NATIONAL FUEL GAS COMPANY OVERVIEW
Please note that this overview is a high-level summary of items that are discussed in greater detail in subsequent sections of this report.
The Company is a diversified energy company engaged principally in the production, gathering, transportation, storage and distribution of natural gas. The Company operates an integrated business, with assets centered in westernNew York andPennsylvania , being utilized for, and benefiting from, the production and transportation of natural gas from the Appalachian basin. Current development activities are focused primarily in theMarcellus andUtica shales. The common geographic footprint of the Company's subsidiaries enables them to share management, labor, facilities and support services across various businesses and pursue coordinated projects designed to produce and transport natural gas from the Appalachian basin to markets in the easternUnited States andCanada . The Company's efforts in this regard are not limited to affiliated projects. The Company has also been designing and building pipeline projects for the transportation of natural gas for non-affiliated natural gas customers in the Appalachian basin. The Company reports financial results for four business segments. For a discussion of the Company's earnings, refer to the Results of Operations section below. OnJune 30, 2022 , the Company completed the sale ofSeneca's California assets toSentinel Peak Resources California LLC for a total sale price of$253.5 million , consisting of$240.9 million in cash and contingent consideration valued at$12.6 million at closing. The Company pursued this sale given the strong commodity price environment and the Company's strategic focus in theAppalachian Basin . Under the terms of the purchase and sale agreement, the Company can receive up to three annual contingent payments between calendar year 2023 and calendar year 2025, not to exceed$10 million per year, with the amount of each annual payment calculated as$1.0 million for each$1 per barrel that the ICE Brent Average for each calendar year exceeds$95 per barrel up to$105 per barrel. The sale price, which reflected an effective date ofApril 1, 2022 , was reduced for production revenues less expenses that were retained bySeneca from the effective date to the closing date. Under the full cost method of accounting for oil and natural gas properties,$220.7 million of the sale price at closing was accounted for as a reduction of capitalized costs since the disposition did not alter the relationship between capitalized costs and proved reserves of oil and gas attributable to the cost center. The remainder of the sale price ($32.8 million ) was applied against assets that are not subject to the full cost method of accounting, with the Company recognizing a gain of$12.7 million on the sale of such assets. The majority of this gain related to the sale of emission allowances. OnJune 30, 2022 , the Company entered into a new 364-Day Credit Agreement (the "364-Day Credit Agreement") with a syndicate of five banks, all of which are also lenders under the Credit Agreement. The 364-Day Credit Agreement provides an additional$250.0 million unsecured committed delayed draw term loan credit facility with a maturity date ofJune 29, 2023 . The Company elected to draw$250.0 million under the facility onOctober 27, 2022 . The Company is using the proceeds for general corporate purposes, which included the redemption inNovember 2022 of a portion of the Company's outstanding long-term debt maturing inMarch 2023 . The Company does not anticipate long-term refinancing for the long-term debt maturing inMarch 2023 . 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. CRITICAL ACCOUNTING ESTIMATES For a complete discussion of critical accounting estimates, refer to "Critical Accounting Estimates" in Item 7 of the Company's 2022 Form 10-K. There have been no material changes to that disclosure other than as set forth below. The information presented below updates and should be read in conjunction with the critical accounting estimates in that Form 10-K. Oil and Gas Exploration and Development Costs. The Company, in its Exploration and Production segment, follows the full cost method of accounting for determining the book value of its oil and natural gas properties, with natural gas properties in theAppalachian Region being the primary component after theJune 30, 2022 sale of the Company'sCalifornia oil and natural gas properties. That sale is discussed in more detail in Item 1 at Note 2 - Asset Acquisitions and Divestitures. In accordance with the full cost methodology, the Company is required to perform a quarterly ceiling test. Under the ceiling test, the present value of future revenues from the Company's oil and gas reserves based on an unweighted arithmetic average of the first day of the month oil and gas prices for each month within the twelve-month period prior to the end of the reporting period (the "ceiling") is compared with the book value of the Company's oil and gas properties at the balance sheet date. The present value of future 26 -------------------------------------------------------------------------------- Table of Contents revenues is calculated using a 10% discount factor. If the book value of the oil and gas properties exceeds the ceiling, a non-cash impairment charge must be recorded to reduce the book value of the oil and gas properties to the calculated ceiling. AtDecember 31, 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 endedDecember 31, 2022 , based on the quotedHenry Hub spot price for natural gas, was$6.36 per MMBtu. (Note: Because actual pricing of the Company's producing properties vary depending on their location and hedging, the prices used to calculate the ceiling may differ from the Henry Hub price, which is only indicative of 12-month average prices for the twelve months endedDecember 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 atDecember 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. This calculated amount is based solely on price changes and does not take into account any other changes to the ceiling test calculation, including, among others, changes in reserve quantities and future cost estimates. It is difficult to predict what factors could lead to future non-cash impairments under theSEC's full cost ceiling test. Fluctuations in or subtractions from proved reserves, increases in development costs for undeveloped reserves and significant fluctuations in natural gas prices have an impact on the amount of the ceiling at any point in time. For a more complete discussion of the full cost method of accounting, refer to "Oil and Gas Exploration and Development Costs" under "Critical Accounting Estimates" in Item 7 of the Company's 2022 Form 10-K. RESULTS OF OPERATIONS
Earnings
The Company's earnings were$169.7 million for the quarter endedDecember 31, 2022 compared to earnings of$132.4 million for the quarter endedDecember 31, 2021 . The increase in earnings of$37.3 million is primarily the result of higher earnings in all reportable segments as well as in the Corporate category, slightly offset by a loss in the All Other category. Additional discussion of earnings in each of the business segments can be found in the business segment information that follows. Note that all amounts used in earnings discussions are after-tax amounts, unless otherwise noted. Earnings (Loss) by Segment Three Months Ended December 31, Increase (Thousands) 2022 2021 (Decrease) Exploration and Production$ 91,192 $ 62,369 $ 28,823 Pipeline and Storage 29,476 25,168 4,308 Gathering 24,738 23,137 1,601 Utility 23,817 22,130 1,687 Total Reportable Segments 169,223 132,804 36,419 All Other (280) (7) (273) Corporate 746 (405) 1,151 Total Consolidated$ 169,689 $ 132,392 $ 37,297 27
-------------------------------------------------------------------------------- Table of Contents Exploration and Production
Exploration and Production Operating Revenues
Three Months Ended
December 31,
Increase
(Thousands) 2022 2021 (Decrease)
Gas (after Hedging) $ 273,197 $ 205,801 $ 67,396
Oil (after Hedging) 628 35,223 (34,595)
Gas Processing Plant 374 1,029 (655)
Other 2,774 2,145 629
$ 276,973 $ 244,198 $ 32,775
Production Volumes
Three Months Ended
December 31,
Increase
2022 2021 (Decrease)
Gas Production (MMcf)
Appalachia 90,574 81,389 9,185
West Coast - 408 (408)
Total Production 90,574 81,797 8,777
Oil Production (Mbbl)
Appalachia 8 - 8
West Coast - 548 (548)
Total Production 8 548 (540)
Average Prices
Three Months Ended
December 31,
Increase
2022 2021 (Decrease)
Average Gas Price/Mcf
Appalachia $ 4.77 $ 4.39 $ 0.38
West Coast N/M $ 9.79 N/M
Weighted Average $ 4.77 $ 4.42 $ 0.35
Weighted Average After Hedging
Average Oil Price/Bbl Appalachia$ 82.09 $ 70.86 $ 11.23 West Coast N/M$ 77.34 N/M Weighted Average$ 82.09 $ 77.34 $ 4.75
Weighted Average After Hedging
N/M - Not Meaningful (as a result of the sale of
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2022 Compared with 2021
Operating revenues for the Exploration and Production segment increased$32.8 million for the quarter endedDecember 31, 2022 as compared with the quarter endedDecember 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. Natural gas production increased largely due to additional production from newMarcellus andUtica wells in the Appalachian region. Oil production revenue after hedging decreased$34.6 million due to the sale of the Exploration and Production segment'sCalifornia assets onJune 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 theTransCanada Pipeline transportation contract. The decrease in gas processing plant revenue was attributed to the sale of theCalifornia assets. The Exploration and Production segment's earnings for the quarter endedDecember 31, 2022 were$91.2 million , an increase of$28.8 million when compared with earnings of$62.4 million for the quarter endedDecember 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 theCalifornia assets, partially offset by higher gathering and transportation costs in the Appalachian region due to increased production. The decrease in other operating expenses was primarily attributed to theCalifornia 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 theCalifornia asset sale, as well as non-service pension and post-retirement income in the quarter endedDecember 31, 2022 compared to non-service pension and post-retirement benefit costs in the quarter endedDecember 31, 2021 . The increase in depletion expense was primarily due to the net increase in production combined with a$0.03 per Mcf increase in the depletion rate. The increase in other taxes was attributed to higher Impact Fees in the Appalachian region offset partially by lower production and other taxes as a result of theCalifornia 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 theCalifornia assets.
Pipeline and Storage
Pipeline and Storage Operating Revenues
Three Months Ended
December 31,
Increase
(Thousands) 2022 2021 (Decrease)
Firm Transportation $ 75,456 $ 65,825 $ 9,631
Interruptible Transportation 745 444 301
76,201 66,269 9,932
Firm Storage Service 21,284 20,800 484
Interruptible Storage Service 2 - 2
Other 168 1,281 (1,113)
$ 97,655 $ 88,350 $ 9,305
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Pipeline and Storage Throughput
Three Months Ended
December 31,
Increase
(MMcf) 2022 2021 (Decrease)
Firm Transportation 224,623 193,594 31,029
Interruptible Transportation 1,308 767 541
225,931 194,361 31,570
2022 Compared with 2021
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 .
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. 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.
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.
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 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 . These earnings increases were
partially offset by increases in operating expenses ($1.5 million ), depreciation
expense ($1.3 million ), and interest expense ($0.6 million ). The increase in
operating expenses was primarily due to higher personnel costs, timing of dues
and memberships and higher pipeline integrity 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.
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Gathering
Gathering Operating Revenues
Three Months Ended
December 31,
Increase
(Thousands) 2022 2021 (Decrease)
Gathering Revenues $ 56,413 $ 52,225 $ 4,188
Gathering Volume
Three Months Ended
December 31,
Increase
2022 2021 (Decrease)
Gathered Volume - (MMcf) 108,027 101,094 6,933
2022 Compared with 2021
Operating revenues for the Gathering 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. 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 16.3 Bcf and 1.6 Bcf, respectively, partially offset by
decreases on the Trout Run and Wellsboro gathering systems, which recorded
decreases of 10.1 Bcf and 0.9 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 . The increase in earnings was
mainly due to higher gathering revenues ($3.3 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.
Utility
Utility Operating Revenues
Three Months Ended
December 31,
Increase
(Thousands) 2022 2021 (Decrease)
Retail Sales Revenues:
Residential $ 245,442 $ 182,708 $ 62,734
Commercial 35,343 25,242 10,101
Industrial 1,643 1,157 486
282,428 209,107 73,321
Transportation 29,512 29,652 (140)
Other (259) (2,000) 1,741
$ 311,681 $ 236,759 $ 74,922
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Utility Throughput
Three Months Ended
December 31,
Increase
(MMcf) 2022 2021 (Decrease)
Retail Sales:
Residential 20,153 17,496 2,657
Commercial 2,994 2,543 451
Industrial 151 123 28
23,298 20,162 3,136
Transportation 18,310 17,593 717
41,608 37,755 3,853
Degree Days
Percent Colder (Warmer) Than
Three Months Ended December 31, Normal 2022 2021 Normal(1) Prior Year(1)
Buffalo, NY 2,253 2,048 1,704 (9.1) % 20.2 %
Erie, PA 2,044 1,987 1,560 (2.8) % 27.4 %
(1)Percents compare actual 2022 degree days to normal degree days and actual 2022 degree days to actual 2021 degree days.
2022 Compared with 2021
Operating revenues for the Utility segment increased$74.9 million for the quarter endedDecember 31, 2022 as compared with the quarter endedDecember 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 inNew York andPennsylvania ,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 effectiveOctober 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 endedDecember 31, 2022 were$23.8 million , an increase of$1.7 million when compared with earnings of$22.1 million for the quarter endedDecember 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 inNew 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 theNew 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 effectiveOctober 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 ), asDistribution Corporation's New York service territory recognized pension and OPEB income during the quarter endedDecember 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. 32
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The Utility segment also experienced higher operating expenses ($2.4 million ) and higher interest expense ($2.0 million ) when comparing the quarter endedDecember 31, 2022 to the quarter endedDecember 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. The increase in interest expense was largely the result of a higher weighted average interest rate on intercompany short-term borrowings. The impact of weather variations on earnings in the Utility segment'sNew York rate jurisdiction is mitigated by that jurisdiction's weather normalization clause (WNC). The WNC inNew York , which covers the eight-month period from October through May, has had a stabilizing effect on earnings for theNew York rate jurisdiction. In addition, in periods of colder than normal weather, the WNC benefits the Utility segment'sNew York customers. For the quarter endedDecember 31, 2022 , the WNC increased earnings by approximately$0.9 million , as the weather was warmer than normal. For the quarter endedDecember 31, 2021 , the WNC increased earnings by approximately$2.6 million , as the weather was warmer than normal. Corporate and All Other 2022 Compared with 2021 Corporate and All Other operations had earnings of$0.5 million for the quarter endedDecember 31, 2022 , an increase of$0.9 million when compared with a loss of$0.4 million for the quarter endedDecember 31, 2021 . The increase was primarily attributable to changes in unrealized gains and losses on investments in equity securities. During the quarter endedDecember 31, 2022 , the Company recorded unrealized gains of$0.2 million . During the quarter endedDecember 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 ).
Other Income (Deductions)
Net other income on the Consolidated Statement of Income was$6.3 million for the quarter endedDecember 31, 2022 , compared to net other deductions of$1.1 million for the quarter endedDecember 31, 2021 . This change is primarily attributable to non-service pension and post-retirement benefit income of$1.4 million for the quarter endedDecember 31, 2022 as compared to non-service pension and post-retirement benefit expense of$4.8 million for the quarter endedDecember 31, 2021 . As discussed above in the Utility segment, this is largely related to a tariff filing approved by the NYPSC duringSeptember 2022 inDistribution Corporation's New York service territory, which created a surcredit that temporarily eliminates pension and OPEB cost recovery from base rates effectiveOctober 1, 2022 . Accordingly, no pension and OPEB expenses were recorded during the quarter endedDecember 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 inDistribution 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 .
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 endedDecember 31, 2022 as compared to the quarter endedDecember 31, 2021 , primarily due to theNovember 2022 redemption of$150.0 million of the$500.0 million 3.75% note dueMarch 2023 . 33
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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 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. These cash flow projections do not reflect the
impact of acquisitions or divestitures that may arise in the future.
Operating Cash Flow
Internally generated cash from operating activities consists of net income available for common stock, adjusted for non-cash expenses, non-cash income, gains and losses associated with investing and financing activities, and changes in operating assets and liabilities. Non-cash items include depreciation, depletion and amortization, deferred income taxes and stock-based compensation. Cash provided by operating activities in the Utility and Pipeline and Storage segments may vary substantially from period to period because of the impact of rate cases. In the Utility segment, supplier refunds, over- or under-recovered purchased gas costs and weather may also significantly impact cash flow. The impact of weather on cash flow is tempered in the Utility segment'sNew York rate jurisdiction by its WNC and in the Pipeline and Storage segment by the straight fixed-variable rate design used bySupply Corporation and Empire. Because of the seasonal nature of the heating business in the Utility segment, revenues in this business are relatively high during the heating season, primarily the first and second quarters of the fiscal year, and receivable balances historically increase during these periods from the receivable balances atSeptember 30 . The storage gas inventory normally declines during the first and second quarters of the fiscal year and is replenished during the third and fourth quarters. For storage gas inventory accounted for under the LIFO method, the current cost of replacing gas withdrawn from storage is recorded in the Consolidated Statements of Income and a reserve for gas replacement is recorded in the Consolidated Balance Sheets under the caption "Other Accruals and Current Liabilities." Such reserve is reduced as the inventory is replenished. Cash provided by operating activities in the Exploration and Production segment may vary from period to period as a result of changes in the commodity prices of natural gas as well as changes in production. The Company uses various derivative financial instruments, including price swap agreements and no cost collars, in an attempt to manage this energy commodity price risk. Net cash provided by operating activities totaled$327.3 million for the three months endedDecember 31, 2022 , an increase of$155.8 million compared with$171.5 million provided by operating activities for the three months endedDecember 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. 34 -------------------------------------------------------------------------------- Table of Contents Investing Cash Flow
Expenditures for Long-Lived Assets
The Company's expenditures for long-lived assets totaled$223.5 million during the three months endedDecember 31, 2022 and$191.8 million during the three months endedDecember 31, 2021 . The table below presents these expenditures: Total Expenditures for Long-Lived Assets Three Months Ended December 31, Increase (Millions) 2022 2021 (Decrease) Exploration and Production: Capital Expenditures$ 168.5 (1)$ 139.2 (2)$ 29.3 Pipeline and Storage: Capital Expenditures 16.4 (1) 24.1 (2) (7.7) Gathering: Capital Expenditures 13.3 (1) 8.9 (2) 4.4 Utility: Capital Expenditures 25.3 (1) 19.4 (2) 5.9 All Other: Capital Expenditures - 0.2 (0.2)$ 223.5 $ 191.8 $ 31.7 (1)AtDecember 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. AtSeptember 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)AtDecember 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. AtSeptember 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 endedDecember 31, 2022 were primarily well drilling and completion expenditures in the Appalachian region (including$60.9 million in theMarcellus Shale area and$104.6 million in theUtica Shale area). These amounts included approximately$110.5 million spent to develop proved undeveloped reserves. The Exploration and Production segment capital expenditures for the three months endedDecember 31, 2021 were primarily well drilling and completion expenditures and included approximately$132.1 million for the Appalachian region (including$45.1 million in theMarcellus Shale area and$83.3 million in theUtica Shale area) and$7.1 million for theWest Coast region. These amounts included approximately$54.2 million spent to develop proved undeveloped reserves.
Pipeline and Storage
The Pipeline and Storage segment capital expenditures for the three months endedDecember 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 endedDecember 31, 2021 were primarily for expenditures related toSupply Corporation's FM100 Project ($15.7 million ). In addition, the Pipeline and Storage segment capital expenditures for the three months endedDecember 31, 2021 included additions, improvements and replacements to this segment's transmission and gas storage systems.
Gathering
The majority of the Gathering segment capital expenditures for the three
months ended
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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. 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.
Utility
The majority of the Utility segment capital expenditures for the three months endedDecember 31, 2022 andDecember 31, 2021 were made for main and service line improvements and replacements that enhance the reliability and safety of the system and reduce emissions. Expenditures were also made for main extensions.
Other Investing Activities
InOctober 2021 , the Company sold$30 million of fixed income mutual fund shares held in a grantor trust that was established for the benefit ofPennsylvania ratepayers. The proceeds were used in the Utility segment'sPennsylvania service territory to fund a one-time customer bill credit of$25 million inOctober 2021 for previously overcollected OPEB expenses and the first year installment of a 5-year pass back of an additional$29 million in previously overcollected OPEB expenses in accordance with new rates that went into effect onOctober 1, 2021 . InOctober 2022 , the Company sold an additional$10 million of fixed income mutual fund shares held in the grantor trust. The proceeds from this sale were used to fund the second year installment of the 5-year pass back of overcollected OPEB expenses as well as to diversify a portion of grantor trust investments into lower risk money market mutual fund shares. Please refer to the Rate Matters section that follows for additional discussion of this matter. OnJune 30, 2022 , the Company completed the sale ofSeneca's California assets, all of which are in the Exploration and Production segment, toSentinel Peak Resources California LLC for a total sale price of$253.5 million , consisting of$240.9 million in cash and contingent consideration valued at$12.6 million at closing. The Company pursued this sale given the strong commodity price environment and the Company's strategic focus in theAppalachian Basin . Under the terms of the purchase and sale agreement, the Company can receive up to three annual contingent payments between calendar year 2023 and calendar year 2025, not to exceed$10 million per year, with the amount of each annual payment calculated as$1.0 million for each$1 per barrel that the ICE Brent Average for each calendar year exceeds$95 per barrel up to$105 per barrel. The sale price, which reflected an effective date ofApril 1, 2022 , was reduced for production revenues less expenses that were retained bySeneca from the effective date to the closing date. Under the full cost method of accounting for oil and natural gas properties,$220.7 million of the sale price at closing was accounted for as a reduction of capitalized costs since the disposition did not alter the relationship between capitalized costs and proved reserves of oil and gas attributable to the cost center. The remainder of the sale price ($32.8 million ) was applied against assets that are not subject to the full cost method of accounting, with the Company recognizing a gain of$12.7 million on the sale of such assets. The majority of this gain related to the sale of emission allowances. 36 -------------------------------------------------------------------------------- Table of Contents 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'sCalifornia assets. During the three months endedDecember 31, 2022 andDecember 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. It will also likely depend on the timing of gas cost recovery in the Utility segment. The Company continuously evaluates capital expenditures and potential investments in corporations, partnerships, and other business entities. The amounts are subject to modification for opportunities such as the acquisition of attractive natural gas properties, quicker development of existing natural gas properties, natural gas storage and transmission facilities, natural gas gathering and compression facilities and the expansion of natural gas transmission line capacities, regulated utility assets and other opportunities as they may arise. 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.
Financing Cash Flow
Consolidated short-term debt increased$190.0 million , to a total of$250.0 million , when comparing the balance sheet atDecember 31, 2022 to the balance sheet atSeptember 30, 2022 . The maximum amount of short-term debt outstanding during the three months endedDecember 31, 2022 was$250.0 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 ofDecember 31, 2022 . The Company's margin deposits are reflected on the balance sheet as a current asset titled Hedging Collateral Deposits. As ofDecember 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 atDecember 31, 2022 . OnFebruary 28, 2022 , the Company entered into a Credit Agreement (as amended from time to time, the "Credit Agreement") with a syndicate of twelve banks. The Credit Agreement replaced the previous Fourth Amended and Restated Credit Agreement and a previous 364-Day Credit Agreement. The Credit Agreement provides a$1.0 billion unsecured committed revolving credit facility with a maturity date ofFebruary 26, 2027 . OnJune 30, 2022 , the Company entered into the 364-Day Credit Agreement with a syndicate of five banks, all of which are also lenders under the Credit Agreement. The 364-Day Credit Agreement provides an additional$250.0 million unsecured committed delayed draw term loan credit facility with a maturity date ofJune 29, 2023 . The Company elected to draw$250.0 million under the facility onOctober 27, 2022 . The Company is using the proceeds for general corporate purposes, which included using$150.0 million for theNovember 2022 redemption of a portion of the Company's outstanding long-term debt maturing inMarch 2023 . The Company also has uncommitted lines of credit with financial institutions for general corporate purposes. Borrowings under these uncommitted lines of credit would be made at competitive market rates. The uncommitted credit lines are revocable at the option of the financial institution and are reviewed on an annual basis. The Company anticipates that its uncommitted lines of credit generally will be renewed or substantially replaced by similar lines. Other financial institutions may also provide the Company with uncommitted or discretionary lines of credit in the future. The total amount available to be issued under the Company's commercial paper program is$500.0 million . The commercial paper program is backed by the Credit Agreement, which provides that the Company's debt to capitalization ratio will not exceed .65 at the last day of any fiscal quarter. For purposes of calculating the debt to capitalization ratio, the Company's total capitalization will be increased by adding back 50% of the aggregate after-tax amount of non-cash charges 37 -------------------------------------------------------------------------------- Table of Contents directly arising from any ceiling test impairment occurring on or afterJuly 1, 2018 , not to exceed$400 million . SinceJuly 1, 2018 , the Company recorded non-cash, after-tax ceiling test impairments totaling$381.4 million . As a result, atDecember 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. OnMay 3, 2022 , the Company entered into Amendment No. 1 to the Credit Agreement with the same twelve banks under the initial Credit Agreement. The amendment further modified the definition of consolidated capitalization, for purposes of calculating the debt to capitalization ratio under the Credit Agreement, to exclude, beginning with the quarter endedJune 30, 2022 , all unrealized gains or losses on commodity-related derivative financial instruments and up to$10 million in unrealized gains or losses on other derivative financial instruments included in Accumulated Other Comprehensive Income (Loss) within Total Comprehensive Shareholders' Equity on the Company's consolidated balance sheet. Under the Credit Agreement, such unrealized losses will not negatively affect the calculation of the debt to capitalization ratio, and such unrealized gains will not positively affect the calculation. The 364-Day Credit Agreement includes the same debt to capitalization covenant and the same exclusions of unrealized gains or losses on derivative financial instruments as the Credit Agreement. AtDecember 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 atDecember 31, 2022 (further limited by the indenture covenants discussed below) before the Company's debt to capitalization ratio exceeded .65. A downgrade in the Company's credit ratings could increase borrowing costs, negatively impact the availability of capital from banks, commercial paper purchasers and other sources, and require the Company's subsidiaries to post letters of credit, cash or other assets as collateral with certain counterparties. If the Company is not able to maintain investment-grade credit ratings, it may not be able to access commercial paper markets. However, the Company expects that it could borrow under its credit facilities or rely upon other liquidity sources. The Credit Agreement and 364-Day Credit Agreement contain a cross-default provision whereby the failure by the Company or its significant subsidiaries to make payments under other borrowing arrangements, or the occurrence of certain events affecting those other borrowing arrangements, could trigger an obligation to repay any amounts outstanding under the Credit Agreement and 364-Day Credit Agreement. In particular, a repayment obligation could be triggered if (i) the Company or any of its significant subsidiaries fails to make a payment when due of any principal or interest on any other indebtedness aggregating$40.0 million or more or (ii) an event occurs that causes, or would permit the holders of any other indebtedness aggregating$40.0 million or more to cause, such indebtedness to become due prior to its stated maturity. The Current Portion of Long-Term Debt atDecember 31, 2022 consists of$350.0 million of 3.75% notes and$49.0 million of 7.395% notes, that each mature inMarch 2023 . The Current Portion of Long-Term Debt atSeptember 30, 2022 consisted of$500.0 million of 3.75% notes ($150.0 million of which was subsequently paid inNovember 2022 ) and$49.0 million of 7.395% notes, that each mature inMarch 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
Under the Company's existing indenture covenants atDecember 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. The Company's present liquidity position is believed to be adequate to satisfy known demands. It is possible, depending on amounts reported in various income statement and balance sheet line items, that the indenture covenants could, for a period of time, prevent the Company from issuing incremental unsubordinated long-term debt, or significantly limit the amount of such debt that could be issued. Losses incurred as a result of significant impairments of oil and gas properties have in the past resulted in such temporary restrictions. The indenture covenants would not preclude the Company from issuing new long-term debt to replace existing long-term debt, or from issuing additional short-term debt. Please refer to the Critical Accounting Estimates section above for a sensitivity analysis concerning commodity price changes and their impact on the ceiling test. The Company's 1974 indenture pursuant to which$99.0 million (or 4.0%) of the Company's long-term debt (as ofDecember 31, 2022 ) was issued, contains a cross-default provision whereby the failure by the Company to perform certain obligations under other borrowing arrangements could trigger an obligation to repay the debt outstanding under the indenture. In particular, a repayment obligation could be triggered if the Company fails (i) to pay any scheduled principal or interest on any debt under any other indenture or agreement or (ii) to perform any other term in any other such indenture or agreement, and the effect of the failure causes, or would permit the holders of the debt to cause, the debt under such indenture or agreement to become due prior to its stated maturity, unless cured or waived. 38
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OTHER MATTERS
In addition to the legal proceedings disclosed in Part II, Item 1 of this
report, the Company is involved in other litigation and regulatory matters
arising in the normal course of business. These other matters may include, for
example, negligence claims and tax, regulatory or other governmental audits,
inspections, investigations or other proceedings. These matters may involve
state and federal taxes, safety, compliance with regulations, rate base, cost of
service and purchased gas cost issues, among other things. While these
normal-course matters could have a material effect on earnings and cash flows in
the period in which they are resolved, they are not expected to change
materially the Company's present liquidity position, nor are they expected to
have a material adverse effect on the financial condition of the Company.
Supply Corporation and Empire have developed a project which would move
significant prospective Marcellus and Utica production from Seneca's Western
Development Area at Clermont to an Empire interconnection with the TC Energy
pipeline at Chippawa and an interconnection with TGP's 200 Line in East Aurora,
New York (the "Northern Access project"). The Northern Access project would
provide an outlet to Dawn-indexed markets in Canada and to the TGP line serving
the U.S. Northeast. The Northern Access project involves the construction of
approximately 99 miles of largely 24" pipeline and approximately 27,500
horsepower of compression on the two systems. Supply Corporation , Empire and
Seneca executed anchor shipper agreements for 350,000 Dth per day of firm
transportation delivery capacity to Chippawa and 140,000 Dth per day of firm
transportation capacity to a new interconnection with TGP's 200 Line on this
project. The Company remains committed to the project and, on June 29, 2022 ,
received an extension of time from FERC , until December 31, 2024 , to construct
the project. The Company will update the $500 million preliminary cost estimate
and expected in-service date for the project when there is further clarity on
the timing of receipt of necessary regulatory approvals. As of 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.
Market Risk Sensitive Instruments
OnJuly 21, 2010 , the Dodd-Frank Act was signed into law. The Dodd-Frank Act required the CFTC,SEC and other regulatory agencies to promulgate rules and regulations implementing the legislation, and includes provisions related to the swaps and over-the-counter derivatives markets that are designed to promote transparency, mitigate systemic risk and protect against market abuse. Although regulators have issued certain regulations, other rules that may impact the Company have yet to be finalized. Rules developed by the CFTC and other regulators could impact the Company. While many of those rules place specific conditions on the operations of swap dealers and major swap participants, concern remains that swap dealers and major swap participants will pass along their increased costs stemming from final rules through higher transaction costs and prices or other direct or indirect costs. Additionally, given the enforcement authority granted to the CFTC on anti-market manipulation, anti-fraud and disruptive trading practices, it is difficult to predict how the evolving enforcement priorities of the CFTC will impact our business. Should the Company violate any laws or regulations applicable to our hedging activities, it could be subject to CFTC enforcement action and material penalties and sanctions. The Company continues to monitor these enforcement and other regulatory developments, but cannot predict the impact that evolving application of the Dodd-Frank Act may have on its operations. The authoritative guidance for fair value measurements and disclosures require consideration of the impact of nonperformance risk (including credit risk) from a market participant perspective in the measurement of the fair value of assets and liabilities. AtDecember 31, 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. To assess nonperformance risk, the Company considered information such as any applicable collateral posted, master netting arrangements, and applied a market-based method by using the counterparty's (assuming the derivative is in a gain position) or the Company's (assuming the derivative is in a loss position) credit default swaps rates. For a complete discussion of all other market risk sensitive instruments used by the Company, refer to "Market Risk Sensitive Instruments" in Item 7 of the Company's 2022 Form 10-K. 39 --------------------------------------------------------------------------------
Table of Contents Rate Matters Utility Operation Delivery rates for both theNew York andPennsylvania divisions are regulated by the states' respective public utility commissions and typically are changed only when approved through a procedure known as a "rate case." As noted below, thePennsylvania division currently has a rate case on file. In both jurisdictions, delivery rates do not reflect the recovery of purchased gas costs. Prudently-incurred gas costs are recovered through operation of automatic adjustment clauses, and are collected primarily through a separately-stated "supply charge" on the customer bill.
New York Jurisdiction
Distribution Corporation's current delivery rates in itsNew York jurisdiction were approved by the NYPSC in an order issued onApril 20, 2017 with rates becoming effectiveMay 1, 2017 . The order provided for a return on equity of 8.7%, and directed the implementation of an earnings sharing mechanism to be in place beginning onApril 1, 2018 . The order also authorized the Company to recover approximately$15 million annually for pension and OPEB expenses from customers. Because the Company's future pension and OPEB costs were projected to be satisfied with existing funds held in reserve, in July,Distribution Corporation made a filing with the NYPSC to effectuate a pension and OPEB surcredit to customers to offset these amounts being collected in base rates effectiveOctober 1, 2022 . OnSeptember 16, 2022 , the NYPSC issued an order approving the filing. The surcredit will remain in effect until modified by the NYPSC in another proceeding, or untilDecember 31, 2024 , whichever is earlier. With the implementation of this surcredit,Distribution Corporation will no longer be funding the Retirement Plan or its VEBA trusts in itsNew York jurisdiction. OnAugust 13, 2021 , the NYPSC issued an order extending the date through which qualified pipeline replacement costs incurred by the Company can be recovered using the existing system modernization tracker for two years (untilMarch 31, 2023 ). The extension is contingent on the Company not filing a base rate case that would result in new rates becoming effective prior toApril 1, 2023 . OnDecember 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, effectiveApril 1, 2023 . That petition has been noticed for public comment and a determination is pending. OnJanuary 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 directedDistribution Corporation and certain otherNew 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 throughMay 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 throughJune 30, 2023 . The order further directs utilities to suspend residential service terminations for non-payment while arrears credits are applied to accounts throughMarch 1, 2023 , or 30 days after credits have been applied, whichever is later. The order authorizes the utilities to recover the Phase 2 costs (the arrears credits and associated carrying charges) through a surcharge. Utilities proposed various offsets to Phase 2 program costs, andDistribution 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 theJanuary 19, 2023 effective date of the order. Application of the proposed offsets and collection periods will be determined when the NYPSC rules on the uncollectible expense reconciliation filing. Pennsylvania JurisdictionDistribution Corporation's current delivery rates in itsPennsylvania jurisdiction were approved by the PaPUC onNovember 30, 2006 as part of a settlement agreement that became effectiveJanuary 1, 2007 . OnOctober 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 ofDecember 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. OnDecember 8, 2022 , the PaPUC issued an order suspending the filing untilJuly 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. 40
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EffectiveOctober 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 onFebruary 24, 2022 . Concurrent with that decision, the Company discontinued regulatory accounting for OPEB expenses and recorded an$18.5 million adjustment during the quarter endedMarch 31, 2022 to reduce its regulatory liability for previously deferred OPEB income amounts throughSeptember 30, 2021 and to increase Other Income (Deductions) on the consolidated financial statements by a like amount. The Company also increased customer refunds of overcollected OPEB expenses from$50.0 million to$54.0 million . All refunds specified in the tariff supplement are being funded entirely by grantor trust assets held by the Company, most of which are included in a fixed income mutual fund that is a component of Other Investments on the Company's Consolidated Balance Sheet. With the elimination of OPEB expenses in base rates,Distribution Corporation is no longer funding the grantor trust or its VEBA trusts in itsPennsylvania jurisdiction.
Pipeline and Storage
Supply Corporation's 2020 rate settlement provides that no party may make a rate filing for new rates to be effective beforeFebruary 1, 2024 , except thatSupply Corporation may file an NGA general Section 4 rate case to change rates if the corporate federal income tax rate is increased. If no case has been filed,Supply Corporation must file for rates to be effectiveFebruary 1, 2025 .
Empire's 2019 rate settlement provides that Empire must make a rate case
filing no later than
Environmental Matters
The Company is subject to various federal, state and local laws and regulations relating to the protection of the environment. The Company has established procedures for the ongoing evaluation of its operations to identify potential environmental exposures and comply with regulatory requirements. In 2021, the Company set methane intensity reduction targets at each of its businesses, an absolute greenhouse gas emissions reduction target for the consolidated Company, and greenhouse gas reduction targets associated with the Company's utility delivery system. In 2022, the Company began measuring progress against these reduction targets. The Company's ability to estimate accurately the time, costs and resources necessary to meet emissions targets may change as environmental exposures and opportunities change and regulatory updates are issued.
For further discussion of the Company's environmental exposures, refer to Item 1 at Note 8 - Commitments and Contingencies under the heading "Environmental Matters."
Legislative and regulatory measures to address climate change and greenhouse gas emissions are in various phases of discussion or implementation inthe United States . These efforts include legislation, legislative proposals and new regulations at the state and federal level, and private party litigation related to greenhouse gas emissions. Legislation or regulation that aims to reduce greenhouse gas emissions could also include emissions limits, reporting requirements, carbon taxes, restrictive permitting, increased efficiency standards, and incentives or mandates to conserve energy or use renewable energy sources. For example, the Inflation Reduction Act of 2022 (IRA) legislation was signed into law onAugust 16, 2022 . The IRA includes a methane charge that is expected to be applicable to the reported annual methane emissions of certain oil and gas facilities, above specified methane intensity thresholds, starting in calendar year 2024. This portion of the IRA is to be administered by theEPA and potential fees will begin with emissions reported for calendar year 2024. TheEPA regulates greenhouse gas emissions pursuant to the Clean Air Act. The regulations implemented by theEPA impose more stringent leak detection and repair requirements, and further address reporting and control of methane and volatile organic compound emissions. The Company must continue to comply with all applicable regulations. Additionally, a number of states have adopted energy strategies or plans with aggressive goals for the reduction of greenhouse gas emissions.Pennsylvania has a methane reduction framework with the stated goal of reducing methane emissions from well sites, compressor stations and pipelines.Pennsylvania's Governor also entered the Commonwealth into a cap-and-trade program known as the Regional Greenhouse Gas Initiative, however, the Commonwealth's participation is currently stayed due to ongoing litigation. Federal, state or local governments may provide tax advantages and other subsidies to support alternative energy sources, mandate the use of specific fuels or technologies, or promote research into new technologies to reduce the cost and increase the scalability of alternative energy sources. The NYPSC, for example, initiated a proceeding to consider climate-related financial disclosures at the utility operating company level, and theNew York State legislature passed the CLCPA that mandates reducing greenhouse gas emissions by 40% from 1990 levels by 2030, and by 85% from 1990 levels by 2050, with the remaining emission reduction achieved by controlled offsets. The CLCPA also requires electric generators to meet 70% of demand with renewable energy by 41 -------------------------------------------------------------------------------- Table of Contents 2030 and 100% with zero emissions generation by 2040. These climate change and greenhouse gas initiatives could impact the Company's customer base and assets depending on the promulgation of final regulations and on regulatory treatment afforded in the process. Thus far, the only regulations promulgated in connection with the CLCPA are greenhouse gas emissions limits established by the NYDEC in 6 NYCRR Part 496, effectiveDecember 30, 2020 . The NYDEC has untilJanuary 1, 2024 to issue further rules and regulations implementing the statute. The above-enumerated initiatives could also increase the Company's cost of environmental compliance by increasing reporting requirements, requiring retrofitting of existing equipment, requiring installation of new equipment, and/or requiring the purchase of emission allowances. They could also delay or otherwise negatively affect efforts to obtain permits and other regulatory approvals. Changing market conditions and new regulatory requirements, as well as unanticipated or inconsistent application of existing laws and regulations by administrative agencies, make it difficult to predict a long-term business impact across twenty or more years.
Effects of Inflation
The Company's operations are sensitive to increases in the rate of inflation because of its operational and capital spending requirements in both its regulated and non-regulated businesses. For the regulated businesses, recovery of increasing costs from customers can be delayed by the regulatory process of a rate case filing. For the non-regulated businesses, prices received for services performed or products produced are determined by market factors that are not necessarily correlated to the underlying costs required to provide the service or product.
Safe Harbor for Forward-Looking Statements
The Company is including the following cautionary statement in this Form 10-Q to make applicable and take advantage of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by, or on behalf of, the Company. Forward-looking statements include statements concerning plans, objectives, goals, projections, strategies, future events or performance, and underlying assumptions and other statements which are other than statements of historical facts. From time to time, the Company may publish or otherwise make available forward-looking statements of this nature. All such subsequent forward-looking statements, whether written or oral and whether made by or on behalf of the Company, are also expressly qualified by these cautionary statements. Certain statements contained in this report, including, without limitation, statements regarding future prospects, plans, objectives, goals, projections, estimates of oil and gas quantities, strategies, future events or performance and underlying assumptions, capital structure, anticipated capital expenditures, completion of construction projects, projections for pension and other post-retirement benefit obligations, impacts of the adoption of new authoritative accounting and reporting guidance, and possible outcomes of litigation or regulatory proceedings, as well as statements that are identified by the use of the words "anticipates," "estimates," "expects," "forecasts," "intends," "plans," "predicts," "projects," "believes," "seeks," "will," "may," and similar expressions, are "forward-looking statements" as defined in the Private Securities Litigation Reform Act of 1995 and accordingly involve risks and uncertainties which could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. The Company's expectations, beliefs and projections are expressed in good faith and are believed by the Company to have a reasonable basis, but there can be no assurance that management's expectations, beliefs or projections will result or be achieved or accomplished. In addition to other factors and matters discussed elsewhere herein, the following are important factors that, in the view of the Company, could cause actual results to differ materially from those discussed in the forward-looking statements: 1.Changes in laws, regulations or judicial interpretations to which the Company is subject, including those involving derivatives, taxes, safety, employment, climate change, other environmental matters, real property, and exploration and production activities such as hydraulic fracturing; 2.Governmental/regulatory actions, initiatives and proceedings, including those involving rate cases (which address, among other things, target rates of return, rate design, retained natural gas and system modernization), environmental/safety requirements, affiliate relationships, industry structure, and franchise renewal;
3.The Company's ability to estimate accurately the time and resources necessary to meet emissions targets;
4.Governmental/regulatory actions and/or market pressures to reduce or eliminate reliance on natural gas;
5.Changes in economic conditions, including inflationary pressures, supply chain issues, liquidity challenges, and global, national or regional recessions, and their effect on the demand for, and customers' ability to pay for, the Company's products and services;
6.Changes in the price of natural gas;
7.The creditworthiness or performance of the Company's key suppliers, customers and counterparties;
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8.Financial and economic conditions, including the availability of credit, and occurrences affecting the Company's ability to obtain financing on acceptable terms for working capital, capital expenditures and other investments, including any downgrades in the Company's credit ratings and changes in interest rates and other capital market conditions;
9.Impairments under the
10.Increased costs or delays or changes in plans with respect to Company projects or related projects of other companies, as well as difficulties or delays in obtaining necessary governmental approvals, permits or orders or in obtaining the cooperation of interconnecting facility operators;
11.The Company's ability to complete planned strategic transactions;
12.Changes in price differentials between similar quantities of natural gas sold at different geographic locations, and the effect of such changes on commodity production, revenues and demand for pipeline transportation capacity to or from such locations;
13.The impact of information technology disruptions, cybersecurity or data security breaches;
14.Factors affecting the Company's ability to successfully identify, drill for and produce economically viable natural gas reserves, including among others geology, lease availability and costs, title disputes, weather conditions, shortages, delays or unavailability of equipment and services required in drilling operations, insufficient gathering, processing and transportation capacity, the need to obtain governmental approvals and permits, and compliance with environmental laws and regulations;
15.Increasing health care costs and the resulting effect on health insurance premiums and on the obligation to provide other post-retirement benefits;
16.Other changes in price differentials between similar quantities of natural gas having different quality, heating value, hydrocarbon mix or delivery date;
17.The cost and effects of legal and administrative claims against the Company or activist shareholder campaigns to effect changes at the Company;
18.Negotiations with the collective bargaining units representing the Company's workforce, including potential work stoppages during negotiations;
19.Uncertainty of natural gas reserve estimates;
20.Significant differences between the Company's projected and actual production levels for natural gas;
21.Changes in demographic patterns and weather conditions (including those related to climate change);
22.Changes in the availability, price or accounting treatment of derivative financial instruments;
23.Changes in laws, actuarial assumptions, the interest rate environment and the return on plan/trust assets related to the Company's pension and other post-retirement benefits, which can affect future funding obligations and costs and plan liabilities;
24.Economic disruptions or uninsured losses resulting from major accidents, fires, severe weather, natural disasters, terrorist activities or acts of war, as well as economic and operational disruptions due to third-party outages;
25.Significant differences between the Company's projected and actual capital expenditures and operating expenses; or
26.Increasing costs of insurance, changes in coverage and the ability to obtain insurance.
The Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date hereof.
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