrease in base rates, as previously mentioned.

The decrease in transportation revenues was partially offset by an increase in the system modernization tracker allocation to transportation customers.

The Utility segment’s earnings for the quarter ended March 31, 2023 were $31.7 million, a decrease of $21.3 million when compared with earnings of $53.0 million for the quarter ended March 31, 2022.

The decrease in earnings was primarily attributable to the non-recurrence of an adjustment that increased earnings by $14.6 million during the quarter ended March 31, 2022.

The adjustment, which resulted from the conclusion of a proceeding in the Utility's Pennsylvania service territory, recognized the cumulative amount of OPEB income in that jurisdiction that previously had been deferred as a regulatory liability.

In addition to the non-recurrence of this transaction, there was a decrease in OPEB income ($1.7 million) in the Utility's Pennsylvania service territory quarter over quarter.

Other factors contributing to the decrease included a decrease in usage due to warmer weather ($2.9 million), higher interest expense ($3.4 million), and higher operating expenses ($1.7 million).

The increase in interest expense was largely the result of a higher weighted average interest rate on intercompany short-term borrowings.

The increase in operating expenses was mainly due to higher personnel costs and an increase in the accrual for uncollectible accounts.

An additional decrease of $6.3 million resulted from a reduction in the New York jurisdiction’s base rates as a result of the NYPSC tariff filing related to pension and OPEB costs discussed above, which temporarily eliminated the recovery of pension and OPEB expenses effective October 1, 2022.

This was offset by a decrease in non-service pension and post-retirement benefit costs ($6.6 million), as Distribution Corporation’s New York service territory ceased recognizing pension and OPEB expenses.

Partially offsetting these decreases, the Utility segment also experienced the positive earnings impact of a system modernization tracker in New York ($1.7 million), interest earned on deferred gas costs ($0.7 million), and lower income tax expense ($0.8 million) when comparing the quarter ended March 31, 2023 to the quarter ended March 31, 2022.

The impact of weather variations on earnings in the Utility segment's New York rate jurisdiction is mitigated by that jurisdiction's weather normalization clause (WNC).

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In addition, in periods of colder than normal weather, the WNC benefits the Utility segment's New York customers.

For the quarter ended December 31, 2022, the WNC increased earnings by approximately $0.9 million, as the weather was warmer than normal.

For the quarter ended December 31, 2021, the WNC increased earnings by approximately $2.6 million, as the weather was warmer than normal.

For the quarter ended March 31, 2023, the WNC increased earnings by approximately $3.3 million, as the weather was warmer than normal.

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

The Utility segment’s earnings for the six months ended March 31, 2023 were $55.5 million, a decrease of $19.7 million when compared with earnings of $75.2 million for the six months ended March 31, 2022.

The decrease is primarily attributable to the non-recurrence of an adjustment that increased earnings by $14.6 million during the quarter ended March 31, 2022, as discussed above.

In addition to the non-recurrence of this transaction, there was a decrease in OPEB income ($1.6 million) in the Utility's Pennsylvania service territory period over period.

The reduction in the New York jurisdiction's base rates resulting from the NYPSC tariff filing also discussed above ($10.1 million), higher interest expense primarily due to a

higher weighted average interest rate on intercompany short-term borrowings ($5.4 million), and higher operating expenses ($4.1 million) resulting from higher personnel costs and an increase in the accrual for uncollectible accounts also contributed to the decrease in earnings.

Given the elimination of pension and OPEB expense in customer rates, earnings benefited from a decrease in non-service pension and OPEB costs ($10.2 million) in Distribution Corporation's New York service territory, as a result of the NYPSC tariff filing, discussed above.

In addition, the impact of a system modernization tracker in New York ($2.6 million), higher other operating revenues ($1.7 million), and lower income tax expense ($0.7 million) partially offset the decrease in earnings when comparing the six months ended March 31, 2023, to the six months ended March 31, 2022.

Other operating revenues increased largely due to higher capacity release revenues.

For the six months ended March 31, 2023, the WNC increased earnings by approximately $4.2 million, as the weather was warmer than normal.

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

Corporate and All Other

2023 Compared with 2022

Corporate and All Other operations had earnings of $0.5 million for the quarter ended December 31, 2022, an increase of $0.9 million when compared with a loss of $0.4 million for the quarter ended December 31, 2021.

The increase was primarily attributable to changes in unrealized gains and losses on investments in equity securities.

During the quarter ended December 31, 2022, the Company recorded unrealized gains of $0.2 million.

During the quarter ended December 31, 2021, the Company recorded unrealized losses of $3.5 million.

These changes were offset by a decrease in realized gains from sales of investments in equity securities ($2.9 million).

Corporate and All Other operations had a net loss of less than $0.1 million for the quarter ended March 31, 2023, a decrease in net loss of $4.4 million when compared with the quarter ended March 31, 2022 .

The reduction in net loss was primarily attributable to changes in unrealized gains and losses on investments in equity securities.

During the quarter ended March 31, 2023, the Company recorded unrealized gains of $0.8 million.

During the quarter ended March 31, 2022, the Company recorded unrealized losses of $1.7 million.

Also contributing to the reduction in net loss were changes in cash surrender value of life insurance policies, which increased in value $0.4 million during the current quarter compared to a decrease in value of $0.7 million during the prior-year second quarter.

For the six months ended March 31, 2023, Corporate and All Other operations had earnings of $0.5 million, an increase of $5.3 million when compared with a net loss of $4.8 million for the six months ended March 31, 2022.

The increase in earnings was primarily attributable to changes in unrealized gains and losses on investments in equity securities.

During the six months ended March 31, 2023, the Company recorded unrealized gains of $1.0 million.

During the six months ended March 31, 2022, the Company recorded unrealized losses of $5.3 million.

Lower non-service pension and post-retirement benefit costs ($1.0 million) also contributed to the increase in earnings.

These changes were partially offset by a decrease in realized gains from sales of investments in equity securities ($2.9 million).

Other Income (Deductions)

Net other income on the Consolidated Statement of Income was $6.3 million for the quarter ended December 31, 2022, compared to net other deductions of $1.1 million for the quarter ended December 31, 2021.

This change is primarily attributable to non-service pension and post-retirement benefit income of $1.4 million for the quarter ended December 31, 2022 as compared to non-service pension and post-retirement benefit expense of $4.8 million for the quarter ended December 31, 2021.

As discussed above in the Utility segment, this is largely related to a tariff filing approved by the NYPSC during September 2022 in Distribution Corporation's New York service territory, which created a surcredit that temporarily eliminates pension and OPEB cost recovery from base rates effective October 1, 2022.

Accordingly, no pension and OPEB expenses were recorded during the quarter ended December 31, 2022 for that jurisdiction.

Other income (deductions) was also impacted by an increase in other interest income of $2.0 million.

This was driven by an increase in interest on temporary cash investments, increased interest on a larger undercollection of gas costs over the prior year in Distribution Corporation and an increase in interest received from hedging collateral deposits in the Exploration and Production segment.

These increases were partially offset by a decrease in the allowance for funds used during construction (equity component) of $1.0 million.

Net other income on the Consolidated Statement of Income was $2.9 million for the quarter ended March 31, 2023, compared to net other income of $10.0 million for the quarter ended March 31, 2022.

This change is primarily attributable to an $11.2 million decrease in non-service pension and post-retirement benefit income quarter over quarter.

This is largely related to lower non-service post-retirement benefit income in the Utility’s Pennsylvania service territory stemming from the conclusion of a rate proceeding in the Utility’s Pennsylvania service territory during the quarter ended March 31, 2022.

As a result of that proceeding, a one-time adjustment was recorded to reduce a regulatory liability in that jurisdiction by $18.5 million.

This decrease in OPEB income was partially offset by an $8.3 million decrease in non-service pension and post-retirement benefit expense in the Utility’s New York Service territory as a result of a tariff filing that became effective October 1, 2022.

Additional details related to the regulatory proceedings are discussed in the Rate Matters section and in Item 1, Note 11 – Regulatory Matters.

Net other income on the Consolidated Statement of Income was $9.2 million for the six months ended March 31, 2023, compared to net other income of $8.9 million for the six months ended March 31, 2022.

Higher interest income of $4.6 million contributed to the increase.

This was primarily due to an increase in interest on temporary cash investments, increased interest on a larger undercollection of gas costs over the prior year in Distribution Corporation and an increase in interest received from hedging collateral deposits in the Exploration and Production segment.

Changes in unrealized and realized gains and losses on investments in equity securities also increased other income by $5.1 million period over period.

Offsetting these increases, there was a $5.0 million reduction in non-service pension and post-retirement benefit income period over period.

As discussed above, the Utility's Pennsylvania service territory recorded a one-time adjustment that resulted in $18.5 million of income during the quarter ended March 31, 2022.

The resulting earnings reduction in 2023 was largely offset by a $12.9 million decrease in non-service pension and post-retirement benefit expense in the Utility's New York service territory as a result of the

tariff filing that became effective October 1, 2022.

Other offsetting factors include a mark-to-market adjustment that reduced the value of the contingent consideration received from the sale of Seneca's California assets in June 2022 and a $1.9 million reduction in allowance for funds used during construction.

Interest Expense on Long-Term Debt

Interest expense on long-term debt on the Consolidated Statement of Income decreased $0.5 million for the quarter ended December 31, 2022 as compared to the quarter ended December 31, 2021, primarily due to the November 2022 redemption of $150.0 million of the $500.0 million 3.75% note due March 2023.

Interest expense on long-term debt on the Consolidated Statement of Income decreased $2.5 million for the quarter ended March 31, 2023 as compared to the quarter ended March 31, 2022.

For the six months ended March 31, 2023, interest expense on long-term debt decreased $3.0 million as compared with the six months ended March 31, 2022.

This was primarily due to the March 2023 redemptions of $350.0 million of the $500.0 million 3.75% note and the $49.0 million 7.395% note.

In addition, $150.0 million of the $500.0 million 3.75% note was redeemed in November 2022, which also contributed to the decrease.

CAPITAL RESOURCES AND LIQUIDITY

The Company’s primary sources of cash during the three-month period ended December 31, 2022 consisted of cash provided by operating activities, proceeds from short-term borrowings and proceeds from the sale of a fixed income mutual fund held in a grantor trust.

The Company’s primary sources of cash during the three-month period ended December 31, 2021 consisted of cash provided by operating activities and proceeds from the sale of a fixed income mutual fund held in a grantor trust.

The Company’s primary sources of cash during the six-month period ended March 31, 2023 consisted of cash provided by operating activities, proceeds from short-term borrowings and proceeds from the sale of a fixed income mutual fund held in a grantor trust.

The Company’s primary sources of cash during the six-month period ended March 31, 2022 consisted of cash provided by operating activities, net proceeds from short-term borrowings, proceeds from the sale of a fixed income mutual fund held in a grantor trust and net proceeds from the sale of oil and gas properties.

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 the remainder of 2023, cash provided by operating activities is expected to increase over the amount of cash provided by operating activities when compared to the same period in 2022 and will be used to fund the Company's capital expenditures.

There are two long-term debt maturities in March 2023, of which $399 million are outstanding.

The Company expects to repay those securities through the use of cash on hand at the date of maturity and short-term borrowings.

Based on current commodity prices, cash provided by operating activities is expected to exceed capital expenditures in fiscal 2023 and 2024.

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.

During the remainder of 2023, cash provided by operating activities is expected to increase when compared to the same period in 2022 and will be used to fund the Company's capital expenditures.

Based on current commodity prices, cash provided by operating activities is expected to exceed capital expenditures in 2024.

This is expected to provide the Company with the option to consider additional growth investments, further reductions in short-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.

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The Company uses various derivative financial instruments, including price swap agreements and no cost collars, in an attempt to manage this energy commodity price risk.

Net cash provided by operating activities totaled $327.3 million for the three months ended December 31, 2022, an increase of $155.8 million compared with $171.5 million provided by operating activities for the three months ended December 31, 2021.

The increase in cash provided by operating activities primarily reflects higher cash provided by operating activities in the Exploration and Production segment primarily due to higher cash receipts from natural gas production in the Appalachian region and higher realized natural gas prices.

Net cash provided by operating activities totaled $711.2 million for the six months ended March 31, 2023, an increase of $285.6 million compared with $425.6 million provided by operating activities for the six months ended March 31, 2022.

Investing Cash Flow

Expenditures for Long-Lived Assets

The Company’s expenditures for long-lived assets totaled $223.5 million during the three months ended December 31, 2022 and $191.8 million during the three months ended December 31, 2021.

The Company’s expenditures for long-lived assets totaled $440.6 million during the six months ended March 31, 2023 and $376.2 million during the six months ended March 31, 2022.

The table below presents these expenditures:

Total Expenditures for Long-Lived Assets

Three Months Ended December 31, 2022 2021 Increase (Decrease)

Six Months Ended March 31, 2023 2022 Increase (Decrease)

Exploration and Production:

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$ 440.6 $ 376.2 $ 64.4

(1) At December 31, 2022, capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment include $102.9 million, $2.1 million, $1.1 million and $4.2 million, respectively, of non-cash capital expenditures.

(1) At March 31, 2023, capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment include $56.1 million, $2.2 million, $2.0 million and $4.2 million, respectively, of non-cash capital expenditures.

At September 30, 2022, capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment included $83.0 million, $15.2 million, $10.7 million and $11.4 million, respectively, of non-cash capital expenditures.

(2) At December 31, 2021, capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment included $69.9 million, $5.4 million, $2.6 million and $3.1 million, respectively, of non-cash capital expenditures.

(2) At March 31, 2022, capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment included $52.5 million, $3.5 million, $3.4 million and $4.1 million, respectively, of non-cash capital expenditures.

At September 30, 2021, capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment included $47.9 million, $39.4 million, $4.8 million and $10.6 million, respectively, of non-cash capital expenditures.

Exploration and Production

The Exploration and Production segment capital expenditures for the three months ended December 31, 2022 were primarily well drilling and completion expenditures in the Appalachian region (including $60.9 million in the Marcellus Shale area and $104.6 million in the Utica Shale area).

The Exploration and Production segment capital expenditures for the six months ended March 31, 2023 were primarily well drilling and completion expenditures in the Appalachian region (including $143.2 million in the Marcellus Shale area and $172.4 million in the Utica Shale area).

These amounts included approximately $208.2 million spent to develop proved undeveloped reserves.

The Exploration and Production segment capital expenditures for the three months ended December 31, 2021 were primarily well drilling and completion expenditures and included approximately $132.1 million for the Appalachian region (including $45.1 million in the Marcellus Shale area and $83.3 million in the Utica Shale area) and $7.1 million for the West Coast region.

The Exploration and Production segment capital expenditures for the six months ended March 31, 2022 were primarily well drilling and completion expenditures and included approximately $258.8 million for the Appalachian region (including $84.8 million in the Marcellus Shale area and $166.8 million in the Utica Shale area) and $15.2 million for the West Coast region.

These amounts included approximately $93.4 million spent to develop proved undeveloped reserves.

Pipeline and Storage

The Pipeline and Storage segment capital expenditures for the three months ended December 31, 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.

The Pipeline and Storage segment capital expenditures for the three months ended December 31, 2021 were primarily for expenditures related to Supply Corporation's FM100 Project ($15.7 million).

In addition, the Pipeline and Storage segment capital expenditures for the three months ended December 31, 2021 included additions, improvements and replacements to this segment’s transmission and gas storage systems.

The majority of the Gathering segment capital expenditures for the three months ended December 31, 2022 included expenditures related to the continued expansion of Midstream Company's Clermont and Covington gathering systems, as

discussed below.

Midstream Company spent $5.7 million and $5.2 million, respectively, during the three months ended December 31, 2022 on the development of the Clermont and Covington gathering systems.

These expenditures were largely attributable to the installation of new in-field gathering pipelines in the Clermont gathering system.

The Pipeline and Storage segment capital expenditures for the six months ended March 31, 2023 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.

The Pipeline and Storage segment capital expenditures for the six months ended March 31, 2022 were primarily for expenditures related to Supply Corporation's FM100 Project ($21.0 million).

In addition, the Pipeline and Storage segment capital expenditures for the

six months ended March 31, 2022 included additions, improvements and replacements to this segment’s transmission and gas storage systems.

The majority of the Gathering segment capital expenditures for the six months ended March 31, 2023 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 $10.2 million, $10.4 million, $3.8 million and $6.4 million, respectively, during the six months ended March 31, 2023 on the development of the Clermont, Covington, Trout Run, and Wellsboro gathering systems.

These expenditures were largely attributable to the installation of new in-field gathering pipelines, as well as the continued development 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 expansion of on-pad and centralized station facilities related to bringing new development online.

The majority of the Gathering segment capital expenditures for the three months ended December 31, 2021 included expenditures related to the continued expansion of Midstream Company's Clermont and Covington gathering systems.

Midstream Company spent $4.0 million and $4.5 million, respectively, during the three months ended December 31, 2021 on the development of the Clermont and Covington gathering systems.

These expenditures were largely attributable to new Clermont gathering pipelines, as well as the development of new gathering facilities, including new gathering pipelines and upgrades to existing stations in the Tioga gathering system.

NFG Midstream Covington, LLC, a wholly-owned subsidiary of Midstream Company, operates its Covington gathering system as well as the Tioga gathering system, 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.

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.

The majority of the Utility segment capital expenditures for the three months ended December 31, 2022 and December 31, 2021 were made for main and service line improvements and replacements that enhance the reliability and safety of the system and reduce emissions.

The majority of the Gathering segment capital expenditures for the six months ended March 31, 2022 included expenditures related to the continued expansion of Midstream Company's Clermont and Covington gathering systems.

Midstream Company spent $8.7 million and $10.6 million, respectively, during the six months ended March 31, 2022 on the development of the Clermont and Covington gathering systems.

These expenditures were largely attributable to the installation of new in-field gathering pipelines in the Clermont gathering system, as well as the development of new gathering facilities, including new in-field gathering pipelines and station upgrades in the Tioga gathering system.

The majority of the Utility segment capital expenditures for the six months ended March 31, 2023 and March 31, 2022 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.

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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, all of which are in the Exploration and Production segment, 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 fair value of the contingent consideration was $5.9 million at March 31, 2023.

The Company pursued this sale given the strong commodity price environment and the Company’s strategic focus in the Appalachian Basin.

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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 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.

On March 22, 2023, the Company entered into a purchase and sale agreement to acquire certain upstream assets located in Potter and Tioga counties, Pennsylvania from SWN Production Company, LLC effective as of January 1, 2023 for total consideration of $127.0 million, subject to certain purchase price adjustments at closing.

These assets are contiguous with existing Company owned upstream assets in Pennsylvania.

The Company made a deposit of $12.7 million at the signing of the purchase and sale agreement and intends to finance the remaining acquisition cost using short and/or long-term borrowings.

The transaction is expected to close before the end of June 2023.

Project Funding

Over the past two years, the Company has been financing capital expenditures with cash from operations, short-term and long-term debt and proceeds from the sale of the Company's California assets.

During the three months ended December 31, 2022 and December 31, 2021, capital expenditures were funded with cash from operations and short-term debt.

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 natural gas production, and the associated commodity price realizations, as well as the level of hedging collateral deposits in the Exploration and Production segment.

Over the past two years, the Company has been financing capital expenditures with cash from operations, short-term debt and proceeds from the sale of the Company's California assets.

During the six months ended March 31, 2023 and March 31, 2022, capital expenditures were funded with cash from operations and short-term debt.

Going forward, the Company expects to use cash on hand, cash from operations and short-term or long-term borrowings, as needed, to finance capital expenditures.

The level of short-term and/or long-term borrowings will depend upon the amount of cash provided by operations, which, in turn, will likely be most impacted by natural gas production, and the associated commodity price realizations, as well as the level of hedging collateral deposits in the Exploration and Production segment.

It will also likely depend on the timing of gas cost recovery in the Utility segment.

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The amounts are also subject to modification for opportunities involving carbon emission reductions and/or energy transition including investments directly related to low- and no-carbon fuels.

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.

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 business segments depends, to a large degree, upon market and regulatory conditions as well as legislative actions.

Financing Cash Flow

Consolidated short-term debt increased $190.0 million, to a total of $250.0 million, when comparing the balance sheet at December 31, 2022 to the balance sheet at September 30, 2022.

The maximum amount of short-term debt outstanding during the three months ended December 31, 2022 was $250.0 million.

Consolidated short-term debt increased $350.0 million, to a total of $410.0 million, when comparing the balance sheet at March 31, 2023 to the balance sheet at September 30, 2022.

The maximum amount of short-term debt outstanding during the six months ended March 31, 2023 was $410.0 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 could lead the Company to post margin with a number of its derivative counterparties.

Given the recent decline in natural gas prices, the Company's margin requirements decreased to $1.6 million as of December 31, 2022.

The Company's margin deposits are reflected on the balance sheet as a current asset titled Hedging Collateral Deposits.

As of December 31, 2022, the Company had outstanding short-term notes payable to banks of $250.0 million.

The Company did not have any commercial paper outstanding at December 31, 2022.

For example, during the six months ended March 31, 2023, the Company repaid $549.0 million of long-term debt with maturity dates in March 2023.

The Company utilized short-term borrowings and cash on hand to redeem the maturities, resulting in an increase in the short-term debt balance.

As of March 31, 2023, the Company had outstanding commercial paper of $160.0 million and short-term notes payable to banks of $250.0 million.

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.

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The Company elected to draw $250.0 million under the facility on October 27, 2022.

The Company used the proceeds for general corporate purposes, which included using $150.0 million for the November 2022 redemption of a portion of the Company's outstanding long-term debt with a maturity date in March 2023.

The Company also has uncommitted lines of credit with financial institutions for general corporate purposes.

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The commercial paper program is backed by the Credit Agreement, which provides that the Company's debt to capitalization ratio will not exceed .65 at the last day of any fiscal quarter.

For purposes of calculating the debt to capitalization ratio, the Company's total capitalization will be increased by adding back 50% of the aggregate after-tax amount of non-cash charges

directly arising from any ceiling test impairment occurring on or after July 1, 2018, not to exceed $400 million.

For purposes of calculating the debt to capitalization ratio, the Company's total capitalization will be increased by adding back 50% of the aggregate after-tax amount of non-cash charges directly arising from any ceiling test impairment occurring on or after July 1, 2018, not to exceed $400 million.

Since July 1, 2018, the Company recorded non-cash, after-tax ceiling test impairments totaling $381.4 million.

As a result, at December 31, 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.

As a result, at March 31, 2023, $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.

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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 December 31, 2022, the Company’s debt to capitalization ratio, as calculated under the Credit Agreement and 364-Day Credit Agreement, was .48.

The constraints specified in the Credit Agreement and 364-Day Credit Agreement would have permitted an additional $2.77 billion in short-term and/or long-term debt to be outstanding at December 31, 2022 (further limited by the indenture covenants discussed below) before the Company’s debt to capitalization ratio exceeded .65.

At March 31, 2023, the Company’s debt to capitalization ratio, as calculated under the Credit Agreement and 364-Day Credit Agreement, was .45.

The constraints specified in the Credit Agreement and 364-Day Credit Agreement would have permitted an additional $3.20 billion in short-term and/or long-term debt to be outstanding at March 31, 2023 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.

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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.

The Current Portion of Long-Term Debt at December 31, 2022 consists of $350.0 million of 3.75% notes and $49.0 million of 7.395% notes, that each mature in March 2023.

The Current Portion of Long-Term Debt at September 30, 2022 consisted of $500.0 million of 3.75% notes ($150.0 million of which was subsequently paid in November 2022) 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.

The Company’s embedded cost of long-term debt was 4.52% at December 31, 2022 and 4.48% at December 31, 2021.

Under the Company’s existing indenture covenants at December 31, 2022, the Company would have been permitted to issue up to a maximum of approximately $2.85 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.

None of the Company's long-term debt as of March 31, 2023 had a maturity date within the following twelve-month period.

The Company utilized short-term borrowings and cash on hand to repay $150.0 million of these maturities in November 2022 and the remaining $399.0 million in March 2023.

The Company’s embedded cost of long-term debt was 4.58% at March 31, 2023 and 4.48% at March 31, 2022.

Under the Company’s existing indenture covenants at March 31, 2023, the Company would have been permitted to issue up to a maximum of approximately $3.73 billion in additional unsubordinated long-term indebtedness at then current market interest rates, in addition to being able to issue new indebtedness to replace existing debt (further limited by debt to capitalization ratio constraints under the Company's Credit Agreement, as discussed above).

The Company's present liquidity position is believed to be adequate to satisfy known demands.

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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.

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 4.0%) of the Company’s long-term debt (as of December 31, 2022) was issued, contains a cross-default provision whereby the failure by the Company to perform certain obligations under other borrowing arrangements could trigger an obligation to repay the debt outstanding under the indenture.

The Company’s 1974 indenture pursuant to which $50.0 million (or 2.4%) of the Company’s long-term debt (as of March 31, 2023) 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.

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The Company will update the $500 million preliminary cost estimate and expected in-service date for the project when there is further clarity on the timing of receipt of necessary regulatory approvals.

As of December 31, 2022, approximately $55.9 million has been spent on the Northern Access project, including $24.3 million that has been spent to study the project.

The remaining $31.6 million spent on the project is included in Property, Plant and Equipment on the Consolidated Balance Sheet at December 31, 2022.

The Company did not make any contributions to its tax-qualified, noncontributory defined benefit retirement plan (Retirement Plan) or its VEBA trusts for its other post-retirement benefits during the three months ended December 31, 2022, and does not anticipate making any such contributions during the remainder of fiscal 2023.

As of March 31, 2023, approximately $55.9 million has been spent on the Northern Access project, including $24.3 million that has been spent to study the project.

The remaining $31.6 million spent on the project is included in Property, Plant and Equipment on the Consolidated Balance Sheet at March 31, 2023.

The Company did not make any contributions to its tax-qualified, noncontributory defined benefit retirement plan (Retirement Plan) or its VEBA trusts for its other post-retirement benefits during the six months ended March 31, 2023, and does not anticipate making any such contributions during the remainder of fiscal 2023.

Market Risk Sensitive Instruments

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The Dodd-Frank Act required the CFTC, SEC and other regulatory agencies to promulgate rules and regulations implementing the legislation, and includes provisions related to the swaps and over-the-counter derivatives markets that are designed to promote transparency, mitigate systemic risk and protect against market abuse.

Although regulators have issued certain regulations, other rules that may impact the Company have yet to be finalized.

Rules developed by the CFTC and other regulators could impact the Company.

While many of those rules place specific conditions on the operations of swap dealers and major swap participants, concern remains that swap dealers and major swap participants will pass along their increased costs stemming from final rules through higher transaction costs and prices or other direct or indirect costs.

Additionally, given the enforcement authority granted to the CFTC on anti-market manipulation, anti-fraud and disruptive trading practices, it is difficult to predict how the evolving enforcement priorities of the CFTC will impact our business.

Although regulators have adopted several final regulations, other rules that may impact the Company have yet to be finalized.

Rules adopted by the CFTC and other regulators could adversely impact the Company.

While many of those rules place specific conditions on the operations of swap dealers rather than directly on the Company, concern remains that swap dealers with whom the Company may transact will pass along their increased costs stemming from final rules through higher transaction costs and prices or other direct or indirect costs.

Some of those rules also may apply directly to the Company and adversely impact its ability to trade swaps and over-the-counter derivatives, whether due to increased costs, limitations on trading capacity or for other reasons.

Additionally, given the enforcement authority granted to the CFTC on anti-market manipulation, anti-fraud and anti-disruptive trading practices, it is difficult to predict how the evolving enforcement priorities of the CFTC will impact our business.

Should the Company violate any laws or regulations applicable to our hedging activities, it could be subject to CFTC enforcement action and material penalties and sanctions.

The Company continues to monitor these enforcement and other regulatory developments, but cannot predict the impact that evolving application of the Dodd-Frank Act may have on its operations.

The Company cannot predict the impact that evolving application of the Dodd-Frank Act may have on its operations.

The authoritative guidance for fair value measurements and disclosures require consideration of the impact of nonperformance risk (including credit risk) from a market participant perspective in the measurement of the fair value of assets and liabilities.

At December 31, 2022, the Company determined that nonperformance risk associated with its natural gas price swap agreements, natural gas no cost collars and foreign currency contracts would have no material impact on its financial position or results of operation.

At March 31, 2023, the Company determined that nonperformance risk associated with its natural gas price swap agreements, natural gas 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.

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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.

On December 9, 2022, the Company filed a petition with the NYPSC to effectuate a system improvement tracker through which qualified pipeline replacement costs would be tracked and recovered, and to recover certain deferred costs associated with the existing system modernization tracker, effective April 1, 2023.

That petition has been noticed for public comment and a determination is pending.

On December 9, 2022, the Company filed a petition with the NYPSC to effectuate a system improvement tracker through which qualified pipeline replacement costs through September 30, 2024 would be tracked and recovered, and to recover certain deferred costs associated with the existing system modernization tracker, effective April 1, 2023.

The NYPSC approved the petition via order dated March 17, 2023 contingent on the Company not filing a base rate case that would result in new rates becoming effective prior to October 1, 2024.

On January 19, 2023, the NYPSC issued an order in its Effects of COVID-19 on Utility Service (20-M-0266) and Energy Affordability for Low Income Utility Customers (14-M-0565) proceedings whereby a Phase 2 Utility Arrears Relief Program was authorized.

Specifically, the order directed Distribution Corporation and certain other New York utilities to, among other things, address arrears on residential non-energy affordability program ratepayer accounts that did not receive a credit under the NYPSC’s Phase 1 program and small commercial ratepayer accounts by issuing a one-time bill credit to such customers to reduce or eliminate accrued arrears through May 1, 2022.

Specifically, the order directed Distribution Corporation and certain other New York utilities to, among other things, address arrears on residential non-energy affordability program (EAP) ratepayer accounts that did not receive a credit under the NYPSC’s Phase 1 program and small commercial ratepayer accounts by issuing a one-time bill credit to such customers to reduce or eliminate accrued arrears through May 1, 2022.

The credits shall be processed within 90 days of the effective date of the order, provided that residential non-EAP customers who had their service disconnected for non-payment in 2022 shall be allowed the opportunity to have their service reinstated in order to receive the credit through June 30, 2023.

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Utilities proposed various offsets to Phase 2 program costs, and Distribution Corporation has proposed certain offsets as part of an uncollectible expense reconciliation proposal.

Distribution Corporation will make a filing with the NYPSC seeking approval of its uncollectible expense reconciliation mechanism no later than 30 days from the January 19, 2023 effective date of the order.

On February 17, 2023, Distribution Corporation made a filing with the NYPSC seeking approval of its uncollectible expense reconciliation mechanism and a determination is pending.

Application of the proposed offsets and collection periods will be determined when the NYPSC rules on the uncollectible expense reconciliation filing.

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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 (WNA) mechanism and a new energy efficiency and conservation pilot program for residential customers.

On December 8, 2022, the PaPUC issued an order suspending the filing until July 27, 2023 by operation of law unless directed otherwise by the PaPUC.

The matter has been assigned to an administrative law judge and remains pending.

Following discovery, the submission of testimony and an evidentiary hearing, the parties to the proceeding agreed to a settlement that authorizes, among other things, an increase in Distribution Corporation’s annual base rate operating revenues of $23 million as of August 1, 2023.

On April 13, 2023, Distribution Corporation filed a joint petition with the PaPUC seeking approval of the settlement on behalf of all active parties to the proceeding.

The joint petition is currently pending before 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.

All matters with respect to this tariff supplement were finalized on February 24, 2022 with the PaPUC's approval of an Administrative Law Judge's Recommended Decision.

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.

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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 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.

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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.

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.

Thus far, the only regulations promulgated in connection with the CLCPA are statewide 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 and had indicated that it will initiate regulatory proceedings to investigate development of a cap-and-invest program in New York.

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.

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Safe Harbor for Forward-Looking Statements

The Company is including the following cautionary statement in this Form 10-Q to make applicable and take advantage of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by, or on behalf of, the Company.

The Company is including the following cautionary statement in this Quarterly Report on Form 10-Q to make applicable and take advantage of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by, or on behalf of, the Company.

Forward-looking statements include statements concerning plans, objectives, goals, projections, strategies, future events or performance, and underlying assumptions and other statements which are other than statements of historical facts.

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

Forward-looking and other statements in this Quarterly Report on Form 10-Q regarding methane and greenhouse gas reduction plans and goals are not an indication that these statements are necessarily material to investors or required to be disclosed in our filings with the SEC.

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 developing, internal controls and processes that continue to evolve and assumptions that are subject to change in the future.

Quantitative and Qualitative Disclosures About Market Risk

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Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-Q

Item 2. Management’s Discussion and Analysis