0000070145srt:NaturalGasPerThousandCubicFeetMember2022-09-30 UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
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| þ☑ | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the Fiscal Year Ended September 30, 2017
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| ¨☐ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the Transition Period from to
Commission File Number 1-3880
National Fuel Gas Company
(Exact name of registrant as specified in its charter)
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| New Jersey | | 13-1086010 |
(State or other jurisdiction of
incorporation or organization)
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Identification No.)
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6363 Main Street | |
| Williamsville, | New York | 14221 |
| (Address of principal executive offices) | | 14221
(Zip Code) |
(716) 857-7000
(Registrant’s telephone number, including area code)
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(716) 857-7000 |
Registrant’s telephone number, including area code |
| Securities registered pursuant to Section 12(b) of the Act: |
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| Title of Each Class | Trading Symbol | Name of Each Exchange on Which Registered |
Common Stock, par value $1.00 per share and Common Stock Purchase Rights
| NFG | New York Stock Exchange |
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes þ☑ No ¨☐
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15 (d) of the Act. Yes ¨☐ No þ☑
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ☑ No ¨☐
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ☑ No ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act. (Check one):
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Large accelerated filerþ | ☑ | | | Accelerated filer¨ | ☐ |
Non-accelerated filer¨ (Do not check if a smaller reporting company) | ☐ | | | Smaller reporting company¨ | ☐ |
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| Emerging growth company¨ | | | | ☐ |
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨☐
Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☑
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ¨☐ No þ☑
The aggregate market value of the voting stock held by nonaffiliates of the registrant amounted to $4,970,818,000$6,253,478,000 as of March 31, 2017.2022.
Common Stock, par value $1.00 per share, outstanding as of October 31, 2017: 85,582,2012022: 91,485,294 shares.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrant’s definitive Proxy Statement for its 20182023 Annual Meeting of Stockholders, to be filed with the Securities and Exchange Commission within 120 days of September 30, 2017,2022, are incorporated by reference into Part III of this report.
Glossary of Terms
Frequently used abbreviations, acronyms, or terms used in this report:
National Fuel Gas Companies
Company The Registrant, the Registrant and its subsidiaries or the Registrant’s subsidiaries as appropriate in the context of the disclosure
Distribution Corporation National Fuel Gas Distribution Corporation
Empire Empire Pipeline, Inc.
Midstream CorporationCompany National Fuel Gas Midstream CorporationCompany, LLC
National Fuel National Fuel Gas Company
NFR National Fuel Resources, Inc.
Registrant National Fuel Gas Company
Seneca Seneca Resources CorporationCompany, LLC
Supply Corporation National Fuel Gas Supply Corporation
Regulatory Agencies
CFTC Commodity Futures Trading Commission
EPA United States Environmental Protection Agency
FASB Financial Accounting Standards Board
FERC Federal Energy Regulatory Commission
IRS Internal Revenue Service
NYDEC New York State Department of Environmental Conservation
NYPSC State of New York Public Service Commission
PaDEP Pennsylvania Department of Environmental Protection
PaPUC Pennsylvania Public Utility Commission
PHMSA Pipeline and Hazardous Materials Safety Administration
SEC Securities and Exchange Commission
Other
Bbl Barrel (of oil)
Bcf Billion cubic feet (of natural gas)
Bcfe (or Mcfe) — represents Bcf (or Mcf) Equivalent The total heat value (Btu) of natural gas and oil expressed as a volume of natural gas. The Company uses a conversion formula of 1 barrel of oil = 6 Mcf of natural gas.
Btu British thermal unit; the amount of heat needed to raise the temperature of one pound of water one degree Fahrenheit.
Capital expenditure Represents additions to property, plant, and equipment, or the amount of money a company spends to buy capital assets or upgrade its existing capital assets.
Cashout revenues A cash resolution of a gas imbalance whereby a customer pays Supply Corporation and/or Empire for gas the customer receives in excess of amounts delivered into Supply Corporation’s and Empire’s systems by the customer’s shipper.
CLCPA Legislation referred to as the "Climate Leadership & Community Protection Act," enacted by the State of New York on July 18, 2019.
Degree day A measure of the coldness of the weather experienced, based on the extent to which the daily average temperature falls below a reference temperature, usually 65 degrees Fahrenheit.
Derivative A financial instrument or other contract, the terms of which include an underlying variable (a price, interest rate, index rate, exchange rate, or other variable) and a notional amount (number of units, barrels, cubic feet, etc.). The terms also permit for the instrument or contract to be settled net and no initial net investment is required to enter into the financial instrument or contract. Examples include futures contracts, options, no cost collars and swaps.
Development costs Costs incurred to obtain access to proved oil and gas reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas.
Development well A well drilled to a known producing formation in a previously discovered field.
Dodd-Frank Act Dodd-Frank Wall Street Reform and Consumer Protection Act.
Dth Decatherm; one Dth of natural gas has a heating value of 1,000,000 British thermal units, approximately equal to the heating value of 1 Mcf of natural gas.
Exchange Act Securities Exchange Act of 1934, as amended
Expenditures for long-lived assets Includes capital expenditures, stock acquisitions and/or investments in partnerships.
Exploitation Development of a field, including the location, drilling, completion and equipment of wells necessary to produce the commercially recoverable oil and gas in the field.
Exploration costs Costs incurred in identifying areas that may warrant examination, as well as costs incurred in examining specific areas, including drilling exploratory wells.
Exploratory well A well drilled in unproven or semi-proven territory for the purpose of ascertaining the presence underground of a commercial hydrocarbon deposit.
FERC 7(c) application An application to the FERC under Section 7(c) of the federal Natural Gas Act for authority to construct, operate (and provide services through) facilities to transport or store natural gas in interstate commerce.
Exploratory well A well drilled in unproven or semi-proven territory for the purpose of ascertaining the presence underground of a commercial hydrocarbon deposit.
Firm transportation and/or storage The transportation and/or storage service that a supplier of such service is obligated by contract to provide and for which the customer is obligated to pay whether or not the service is utilized.
GAAP Accounting principles generally accepted in the United States of America
Goodwill An intangible asset representing the difference between the fair value of a company and the price at which a company is purchased.
Hedging A method of minimizing the impact of price, interest rate, and/or foreign currency exchange rate changes, often times through the use of derivative financial instruments.
Hub Location where pipelines intersect enabling the trading, transportation, storage, exchange, lending and borrowing of natural gas.
ICE Intercontinental Exchange. An exchange which maintains a futures market for crude oil and natural gas.
Interruptible transportation and/or storage The transportation and/or storage service that, in accordance with contractual arrangements, can be interrupted by the supplier of such service, and for which the customer does not pay unless utilized.
LDC Local distribution company
LIBOR London Interbank Offered Rate
LIFO Last-in, first-out
Marcellus Shale A Middle Devonian-age geological shale formation that is present nearly a mile or more below the surface in the Appalachian region of the United States, including much of Pennsylvania and southern New York.
Mbbl Thousand barrels (of oil)
Mcf Thousand cubic feet (of natural gas)
MD&A Management’s Discussion and Analysis of Financial Condition and Results of Operations
MDth Thousand decatherms (of natural gas)
MMBtu Million British thermal units (heating value of one dekathermdecatherm of natural gas)
MMcf Million cubic feet (of natural gas)
MMcfe Million cubic feet equivalent
NEPA National Environmental Policy Act of 1969, as amended
NGA The Natural Gas Act of 1938, as amended; the federal law regulating interstate natural gas pipeline and storage companies, among other things, codified beginning at 15 U.S.C. Section 717.
NYMEX New York Mercantile Exchange. An exchange which maintains a futures market for crude oil and natural gas.
OPEB Other Post-Employment Benefit
Open Season A bidding procedure used by pipelines to allocate firm transportation or storage capacity among prospective shippers, in which all bids submitted during a defined time period are evaluated as if they had been submitted simultaneously.
PCB Polychlorinated Biphenyl
Precedent Agreement An agreement between a pipeline company and a potential customer to sign a service agreement after specified events (called “conditions precedent”) happen, usually within a specified time.
Proved developed reserves Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.
Proved undeveloped (PUD) reserves Reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required to make those reserves productive.
PRP Potentially responsible party
Reliable technology Technology that a company may use to establish reserves estimates and categories that has been proven empirically to lead to correct conclusions.
Reserves The unproduced but recoverable oil and/or gas in place in a formation which has been proven by production.
Restructuring Generally referring to partial “deregulation” of the pipeline and/or utility industry by statutory or regulatory process. Restructuring of federally regulated natural gas pipelines resulted in the separation (or “unbundling”) of gas commodity service from transportation service for wholesale and large-volume retail markets. State restructuring programs attempt to extend the same process to retail mass markets.
Revenue decoupling mechanism A rate mechanism which adjusts customer rates to render a utility financially indifferent to throughput decreases resulting from conservation.
S&P Standard & Poor’s Ratings Service
SAR Stock appreciation right
Service Agreement The binding agreement by which the pipeline company agrees to provide service and the shipper agrees to pay for the service.
SOFR Secured Overnight Financing Rate
Spot gas purchases The purchase of natural gas on a short-term basis.
Stock acquisitions Investments in corporations.
Unbundled service A service that has been separated from other services, with rates charged that reflect only the cost of the separated service.
Utica Shale A Middle Ordovician-age geological formation lying several thousand feet below the Marcellus Shale in the Appalachian region of the United States, including much of Ohio, Pennsylvania, West Virginia and southern New York.
VEBA Voluntary Employees’ Beneficiary Association
WNCWNC/WNA Weather normalization clause;clause/adjustment; a clause in utility rates which adjusts customer rates to allow a utility to recover its normal operating costs calculated at normal temperatures. If temperatures during the measured period are warmer than normal, customer rates are adjusted upward in order to recover projected operating costs. If temperatures during the measured period are colder than normal, customer rates are adjusted downward so that only the projected operating costs will be recovered.
For the Fiscal Year Ended September 30, 2017
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| CONTENTS |
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| Part I |
| ITEM 1 | | |
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| ITEM 1A | | |
| ITEM 1B | | |
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| Part II |
| ITEM 5 | | |
| ITEM 6 | | |
| ITEM 7 | | |
| ITEM 7A | | |
| ITEM 8 | | |
| ITEM 9 | | |
| ITEM 9A | | |
| ITEM 9B | | |
| ITEM 9C | | |
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| Part III |
| ITEM 10 | | |
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| ITEM 14 | | |
| Part IV |
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| ITEM 16 | | |
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PART I
The Company and its Subsidiaries
National Fuel Gas Company (the Registrant), incorporated in 1902, is a holding company organized under the laws of the State of New Jersey. Except as otherwise indicated below, theThe Registrant owns directly or indirectly all of the outstanding securities of its subsidiaries. Reference to “the Company” in this report means the Registrant, the Registrant and its subsidiaries or the Registrant’s subsidiaries as appropriate in the context of the disclosure. Also, all references to a certain year in this report relate to the Company’s fiscal year ended September 30 of that year unless otherwise noted.
The Company is a diversified energy company engaged principally in the production, gathering, transportation, distributionstorage and marketingdistribution of natural gas. The Company operates an integrated business, with assets centered in western New York and Pennsylvania, being used for, and benefiting from, the production and transportation of natural gas from the Appalachian basin. Current natural gas production development activities are focused in the Marcellus Shale, a Middle Devonian-ageand Utica shales, geological shale formationformations that isare present nearly a mile or more below the surface in the Appalachian region of the United States, including much of PennsylvaniaStates. Pipeline development activities are designed to transport natural gas production to both existing and southern New York.new markets. 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 Canada and the eastern United States. The Company also developsStates and produces oil reserves, primarily in California.Canada. The Company reports financial results for fivefour business segments: Exploration and Production, Pipeline and Storage, Gathering, Utility, and Energy Marketing.Utility.
1. The Exploration and Production segment operations are carried out by Seneca Resources CorporationCompany, LLC (Seneca), a Pennsylvania corporation.limited liability company. Seneca is engaged in the exploration for, and the development and production of, primarily natural gas and oil reserves in California and in the Appalachian region of the United States. At September 30, 2017,2022, Seneca had U.S. proved developed and undeveloped reserves of 30,207 Mbbl of oil and 1,973,1204,170,662 MMcf of natural gas.gas and 250 Mbbl of oil.
2. The Pipeline and Storage segment operations are carried out by National Fuel Gas Supply Corporation (Supply Corporation), a Pennsylvania corporation, and Empire Pipeline, Inc. (Empire), a New York corporation. Supply Corporation providesand Empire provide interstate natural gas transportation and storage services for affiliated and nonaffiliated companies through (i) an integrated gas pipeline system extending from southwestern Pennsylvania to the New York-Canadian border at the Niagara River and eastward to Ellisburg and Leidy,systems in Pennsylvania and (ii) 27New York. Supply Corporation also provides storage services through its underground natural gas storage fields, owned and operated byEmpire provides storage service (via lease with Supply Corporation as well as four other underground natural gas storage fields owned and operated jointly with other interstate gas pipeline companies. Empire transports and stores natural gas for major industrial companies, utilities (including Distribution Corporation) and power producers in New York State. Empire also transports natural gas for natural gas marketers along with exploration and production companies from natural gas producing areas in Pennsylvania to markets in New York and to interstate pipeline delivery points for additional markets in the northeastern United States and Canada. Empire owns the Empire Pipeline, a 249-mile pipeline system comprising three principal components: a 157-mile pipeline that extends from the United States/Canadian border at the Niagara River near Buffalo, New York to near Syracuse, New York; a 77-mile pipeline extension from near Rochester, New York to an interconnection with the unaffiliated Millennium Pipeline near Corning, New York (the Empire Connector), and a 15-mile pipeline extension from Corning into Tioga County, Pennsylvania (the Tioga County Extension).nonaffiliated company.
3. The Gathering segment operations are carried out by wholly-owned subsidiaries of National Fuel Gas Midstream CorporationCompany, LLC (Midstream Corporation)Company), a Pennsylvania corporation.limited liability company. Through these subsidiaries, Midstream CorporationCompany builds, owns and operates natural gas processing and pipeline gathering facilities in the Appalachian region.
4. The Utility segment operations are carried out by National Fuel Gas Distribution Corporation (Distribution Corporation), a New York corporation. Distribution Corporation sells natural gas or provides natural gas transportationutility services to approximately 743,500754,000 customers through a local distribution system located in western
New York and northwestern Pennsylvania. The principal metropolitan areas served by Distribution Corporation include Buffalo, Niagara Falls and Jamestown, New York and Erie and Sharon, Pennsylvania.
5. The Energy Marketing segment operations are carried out by National Fuel Resources, Inc. (NFR), a New York corporation, which markets natural gas to industrial, wholesale, commercial, public authority and residential customers primarily in western and central New York and northwestern Pennsylvania, offering competitively priced natural gas for its customers.
Financial information about each of the Company’s business segments can be found in Item 7, MD&A and also in Item 8 at Note JM — Business Segment Information.
The following business is not included in any of the five reported business segments:
Seneca’s Northeast Division which marketsis included in the Company's All Other category for 2021 and 2020. This division marketed timber from Appalachian land holdings. AtOn August 5, 2020, the Company entered into a purchase and sale agreement to sell substantially all timber and other assets, which at September 30, 2017,2020, accounted for the Company ownedCompany's ownership of approximately 93,00095,000 acres of timber property and managedmanagement of approximately 3,0002,500 additional acres of timber cutting rights. The transaction closed on December 10, 2020.
No single customer, or group of customers under common control, accounted for more than 10%
For additional discussion of the Company’spurchase and sale agreement to sell these assets, see Item 8 at Note B — Asset Acquisitions and Divestitures.
Revenues from three customers of the Company's Exploration and Production segment, exclusive of hedging losses transacted with separate parties, represented approximately $850 million, or 38.9%, of the Company's consolidated revenues in 2017.revenue for the year ended September 30, 2022. These three customers were also customers of the Company's Pipeline and Storage segment, accounting for an additional $15 million, or 0.7%, of the Company's consolidated revenue for the year ended September 30, 2022.
Rates and Regulation
The Utility segment’s rates, servicesCompany’s businesses are subject to regulation under a wide variety of federal, state and other matters are regulated by the NYPSClocal laws, regulations and policies. This includes federal and state agency regulations with respect to services provided within New Yorkrate proceedings, project permitting and byenvironmental requirements.
The Company is subject to the PaPUCjurisdiction of the FERC with respect to services provided within Pennsylvania.Supply Corporation, Empire and some transactions performed by other Company subsidiaries. The FERC, among other things, approves the rates that Supply Corporation and Empire may charge to their gas transportation and/or storage customers. Those approved rates also impact the returns that Supply Corporation and Empire may earn on the assets that are dedicated to those operations. The operations of Distribution Corporation are subject to the jurisdiction of the NYPSC, the PaPUC and, with respect to certain transactions, the FERC. The NYPSC and the PaPUC, among other things, approve the rates that Distribution Corporation may charge to its utility customers. Those approved rates also impact the returns that Distribution Corporation may earn on the assets that are dedicated to those operations. If Supply Corporation, Empire or Distribution Corporation are unable to obtain approval from these regulators for the rates they are requesting to charge customers, particularly when necessary to cover increased costs, earnings may decrease. For additional discussion of the Pipeline and Storage and Utility segment’ssegments’ rates, and regulation, see Item 7, MD&A under the heading “Rate and Regulatory Matters” and Item 8 at Note A — Summary of Significant Accounting Policies (Regulatory Mechanisms) and Note C — Regulatory Matters.
The Pipeline and Storage segment’s rates, services and other matters are regulated by the FERC. For additional discussion of the Pipeline and Storage segment’s rates and regulation, see Item 7, MD&A under the heading “Rate and Regulatory Matters” and Item 8 at Note A — Summary of Significant Accounting Policies (Regulatory Mechanisms) and Note CF — Regulatory Matters.
The discussion under Item 8 at Note CF — Regulatory Matters includes a description of the regulatory assets and liabilities reflected on the Company’s Consolidated Balance Sheets in accordance with applicable accounting standards. To the extent that the criteria set forth in such accounting standards are not met by the operations of the Utility segment or the Pipeline and Storage segment, as the case may be, the related regulatory assets and liabilities would be eliminated from the Company’s Consolidated Balance Sheets and such accounting treatment would be discontinued.
In addition,The FERC also exercises jurisdiction over the construction and operation of interstate gas transmission and storage facilities and possesses significant penalty authority with respect to violations of the laws and regulations it administers. The Company and its subsidiaries areis also subject to the same federal,jurisdiction of the Pipeline and Hazardous Materials Safety Administration (PHMSA). PHMSA issues regulations and conducts evaluations, among other things, that set safety standards for pipelines and underground storage facilities. PHMSA may delegate this authority to a state, as it has in New York and localPennsylvania, and that state may choose to institute more stringent safety regulations for the construction, operation and maintenance of intrastate facilities. In addition to this state safety authority program, the NYPSC imposes additional requirements on various subjects, includingthe construction of certain utility facilities. Increased regulation by these agencies, and other regulators, or requested changes to construction projects, could lead to operational delays or restrictions and increase compliance costs that the Company may not be able to recover fully through rates or otherwise offset.
For additional discussion of the material effects of compliance with government environmental matters, to which other companies doing similar business inregulation, see Item 7, MD&A under the same locations are subject.heading “Environmental Matters.”
The Exploration and Production Segment
The Exploration and Production segment contributed approximately 45.6% of the Company's 2017 net income available for common stock.of $306.1 million in 2022.
Additional discussion of the Exploration and Production segment appears below in this Item 1 under the headings “Sources and Availability of Raw Materials” and “Competition: The Exploration and Production Segment,” in Item 7, MD&A and in Item 8, Financial Statements and Supplementary Data.
The Pipeline and Storage Segment
The Pipeline and Storage segment contributed approximately 24.2% of the Company's 2017 net income available for common stock.of $102.6 million in 2022.
Supply Corporation’s firm transportation capacity is subjectThe Pipeline and Storage segment generated approximately 30% of its revenues in 2022 from services provided to change as the market identifies different transportation paths and receipt/delivery point combinations. At the end of fiscal year 2017, Supply Corporation
had firm transportation service agreements and leases for approximately 3,157 MDth per day (contracted transportation capacity). The Utility segment accounts for approximately 1,124 MDth per day or 35% of contracted transportation capacity, and the Energy Marketing and Exploration and Production segments represent another 157 MDth per day or 5%. Additionally, Supply Corporation leases 55 MDth per day or 2% of firm transportation capacity to Empire Pipeline. The remaining 1,821 MDth or 58% is subject to firm contracts or leases with nonaffiliated customers. Contracted transportation capacity with both affiliated and nonaffiliated shippers is expected to remain relatively constant in fiscal year 2018.
Supply Corporation had service agreements and leases for all of its firm storage capacity, totaling 68,042 MDth, at the end of 2017. The Utility segment has contracted for 28,491 MDth or 42% of the total firm storage capacity, and the Energy Marketing segment accounts for another 2,644 MDth or 4%. Additionally, Supply Corporation leases 3,753 MDth or 5% of its firm storage capacity to Empire. Nonaffiliated customers have contracted for the remaining 33,154 MDth or 49%. Supply Corporation does not expect any of its contracted firm storage services to terminate and be available for remarketing in fiscal year 2018.
At the end of 2017, Empire had service agreements in place for firm transportation capacity totaling up to approximately 954 MDth per day, with 98% of that capacity contracted as long-term, full-year deals. The Utility segment accounted for 4% of Empire’s firm contracted capacity, with the remaining 96% subject to contracts with nonaffiliated customers. None of the long-term contracts will expire or terminate in fiscal year 2018.
Empire’s firm storage capacity, totaling 3,753 MDth, was fully contracted at the end of fiscal year 2017. The total storage capacity is contracted on a long-term basis, with a nonaffiliated customer. The contract will not expire or terminate in fiscal year 2018.
The majority of Supply Corporation’s transportation and storage contracts, and the majority of Empire’s transportation contracts, allow either party to terminate the contract upon six or twelve months’ notice effective at the end of the primary term, and include “evergreen” language that allows for annual term extension(s).segment.
Additional discussion of the Pipeline and Storage segment appears below under the headings “Sources and Availability of Raw Materials,” “Competition: The Pipeline and Storage Segment” and “Seasonality,” in Item 7, MD&A and in Item 8, Financial Statements and Supplementary Data.
The Gathering Segment
The Gathering segment contributed approximately 14.2% of the Company's 2017 net income available for common stock.of $101.1 million in 2022.
The Gathering segment generated approximately 94% of its revenues in 2022 from services provided to the Exploration and Production segment.
Additional discussion of the Gathering segment appears below under the headings “Sources and Availability of Raw Materials” and “Competition: The Gathering Segment,” in Item 7, MD&A and in Item 8, Financial Statements and Supplementary Data.
The Utility Segment
The Utility segment contributed approximately 16.6% of the Company's 2017 net income available for common stock.of $68.9 million in 2022.
Additional discussion of the Utility segment appears below under the headings “Sources and Availability of Raw Materials,” “Competition: The Utility Segment” and “Seasonality,” in Item 7, MD&A and in Item 8, Financial Statements and Supplementary Data.
The Energy Marketing Segment
The Energy Marketing segment contributed approximately 0.5% of the Company's 2017 net income available for common stock.
Additional discussion of the Energy Marketing segment appears below under the headings “Sources and Availability of Raw Materials,” “Competition: The Energy Marketing Segment” and “Seasonality,” in Item 7, MD&A and in Item 8, Financial Statements and Supplementary Data.
All Other Category and Corporate Operations
The All Other category and Corporate operations incurred a net loss of $12.7 million in 2017. The impact of this net loss in relation to the Company's 2017 net income available for common stock was negative 1.1%.2022.
Additional discussion of the All Other category and Corporate operations appears below in Item 7, MD&A and in Item 8, Financial Statements and Supplementary Data.
Sources and Availability of Raw Materials
The Exploration and Production segment seeks to discover and produce raw materials (natural gas oil and hydrocarbon liquids) as further described in this report in Item 7, MD&A and Item 8 at Note JM — Business Segment Information and Note MN — Supplementary Information for Oil and Gas Producing Activities.
The Pipeline and Storage segment transports and stores natural gas owned by its customers, whose gas primarily originates in the southwestern, mid-continent and Appalachian regionsregion of the United States, as well as other gas supply regions in the United States and Canada. Additional discussion of proposed pipeline projects appears below under “Competition: The Pipeline and Storage Segment” and in Item 7, MD&A.
The Gathering segment gathers, processes and transports natural gas that is, in large part, produced by Seneca in the Appalachian region of the United States. Additional discussion of proposed gathering projects appears below in Item 7, MD&A.
Natural gas is the principal raw material for the Utility segment. In 2017,2022, the Utility segment purchased 65.776.0 Bcf of gas (including 60.774.2 Bcf for delivery to retail customers 1.3 Bcf for off-system sales and 3.71.8 Bcf used in operations). pursuant to its purchase contracts with firm delivery requirements. Gas purchased from producers and suppliers in the United States under firmmulti-month contracts (seasonal and longer) accounted for 53%48% of these purchases. Purchases of gas onin the spot market (contracts of one month or less) accounted for 47%52% of the Utility segment’s 20172022 purchases. Purchases from DTE Energy Trading, Inc. (26%(33%), NextEra Energy Marketing, LLC (15%), SWNEmera Energy Services, Company, LLCInc. (12%), South Jersey Resources Group,Chevron Natural Gas (8%), EQT Energy, LLC (11%(7%), J. Aron & Company (9%Vitol Inc. (6%), Tenaska Marketing Ventures (6%), and DirectShell Energy Business Marketing (8%North America US (6%), accounted for 81%nearly 78% of the Utility’s 2017Utility segment's 2022 gas purchases. No other producer or supplier provided the Utility segment with more than 5% of its gas requirements in 2017.2022. The Utility segment does not directly purchase gas from affiliates.
The Energy Marketing segment depends on an adequate supply of natural gas to deliver to its customers. In 2017, this segment purchased 39.7 Bcf of gas, including 38.9 Bcf for delivery to its customers. The remaining 0.8 Bcf largely represents gas used in operations. The gas purchased by the Energy Marketing segment originates primarily in either the Appalachian or mid-continent regions of the United States.
Competition
Competition in the natural gas industry exists among providers of natural gas, as well as between natural gas and other sources of energy, such as fuel oil and electricity. Management believes that the reliability and affordability, along with the environmental advantages of natural gas have enhanced its competitive position relative to other fuels.
The Company competes on the basis of price, service and reliability, product performance and other factors. Sources and providers of energy, other than those described under this “Competition” heading, do not compete with the Company to any significant extent.
Competition: The Exploration and Production Segment
The Exploration and Production segment competes with other oil and natural gas producers and marketers with respect to sales of oil and natural gas. The Exploration and Production segment also competes, by competitive bidding and otherwise, with other oil and natural gas producers with respect to exploration and development prospects and mineral leaseholds.
To compete in this environment, Seneca originates and acts primarily as operator on certain of its prospects, seeks to minimize the risk of exploratory efforts through partnership-type arrangements, utilizes technology for both exploratory studies and drilling operations, and seeks market nichesprospect and partnership opportunities based on size, operating expertise and financial criteria.
Competition: The Pipeline and Storage Segment
Supply Corporation competes for market growth in the natural gas market with other pipeline companies transporting gas in the northeast United States and with other companies providing gas storage services. Supply Corporation has some unique characteristics which enhance its competitive position, as described below.position. Most of Supply Corporation’s facilities are in or near areas overlying the Marcellus and Utica Shaleshale production areas in Pennsylvania, and it has established interconnections with producers and other pipelines that provide access to access these supplies.supplies and to premium off-system markets. Its facilities are also located adjacent to the Canadian border at the Niagara River (Niagara) providing access to markets in Canada and through TransCanada Pipeline, to markets in the northeastern and midwestern United States.States via the TC Energy pipeline system. Supply Corporation has developed and placed into service a number of pipeline expansion projects designed to receivetransport natural gas produced from the Marcellus Shale and transport it to key markets withinin New York, and Pennsylvania, the northeastern United States, Canada, and most recently to long-haul pipelines moving gas intowith access to the U.S. Midwest and even back to the gulf coast.Gulf Coast. For further discussion of Pipeline and Storage projects, refer to Item 7, MD&A under the headingsheading “Investing Cash Flow.”
Empire competes for market growth in the natural gas market growth with other pipeline companies transporting gas in the northeast United States and upstate New York in particular. Empire is well situated to provide transportation of Appalachian-sourcedAppalachian shale gas as well as gas receivedsupplies available at the Niagara RiverEmpire’s interconnect with TC Energy at Chippawa. Empire’s geographic location provides it the opportunity to compete for an increasedservice to its on-system LDC markets, as well as for a share of the gas transportation markets both for delivery to the New York and Northeast markets and frominto Canada (via Chippawa) and into Canada. As noted above, the northeastern United States. The Empire Connector, andalong with other subsequent projects, has expanded Empire’s natural gas pipelinefootprint and enablescapability, allowing Empire to serve new markets in New York and elsewhere in the Northeast, and to attach to prolific Marcellus and Utica supplies principally from Tioga and Bradford Counties in Pennsylvania. Like Supply Corporation, Empire’s expanded system facilitates transportation of Marcellus Shalenatural gas to key markets within New York State, the northeastern United States and Canada.
Competition: The Gathering Segment
The Gathering segment provides gathering services for Seneca’s productionSeneca and, to a lesser extent, other producers. It competes with other companies that gather and process natural gas in the Appalachian region.
Competition: The Utility Segment
With respect to gas commodity service, in New York and Pennsylvania, both of which have implemented “unbundling” policies that allow customers to choose their gas commodity supplier, Distribution Corporation
has retained a substantial majority of small sales customers. In both New York approximately 20%, and in Pennsylvania, approximately 14%,8% of Distribution Corporation’s small-volume residential and commercial customers purchase their supplies from unregulated marketers. In contrast, almost all large-volume load is served by unregulated retail marketers. However, retail competition for gas commodity service does not pose an acute competitive threat for Distribution Corporation, because in both jurisdictions, utility cost of service is recovered through rates and charges for gas delivery service, not gas commodity service. Over the longer run, it is possible that rate design changes resulting from further customer migration to marketer service could expose utility companies such as Distribution Corporation to stranded costs and revenue erosion in the absence of compensating rate relief.
Competition for transportation service to large-volume customers continues with local producers or pipeline companies attempting to sell or transport gas directly to end-users located within the Utility segment’s service territories without use of the utility’s facilities (i.e., bypass). In addition, while competition continues with fuel oil suppliers.suppliers exists, natural gas retains its competitive position despite recent commodity pricing.
The Utility segment competes in its most vulnerable markets (the large commercial and industrial markets) by offering unbundled, flexible, high quality services. The Utility segment continues to develop or promote new usesadvance programs promoting the efficient use of natural gas.
Legislative and regulatory measures to address climate change and greenhouse gas emissions are in various phases of discussion or implementation in jurisdictions that impact the Utility segment. In addition to the Inflation Reduction Act, New York, for example, adopted the Climate Leadership & Community Protection Act (CLCPA) in July 2019, which could ultimately result in increased competition from electric and geothermal forms of energy. However, given the extended time frames associated with the CLCPA's emission reduction mandates as well as new services, ratesdiscussed in Item 7, MD&A under the heading “Environmental Matters” and contracts.subheading “Environmental Regulation,” any meaningful competition resulting from the CLCPA cannot be determined.
Competition: The Energy Marketing Segment
The Energy Marketing segment competes with other marketers of natural gas and with other providers of energy supply. Competition in this area is well developed with regard to price and services from local, regional and national marketers.
Seasonality
Variations in weather conditions can materially affect the volume of natural gas delivered by the Utility segment, as virtually all of its residential and commercial customers use natural gas for space heating. The effect that this has on Utility segment margins in New York is largely mitigated by a WNC,weather normalization clause (WNC), which covers the eight-month period from October through May. Weather that is warmer than normal results in an upward adjustment to customers’ current bills, while weather that is colder than normal results in a downward adjustment, so that in either case projected operating costsdelivery revenues calculated at normal temperatures will be largely recovered.
Volumes transported and stored by Supply Corporation and volumes transported by Empire may vary materiallysignificantly depending on weather, without materially affecting the revenues of those companies. Supply Corporation’s and Empire’s allowed rates are based on a straight fixed-variable rate design which allows recovery of fixed costs in fixed monthly reservation charges. Variable charges based on volumes are designed to recover only the variable costs associated with actual transportation or storage of gas.
Variations in weather conditions materially affect the volume of gas consumed by customers of the Energy Marketing segment. Volume variations have a corresponding impact on revenues within this segment.
Capital Expenditures
A discussion of capital expenditures by business segment is included in Item 7, MD&A under the heading “Investing Cash Flow.”
Environmental Matters
A discussion of material environmental matters involving the Company is included in Item 7, MD&A under the heading “Environmental Matters” and in Item 8, Note IL — Commitments and Contingencies.
Miscellaneous
The Company and its wholly owned or majority-owned subsidiaries had a total of 2,100 full-time employees at September 30, 2017.
The Company has agreements in place with collective bargaining units in New York and Pennsylvania. Agreements covering employees in collective bargaining units in New York are scheduled to expire in February 2021. Agreements covering employees in collective bargaining units in Pennsylvania are scheduled to expire in April 2018 and May 2018. The Company is scheduled to begin negotiation discussions with these bargaining units in early 2018.
The Utility segment has numerous municipal franchises under which it uses public roads and certain other rights-of-way and public property for the location of facilities. When necessary, the Utility segment renews such franchises.
The Company makes its annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and any amendments to those reports, available free of charge on the Company’s internet website, www.nationalfuelgas.com, as soon as reasonably practicable after they are electronically filed with or furnished
to the SEC. The information available at the Company’s internet website is not part of this Form 10-K or any other report filed with or furnished to the SEC.
Human Capital
The Company aims to attract the best employees, to retain those employees through offering competitive benefits, career development and training opportunities, while also prioritizing their safety and wellness, and to create a safe, inclusive and productive work environment for everyone. Human capital measures and objectives that the Company focuses on in managing its business include the safety of its employees, its voluntary attrition rate, the number of work stoppages, its employee benefits, employee development, and diversity and inclusion. Additional information regarding the Company’s human capital measures and objectives is contained in the Company’s recently published Corporate Responsibility Report, which is available on the Company’s website, www.nationalfuelgas.com. The information on the Company’s website is not, and will not be deemed to be, a part of this annual report on Form 10-K or incorporated into any of the Company’s other filings with the SEC.
Employees and Collective Bargaining Agreements
The Company and its wholly-owned subsidiaries had a total of 2,132 full-time employees at September 30, 2022.
As of September 30, 2022, 48% of the Company’s active workforce was covered under collective bargaining agreements. The Company has agreements in place with collective bargaining units in New York into February 2025, as well as with collective bargaining units in Pennsylvania into April 2026.
Safety
Safety is one of the Company’s guiding principles. In managing the business, the Company focuses on the safety of its employees and contractors and has implemented safety programs and management practices to promote a culture of safety. This includes required trainings for both field and office employees, as well as specific qualifications and certifications for field employees. The Company also ties executive compensation to safety related goals to emphasize the importance of and focus on safety at the Company.
Voluntary Attrition Rate
The Company measures the voluntary attrition rate of its employees in assessing the Company’s overall human capital. The Company's voluntary attrition rate (not including retirements and excluding the severance related to the sale of Seneca's assets in California) was 8%. Additionally, throughout the COVID-19 pandemic, the Company did not institute any furloughs or workforce reductions.
No Work Stoppages
During the Company’s fiscal year, the Company did not incur any work stoppages (strikes or lockouts) and therefore experienced zero idle days for the fiscal year.
Employee Benefits
To attract employees and meet the needs of the Company’s workforce, the Company offers market-competitive benefits packages to employees of its subsidiaries. The Company’s benefits package options may vary depending on type of employee and date of hire. Additionally, the Company continuously looks for ways to improve employee work-life balance and well-being.
Employee Development
The Company provides its employees with tools and development resources to enhance their skills and careers at the Company, including: (i) encouraging employees to discuss their professional development and identify interests or possible cross-training areas during annual performance reviews with their supervisors; (ii) offering corporate and technical training programs based on position, regulatory environment, and employee needs; (iii) providing a tuition aid program for educational pursuits related to present work or possible future positions; (iv) providing talent review and succession planning; (v) providing opportunities for on-the-job growth, through stretch assignments or temporary projects outside of an employee’s typical responsibilities; and
(vi) offering one-on-one meetings for supervisory employees at the Company’s subsidiaries to discuss career pathing and employee development.
Diversity, Equity and Inclusion
The Company recognizes that a diverse talent pool provides the opportunity to gain a diversity of perspectives, ideas and solutions to help the Company succeed. As such, the Company approaches diversity from the top-down, which is reflected in the makeup of our Board of Directors and senior leadership team: three out of eleven directors are diverse, and four of the Company’s eight designated executive officers are women. The Company's Corporate Governance Guidelines incorporate the “Rooney Rule.” As a result, when identifying independent director candidates for nomination to the Board, the Nominating/Corporate Governance Committee is committed to including in any initial candidate pool qualified racially, ethnically and/or gender diverse candidates. Beginning in fiscal 2021, the Compensation Committee adopted specific diversity and inclusion performance goals as part of the Company's Annual at Risk Compensation Incentive Plan and Executive Annual Compensation Incentive Program to link executive compensation to the Company's focus on diversity.
During fiscal 2022, the Company furthered numerous initiatives to increase the diversity of our workforce and create a more inclusive environment. The Company's Director of Diversity and Inclusion (“D&I Director”) continued to spearhead diversity and inclusion initiatives across the organization. Additional resources were added to the Diversity and Inclusion team with the creation of a Diversity and Inclusion Specialist ("D&I Specialist") role to assist and expand the Company’s proactive efforts of creating a more inclusive organization. These efforts include initiatives to focus on diversity when making hiring and promotional decisions. To attract diverse candidates, the Company works with community groups and organizations to help promote awareness of our job opportunities within diverse communities. The D&I Director maintains close partnerships with the employment teams, cultivates the Company’s relationships with community organizations, and focuses on initiatives to attract diverse candidates, vendors and suppliers. The executive team receives a monthly report about the composition of the Company’s salaried applicant pools to encourage the recruiting team to focus recruiting in diverse communities and identify resources needed to do so. The Company has also focused on encouraging diverse suppliers to receive the necessary certifications to participate in the industry and has added new diverse suppliers to its list of vendors in an effort to promote diversity.
The D&I Director and D&I Specialist also spearhead inclusion initiatives throughout the organization. To promote a more inclusive work environment, the Company has continued to provide training opportunities to employees relating to Unconscious Bias, Inclusivity, and Micro-aggressions. In addition, four new Employee Resource Groups, focused towards ethnically diverse, veteran, LGBTQ and female employees, were developed. These Employee Resource Groups provide an opportunity to engage and connect with underrepresented employees, and each group has an executive sponsor which helps facilitate communication directly to senior management. In addition, the Company has several policies that reinforce its commitment to diversity and inclusion within the workplace. The Company’s Employee Handbook Policy includes equal employment opportunity commitments and nondiscrimination and anti-harassment disclosures, which communicate the Company’s expectations with respect to maintaining a professional workplace free of harassment. The Company prohibits discrimination or harassment against any employee or applicant on the basis of sex, race/ethnicity, or the other protected categories listed within the Company’s Non-Discrimination and Anti-Harassment Policy. This policy is mailed to employees annually with an employee survey, and employees must acknowledge that they have received the policy. The Company reiterates its commitment to a harassment free workplace through this process, as well as through prevention training for employees. Annually, the Company’s Chief Executive Officer reinforces the Company’s commitment to harassment prevention and equal employment opportunity by signing corporate Equal Employment Opportunity and Non-Discrimination and Anti-Harassment policy statements. These statements are then displayed at Company locations, included in employee handbooks, and discussed with new hires during their onboarding process.
Executive Officers of the Company as of November 15, 2017(1)
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| | | | | | | |
Name and Age (as of November 15, 2017)2022) | | Current Company Positions and
Other Material Business Experience
During Past Five Years
|
Ronald J. TanskiDavid P. Bauer
(65)(53)
| | Chief Executive Officer of the Company since April 2013 andJuly 2019. President of the Company since July 2010. Mr. Tanski previously served as Chief OperatingSupply Corporation from February 2016 through June 2019. Treasurer and Principal Financial Officer of the Company from July 2010 through March 2013.June 2019. Treasurer of Seneca from April 2015 through June 2019. Treasurer of Distribution Corporation from April 2015 through June 2019. Treasurer of Midstream Company from April 2013 through June 2019. Treasurer of Supply Corporation from June 2007 through June 2019. Treasurer of Empire from June 2007 through June 2019. |
John R. PustulkaDonna L. DeCarolis
(65)(63)
| | President of Distribution Corporation since February 2019. Ms. DeCarolis previously served as Vice President of Business Development of the Company from October 2007 through January 2019. |
Ronald C. Kraemer (66) | | Chief Operating Officer of the Company since February 2016.March 2021, President of Supply Corporation since July 2019 and President of Empire since August 2008. Mr. PustulkaKraemer previously served as Senior Vice President of Supply Corporation from July 2010June 2016 through January 2016.June 2019. |
David P. BauerKaren M. Camiolo
(48)(63)
| | President of Supply Corporation since February 2016. Treasurer and Principal Financial Officer of the Company since July 2010.2019. Treasurer of Seneca Resources Company since April 2015;July 2019. Ms. Camiolo previously served as Treasurer of Distribution Corporation, since April 2015; Treasurer of Midstream Corporation since April 2013; Treasurer of Supply Corporation, sinceEmpire and Midstream Company from July 2019 through June 2007; and Treasurer of Empire since June 2007. Mr. Bauer2021. Ms. Camiolo previously served as Assistant TreasurerController and Principal Accounting Officer of Distribution Corporationthe Company from April 2004 through March 2015. |
Carl M. Carlotti
(62)
| | President of Distribution Corporation since February 2016. Mr. Carlotti previously served as SeniorJune 2019. Vice President of Distribution Corporation from January 2008April 2015 through January 2016. |
Ronald C. Kraemer
(61)
| | PresidentJune 2019. Controller of Midstream Company from April 2013 through June 2019. Controller of Empire Pipeline, Inc. since August 2008from June 2007 through June 2019. Controller of Distribution Corporation and Senior Vice President of Supply Corporation since June 2016. Mr. Kraemer previously served as Vice President of Supply Corporation from August 2008April 2004 through May 2016.June 2019. |
John P. McGinnisElena G. Mendel
(57)(56)
| | President of Seneca Resources Corporation since May 2016. Mr. McGinnis previously served as Chief Operating Officer of Seneca Resources Corporation from October 2015 through April 2016 and Senior Vice President of Seneca Resources Corporation from March 2007 through September 2015. |
Paula M. Ciprich
(57)
| | Senior Vice President of the Company since April 2015; Secretary of the Company since July 2008; General Counsel of the Company since January 2005; Secretary of Distribution Corporation since July 2008. |
Karen M. Camiolo
(58)
| | Controller and Principal Accounting Officer of the Company since April 2004; Vice President of Distribution Corporation since April 2015; Controller of Midstream Corporation since April 2013; Controller of Empire since June 2007; andJuly 2019. Controller of Distribution Corporation, and Supply Corporation, Empire, and Midstream Company since April 2004.July 2019. Assistant Controller of Distribution Corporation, Supply Corporation and Empire from February 2017 through June 2019. |
Donna L. DeCarolisMartin A. Krebs
(58)(52)
| | Vice President Business Development of the Company since October 2007. |
Ann M. Wegrzyn
(59) | | Chief Information Officer of the Company since February 2017. Mrs. WegrzynDecember 2018. Prior to joining the Company, Mr. Krebs served as Chief Information Officer and Chief Information Security Officer of Fidelis Care, a health insurance provider for New York State residents, from January 2012 to June 2018. Centene Corporation acquired Fidelis Care in July 2018, and Mr. Krebs served as the Chief Information Officer of the Fidelis Plan and Senior Vice President of Information Technology and Security from the acquisition to November 2018. Mr. Krebs' prior employers are not subsidiaries or affiliates of the Company. |
Sarah J. Mugel (58) | | Corporate Responsibility Officer of the Company since April 2022. General Counsel of the Company since May 2020 and Secretary of the Company since July 2018. Ms. Mugel has been Vice President of Supply Corporation since April 2015 and General Counsel and Secretary of Supply Corporation since April 2016. Ms. Mugel has been Secretary of Empire Pipeline and Secretary of Midstream Company, and has served as the General Counsel of both entities, since April 2016. Ms. Mugel previously served as Assistant Secretary of the Company from June 2016 through June 2018. |
Justin I. Loweth (44) | | President of Midstream Company since April 2022 and President of Seneca Resources Company since May 2021. Mr. Loweth previously served as Senior Vice President of Distribution CorporationSeneca Resources Company from December 2010October 2017 through January 2017.April 2021. |
(1)The executive officers serve at the pleasure of the Board of Directors. The information provided relates to the Company and its principal subsidiaries. Many of the executive officers also have served, or currently serve, as officers or directors of other subsidiaries of the Company.
| | | | | |
(1) | The executive officers serve at the pleasure of the Board of Directors. The information provided relates to the Company and its principal subsidiaries. Many of the executive officers also have served or currently serve as officers or directors of other subsidiaries of the Company. |
As a holding company, the Company depends on its operating subsidiaries to meet its financial obligations.
The Company is a holding company with no significant assets other than the stock of its operating subsidiaries. In order to meet its financial needs, the Company relies exclusively on repayments of principal and interest on intercompany loans made by the Company to its operating subsidiaries and income from dividends and other cash flow from the subsidiaries. Such operating subsidiaries may not generate sufficient net income to pay upstream dividends or generate sufficient cash flow to make payments of principal or interest on such intercompany loans.STRATEGIC RISKS
The Company is dependent on capital and credit markets to successfully execute its business strategies.
The Company relies upon short-term bank borrowings, commercial paper markets and longer-term capital markets to finance capital requirements not satisfied by cash flow from operations. The Company is dependent on these capital sources to provide capital to its subsidiaries to fund operations, acquire, maintain and develop properties, and execute growth strategies. The availability and cost of credit sources may be cyclical and these capital sources may not remain available to the Company. Turmoil in credit markets may make it difficult for the Company to obtain financing on acceptable terms or at all for working capital, capital expenditures and other investments, or to refinance maturing debt on favorable terms.existing debt. These difficulties could adversely affect the Company's growth strategies, operations and financial performance.
The Company's ability to borrow under its credit facilities and commercial paper agreements, and its ability to issue long-term debt under its indentures, depend on the Company's compliance with its obligations under the facilities, agreements and indentures. For example, to issue incremental long-term debt, the Company must meet an interest coverage test under its 1974 indenture. In general, the Company’s operating income, subject to certain adjustments, over a consecutive 12-month period within the 15 months preceding the debt issuance, must be not less than two times the total annual interest charges on the Company’s long-term debt, taking into account the incremental issuance. In addition, taking into account the incremental issuance, and using a pro forma balance sheet as of the last day of the 12-month period used in the interest coverage test, the Company must maintain a ratio of long-term debt to consolidated assets (as defined under the 1974 indenture) of not more than 60%. The 1974 indenture defines consolidated assets as total assets less a number of items, including current and accrued liabilities. Depending on their magnitude, factors that reduce the Company’s operating income and/or total assets, including impairments (i.e., write-downs) of the Company’s natural gas properties, or that increase current and accrued liabilities, like short-term borrowings and "out of the money" derivative financial instruments, could contribute to the Company’s inability to meet the interest coverage test or debt-to-assets ratio.
In addition, the Company's short-term bank loans and commercial paper are in the form of floating rate debt or debt that may have rates fixed for very short periods of time, resulting in exposure to interest rate fluctuations in the absence of interest rate hedging transactions. The cost of long-term debt, the interest rates on the Company's short-term bank loans and commercial paper and the ability of the Company to issue commercial paper are affected by its debt credit ratings published by S&P, Moody's Investors Service, Inc. and Fitch Ratings.Ratings, Inc. A downgrade in the Company's credit ratings could increase borrowing costs, restrict or eliminate access to commercial paper markets, negatively impact the availability of capital from banks, commercial paper purchasers and otheruncommitted sources, and require the Company’s subsidiaries to post letters of credit, cash or other assets as collateral with certain counterparties. Additionally, $300 million$1.1 billion of the Company’s outstanding long-term debt would be subject to an interest rate increase if certain fundamental changes occur that involve a material subsidiary and result in a downgrade of thea credit ratingsrating assigned to the notes below investment grade. In addition to the $1.1 billion, another $500 million of the Company’s outstanding long-term debt would be subject to an interest rate increase based solely on a downgrade of a credit rating assigned to the notes below investment grade, regardless of any additional fundamental changes.
Climate change, and the regulatory, legislative, consumer behaviors and capital access developments related to climate change, may adversely affect operations and financial results.
Climate change, and the laws, regulations and other initiatives to address climate change, may impact the Company’s financial results. In early 2021, the U.S. rejoined the Paris Agreement, the international effort to establish emissions reduction goals for signatory countries. Under the Paris Agreement, signatory countries are expected to submit their nationally determined contributions to curb greenhouse gas emissions and meet the agreed temperature objectives every five years. On April 22, 2021, the federal administration announced the U.S. nationally determined contribution to achieve a fifty to fifty-two percent reduction from 2005 levels in economy-wide net greenhouse gas pollution by 2030. In addition to the federal reentry into the Paris
Agreement, state and local governments, non-governmental organizations, investment firms, and financial institutions have made, and will likely continue to make, more aggressive efforts to reduce emissions and advance the objectives of the Paris Agreement. Executive orders from the federal administration, in addition to federal, state and local legislative and regulatory initiatives proposed or adopted in an attempt to limit the effects of climate change, including greenhouse gas emissions, could have significant impacts on the energy industry including government-imposed limitations, prohibitions or moratoriums on the use and/or production of gas, establishment of a carbon tax and/or methane fee, lack of support for system modernization, as well as accelerated depreciation of assets and/or stranded assets.
Federal and state legislatures have from time to time considered bills that would establish a cap-and-trade program, methane fee or carbon tax to incent the reduction of greenhouse gas emissions. For example, in August 2022, the federal Inflation Reduction Act was signed into law, which 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. In addition, the New York State legislature, in early 2021, proposed a bill known as the Climate and Community Investment Act, which proposed an escalating fee starting at $55 per short ton of carbon dioxide equivalent on any carbon-based fuels sold, used or brought into the state. That bill did not pass, but similar legislation may be proposed in the future. If the Company becomes subject to new or revised cap-and-trade programs, methane charges, fees for carbon-based fuels or other similar costs or charges, the Company may experience additional costs and incremental operating expenses, which would impact our future earnings and cash flows.
A number of states have also adopted energy strategies or plans with goals that include the reduction of greenhouse gas emissions. For example, Pennsylvania has a methane reduction framework for the natural gas industry which has resulted in permitting changes with the stated goal of reducing methane emissions from well sites, compressor stations and pipelines. In addition, the NYPSC initiated a proceeding to consider climate-related financial disclosures at the utility operating level, and in 2019, the New York State legislature passed the CLCPA, which created emission reduction and electric generation mandates, and could ultimately impact the Utility segment’s customer base and business. Pursuant to the CLCPA, New York's Climate Action Council issued for comment a draft scoping plan that includes recommendations to decommission substantial portions of the natural gas system and curtail use of natural gas and natural gas appliances.
Legislation or regulation that aims to reduce greenhouse gas emissions could also include natural gas bans, greenhouse gas emissions limits and reporting requirements, carbon taxes and/or similar fees on carbon dioxide, methane or equivalent emissions, restrictive permitting, increased efficiency standards requiring system remediation and/or changes in operating practices, and incentives or mandates to conserve energy or use renewable energy sources. NYDEC finalized its Part 203 Oil and Gas Sector Rule in March 2022, which significantly increases leak detection and repair inspections, recordkeeping, reporting, and notification requirements for multiple sources along city gates, transmission pipelines, compressor stations, storage facilities, and gathering lines.
Additionally, the trend toward increased energy conservation, change in consumer behaviors, competition from renewable energy sources, and technological advances to address climate change may reduce the demand for natural gas. For further discussion of the risks associated with environmental regulation to address climate change, refer to Item 7, MD&A under the heading “Environmental Matters.”
Further, recent trends directed toward a low-carbon economy could shift funding away from, or limit or restrict certain sources of funding for, companies focused on fossil fuel-related development or carbon-intensive investments. To the extent financial markets view climate change and greenhouse gas emissions as a financial risk, the Company’s cost of and access to capital could be negatively impacted.
Organized opposition to the natural gas industry could have an adverse effect on Company operations.
Organized opposition to the natural gas industry, including exploration and production activity, pipeline expansion and replacement projects, and the extension and continued operation of natural gas distribution systems, may continue to increase as a result of, among other things, safety incidents involving natural gas facilities, and concerns raised by politicians, financial institutions and advocacy groups about greenhouse gas
emissions, hydraulic fracturing, or fossil fuels generally. This opposition may lead to increased regulatory and legislative initiatives that could place limitations, prohibitions or moratoriums on the use of natural gas, impose costs tied to carbon emissions, provide cost advantages to alternative energy sources, or impose mandates that increase operational costs associated with new natural gas infrastructure and technology. There are also increasing litigation risks associated with climate change concerns and related disclosures. Increased litigation could cause operational delays or restrictions, and increase the Company’s operating costs. In turn, these factors could impact the competitive position of natural gas, ultimately affecting the Company’s results of operations and cash flows.
Delays or changes in plans or costs with respect to Company projects, including regulatory delays or denials with respect to necessary approvals, permits or orders, could delay or prevent anticipated project completion and may result in asset write-offs and reduced earnings.
Construction of planned distribution, gathering, and transmission pipeline and storage facilities, as well as the expansion and replacement of existing facilities, and the development of new natural gas wells, is not ablesubject to maintain investment-grade credit ratings, itvarious regulatory, environmental, political, legal, economic and other development risks, including the ability to obtain necessary approvals and permits from regulatory agencies on a timely basis and on acceptable terms, or at all. Existing or potential third-party opposition, such as opposition from landowner and environmental groups, which are beyond our control, could materially affect the anticipated construction of a project. In addition, third parties could impede the Company’s acquisition, expansion or renewal of rights-of-way or land rights on a timely basis and on acceptable terms. Any delay in project development or construction may prevent a planned project from going into service when anticipated, which could cause a delay in the receipt of revenues from those facilities, result in asset write-offs and materially impact operating results or anticipated results. Additionally, delays in pipeline construction projects or gathering facility completion could impede the Exploration and Production segment's ability to transport its production to premium markets, or to fulfill obligations to sell at contracted delivery points.
FINANCIAL RISKS
As a holding company, the Company depends on its operating subsidiaries to meet its financial obligations.
The Company is a holding company with no significant assets other than the stock of its operating subsidiaries. In order to meet its financial needs, the Company relies exclusively on repayments of principal and interest on intercompany loans made by the Company to its operating subsidiaries and income from dividends. Such operating subsidiaries may not be ablegenerate sufficient net income to access commercial paper markets.pay dividends to the Company or generate sufficient cash flow to make payments of principal or interest on such intercompany loans.
The Company may be adversely affected by economic conditions and their impact on our suppliers and customers.
Periods of slowed economic activity generally result in decreased energy consumption, particularly by industrial and large commercial companies. As a consequence, national or regional recessions or other downturns in economic activity could adversely affect the Company’s revenues and cash flows or restrict its future growth. Additionally, supply chain disruptions, and the associated costs and inflation related thereto, could have an impact on the Company's operations. Economic conditions in the Company’s utility service territories, along with legislative and energy marketing territoriesregulatory prohibitions and/or limitations on terminations of service, also impact its collections of accounts receivable. All of the Company’s segments are exposed to risks associated with the creditworthiness or performance of key suppliers and customers, many of which may be adversely affected by volatile conditions in the financial markets. These conditions could result in financial instability or other adverse effects at any of our suppliers or customers. For example, counterparties to the Company’s commodity hedging arrangements or commodity sales contracts might not be able to perform their obligations under these arrangements or contracts. Customers of the Company’s Utility and Energy Marketing segmentssegment may have particular trouble paying their bills during periods of declining economic activity, high inflation, or high commodity prices, potentially resulting in increased bad debt expense and reduced earnings. Similarly, if reductions were to occur in funding of the federal Low Income Home Energy Assistance Program, bad debt expense could increase and earnings could decrease. In addition, oil and natural gas exploration and production companies that are customers of the Company’s Pipeline and Storage segment may decide not to renew contracts for the same transportation capacitycapacity. Certain customers of the Company's Exploration and Production segment can represent a concentrated risk during periodstimes of reduced
production due to persistent lowhigh commodity prices.prices and high hedge losses. Any of these events
or circumstances could have or contribute to a material adverse effect on the Company’s results of operations, financial condition and cash flows.
TheChanges in interest rates may affect the Company’s credit ratingsfinancing and its regulated businesses’ rates of return.
Rising interest rates may not reflect allimpair the risksCompany’s ability to cost-effectively finance capital expenditures and to refinance maturing debt. In addition, the Company’s authorized rate of an investmentreturn in its securities.regulated businesses is based upon certain assumptions regarding interest rates. If interest rates are lower than assumed rates, the Company’s authorized rate of return could be reduced. If interest rates are higher than assumed rates, the Company’s ability to earn its authorized rate of return may be adversely impacted.
Loans to the Company under its committed credit facilities may be alternate base rate loans or term SOFR loans. SOFR is a reference rate (the Secured Overnight Financing Rate) published by the Federal Reserve Bank of New York. SOFR is one available replacement for LIBOR (the London Interbank Offered Rate), which the U.K.’s Financial Conduct Authority is phasing out as a benchmark. The change from LIBOR to SOFR could expose the Company’s credit ratingsborrowings to less favorable rates. If the change to SOFR results in increased interest rates or if the Company's lenders have increased costs due to the change, then the Company's debt that uses benchmark rates could be affected and, in turn, the Company's cash flows and interest expense could be adversely impacted.
Fluctuations in natural gas prices could adversely affect revenues, cash flows and profitability.
Financial results in the Company’s Exploration and Production segment are an independent assessmentmaterially dependent on prices received for its natural gas production. Both short-term and long-term price trends affect the economics of exploring for, developing, producing, and gathering natural gas. Natural gas prices can be volatile and can be affected by various factors, including weather conditions, natural disasters, the level of consumer product demand, national and worldwide economic conditions, economic disruptions caused by terrorist activities, acts of war or major accidents, political conditions in foreign countries, the price and availability of alternative fuels, the proximity to, and availability of, sufficient capacity on transportation and liquefaction facilities, regional and global levels of supply and demand, energy conservation measures, and government regulations. The Company sells the natural gas that it produces at a combination of current market prices, indexed prices or through fixed-price contracts. The Company hedges a significant portion of future sales that are based on indexed prices utilizing the physical sale counter-party and/or the financial markets. The prices the Company receives depend upon factors beyond the Company’s control, including the factors affecting price mentioned above. The Company believes that any prolonged reduction in natural gas prices could restrict its ability to paycontinue the level of exploration and production activity the Company otherwise would pursue, which could have a material adverse effect on its obligations. Consequently, real or anticipatedfuture revenues, cash flows and results of operations.
In the Company’s Pipeline and Storage segment, significant changes in the price differential between equivalent quantities of natural gas at different geographic locations could adversely impact the Company. For example, if the price of natural gas at a particular receipt point on the Company’s credit ratings will generally affectpipeline system increases relative to the market valueprice of natural gas at other locations, then the volume of natural gas received by the Company at the relatively more expensive receipt point may decrease, or the Company may need to discount the approved tariff rate for that transportation path in the future in order to maintain the existing volumes on its system. Changes in price differentials can cause shippers to seek alternative lower priced natural gas supplies and, consequently, alternative transportation routes. In some cases, shippers may decide not to renew transportation contracts due to changes in price differentials. While much of the specificimpact of lower volumes under existing contracts would be offset by the straight fixed-variable rate design, this rate design does not protect Supply Corporation or Empire where shippers do not contract for expiring capacity at the same quantity and rate. If contract renewals were to decrease, revenues and earnings in this segment may decrease. Significant changes in the price differential between futures contracts for gas having different delivery dates could also adversely impact the Company. For example, if the prices of natural gas futures contracts for winter deliveries to locations served by the Pipeline and Storage segment decline relative to the prices of such contracts for summer deliveries (as a result, for instance, of increased production of gas within the segment’s geographic area or other
factors), then demand for the Company’s natural gas storage services driven by that price differential could decrease.These changes could adversely affect future revenues, cash flows and results of operations.
In the Company’s Utility segment, during periods when natural gas prices are significantly higher than historical levels, customers may have trouble paying the resulting higher bills, which could increase bad debt instruments that are rated,expenses and ultimately reduce earnings. Additionally, increases in the cost of purchased gas affect cash flows and can therefore impact the amount or availability of the Company’s capital resources.
The Company has significant transactions involving price hedging of its natural gas production as well as its fixed price sale commitments.
To protect itself to some extent against price volatility and to lock in fixed pricing on natural gas production for certain periods of time, the Company’s Exploration and Production segment regularly enters into commodity price derivatives contracts (hedging arrangements) with respect to a portion of its expected production. These contracts may extend over multiple years, covering a substantial majority of the Company’s expected energy production over the course of the current fiscal year, and lesser percentages of subsequent years' expected production. These contracts reduce exposure to subsequent price drops but can also limit the Company’s ability to benefit from increases in commodity prices.
The nature of these hedging contracts could lead to potential liquidity impacts in scenarios of significantly increased natural gas prices if the Company has hedged its current production at prices below the current market price. Hedging collateral deposits represent the cash, letters of credit, or other eligible instruments held in Company funded margin accounts to serve as collateral for hedging positions used in the Company’s Exploration and Production segment. A significant increase in natural gas prices may cause the Company’s outstanding derivative instrument contracts to be in a liability position creating margin calls on the Company’s hedging arrangements, which could require the Company to temporarily post significant amounts of cash collateral with our hedge counterparties. That collateral could be in excess of the Company’s available short-term liquidity under its committed credit facility and other uncommitted sources of capital, leading to potential default under certain of its hedging arrangements. That interest-bearing cash collateral is returned to us in whole or in part upon a reduction in forward market prices, depending on the amount of such reduction, or in whole upon settlement of the related derivative contract.
Use of energy commodity price hedges also exposes the Company to the risk of nonperformance by a contract counterparty. These parties might not be able to perform their obligations under the hedge arrangements.
In the Exploration and Production segment, under the Company’s hedging guidelines, commodity derivatives contracts must be confined to the price hedging of existing and forecast production. The Company maintains a system of internal controls to monitor compliance with its policy. However, unauthorized speculative trades, if they were to occur, could expose the Company to substantial losses to cover positions in its derivatives contracts. In addition, in the event the Company’s actual production of natural gas falls short of hedged forecast production, the Company may incur substantial losses to cover its hedges.
The Dodd-Frank Act increased federal oversight and regulation of the over-the-counter derivatives markets and certain entities that participate in those markets. Although regulators have issued certain regulations, other rules that may be relevant to the Company have yet to be finalized. For discussion of the risks associated with the Dodd-Frank Act, refer to Item 7, MD&A under the heading “Market Risk Sensitive Instruments.”
You should not place undue reliance on reserve information because such information represents estimates.
This Form 10-K contains estimates of the Company’s proved natural gas reserves and the future net cash flows from those reserves, which the Company’s petroleum engineers prepared and independent petroleum engineers audited. Petroleum engineers consider many factors and make assumptions in estimating natural gas reserves and future net cash flows. These factors include: historical production from the area compared with production from other producing areas; the assumed effect of governmental regulation; and assumptions
concerning natural gas prices, production and development costs, severance and excise taxes, and capital expenditures. Changes in natural gas prices impact the quantity of economic natural gas reserves. Estimates of reserves and expected future cash flows prepared by different engineers, or by the same engineers at different times, may differ substantially. Ultimately, actual production, revenues and expenditures relating to the Company’s reserves will vary from any estimates, and these variations may be material. Accordingly, the accuracy of the Company’s reserve estimates is a function of the quality of available data and of engineering and geological interpretation and judgment.
If conditions remain constant, then the Company is reasonably certain that its reserve estimates represent economically recoverable natural gas reserves and future net cash flows. If conditions change in the future, then subsequent reserve estimates may be revised accordingly. You should not assume that the present value of future net cash flows from the Company’s proved reserves is the current market value of the Company’s common stock. The Company’s credit ratings, however,estimated natural gas reserves. In accordance with SEC requirements, the Company bases the estimated discounted future net cash flows from its proved reserves on a 12-month average of historical prices for natural gas (based on first day of the month prices and adjusted for hedging) and on costs as of the date of the estimate, which are all discounted at the SEC mandated discount rate. Actual future prices and costs may not reflectdiffer materially from those used in the potential impactnet present value estimate. Any significant price changes will have a material effect on the present value of its common stockthe Company’s reserves.
Petroleum engineering is a subjective process of risks related to structural, market or other factors discussed in this Form 10-K.
The Company’s need to comply with comprehensive, complex, and the sometimes unpredictable enforcement of government regulations may increase its costs and limit its revenue growth, which may result in reduced earnings.
While the Company generally refers to its Utility segment and its Pipeline and Storage segment as its "regulated segments," there are many governmental laws and regulations that have an impact on almost every aspect of the Company's businesses including, but not limited to, tax law and environmental law. Existing statutes and regulations may be revised or reinterpreted and new laws and regulations may be adopted or become applicable to the Company, such as tax legislation, which may increase the Company's costs or affect its business in ways that the Company cannot predict. Administrative agencies may apply existing laws and regulations in unanticipated, inconsistent or legally unsupportable ways, making it difficult to develop and complete projects, and harming the economic climate generally. New York State, for example, under the current executive administration, appears intent on imposing unattainable regulatory standards, at least with respect to certain fossil fuel energy infrastructure projects.
In the Company's Utility segment, the operations of Distribution Corporation are subject to the jurisdiction of the NYPSC, the PaPUC and, with respect to certain transactions, the FERC. The NYPSC and the PaPUC, among other things, approve the rates that Distribution Corporation may charge to its utility customers. Those approved rates also impact the returns that Distribution Corporation may earn on the assets that are dedicated to those operations. If Distribution Corporation is required in a rate proceeding to reduce the rates it charges its utility customers, or to the extent Distribution Corporation is unable to obtain approval for rate increases from these regulators, particularly when necessary to cover increased costs (including costs that may be incurred in connection with governmental investigations or proceedings or mandated infrastructure inspection, maintenance or replacement programs), earnings may decrease.
In addition to their historical methods of utility regulation, both the PaPUC and NYPSC have established competitive markets in which customers may purchase gas commodity from unregulated marketers, in addition to utility companies. Retail competition for gas commodity service does not pose an acute competitive threat for Distribution Corporation because in both jurisdictions it recovers its cost of service through delivery rates and charges, and not through any mark-up on the gas commodity purchased by its customers. Over the longer run, however, rate design changes resulting from customer migration to marketer service ("unbundling") can expose utilities such as Distribution Corporation to stranded costs and revenue erosion in the absence of compensating rate relief.
Both the NYPSC and the PaPUC have, from time-to-time, instituted proceedings for the purpose of promoting conservation of energy commodities, including natural gas. In New York, Distribution Corporation implemented a Conservation Incentive Program that promotes conservation and efficient useestimating underground accumulations of natural gas and other hydrocarbons that cannot be measured in an exact manner. The process of estimating natural gas reserves is complex. The process involves significant assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. Future economic and operating conditions are uncertain, and changes in those conditions could cause a revision to the Company’s reserve estimates in the future. Estimates of economically recoverable natural gas reserves and of future net cash flows depend upon a number of variable factors and assumptions, including historical production from the area compared with production from other comparable producing areas, and the assumed effects of regulations by offering customer rebatesgovernmental agencies. Because all reserve estimates are to some degree subjective, each of the following items may differ materially from those assumed in estimating reserves: the quantities of natural gas that are ultimately recovered, the timing of the recovery of natural gas reserves, the production and operating costs to be incurred, the amount and timing of future development and abandonment expenditures, and the price received for the installation of high-efficiency appliances, among other things. The intent of conservationproduction.
Financial accounting requirements regarding exploration and efficiency programs is to reduce customer usage of natural gas. Under traditional volumetric rates, reduced usage by customers results in decreased revenues toproduction activities may affect the Utility. To prevent revenue erosion caused by conservation, the NYPSC approved a "revenue decoupling mechanism" that renders Distribution Corporation's New York division financially indifferent to the effects of conservation. In Pennsylvania, the PaPUC has not directed Distribution Corporation to implement a conservation program. If the NYPSC were to revoke the revenue decoupling mechanism in a future proceeding or the PaPUC were to adopt a conservation program without revenue decoupling mechanism or other changes in rate design, reduced customer usage could decrease revenues, forcing Distribution Corporation to file for rate relief. If Distribution Corporation were unable to obtain adequate rate relief, its financial condition, results of operations and cash flows would be adversely affected.
In New York, aggressive generic statewide programs created under the label of efficiency or conservation continue to generate a sizable utility funding requirement for state agencies that administer those programs. Although utilities are authorized to recover the cost of efficiency and conservation program funding through special rates and surcharges, the resulting upward pressure on customer rates, coupled with increased assessments and taxes, could affect future tolerance for traditional utility rate increases, especially if natural gas commodity costs were to increase.Company's profitability.
The Company is subjectaccounts for its exploration and production activities under the full cost method of accounting. Each quarter, the Company must perform a "ceiling test" calculation, comparing the level of its unamortized investment in oil and natural gas properties to the jurisdictionpresent value of the FERCfuture net revenue projected to be recovered from those properties according to methods prescribed by the SEC. In determining present value, the Company uses a 12-month historical average price for oil and natural gas (based on first day of the month prices and adjusted for hedging) as well as the SEC mandated discount rate. If, at the end of any quarter, the amount of the unamortized investment exceeds the net present value of the projected future cash flows, such investment may be considered to be "impaired," and the full cost authoritative accounting and reporting guidance require that the investment must be written down to the calculated net present value. Such an instance would require the Company to recognize an immediate expense in that quarter, and its earnings would be reduced. Depending on the magnitude of any decrease in average prices, that charge could be material. Under the Company's existing indenture covenants, an impairment could restrict the Company's ability to issue incremental long-term unsecured indebtedness for a period of time, beginning with respectthe fourth calendar month following the impairment. In addition, because an impairment results in a charge to Supply Corporation, Empire and some transactions performed by other Company subsidiaries, including Seneca, Distribution Corporation and NFR. The FERC, amongretained earnings, it lowers the Company's total capitalization, all other things approvesbeing equal, and increases the rates that Supply CorporationCompany's debt to capitalization ratio. As a result, an impairment can impact the Company's ability to maintain compliance with the debt to capitalization covenant set forth in its credit facilities. For example, for the fiscal year ended September 30, 2020 and Empire may charge to theirthe quarter ended December 31, 2020, the Company recognized non-cash, pre-tax impairment charges on its oil and natural gas transportation and/or storage customers. Those approved rates also impact the returns that Supply Corporationproperties of $449.4 million and Empire may earn on the assets that are dedicated to those operations. Pursuant to the petition of a customer or state commission, or on the FERC's own initiative, the FERC has the authority to investigate whether Supply Corporation's and Empire's rates are still "just and reasonable" as required by the NGA, and if not, to adjust those rates prospectively. If Supply Corporation or Empire is required in a rate proceeding to adjust the rates it charges its natural gas transportation and/or storage customers, or if either Supply Corporation or Empire is unable to obtain approval for rate increases, particularly when necessary to cover increased costs, Supply Corporation's or Empire's earnings may decrease. The FERC also possesses significant penalty authority with respect to violations of the laws and regulations it administers. Supply Corporation, Empire and, to the extent subject to FERC jurisdiction, the Company's other subsidiaries are subject to the FERC's penalty authority. In addition, the FERC exercises jurisdiction over the construction and operation of facilities used in interstate gas transmission. Also, decisions of Canadian regulators such as the National Energy Board and the Ontario Energy Board could affect the viability and profitability of Supply Corporation and Empire projects designed to transport gas between Canada and the U.S.$76.2 million, respectively.
The Company is also subject to the jurisdiction of the Pipeline and Hazardous Materials Safety Administration (PHMSA). PHMSA issues regulations and conducts evaluations, among other things, that set safety standards for pipelines and underground storage facilities. Compliance with new legislation could increase costs to the Company. Non-compliance with this legislation could result in civil penalties for pipeline safety violations. If as a result of these or similar new laws or regulations the Company incurs material costs that it is unable to recover fully through rates or otherwise offset, the Company's financial condition, results of operations, and cash flows could be adversely affected.
In the Company's Exploration and Production segment, various aspects of Seneca's operations are subject to regulation by, among others, the EPA, the U.S. Fish and Wildlife Service, the U.S. Forestry Service, the Bureau of Land Management, the PaDEP, the Pennsylvania Department of Conservation and Natural Resources, the Division of Oil, Gas and Geothermal Resources of the California Department of Conservation, the California Department of Fish and Wildlife, and in some areas, locally adopted ordinances. Administrative proceedings or increased regulation by these or other agencies could lead to operational delays or restrictions and increased expense for Seneca.OPERATIONAL RISKS
The nature of the Company’s operations presents inherent risks of loss that could adversely affect its results of operations, financial condition and cash flows.
The Company’s operations in its various reporting segments are subject to inherent hazards and risks such as: fires; natural disasters; explosions; geological formations with abnormal pressures; blowouts during well drilling; collapses of wellbore casing or other tubulars; pipeline ruptures; spills; and other hazards and risks that may cause personal injury, death, property damage, environmental damage or business interruption losses. Additionally, the Company’s facilities, machinery, and equipment may be subject to sabotage. Any of theseThese events, in turn, could cause a loss of hydrocarbons, environmental pollution, claims for personal injury, death, property damage or business interruption, orlead to governmental investigations, recommendations, claims, fines or penalties. As protection against operational hazards, the Company maintains insurance coverage against some, but not all, potential losses. In addition, many of the agreements that the Company executes with contractors provide for the division of responsibilities between the contractor and the Company, and the Company seeks to obtain an indemnification from the contractor for certain of these risks. The Company is not always able, however,also seeks, but may be unable, to secure written indemnification agreements with its contractors that contain indemnification, and sometimes the Company is required to indemnify others.
Insurance or indemnification agreements, when obtained, may not adequately protect the Company against liability from all of the consequences of the hazards described above. The occurrence of an event not fully insured or indemnified against, the imposition of fines, penalties or mandated programs by governmental authorities, the failure of a contractor to meet its indemnification obligations, or the failure of an insurance company to pay valid claims could result in substantial losses to the Company. In addition, insurance may not be available, or if available may not be adequate, to cover any or all of these risks. It is also possible that insurance premiums or other costs may rise significantly in the future, so as to make such insurance prohibitively expensive.
Hazards and risks faced by the Company, and insurance and indemnification obtained or provided by the Company, may subject the Company to litigation or administrative proceedings from time to time. Such litigation or proceedings could result in substantial monetary judgments, fines or penalties against the Company or be resolved on unfavorable terms, the result of which could have a material adverse effect on the Company’s results of operations, financial condition and cash flows.
Our businesses depend on natural gas gathering, storage, and transmission facilities, which, if unavailable, could adversely affect the Company’s results of operations, financial condition, and cash flows.
Our businesses depend on natural gas gathering, storage, and transmission facilities, including third-party midstream facilities that are not within our control. Our Exploration and Production and Utility segments have entered into long-term agreements with midstream providers for natural gas gathering, storage, and/or transportation services. The disruption or unavailability of the midstream facilities required to provide these services, due to maintenance, mechanical failures, accidents, weather, regulatory requirements and/or other operational hazards, could negatively impact our ability to market and/or deliver our products, especially if such disruption were to last for an extended period of time. In addition, any substantial disruptions to the services provided by our midstream providers could cause us to curtail a significant amount of our production or could impair our ability to deliver natural gas to our utility customers and could have a material adverse effect on the Company’s results of operations, financial condition, and cash flows. Furthermore, as substantially all of our production is transported from the well pad to interconnections with various FERC-regulated pipelines though our affiliated gathering facilities, such a production curtailment could result in significantly reduced throughput on those facilities, adversely affecting revenues and cash flows of our Gathering business.
The disruption of the Company's information technology and operational technology systems, including third party attempts to breach the Company’s network security, could adversely affect the Company's financial results.
The Company relies on information technology and operational technology systems to process, transmit, and store information, to manage and support a variety of business processes and activities, and to comply with regulatory, legal, and tax requirements. The Company's information technology and operational technology systems, some of which are dependent on services provided by third parties, may be vulnerable to damage, interruption, or shutdown due to any number of causes outside of our control such as catastrophic events, natural disasters, fires, power outages, systems failures, telecommunications failures, and employee error or malfeasance. In addition, the Company's information technology and operational technology systems are subject to attempts by others to gain unauthorized access, or to otherwise introduce malicious software. These
attempts might be the result of industrial or other espionage, or actions by hackers seeking to harm the Company, its services or customers. These more sophisticated cyber-related attacks, as well as cybersecurity failures resulting from human error, pose a risk to the security of the Company’s systems and networks and the confidentiality, availability and integrity of the Company’s and its customers’ data. That data may be considered sensitive, confidential, or personal information that is subject to privacy and security laws, regulations and directives. While the Company employs reasonable and appropriate controls to maintain and protect its information technology and operational technology systems, the Company may be vulnerable to material disruptions, material security breaches, lost or corrupted data, programming errors and employee errors and/or malfeasance that could lead to interruptions to the Company's business operations or the unauthorized access, use, disclosure, modification or destruction of sensitive, confidential or personal information. Attempts to breach the Company’s network security may result in disruption of the Company’s business operations and services, delays in production, theft of sensitive and valuable data, damage to our physical systems, and reputational harm. Significant expenditures may be required to remedy system disruptions or breaches, including restoration of customer service and enhancement of information technology and operational technology systems.
The Company seeks to prevent, detect and investigate security incidents, but in some cases the Company might be unaware of an incident or its magnitude and effects. In addition to existing risks, the adoption of new technologies may also increase the Company’s exposure to data breaches or the Company’s ability to detect and remediate effects of a breach. The Company has experienced attempts to breach its network security and has received notifications from third-party service providers who have experienced disruptions to services or data breaches where Company data was potentially impacted. Although the scope of such incidents is sometimes unknown, they could prove to be material to the Company. Even though insurance coverage is in place for cyber-related risks, if a material disruption or breach were to occur, the Company’s operations, earnings, cash flows and financial condition could be adversely affected to the extent not fully covered by such insurance.
The amount and timing of actual future natural gas production and the cost of drilling are difficult to predict and may vary significantly from reserves and production estimates, which may reduce the Company’s earnings.
There are many risks in developing natural gas, including numerous uncertainties inherent in estimating quantities of proved natural gas reserves and in projecting future rates of production and timing of development expenditures. The future success of the Company’s Exploration and Production and Gathering segments depends on its ability to develop additional natural gas reserves that are economically recoverable, and its failure to do so may reduce the Company’s earnings. The total and timing of actual future production may vary significantly from reserves and production estimates. The Company’s drilling of development wells can involve significant risks, including those related to timing, success rates, and cost overruns, and these risks can be affected by lease and rig availability, completion crew and related equipment availability, geology, and other factors. Drilling for natural gas can be unprofitable, not only from non-productive wells, but from productive wells that do not produce sufficient revenues to return a profit. Also, title problems, competition and cost to acquire mineral rights, weather conditions, governmental requirements, including completion of environmental impact analyses and compliance with other environmental laws and regulations, and shortages or delays in the delivery of equipment and services can delay drilling operations or result in their cancellation. The cost of drilling, completing, and operating wells is significant and often uncertain, and new wells may not be productive or the Company may not recover all or any portion of its investment. Production can also be delayed or made uneconomic if there is insufficient gathering, processing and transportation capacity available at an economic price to get that production to a location where it can be profitably sold. Without continued successful exploitation or acquisition activities, the Company’s reserves and revenues will decline as a result of its current reserves being depleted by production. The Company cannot make assurances that it will be able to find or acquire additional reserves at acceptable costs.
The physical risks associated with climate change may adversely affect the Company’s operations and financial results.
Climate change could create acute and/or chronic physical risks to the Company’s operations, which may adversely affect financial results. Acute physical risks include more frequent and severe weather events, which may result in adverse physical effects on portions of U.S. natural gas infrastructure, and could disrupt the Company’s supply chain and ultimately its operations. Disruption of production activities, as well as natural gas transportation and distribution systems, could result in reduced operational efficiency, and customer service interruption. Severe weather events could also cause physical damage to facilities, all of which could lead to reduced revenues, increased insurance premiums or increased operational costs. To the extent the Company’s regulated businesses are unable to recover those costs, or if the recovery of those costs results in higher rates and reduced demand for Company services, the Company’s future financial results could be adversely impacted. Chronic physical risks include long-term shifts in climate patterns resulting in new storm patterns or chronic increased temperatures, which could cause demand for gas to increase or decrease as a result of warmer weather and less degree days, and adversely impact the Company's future financial results.
Disputes with collective bargaining units representing the Company’s workforce, and work stoppage (e.g. strike or lockout), could adversely affect the Company’s operations as well as its financial results.
Approximately half of the Company’s active workforce is represented by collective bargaining units in New York and Pennsylvania. These labor agreements are negotiated periodically, and therefore, the Company is subject to the risk that such agreements may not be able to be renewed on reasonably satisfactory terms, on anticipated timelines, or at all. In connection with the negotiation of such collective bargaining agreements, or in future matters involving collective bargaining units representing the Company’s workforce, the Company could experience, among other things, strikes, work stoppages, slowdowns or lockouts, which could cause a disruption of the Company's operations and have a material adverse effect on the Company's results of operations and financial condition.
REGULATORY RISKS
The Company’s need to comply with comprehensive, complex, and the sometimes unpredictable enforcement of government regulations may increase its costs and limit its revenue growth, which may result in reduced earnings.
The Company’s businesses are subject to regulation under a wide variety of federal and state laws, regulations and policies. Existing statutes and regulations, including current tax rates, may be revised or reinterpreted and new laws and regulations may be adopted or become applicable to the Company, which may increase the Company's costs, require refunds to customers or affect its business in ways that the Company cannot predict. Administrative agencies may apply existing laws and regulations in unanticipated, inconsistent or legally unsupportable ways, making it difficult to develop and complete projects, and harming the economic climate generally.
Various aspects of the Company's operations are subject to regulation by a variety of federal and state agencies with respect to permitting and environmental requirements. In some areas, the Company’s operations may also be subject to locally adopted ordinances. Administrative proceedings or increased regulation by these agencies could lead to operational delays or restrictions and increased expense for one or more of the Company’s subsidiaries.
The Company is subject to the jurisdiction of the Pipeline and Hazardous Materials Safety Administration (PHMSA). The PHMSA issues regulations and conducts evaluations, among other things, that set safety standards for pipelines and underground storage facilities. If as a result of these or similar new laws or regulations the Company incurs material compliance costs that it is unable to recover fully through rates or otherwise offset, the Company's financial condition, results of operations, and cash flows could be adversely affected.
The Company is subject to the jurisdiction of the FERC with respect to Supply Corporation, Empire and some transactions performed by other Company subsidiaries. The FERC, among other things, approves the rates
that Supply Corporation and Empire may charge to their gas transportation and/or storage customers. Those approved rates also impact the returns that Supply Corporation and Empire may earn on the assets that are dedicated to those operations. Pursuant to the petition of a customer or state commission, or on the FERC's own initiative, the FERC has the authority to investigate whether Supply Corporation's and Empire's rates are still "just and reasonable" as required by the NGA, and if not, to adjust those rates prospectively. If Supply Corporation or Empire is required in a rate proceeding to adjust the rates it charges its gas transportation and/or storage customers, or if either Supply Corporation or Empire is unable to obtain approval for rate increases, particularly when necessary to cover increased costs, Supply Corporation's or Empire's earnings may decrease. In addition, the FERC exercises jurisdiction over the construction and operation of interstate natural gas transmission and storage facilities and also possesses significant penalty authority with respect to violations of the laws and regulations it administers.
The operations of Distribution Corporation are subject to the jurisdiction of the NYPSC, the PaPUC and, with respect to certain transactions, the FERC. The NYPSC and the PaPUC, among other things, approve the rates that Distribution Corporation may charge to its utility customers. Those approved rates also impact the returns that Distribution Corporation may earn on the assets that are dedicated to those operations. If Distribution Corporation is unable to obtain approval from these regulators for the rates it is requesting to charge utility customers, particularly when necessary to cover increased costs, earnings and/or cash flows may decrease.
Environmental regulation significantly affects the Company’s business.
The Company’s business operations are subject to federal, state, and local laws, regulations and regulationsagency policies relating to environmental protection.protection including obtaining and complying with permits, leases, approvals, consents and certifications from various governmental and permit authorities. These laws, regulations and regulationspolicies concern the generation, storage, transportation, disposal, emission or discharge of pollutants, contaminants, hazardous substances and greenhouse gases into the environment, the reporting of such matters, and the general protection of public health, natural resources, wildlife and the environment. For example, currently applicable environmental laws and regulations restrict the types, quantities and concentrations of materials that can be released into the environment in connection with regulated activities, limit or prohibit activities in certain protected areas, and may require the Company to investigate and/or remediate contamination at certain current and former properties regardless of whether such contamination resulted from the Company’s actions or whether such actions were in compliance with applicable laws and regulations at the time they were taken. Moreover, spills or releases of regulated substances or the discovery of currently unknown contamination could expose the Company to material losses, expenditures and environmental, health and safety liabilities. Such liabilities could include penalties, sanctions or claims for damages to persons, property or natural resources brought on behalf of the government or private litigants that could cause the Company to incur substantial costs or uninsured losses.
In addition, the Company must obtain, maintain and comply with numerous permits, leases, approvals, consents and certificates from various governmental authorities before commencing regulated activities. In connection with such activities, the Company may need to make significant capital and operating expenditures to detect, repair and/or control air emissions, to control water discharges or to perform certain corrective actions to meet the conditions of the permits issued pursuant to applicable environmental laws and regulations. Any failure to comply with applicable environmental laws and regulations and the terms and conditions of its environmental permits and authorizations could result in the assessment of significant administrative, civil and/or criminal penalties, the imposition of investigatory or remedial obligations and corrective actions, the revocation of required permits, or the issuance of injunctions limiting or prohibiting certain of the Company’s operations.
Costs of compliance and liabilities could negatively affect the Company’s results of operations, financial condition and cash flows. In addition, compliance with environmental laws, and regulations or permit conditions could require unexpected capital expenditures at the Company’s facilities, temporarily shut down the Company’s facilities or delay or cause the cancellation of expansion projects or oil and natural gas drilling activities. Because the costs of complying with environmental regulationssuch compliance are significant, additional regulation could negatively affect the Company’s business. Although the Company cannot predict the impact of the interpretation or enforcement of EPA standards or other federal, state and local laws or regulations, the Company’s costs could increase if environmental laws and regulations change.
Legislative and regulatory measures to address climate change and greenhouse gas emissions are in various phases of discussion or implementation. Under the federal Clean Air Act, the EPA requires that new stationary sources of significant greenhouse gas emissions or major modifications of existing facilities obtain permits prior to construction or modification. The EPA previously adopted final regulations that set methane emissions standards for new oil and natural gas emission sources. In addition, the EPA issued draft guidelines for voluntarily reducing emissions from existing equipment and processes in the oil and natural gas industry. The current U.S. presidential
administration has issued executive orders to roll back many of these regulations, and, in turn, litigation (not involving the Company) has been instituted to challenge the administration’s efforts. The Company must continue to comply with all applicable regulations. Further, the U.S. Congress has from time to time considered bills that would establish a cap-and-trade program to reduce emissions of greenhouse gases. A number of states have adopted energy strategies or plans with goals that include the reduction of greenhouse gas emissions. New York’s State Energy Plan, which includes Reforming the Energy Vision (REV) initiatives, sets greenhouse gas emission reduction targets of 40% by 2030 and 80% by 2050. Additionally, the Plan targets that 50% of electric generation must come from renewable energy sources by 2030. With respect to its operations in California, the Company currently complies with California cap-and-trade guidelines, which increases the Company’s cost of environmental compliance in its Exploration and Production segment operations. Legislation or regulation that aims to reduce greenhouse gas emissions could also include carbon taxes, restrictive permitting, increased efficiency standards, and incentives or mandates to conserve energy or use renewable energy sources. Federal, state or local governments may, for example, 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. These climate change and greenhouse gas initiatives could increase the Company’s cost of environmental compliance by requiring the Company to install new equipment to reduce emissions from larger facilities and/or purchase emission allowances. They could also delay or otherwise negatively affect efforts to obtain permits and other regulatory approvals with regard to existing and new facilities, impose additional monitoring and reporting requirements, and reduce demand for oil and natural gas.
Third parties may attempt to breach the Company’s network security, which could disrupt the Company’s operations and adversely affect its financial results.
The Company’s information technology systems are subject to attempts by others to gain unauthorized access through the Internet, or to otherwise introduce malicious software. These attempts might be the result of industrial or other espionage, or actions by hackers seeking to harm the Company, its services or customers. Attempts to breach the Company’s network security may result in disruption of the Company’s business operations and services, delays in production, theft of sensitive and valuable data, damage to our physical systems, and reputational harm. Significant expenditures may be required to remedy breaches, including restoration of customer service and enhancement of information technology systems. The Company seeks to prevent, detect and investigate these security incidents, but in some cases the Company might be unaware of an incident or its magnitude and effects. The Company has experienced attempts to breach its network security, and although the scope of such incidents is sometimes unknown, they could prove to be material to the Company. These security incidents may have an adverse impact on the Company’s operations, earnings and financial condition.
Delays or changes in plans or costs with respect to Company projects, including regulatory delays or denials with respect to necessary approvals, permits or orders, could delay or prevent anticipated project completion and may result in asset write-offs and reduced earnings.
Construction of the Pipeline and Storage segment’s planned pipelines and storage facilities, as well as the expansion of existing facilities, is subject to various regulatory, environmental, political, legal, economic and other development risks, including the ability to obtain necessary approvals and permits from regulatory agencies on a timely basis and on acceptable terms, or at all. For example, the Company has in the past encountered, and may in the future encounter, delays or denials by regulatory agencies in connection with certain projects, most significantly the Northern Access 2016 project. Existing or potential third party opposition, such as opposition from landowner and environmental groups, which are beyond our control, could interfere significantly with or delay the Company’s receipt of such approvals or permits, which could materially affect the anticipated construction of a project. In addition, third parties could impede the Gathering segment’s acquisition, expansion or renewal of rights-of-way or land rights on a timely basis and on acceptable terms. Any delay in project construction may prevent a planned project from going into service when anticipated, which could cause a delay in the receipt of revenues from those facilities. A significant construction delay in a material project, whatever the cause, or a final judgment denying a necessary permit, may result in asset write-offs and reduced earnings and an inability to complete projects as initially planned, or at all. These events could have a material adverse impact on anticipated operating results.
The Company could be adversely affected by the disallowance of purchased gas costs incurred by the Utility segment.
Tariff rate schedules in each of the Utility segment’s service territories contain purchased gas adjustment clauses which permit Distribution Corporation to file with state regulators for rate adjustments to recover increases in the cost of purchased gas. Assuming those rate adjustments are granted, increases in the cost of purchased gas have no direct impact on profit margins. Distribution Corporation is required to file an accounting reconciliation with the regulators in each of the Utility segment’s service territories regarding the costs of purchased gas. There is a risk of disallowance of full recovery of these costs if regulators determine that Distribution Corporation was imprudent in making its gas purchases. Any material disallowance of purchased gas costs could have a material adverse effect on cash flow and earnings.
Changes in interest rates may affect the Company’s ability to finance capital expenditures and to refinance maturing debt.
The Company’s ability to cost-effectively finance capital expenditures and to refinance maturing debt will depend in part upon interest rates. The direction in which interest rates may move is uncertain. Declining interest rates have generally been believed to be favorable to utilities, while rising interest rates are generally believed to be unfavorable, because of the levels of debt that utilities may have outstanding. In addition, the Company’s authorized rate of return in its regulated businesses is based upon certain assumptions regarding interest rates. If interest rates are lower than assumed rates, the Company’s authorized rate of return could be reduced. If interest rates are higher than assumed rates, the Company’s ability to earn its authorized rate of return may be adversely impacted.
Fluctuations in oil and natural gas prices could adversely affect revenues, cash flows and profitability.
Operations in the Company’s Exploration and Production segment are materially dependent on prices received for its oil and natural gas production. Both short-term and long-term price trends affect the economics of exploring for, developing, producing, gathering and processing oil and natural gas. Oil and natural gas prices can be volatile and can be affected by: weather conditions, natural disasters, the supply and price of foreign oil and natural gas, the level of consumer product demand, national and worldwide economic conditions, economic disruptions caused by terrorist activities, acts of war or major accidents, political conditions in foreign countries, the price and availability of alternative fuels, the proximity to, and availability of, capacity on transportation facilities, regional levels of supply and demand, energy conservation measures, and government regulations, such as regulation of greenhouse gas emissions and natural gas transportation, royalties, and price controls. The Company sells the oil and natural gas that it produces at a combination of current market prices, indexed prices or through fixed-price contracts. The Company hedges a significant portion of future sales that are based on indexed prices utilizing the physical sale counter-party or the financial markets. The prices the Company receives depend upon factors beyond the Company’s control, including the factors affecting price mentioned above. The Company believes that any prolonged reduction in oil and natural gas prices could restrict its ability to continue the level of exploration and production activity the Company otherwise would pursue, which could have a material adverse effect on its revenues, cash flows and results of operations.
To the extent that the natural gas the Company produces is priced in local markets where production occurs, the price may be affected by local or regional supply and demand factors as well as other local market dynamics such as regional pipeline capacity. Currently, the prices the Company receives for its natural gas production in the local markets where production occurs are generally lower than the relevant benchmark prices, such as NYMEX, that are used for commodity trading purposes. The difference between the benchmark price and the price the Company receives is called a differential. The Company may be unable to accurately predict natural gas differentials, which may widen significantly in the future. Numerous factors may influence local commodity pricing, such as pipeline takeaway capacity and specifications, localized storage capacity, disruptions in the midstream or downstream sectors of the industry, trade restrictions and governmental regulations. Insufficient pipeline or storage capacity, or a lack of demand or surplus of supply in any given operating area may cause the differential to widen in that area compared to other natural gas producing areas. Increases in the differential could lead to production curtailments or otherwise have a material adverse effect on the Company’s revenues, cash flows and results of operations.
In the Company’s Pipeline and Storage segment, significant changes in the price differential between equivalent quantities of natural gas at different geographic locations could adversely impact the Company. For example, if the price of natural gas at a particular receipt point on the Company’s pipeline system increases relative to the price of natural gas at other locations, then the volume of natural gas received by the Company at the relatively more expensive receipt point may decrease, or the price the Company charges to transport that natural gas may decrease. Changes in price differentials can cause shippers to seek alternative lower priced gas supplies and, consequently, alternative transportation routes. In some cases, shippers may decide not to renew transportation contracts due to changes in price differentials. While much of the impact of lower volumes under existing contracts would be offset by the straight fixed-variable rate design utilized by Supply Corporation and Empire, this rate design does not protect Supply Corporation or Empire where shippers do not contract for expiring capacity at the same quantity and rate. If contract renewals were to decrease, revenues and earnings in the Pipeline and Storage segment may decrease. Significant changes in the price differential between futures contracts for natural gas having different delivery dates could also adversely impact the Company. For example, if the prices of natural gas futures contracts for winter deliveries to locations served by the Pipeline and Storage segment decline relative to the prices of such contracts for summer deliveries (as a result, for instance, of increased production of natural gas within the Pipeline and Storage segment’s geographic area or other factors), then demand for the Company’s natural gas storage services driven by that price differential could decrease. Such changes in price differential could also affect the Energy Marketing segment’s ability to offset its natural gas storage costs through hedging transactions. These changes could adversely affect revenues, cash flows and results of operations.
The Company has significant transactions involving price hedging of its oil and natural gas production as well as its fixed price purchase and sale commitments.
In order to protect itself to some extent against unusual price volatility and to lock in fixed pricing on oil and natural gas production for certain periods of time, the Company’s Exploration and Production segment regularly enters into commodity price derivatives contracts (hedging arrangements) with respect to a portion of its expected production. These contracts may at any time cover as much as approximately 80% of the Company’s expected energy production during the upcoming 12-month period. These contracts reduce exposure to subsequent price drops but can also limit the Company’s ability to benefit from increases in commodity prices. In addition, the Energy Marketing segment enters into certain hedging arrangements, primarily with respect to its fixed price purchase and sales commitments and its gas stored underground.
Under applicable accounting rules currently in effect, the Company’s hedging arrangements are subject to quarterly effectiveness tests. Inherent within those effectiveness tests are assumptions concerning the long-term price differential between different types of crude oil, assumptions concerning the difference between published natural gas price indexes established by pipelines into which hedged natural gas production is delivered and the reference price established in the hedging arrangements, assumptions regarding the levels of production that will be achieved and, with regard to fixed price commitments, assumptions regarding the creditworthiness of certain customers and their forecasted consumption of natural gas. Depending on market conditions for natural gas and crude oil and the levels of production actually achieved, it is possible that certain of those assumptions may change in the future, and, depending on the magnitude of any such changes, it is possible that a portion of the Company’s hedges may no longer be considered highly effective. In that case, gains or losses from the ineffective derivative financial instruments would be marked-to-market on the income statement without regard to an underlying physical transaction. For example, in the Exploration and Production segment, where the Company uses short positions (i.e. positions that pay off in the event of commodity price decline) to hedge forecasted sales, gains would occur to the extent that natural gas and crude oil hedge prices exceed market prices for the Company’s natural gas and crude oil production, and losses would occur to the extent that market prices for the Company’s natural gas and crude oil production exceed hedge prices.
Use of energy commodity price hedges also exposes the Company to the risk of non-performance by a contract counterparty. These parties might not be able to perform their obligations under the hedge arrangements. In addition, the Company enters into certain commodity price hedges that are cleared through the NYMEX or ICE by futures commission merchants. Under NYMEX and ICE rules, the Company is required to post collateral in connection with such hedges, with such collateral being held by its futures commission merchants. The Company is exposed to the risk of loss of such collateral from occurrences such as financial failure of its futures commission
merchants, or misappropriation or mishandling of clients’ funds or other similar actions by its futures commission merchants. In addition, the Company is exposed to potential hedging ineffectiveness in the event of a failure by one of its futures commission merchants or contract counterparties.
It is the Company’s practice that the use of commodity derivatives contracts comply with various policies in effect in respective business segments. For example, in the Exploration and Production segment, commodity derivatives contracts must be confined to the price hedging of existing and forecast production, and in the Energy Marketing segment, commodity derivatives with respect to fixed price purchase and sales commitments must be matched against commitments reasonably certain to be fulfilled. The Company maintains a system of internal controls to monitor compliance with its policy. However, unauthorized speculative trades, if they were to occur, could expose the Company to substantial losses to cover positions in its derivatives contracts. In addition, in the event the Company’s actual production of oil and natural gas falls short of hedged forecast production, the Company may incur substantial losses to cover its hedges.
The Dodd-Frank Act increased federal oversight and regulation of the over-the-counter derivatives markets and certain entities that participate in those markets. The act requires the CFTC, the SEC and various banking regulators to promulgate rules and regulations implementing the act. Although regulators have issued certain regulations, other rules that may be relevant to the Company have yet to be finalized. For purposes of the Dodd-Frank Act, under rules adopted by the SEC and/or CFTC, the Company believes that it qualifies as a non-financial end user of derivatives, that is, as a non-financial entity that uses derivatives to hedge or mitigate commercial risk. Nevertheless, other rules that are being developed could have a significant impact on the Company. For example, the CFTC has imposed numerous registration, swaps documentation, business conduct, reporting, and recordkeeping requirements on swap dealers and major swap participants, which frequently are counterparties to the Company’s derivative hedging transactions. Regardless of the final capital and margin rules, concern remains that swap dealers and major swap participants will pass along their increased costs stemming from the final and proposed rules through higher transaction costs and prices or other direct or indirect costs. In addition, while the Company expects to be exempt from the Dodd-Frank Act’s requirement that swaps be cleared and traded on exchanges or swap execution facilities, the cost of entering into a non-exchange cleared swap that is available as an exchange cleared swap may be greater. The Dodd-Frank Act may also increase costs for derivative recordkeeping, reporting, position limit compliance, and other compliance; cause parties to materially alter the terms of derivative contracts; cause parties to restructure certain derivative contracts; reduce the availability of derivatives to protect against risks that the Company encounters or to optimize assets; reduce the Company’s ability to monetize or restructure existing derivative contracts; and increase the Company’s exposure to less creditworthy counterparties, all of which could increase the Company’s business costs.
You should not place undue reliance on reserve information because such information represents estimates.
This Form 10-K contains estimates of the Company’s proved oil and natural gas reserves and the future net cash flows from those reserves that were prepared by the Company’s petroleum engineers and audited by independent petroleum engineers. Petroleum engineers consider many factors and make assumptions in estimating oil and natural gas reserves and future net cash flows. These factors include: historical production from the area compared with production from other producing areas; the assumed effect of governmental regulation; and assumptions concerning oil and natural gas prices, production and development costs, severance and excise taxes, and capital expenditures. Lower oil and natural gas prices generally cause estimates of proved reserves to be lower. Estimates of reserves and expected future cash flows prepared by different engineers, or by the same engineers at different times, may differ substantially. Ultimately, actual production, revenues and expenditures relating to the Company’s reserves will vary from any estimates, and these variations may be material. Accordingly, the accuracy of the Company’s reserve estimates is a function of the quality of available data and of engineering and geological interpretation and judgment.
If conditions remain constant, then the Company is reasonably certain that its reserve estimates represent economically recoverable oil and natural gas reserves and future net cash flows. If conditions change in the future, then subsequent reserve estimates may be revised accordingly. You should not assume that the present value of future net cash flows from the Company’s proved reserves is the current market value of the Company’s estimated oil and natural gas reserves. In accordance with SEC requirements, the Company bases the estimated discounted
future net cash flows from its proved reserves on a 12-month average of historical prices for oil and natural gas (based on first day of the month prices and adjusted for hedging) and on costs as of the date of the estimate. Actual future prices and costs may differ materially from those used in the net present value estimate. Any significant price changes will have a material effect on the present value of the Company’s reserves.
Petroleum engineering is a subjective process of estimating underground accumulations of natural gas and other hydrocarbons that cannot be measured in an exact manner. The process of estimating oil and natural gas reserves is complex. The process involves significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. Future economic and operating conditions are uncertain, and changes in those conditions could cause a revision to the Company’s reserve estimates in the future. Estimates of economically recoverable oil and natural gas reserves and of future net cash flows depend upon a number of variable factors and assumptions, including historical production from the area compared with production from other comparable producing areas, and the assumed effects of regulations by governmental agencies. Because all reserve estimates are to some degree subjective, each of the following items may differ materially from those assumed in estimating reserves: the quantities of oil and natural gas that are ultimately recovered, the timing of the recovery of oil and natural gas reserves, the production and operating costs incurred, the amount and timing of future development and abandonment expenditures, and the price received for the production.
The amount and timing of actual future oil and natural gas production and the cost of drilling are difficult to predict and may vary significantly from reserves and production estimates, which may reduce the Company’s earnings.
There are many risks in developing oil and natural gas, including numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves and in projecting future rates of production and timing of development expenditures. The future success of the Company’s Exploration and Production segment depends on its ability to develop additional oil and natural gas reserves that are economically recoverable, and its failure to do so may reduce the Company’s earnings. The total and timing of actual future production may vary significantly from reserves and production estimates. The Company’s drilling of development wells can involve significant risks, including those related to timing, success rates, and cost overruns, and these risks can be affected by lease and rig availability, geology, and other factors. Drilling for oil and natural gas can be unprofitable, not only from non-productive wells, but from productive wells that do not produce sufficient revenues to return a profit. Also, title problems, weather conditions, governmental requirements, including completion of environmental impact analyses and compliance with other environmental laws and regulations, and shortages or delays in the delivery of equipment and services can delay drilling operations or result in their cancellation. The cost of drilling, completing, and operating wells is significant and often uncertain, and new wells may not be productive or the Company may not recover all or any portion of its investment. Production can also be delayed or made uneconomic if there is insufficient gathering, processing and transportation capacity available at an economic price to get that production to a location where it can be profitably sold. Without continued successful exploitation or acquisition activities, the Company’s reserves and revenues will decline as a result of its current reserves being depleted by production. The Company cannot make assurances that it will be able to find or acquire additional reserves at acceptable costs.
Financial accounting requirements regarding exploration and production activities may affect the Company's profitability.
The Company accounts for its exploration and production activities under the full cost method of accounting. Each quarter, the Company must perform a "ceiling test" calculation, comparing the level of its unamortized investment in oil and natural gas properties to the present value of the future net revenue projected to be recovered from those properties according to methods prescribed by the SEC. In determining present value, the Company uses a 12-month historical average price for oil and natural gas (based on first day of the month prices and adjusted for hedging). If, at the end of any quarter, the amount of the unamortized investment exceeds the net present value of the projected future cash flows, such investment may be considered to be "impaired," and the full cost accounting rules require that the investment must be written down to the calculated net present value. Such an instance would require the Company to recognize an immediate expense in that quarter, and its earnings would be reduced. Depending on the magnitude of any decrease in average prices, that charge could be material. For the fiscal year
ended September 30, 2015, the Company recognized pre-tax impairment charges on its oil and natural gas properties of $1.1 billion. For the fiscal year ended September 30, 2016, the Company recognized a pre-tax impairment charge on its oil and natural gas properties of $948.3 million.
Increased regulation of exploration and production activities, including hydraulic fracturing, could adversely impact the Company.
Due to the burgeoning Marcellus Shale natural gas play in the northeast United States, together with the fiscal difficulties faced by state governments in Pennsylvania, variousVarious state legislative and regulatory initiatives regarding the exploration and production business have been proposed or adopted.adopted in the northeast United States affecting the Marcellus and Utica Shale gas plays. These initiatives include potential new or updated statutes and regulations governing the drilling, casing, cementing, testing, abandonmentmonitoring and monitoringabandonment of wells, the protection of water supplies and restrictions on water use and water rights, hydraulic fracturing operations, surface owners’ rights and damage compensation, the spacing of wells, use and disposal of potentially hazardous materials, and environmental and safety issues regarding natural gas pipelines. New permitting fees and/or severance taxes for oil andnatural gas production are also possible.
Additionally, legislative initiatives in the U.S. Congress and regulatory studies, proceedings or rule-making initiatives at federal, state or local agencies focused on the hydraulic fracturing process, the use of underground injection control wells for produced water disposal, and related operations could result in operational delays or prohibitions and/or additional permitting, compliance, reporting and disclosure requirements. For example, the EPA has adopted regulations that establish emission performance standards for hydraulic fracturing operations as well as natural gas gathering and transmission operations. Other EPA initiatives could expand water quality and hazardous waste regulation of hydraulic fracturing and related operations. In California, legislation regarding well stimulation, including hydraulic fracturing, has been adopted. The law mandates technical standards for well construction, hydraulic fracturing water management, groundwater monitoring, seismicity monitoring during hydraulic fracturing operations and public disclosure of hydraulic fracturing fluid constituents. Additionally, the California Division of Oil, Gas & Geothermal Resources (DOGGR) adopted regulations intended to bring California’s Class II Underground Injection Control (UIC) program into compliance with the federal Safe Drinking Water Act, underrequirements, which some wells may require an aquifer exemption. DOGGR began reviewing all active UIC projects, regardless of whether an exemption is required. These and any other new state, federal or local legislative or regulatory measures could lead to operational delays or restrictions, increased operating costs additional regulatory burdens and increased risks of litigation for the Company.
The Company could be adversely affected by the delayed recovery or disallowance of purchased gas costs incurred by the Utility segment.
Tariff rate schedules in each of the Utility segment’s service territories contain purchased natural gas adjustment clauses which permit Distribution Corporation to file with state regulators for rate adjustments to recover increases in the cost of purchased natural gas. Assuming those rate adjustments are granted, increases in the cost of purchased natural gas have no direct impact on profit margins. Distribution Corporation is required to file an accounting reconciliation with the regulators in each of the Utility segment’s service territories regarding the costs of purchased natural gas. Extreme weather events, variations in seasonal weather, and other events disrupting supply and/or demand could cause the Company to experience unforeseeable and unprecedented increases in the costs of purchased natural gas. Any prudently incurred natural gas costs could be subject to deferred recovery if regulators determine such costs are detrimental to customers in the short-term. Furthermore, there is a risk of disallowance of full recovery of these costs if regulators determine that Distribution Corporation was imprudent in making its natural gas purchases. Any material delayed recovery or disallowance of purchased natural gas costs could have a material adverse effect on cash flow and earnings.
GENERAL RISKS
The Company’s credit ratings may not reflect all the risks of an investment in its securities.
The Company’s credit ratings are an independent assessment of its ability to pay its obligations. Consequently, real or anticipated changes in the Company’s credit ratings will generally affect the market value of the specific debt instruments that are rated, as well as the market value of the Company’s common stock. The Company’s credit ratings, however, may not reflect the potential impact on the value of its common stock of risks related to structural, market or other factors discussed in this Form 10-K.
The increasing costs of certain employee and retiree benefits could adversely affect the Company’s results.
The Company’s earnings and cash flow may be impacted by the amount of income or expense it expends or records for employee benefit plans. This is particularly true for pension and other post-retirement benefit plans, which are dependent on actual plan asset returns and factors used to determine the value and current costs of plan benefit obligations. In addition, if medical costs rise at a rate faster than the general inflation rate, the Company might not be able to mitigate the rising costs of medical benefits. Increases to the costs of pension, other post-retirement and medical benefits could have an adverse effect on the Company’s financial results.
Significant shareholders or potential shareholders may attempt to effect changes at the Company or acquire control over the Company, which could adversely affect the Company’s results of operations and financial condition.
Shareholders of the Company may from time to time engage in proxy solicitations, advance shareholder proposals or otherwise attempt to effect changes or acquire control over the Company. Campaigns by shareholders to effect changes at publicly traded companies are sometimes led by investors seeking to increase short-term shareholder value through actions such as financial restructuring, increased debt, special dividends, stock repurchases or sales of assets or the entire company. Additionally, activist shareholders may submit proposals to promote an environmental, social, and/or governance position. Responding to proxy contests and other actions by activist shareholders can be costly and time-consuming, disrupting the Company’s operations and diverting the attention of the Company’s Board of Directors and senior management from the pursuit of business strategies. As a result, shareholder campaigns could adversely affect the Company’s results of operations and financial condition.
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| Item 1B | Unresolved Staff Comments |
None.
General Information on Facilities
The net investment of the Company in property, plant and equipment was $4.7$6.6 billion at September 30, 2017.2022. The Exploration and Production segment constitutes 25.6%31.2% of this investment, and is primarily located in California and in the Appalachian region of the United States. Approximately 63.3%56.1% of the Company's investment in net property, plant and equipment was in the Utility and Pipeline and Storage segments, whose operations are located primarily in western and central New York and northwesternwestern Pennsylvania. The Gathering segment constitutes 9.8%12.6% of the Company’s investment in net property, plant and equipment, and is located in northwestern and central Pennsylvania. The remaining 0.1% of the Company's net investment in property, plant and equipment consisted of thefalls within All Other category and Corporate operations (1.3%), or $0.1 billion.operations. During the past five years, the Company has made significant additions to property, plant and equipment in order to expand its exploration and production and gathering operations in the Appalachian region of the United States and to expand and improvemodernize transmission and distribution facilities for transportation customers in New York and Pennsylvania. Net property, plant and equipment has decreased $66 million,increased $1.9 billion, or 1.4%40.5%, since September 30, 2012.2017. The five year increase is net of impairments of oil and gas producing properties recorded in 2020 and 2021 ($449 million and $76 million, respectively).
The Exploration and Production segment had a net investment in property, plant and equipment of $1.2$2.1 billion at September 30, 2017.2022.
The Pipeline and Storage segment had a net investment of $1.5$2.0 billion in property, plant and equipment at September 30, 2017.2022. Transmission pipeline represents 36% of37% of this segment’s total net investment and includes 2,2742,301 miles of pipeline utilized to move large volumes of gas throughout its service area. Storage facilities represent 16%13% of this segment’s total net investment and consist of 31387 miles of pipeline, as well as 30 storage fields operating at a combined working gas level of 73.477.2 Bcf, fourthree of which are jointly owned and operated with other interstate gas pipeline companies, and 393 miles of pipeline.companies. Net investment in storage facilities includes $82.8$79.7 million of gas stored underground-noncurrent, representing the cost of the gas utilized to maintain pressure levels for normal operating purposes as well as gas maintained for system balancing and other purposes, including that needed for no-notice transportation service. The Pipeline and Storage segment has 3234 compressor stations with 170,707262,393 installed compressor horsepower that represent 25%32% of this segment’s total net investment in property, plant and equipment.
The Pipeline and Storage segment's facilities provided the capacity to meet Supply Corporation’s 2022 peak day sendout for transportation service of 2,092 MMcf, which occurred on January 10, 2022. Withdrawals from storage of 718 MMcf provided approximately 34% of the requirements on that day.
The Gathering segment had a net investment of $0.5 $0.8 billion inin property, plant and equipment at September 30, 2017.2022. Gathering lines and related compressorscompressor stations represent substantially all of this segment’s total net investment, including 135368 miles of linespipelines utilized to move Appalachian production (including Marcellus Shale)and Utica shales) to various transmission pipeline receipt points. The Gathering segment has 525 compressor stations with 51,920119,980 installed compressor horsepower.
The Utility segment had a net investment in property, plant and equipment of $1.4$1.7 billion at September 30, 2017.2022. The net investment in its gas distribution networknetwork (including 14,89515,040 miles of distribution pipeline) and its service connections to customers represent approximately 48%49% and 33%32%, respectively, of the Utility segment’s net investment in property, plant and equipment at September 30, 2017.
The Pipeline and Storage segments’ facilities provided the capacity to meet Supply Corporation’s 2017 peak day sendout for transportation service of 2,252 MMcf, which occurred on January 8, 2017. Withdrawals from storage of 624.3 MMcf provided approximately 28% of the requirements on that day.2022.
Company maps are included in Exhibit 99.2 of this Form 10-K and are incorporated herein by reference.
Exploration and Production Activities
The Company is engaged in the exploration for and the development of natural gas and oil reserves in California andin the Appalachian region of the United States. The Company has been increasing its emphasisCompany's development activities in the Appalachian region are
focused primarily in the Marcellus Shale.and Utica shales. Further discussion of oil and gas producing activities is
included in Item 8, Note M -N — Supplementary Information for Oil and Gas Producing Activities. Note MN sets forth proved developed and undeveloped reserve information for Seneca. The September 30, 2017, 20162022, 2021 and 20152020 reserves shown in Note MN are valued using 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 reserves were estimated by Seneca’s geologists andpetroleum engineers and were audited by independent petroleum engineers from Netherland, Sewell & Associates, Inc. Note MN discusses the qualifications of the Company's reservoirpetroleum engineers, internal controls over the reserve estimation process and audit of the reserve estimates and changes in proved developed and undeveloped oil and natural gas reserves year over year.
Seneca's proved developed and undeveloped natural gas reserves increased from 3,723 Bcf at September 30, 2021 to 4,171 Bcf at September 30, 2022. This increase is attributed to extensions and discoveries of 838 Bcf and revisions of previous estimates of 3 Bcf, partially offset by production of 343 Bcf. Upward revisions included 3 Bcf of price-related revisions and 13 Bcf of revisions related to positive performance improvements including reduced operating expenses. The additions and upward revisions were partially offset by divestures of 50 Bcf as well as downward revisions of 13 Bcf from the removal of 1 PUD location related to pad layout changes. The Company has no near term plans to develop the reserves at this PUD location.
Seneca’s proved developed and undeveloped oil reserves decreased from 21,537 Mbbl at September 30, 2021 to 250 Mbbl at September 30, 2022. The decrease of 21,287 Mbbl is attributed to production of 1,604 Mbbl and the sale of Seneca's West Coast region (i.e., California assets) of 20,766 Mbbl. These decreases were partially offset by positive performance revisions of 787 Mbbl and extensions and discoveries of 296 Mbbl.
On a Bcfe basis, Seneca’s proved developed and undeveloped reserves increased from 3,853 Bcfe at September 30, 2021 to 4,172 Bcfe at September 30, 2022. This increase is attributed to extensions and discoveries of 839 Bcfe and upward revisions of previous estimates of 8 Bcfe, partially offset by production of 353 Bcfe and divestures, primarily from the sale of the West Coast region (i.e., California assets), of 175 Bcfe.
Seneca's proved developed and undeveloped natural gas reserves increased from 1,6753,325 Bcf at September 30, 20162020 to 1,9733,723 Bcf at September 30, 2017.2021. This increase iswas attributed to extensions and discoveries of 386689 Bcf and upward revisions of previous estimates of 9123 Bcf, partially offset by production of 157314 Bcf. Upward revisions included 74 Bcf of price-related revisions and sales29 Bcf of minerals in place of 22 Bcf. Of the total upward gasrevisions related to positive performance improvements including reduced operating expenses. Downward revisions of 9180 Bcf 125 Bcffrom the removal of 8 PUD locations were a result of higher gas prices for Marcellus Shale, Utica Shale and other reservoirs, and 20 Bcf were a result of upward revisions due to performance improvementscontinued integration of the Tioga assets acquired in July 2020, as well as other operational optimizations that resulted in pad layout and lease operating expense reductions, partially offset by 54 Bcf of PUD locations that were removed. The sales of minerals in place were the result of Marcellus and Utica reserves that were sold in the Western Development Area (primarily in Forest, Elk, McKean and Cameron counties in Pennsylvania) in September 2017.development schedule changes.
Seneca’s proved developed and undeveloped oil reserves increaseddecreased from 29,00922,100 Mbbl at September 30, 20162020 to 30,20721,537 Mbbl at September 30, 2017.2021. The increase isdecrease of 563 Mbbl was attributed to extensions and discoveriesproduction of 6742,235 Mbbl and upwarddownward revisions of previous estimates of 3,293579 Mbbl, partially offset by productionpositive price-related revisions of 2,7401,210 Mbbl and extensions and discoveries of 1,041 Mbbl, primarily occurring in the West Coast region, and sales of minerals in place of 29 Mbbl. Upward revisions of 3,293 Mbbl were a result of both higher oil prices of 1,623 Mbbl and upward revisions associated with performance improvements of 1,670 Mbbl. The sales of minerals in place were the result of aforementioned sales of reserves in the Western Development Area.region.
On a Bcfe basis, Seneca’s proved developed and undeveloped reserves increased from 1,8493,458 Bcfe at September 30, 20162020 to 2,1543,853 Bcfe at September 30, 2017. Total revisions of previous estimates2021. This increase was an increase of 110 Bcfe, primarily a result of higher oil and gas prices.
Seneca’s proved developed and undeveloped natural gas reserves decreased from 2,142 Bcf at September 30, 2015attributed to 1,675 Bcf at September 30, 2016. Extensionsextensions and discoveries of 186 Bcf were exceeded by production of 144 Bcf, downward696 Bcfe and upward revisions of previous estimates of 248 Bcf, and sales of minerals in place of 261 Bcf. Of the total downward gas revisions of 248 Bcf, 204 Bcf were a result of lower gas prices for Marcellus Shale and Upper Devonian reservoirs, and 74 Bcf were a result of PUD locations that were removed for reasons other than lower gas prices,26 Bcfe, partially offset by 30 Bcf in upward revisions due to performance improvements and lease operating expense reductions. The sales of minerals in place were primarily the result of reserves that were sold to IOG CRV-Marcellus, LLC (IOG) as part of the joint development agreement coupled with the sale of the majority of Seneca’s Upper Devonian wells and associated reserves in Pennsylvania.
Seneca’s proved developed and undeveloped oil reserves decreased from 33,722 Mbbl at September 30, 2015 to 29,009 Mbbl at September 30, 2016. Extensions and discoveries of 530 Mbbl were exceeded by production of 2,923 Mbbl, primarily occurring in the West Coast region, downward revisions of previous estimates of 2,247 Mbbl, and sales of minerals in place of 73 Mbbl. Downward revisions of 2,247 Mbbl were primarily a result of lower oil prices of 3,900 Mbbl partially offset by upward revisions associated with performance improvements and lease operating expense reductions of 1,653 Mbbl. The sales of minerals in place were reserves related to the aforementioned sale of Upper Devonian Wells.327 Bcfe.
On a Bcfe basis, Seneca’s proved developed and undeveloped reserves decreased from 2,344 Bcfe at September 30, 2015 to 1,849 Bcfe at September 30, 2016. Total revisions of previous estimates was a decrease of 262 Bcfe, primarily a result of lower oil and gas prices.
At September 30, 2017,2022, the Company’s Exploration and Production segment had delivery commitments of 2,187 Bcfe (mostlyfor natural gas as commitments for crude oil were insignificant).production of 2,390 Bcf. The Company expects to meet those commitments through proved reserves, including the future developmentproduction of reserves that are currently classified as proved undeveloped reserves and future exploration.extensions and discoveries.
The following is a summary of certain oil and gas information taken from Seneca’s records. All monetary amounts are expressed in U.S. dollars.
Production
|
| | | | | | | | | | | | | | |
| | For The Year Ended September 30 | |
| | 2017 | | | 2016 | | | 2015 | |
| United States | | | | | | | | |
| Appalachian Region | | | | | | | | |
| Average Sales Price per Mcf of Gas | $ | 2.52 |
| (1) | | $ | 1.94 |
| (1) | | $ | 2.48 |
| (1) |
| Average Sales Price per Barrel of Oil | $ | 48.27 |
| | | $ | 52.15 |
| | | $ | 57.44 |
| |
| Average Sales Price per Mcf of Gas (after hedging) | $ | 2.93 |
| | | $ | 3.01 |
| | | $ | 3.35 |
| |
| Average Sales Price per Barrel of Oil (after hedging) | $ | 48.27 |
| | | $ | 52.15 |
| | | $ | 57.44 |
| |
| Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced | $ | 0.71 |
| (1) | | $ | 0.73 |
| (1) | | $ | 0.81 |
| (1) |
| Average Production per Day (in MMcf Equivalent of Gas and Oil Produced) | 422 |
| (1) | | 385 |
| (1) | | 374 |
| (1) |
| West Coast Region | | | | | | | | |
| Average Sales Price per Mcf of Gas | $ | 4.00 |
| | | $ | 3.25 |
| | | $ | 4.11 |
| |
| Average Sales Price per Barrel of Oil | $ | 46.14 |
| | | $ | 35.26 |
| | | $ | 51.37 |
| |
| Average Sales Price per Mcf of Gas (after hedging) | $ | 4.00 |
| | | $ | 3.25 |
| | | $ | 4.52 |
| |
| Average Sales Price per Barrel of Oil (after hedging) | $ | 53.85 |
| | | $ | 57.97 |
| | | $ | 70.49 |
| |
| Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced | $ | 2.91 |
| | | $ | 2.47 |
| | | $ | 2.69 |
| |
| Average Production per Day (in MMcf Equivalent of Gas and Oil Produced) | 53 |
| | | 56 |
| | | 58 |
| |
| Total Company | | | | | | | | |
| Average Sales Price per Mcf of Gas | $ | 2.55 |
| | | $ | 1.97 |
| | | $ | 2.51 |
| |
| Average Sales Price per Barrel of Oil | $ | 46.18 |
| | | $ | 35.42 |
| | | $ | 51.43 |
| |
| Average Sales Price per Mcf of Gas (after hedging) | $ | 2.95 |
| | | $ | 3.02 |
| | | $ | 3.38 |
| |
| Average Sales Price per Barrel of Oil (after hedging) | $ | 53.87 |
| | | $ | 57.91 |
| | | $ | 70.36 |
| |
| Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced | $ | 0.96 |
| | | $ | 0.96 |
| | | $ | 1.06 |
| |
| Average Production per Day (in MMcf Equivalent of Gas and Oil Produced) | 475 |
| | | 441 |
| | | 432 |
| |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | For The Year Ended September 30 | |
| | 2022 | | | 2021 | | | 2020 | |
| United States | | | | | | | | |
| Appalachian Region | | | | | | | | |
| Average Sales Price per Mcf of Gas | $ | 5.03 | | (1) | | $ | 2.46 | | (1) | | $ | 1.75 | | (1) |
| Average Sales Price per Barrel of Oil | $ | 97.82 | | | | $ | 48.02 | | | | $ | 45.69 | | |
| Average Sales Price per Mcf of Gas (after hedging) | $ | 2.69 | | | | $ | 2.22 | | | | $ | 2.05 | | |
| Average Sales Price per Barrel of Oil (after hedging) | $ | 97.82 | | | | $ | 48.02 | | | | $ | 45.69 | | |
| Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced | $ | 0.68 | | (1) | | $ | 0.67 | | (1) | | $ | 0.68 | | (1) |
| Average Production per Day (in MMcf Equivalent of Gas and Oil Produced) | 936 | | (1) | | 856 | | (1) | | 616 | | (1) |
| West Coast Region | | | | | | | | |
| Average Sales Price per Mcf of Gas | $ | 10.03 | | | | $ | 6.34 | | | | $ | 3.82 | | |
| Average Sales Price per Barrel of Oil | $ | 94.06 | | | | $ | 60.50 | | | | $ | 45.94 | | |
| Average Sales Price per Mcf of Gas (after hedging) | $ | 10.03 | | | | $ | 6.34 | | | | $ | 3.82 | | |
| Average Sales Price per Barrel of Oil (after hedging) | $ | 70.53 | | | | $ | 56.55 | | | | $ | 56.97 | | |
| Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced | $ | 4.83 | | | | $ | 3.74 | | | | $ | 3.14 | | |
| Average Production per Day (in MMcf Equivalent of Gas and Oil Produced) | 39 | | (2) | | 41 | | | | 44 | | |
| Total Company | | | | | | | | |
| Average Sales Price per Mcf of Gas | $ | 5.05 | | | | $ | 2.49 | | | | $ | 1.77 | | |
| Average Sales Price per Barrel of Oil | $ | 94.10 | | | | $ | 60.49 | | | | $ | 45.94 | | |
| Average Sales Price per Mcf of Gas (after hedging) | $ | 2.71 | | | | $ | 2.25 | | | | $ | 2.07 | | |
| Average Sales Price per Barrel of Oil (after hedging) | $ | 70.80 | | | | $ | 56.54 | | | | $ | 56.96 | | |
| Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced | $ | 0.81 | | | | $ | 0.82 | | | | $ | 0.84 | | |
| Average Production per Day (in MMcf Equivalent of Gas and Oil Produced) | 966 | | | | 897 | | | | 660 | | |
| |
(1) | The Marcellus Shale fields (which exceed 15% of total reserves at September 30, 2017, 2016 and 2015) contributed 399 MMcfe, 372 MMcfe and 357 MMcfe of daily production in 2017, 2016 and 2015, respectively. The average sales price (per Mcfe) was $2.52 ($2.93 after hedging) in 2017, $1.94 ($3.01 after hedging) in 2016 and $2.48 ($3.35 after hedging) in 2015. The average lifting costs (per Mcfe) were $0.71 in 2017, $0.72 in 2016 and $0.79 in 2015. |
(1)Average sales prices per Mcf of gas reflect sales of gas in the Marcellus and Utica Shale fields. The Marcellus Shale fields (which exceed 15% of total reserves at September 30, 2022, 2021 and 2020) contributed 574 MMcfe, 597 MMcfe and 463 MMcfe of daily production in 2022, 2021 and 2020, respectively. The average lifting costs (per Mcfe) were $0.71 in 2022, $0.70 in 2021 and $0.70 in 2020. The Utica Shale fields (which exceed 15% of total reserves at September 30, 2022, 2021 and 2020) contributed 357 MMcfe, 255 MMcfe and 151 MMcfe of daily production in 2022, 2021 and 2020, respectively. The average lifting costs (per Mcfe) were $0.63 in 2022, $0.62 in 2021 and $0.62 in 2020.
(2)West Coast region properties were sold at June 30, 2022.
Productive Wells
| | | | | | | | | | | | | | | Appalachian
Region | | West Coast
Region | | Total Company |
| | Appalachian Region | | West Coast Region | | Total Company | |
| At September 30, 2017 | Gas | | Oil | | Gas | | Oil | | Gas | | Oil | |
| At September 30, 2022 | | At September 30, 2022 | Gas | | Oil | | Gas | | Oil | | Gas | | Oil |
| Productive Wells — Gross | 423 |
| | — |
| | — |
| | 2,224 |
| | 423 |
| | 2,224 |
| Productive Wells — Gross | 996 | | | — | | | — | | | — | | | 996 | | | — | |
| Productive Wells — Net | 328 |
| | — |
| | — |
| | 2,173 |
| | 328 |
| | 2,173 |
| Productive Wells — Net | 870 | | | — | | | — | | | — | | | 870 | | | — | |
Developed and Undeveloped Acreage
|
| | | | | | | | | |
| At September 30, 2017 | Appalachian Region | | West Coast Region | | Total Company |
| Developed Acreage | | | | | |
| — Gross | 541,528 |
| | 23,269 |
| | 564,797 |
|
| — Net | 532,435 |
| | 21,531 |
| | 553,966 |
|
| Undeveloped Acreage | | | | | |
| — Gross | 356,080 |
| | 4,518 |
| | 360,598 |
|
| — Net | 342,015 |
| | 689 |
| | 342,704 |
|
| Total Developed and Undeveloped Acreage | | | | | |
| — Gross | 897,608 |
| | 27,787 |
| | 925,395 |
|
| — Net | 874,450 |
| (1 | ) | 22,220 |
| | 896,670 |
|
| | | | | | | | | | | | | | | | | |
| At September 30, 2022 | Appalachian
Region | | West Coast
Region | | Total
Company |
| Developed Acreage | | | | | |
| — Gross | 655,433 | | | — | | | 655,433 | |
| — Net | 643,381 | | | — | | | 643,381 | |
| Undeveloped Acreage | | | | | |
| — Gross | 675,886 | | | — | | | 675,886 | |
| — Net | 636,523 | | | — | | | 636,523 | |
| Total Developed and Undeveloped Acreage | | | | | |
| — Gross | 1,331,319 | | | — | | | 1,331,319 | |
| — Net | 1,279,904 | | (1) | — | | | 1,279,904 | |
| |
(1) | Of the 874,450 Total Developed and Undeveloped Net Acreage in the Appalachian region as of September 30, 2017, there are a total of 800,747 net acres in Pennsylvania. Of the 800,747 total net acres in Pennsylvania, shale development in the Marcellus, Utica or Geneseo shales has occurred on approximately 50,467 net acres, or only 6.3% of Seneca’s total net acres in Pennsylvania. The high amount of developed acreage in the table largely reflects development in the Upper Devonian geological formation and masks the potential for development beneath this formation, which includes the Marcellus, Utica and Geneseo shales. |
(1)Of the 1,279,904 Total Developed and Undeveloped Net Acreage in the Appalachian region as of September 30, 2022, there are a total of 1,208,976 net acres in Pennsylvania. Of the 1,208,976 total net acres in Pennsylvania, shale development in the Marcellus, Utica or Geneseo shales has occurred on approximately 121,411 net acres, or 10% of Seneca’s total net acres in Pennsylvania. Developed Acreage in the table reflects previous development activities in the Upper Devonian formation, but does not include the potential for development beneath this formation in areas of previous development, which includes the Marcellus, Utica and Geneseo shales.
As of September 30, 2017,2022, the aggregate amountamounts of gross undeveloped acreage expiring in the next three years and thereafter are as follows: 1,1602,569 acres in 2018 (5802023 (2,368 net acres), 4,28615,203 acres in 2019 (3,8292024 (14,310 net acres), 1,4471,547 acres in 2020 (1,4472025 (1,388 net acres) and 40,428192,105 acres thereafter (36,511(187,765 net acres).The remaining 313,277464,462 gross acres (300,337(430,692 net acres) represent non-expiring oil and gas rights owned by the Company. Of the acreage that is currently scheduled to expire in 2018, 20192023, 2024 and 2020,2025, Seneca has no80.2 Bcf of associated proved undeveloped gas reserves. As a part of its management approved development plan, Seneca generally commences development of these reserves prior to the expiration of the leases and/or proactively extends/renews these leases.
Drilling Activity
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Productive | | Dry |
| For the Year Ended September 30 | 2022 | | 2021 | | 2020 | | 2022 | | 2021 | | 2020 |
| United States | | | | | | | | | | | |
| Appalachian Region | | | | | | | | | | | |
| Net Wells Completed | | | | | | | | | | | |
| — Exploratory | — | | | — | | | — | | | — | | | — | | | 1.00 | |
| — Development(1) | 43.00 | | | 47.83 | | | 39.84 | | | 2.50 | | | 2.00 | | | 6.50 | |
| West Coast Region | | | | | | | | | | | |
| Net Wells Completed | | | | | | | | | | | |
| — Exploratory | — | | | — | | | — | | | — | | | — | | | — | |
| — Development | 23.00 | | | 10.00 | | | 34.00 | | | — | | | — | | | — | |
| Total Company | | | | | | | | | | | |
| Net Wells Completed | | | | | | | | | | | |
| — Exploratory | — | | | — | | | — | | | — | | | — | | | 1.00 | |
| — Development | 66.00 | | | 57.83 | | | 73.84 | | | 2.50 | | | 2.00 | | | 6.50 | |
|
| | | | | | | | | | | | | | | | | |
| | Productive | | Dry |
| For the Year Ended September 30 | 2017 | | 2016 | | 2015 | | 2017 | | 2016 | | 2015 |
| United States | | | | | | | | | | | |
| Appalachian Region | | | | | | | | | | | |
| Net Wells Completed | | | | | | | | | | | |
| — Exploratory | 9.000 |
| | 1.000 |
| | 3.000 |
| | — |
| | — |
| | — |
|
| — Development | 25.400 |
| | 31.800 |
| | 49.000 |
| | 3.000 |
| | 1.000 |
| | 2.000 |
|
| West Coast Region | | | | | | | | | | | |
| Net Wells Completed | | | | | | | | | | | |
| — Exploratory | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| — Development | 14.000 |
| | 25.000 |
| | 45.000 |
| | — |
| | — |
| | 1.000 |
|
| Total Company | | | | | | | | | | | |
| Net Wells Completed | | | | | | | | | | | |
| — Exploratory | 9.000 |
| | 1.000 |
| | 3.000 |
| | — |
| | — |
| | — |
|
| — Development | 39.400 |
| | 56.800 |
| | 94.000 |
| | 3.000 |
| | 1.000 |
| | 3.000 |
|
(1)Fiscal 2022, 2021 and 2020 Appalachian region dry wells include 2.5, 2 and 4.5 net wells, respectively, drilled prior to 2012 that were never completed under a joint venture in which the Company was the nonoperator. The Company became the operator of the properties in 2017 and plugged and abandoned the wells in 2022, 2021 and 2020 after the Company determined it would not continue development activities. The remaining 2 dry wells in fiscal 2020 relate to plugged and abandoned well locations where preparatory top-hole drilling operations had commenced but further development activities (e.g., vertical and horizontal drilling, hydraulic fracturing, etc.) did not proceed as a result of changes to the Company's development plans.
Present Activities
|
| | | | | | | | |
| At September 30, 2017 | Appalachian Region | | West Coast Region | | Total Company |
| Wells in Process of Drilling(1) | | | | | |
| — Gross | 84.000 |
| | — |
| | 84.000 |
|
| — Net | 69.500 |
| | — |
| | 69.500 |
|
| | | | | | | | | | | | | | | | | |
| At September 30, 2022 | Appalachian
Region | | West Coast Region | | Total Company |
| Wells in Process of Drilling(1) | | | | | |
| — Gross | 49.00 | | | — | | | 49.00 | |
| — Net | 46.50 | | | — | | | 46.50 | |
(1)Includes wells awaiting completion.
| | | | |
(1)Item 3 | Includes wells awaiting completion.Legal Proceedings |
On September 13, 2017, the PaDEP sent a draft Consent Assessment of Civil Penalty (CACP) to Seneca, in relation to an alleged violation of the Pennsylvania Oil and Gas Act, as well as PaDEP rules and regulations regarding gas migration relating to Seneca’s drilling activities. The amount of the penalty sought by the PaDEP is not material to the Company. The draft CACP alleges a violation identified by the PaDEP in 2011. Seneca disputes the alleged violation and will vigorously defend its position in negotiations with the PaDEP.
For a discussion of various environmental and other matters, refer to Part II, Item 7, MD&A and Item 8 at Note IL — Commitments and Contingencies.
For a discussion of certain rate matters involving the NYPSC, refer to Part II, Item 7, MD&A of this report under the heading "Other Matters - Rate and Regulatory Matters."
|
| | | | |
| Item 4 | Mine Safety Disclosures |
Not Applicable.
PART II
|
| | | | |
| Item 5 | Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities |
At September 30, 2022, there were 9,236 registered shareholders of Company common stock. The common stock is listed and traded on the New York Stock Exchange under the trading symbol "NFG". Information regarding the market for the Company’s common equity and related stockholder matters appears under Item 12 at Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters and Item 8 at Note EH — Capitalization and Short-Term Borrowings, and at Note L — Market for Common Stock and Related Shareholder Matters (unaudited).Borrowings.
On July 3, 2017,1, 2022, the Company issued a total of 7,0116,560 unregistered shares of Company common stock to the nine non-employee directors of the Company then serving on the Board of Directors of the Company 779(or, in the case of non-employee directors who elected to defer receipt of such shares pursuant to each suchthe Company's Deferred Compensation Plan for Directors and Officers (the “DCP”), to the DCP trustee), consisting of 656 shares per director. All of these unregistered shares were issued under the Company’s 2009 Non-Employee Director Equity Compensation Plan as partial consideration for such directors’ services during the quarter ended September 30, 2017.2022. The Company issued an additional 273 unregistered shares in the aggregate on July 15, 2022, pursuant to the dividend reinvestment feature of the DCP, to the six non-employee directors who defer the shares issued for the quarter ended September 30, 2022. These transactions were exempt from registration under Section 4(a)(2) of the Securities Act of 1933, as transactions not involving a public offering.
Issuer Purchases of Equity Securities
|
| | | | | | | | | | | | |
| Period | Total Number of Shares Purchased(a) | | Average Price Paid per Share | | Total Number of Shares Purchased as Part of Publicly Announced Share Repurchase Plans or Programs | | Maximum Number of Shares that May Yet Be Purchased Under Share Repurchase Plans or Programs(b) |
| July 1-31, 2017 | — |
| | N/A |
| | — |
| | 6,971,019 |
|
| Aug. 1-31, 2017 | 469 |
| | $ | 58.65 |
| | — |
| | 6,971,019 |
|
| Sept. 1-30, 2017 | 5,310 |
| | $ | 58.72 |
| | — |
| | 6,971,019 |
|
| Total | 5,779 |
| | $ | 58.71 |
| | — |
| | 6,971,019 |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Period | Total Number
of Shares
Purchased(a) | | Average Price
Paid per
Share | | Total Number of
Shares Purchased
as Part of
Publicly Announced
Share Repurchase
Plans or Programs | | Maximum Number
of Shares that May
Yet Be Purchased Under Share Repurchase Plans or Programs(b) |
| July 1-31, 2022 | 12,420 | | | $ | 65.24 | | | — | | | 6,971,019 | |
| Aug. 1-31, 2022 | 10,598 | | | $ | 72.22 | | | — | | | 6,971,019 | |
| Sept. 1-30, 2022 | 9,387 | | | $ | 71.18 | | | — | | | 6,971,019 | |
| Total | 32,405 | | | $ | 69.37 | | | — | | | 6,971,019 | |
| |
(a) | Represents shares of common stock of the Company tendered to the Company by holders of stock options, SARs, restricted stock units or shares of restricted stock for the payment of option exercise prices or applicable withholding taxes. During the quarter ended September 30, 2017, the Company did not purchase any shares of its common stock pursuant to its publicly announced share repurchase program. |
| |
(b) | In September 2008, the Company’s Board of Directors authorized the repurchase of eight million shares of the Company’s common stock. The repurchase program has no expiration date. The Company has not repurchased any shares since September 17, 2008 and has no plans to make further purchases in the near future. |
(a)Represents (i) shares of common stock of the Company purchased with Company “matching contributions” for the accounts of participants in the Company’s 401(k) plans, and (ii) shares of common stock of the Company tendered to the Company by holders of stock-based compensation awards for the payment of applicable withholding taxes. During the quarter ended September 30, 2022, the Company did not purchase any shares of its common stock pursuant to its publicly announced share repurchase program. Of the 32,405 shares purchased other than through a publicly announced share repurchase program, 29,440 were purchased for the Company’s 401(k) plans and 2,965 were purchased as a result of shares tendered to the Company by holders of stock-based compensation awards.
(b)In September 2008, the Company's Board of Directors authorized the repurchase of eight million shares of the Company's common stock. The Company has not repurchased any shares since September 17, 2008. The repurchase program has no expiration date and management would discuss with the Company's Board of Directors any future repurchases under this program.
Performance Graph
The following graph compares the Company’s common stock performance with the performance of the S&P 500 Index, the PHLXS&P Mid Cap 400 Gas Utility Sector Index and the S&P 5001500 Oil & Gas Exploration & Production SUB Industry Index GICS Level 4 for the period September 30, 20122017 through September 30, 2017.2022. The graph assumes that the value of the investment in the Company’s common stock and in each index was $100 on September 30, 20122017 and that all dividends were reinvested.
| | | | 2012 | 2013 | 2014 | 2015 | 2016 | 2017 | | 2017 | 2018 | 2019 | 2020 | 2021 | 2022 |
| National Fuel | $100 | $130 | $136 | $99 | $111 | $120 | National Fuel | $100 | $101 | $87 | $79 | $106 | $127 |
| S&P 500 Index | $100 | $119 | $143 | $142 | $164 | $194 | S&P 500 Index | $100 | $117 | $122 | $141 | $183 | $155 |
| PHLX Utility Sector Index (UTY) | $100 | $105 | $121 | $128 | $151 | $169 | |
| S&P 500 Oil & Gas Exp & Prod SUB Industry Index GICS Level 4 (S5OILP) | $100 | $127 | $138 | $81 | $96 | $86 | |
| S&P Mid Cap 400 Gas Utility Index (S4GASU) | | S&P Mid Cap 400 Gas Utility Index (S4GASU) | $100 | $112 | $116 | $82 | $100 | $103 |
| S&P 1500 Oil & Gas Exp & Prod Index (S15OILP) | | S&P 1500 Oil & Gas Exp & Prod Index (S15OILP) | $100 | $126 | $81 | $45 | $105 | $155 |
Source: Bloomberg
The performance graph above is furnished and not filed for purposes of Section 18 of the Securities Exchange Act of 1934 and will not be incorporated by reference into any registration statement filed under the Securities Act of 1933 unless specifically identified therein as being incorporated therein by reference. The performance graph is not soliciting material subject to Regulation 14A.
|
| | | | |
| Item 6 | Selected Financial Data(Reserved) |
|
| | | | | | | | | | | | | | | | | | | |
| | Year Ended September 30 |
| | 2017 |
| 2016 |
| 2015 |
| 2014 |
| 2013 |
| | (Thousands, except per share amounts and number of registered shareholders) |
| Summary of Operations | | | | | | | | | |
| Operating Revenues: | | | | | | | | | |
Utility and Energy Marketing Revenues | $ | 755,485 |
| | $ | 624,602 |
| | $ | 860,618 |
| | $ | 1,103,149 |
| | $ | 942,309 |
|
Exploration and Production and Other Revenues | 617,666 |
| | 611,766 |
| | 696,709 |
| | 808,595 |
| | 707,734 |
|
Pipeline and Storage and Gathering Revenues | 206,730 |
| | 216,048 |
| | 203,586 |
| | 201,337 |
| | 179,508 |
|
| | 1,579,881 |
| | 1,452,416 |
| | 1,760,913 |
| | 2,113,081 |
| | 1,829,551 |
|
| Operating Expenses: | | | | | | | | | |
| Purchased Gas | 275,254 |
| | 147,982 |
| | 349,984 |
| | 605,838 |
| | 460,432 |
|
| Operation and Maintenance: | | | | | | | | | |
| Utility and Energy Marketing | 199,293 |
| | 192,512 |
| | 203,249 |
| | 196,534 |
| | 180,997 |
|
| Exploration and Production and Other | 145,099 |
| | 160,201 |
| | 184,024 |
| | 188,622 |
| | 175,014 |
|
| Pipeline and Storage and Gathering | 98,200 |
| | 88,801 |
| | 82,730 |
| | 77,922 |
| | 86,079 |
|
| Property, Franchise and Other Taxes | 84,995 |
| | 81,714 |
| | 89,564 |
| | 90,711 |
| | 82,431 |
|
| Depreciation, Depletion and Amortization | 224,195 |
| | 249,417 |
| | 336,158 |
| | 383,781 |
| | 326,760 |
|
| Impairment of Oil and Gas Producing Properties | — |
| | 948,307 |
| | 1,126,257 |
| | — |
| | — |
|
| | 1,027,036 |
| | 1,868,934 |
| | 2,371,966 |
| | 1,543,408 |
| | 1,311,713 |
|
| Operating Income (Loss) | 552,845 |
| | (416,518 | ) | | (611,053 | ) | | 569,673 |
| | 517,838 |
|
| Other Income (Expense): | | | | | | | | | |
| Other Income | 4,113 |
| | 9,820 |
| | 8,039 |
| | 9,461 |
| | 4,697 |
|
| Interest Income | 7,043 |
| | 4,235 |
| | 3,922 |
| | 4,170 |
| | 4,335 |
|
| Interest Expense on Long-Term Debt | (116,471 | ) | | (117,347 | ) | | (95,916 | ) | | (90,194 | ) | | (90,273 | ) |
| Other Interest Expense | (3,366 | ) | | (3,697 | ) | | (3,555 | ) | | (4,083 | ) | | (3,838 | ) |
| Income (Loss) Before Income Taxes | 444,164 |
| | (523,507 | ) | | (698,563 | ) | | 489,027 |
| | 432,759 |
|
| Income Tax Expense (Benefit) | 160,682 |
| | (232,549 | ) | | (319,136 | ) | | 189,614 |
| | 172,758 |
|
| Net Income (Loss) Available for Common Stock | $ | 283,482 |
| | $ | (290,958 | ) | | $ | (379,427 | ) |
| $ | 299,413 |
|
| $ | 260,001 |
|
| Per Common Share Data | | | | | | | | | |
| Basic Earnings (Loss) per Common Share | $ | 3.32 |
| | $ | (3.43 | ) | | $ | (4.50 | ) | | $ | 3.57 |
| | $ | 3.11 |
|
| Diluted Earnings (Loss) per Common Share | $ | 3.30 |
| | $ | (3.43 | ) | | $ | (4.50 | ) | | $ | 3.52 |
| | $ | 3.08 |
|
| Dividends Declared | $ | 1.64 |
| | $ | 1.60 |
| | $ | 1.56 |
| | $ | 1.52 |
| | $ | 1.48 |
|
| Dividends Paid | $ | 1.63 |
| | $ | 1.59 |
| | $ | 1.55 |
| | $ | 1.51 |
| | $ | 1.47 |
|
| Dividend Rate at Year-End | $ | 1.66 |
| | $ | 1.62 |
| | $ | 1.58 |
| | $ | 1.54 |
| | $ | 1.50 |
|
| At September 30: | | | | | | | | | |
| Number of Registered Shareholders | 11,211 |
| | 11,751 |
| | 12,147 |
| | 12,654 |
| | 13,215 |
|
| | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | |
| | Year Ended September 30 |
| | 2017 |
| 2016 |
| 2015 |
| 2014 |
| 2013 |
| | (Thousands, except per share amounts and number of registered shareholders) |
| Net Property, Plant and Equipment | | | | | | | | | |
| Exploration and Production | $ | 1,196,521 |
| | $ | 1,083,804 |
| | $ | 2,126,265 |
| | $ | 2,897,744 |
| | $ | 2,600,448 |
|
| Pipeline and Storage | 1,524,197 |
| | 1,463,541 |
| | 1,387,516 |
| | 1,187,924 |
| | 1,074,079 |
|
| Gathering | 455,701 |
| | 439,660 |
| | 400,409 |
| | 292,793 |
| | 161,111 |
|
| Utility | 1,435,414 |
| | 1,403,286 |
| | 1,351,504 |
| | 1,297,179 |
| | 1,246,943 |
|
| Energy Marketing | 1,503 |
| | 1,745 |
| | 1,989 |
| | 2,070 |
| | 2,002 |
|
| All Other | 57,960 |
| | 59,054 |
| | 60,404 |
| | 61,236 |
| | 62,554 |
|
| Corporate | 2,778 |
| | 3,392 |
| | 3,808 |
| | 4,145 |
| | 4,589 |
|
| Total Net Plant | $ | 4,674,074 |
| | $ | 4,454,482 |
| | $ | 5,331,895 |
| | $ | 5,743,091 |
| | $ | 5,151,726 |
|
| Total Assets | $ | 6,103,320 |
| | $ | 5,636,387 |
| | $ | 6,564,939 |
| | $ | 6,687,717 |
| | $ | 6,125,618 |
|
| Capitalization | | | | | | | | | |
| Comprehensive Shareholders’ Equity | $ | 1,703,735 |
| | $ | 1,527,004 |
| | $ | 2,025,440 |
| | $ | 2,410,683 |
| | $ | 2,194,729 |
|
| Long-Term Debt, Net of Current Portion and Unamortized Discount and Debt Issuance Costs | 2,083,681 |
| | 2,086,252 |
| | 2,084,009 |
| | 1,637,443 |
| | 1,635,630 |
|
| Total Capitalization | $ | 3,787,416 |
| | $ | 3,613,256 |
| | $ | 4,109,449 |
| | $ | 4,048,126 |
| | $ | 3,830,359 |
|
|
| | | | |
| Item 7 | Management’s Discussion and Analysis of Financial Condition and Results of Operations |
OVERVIEW
The Company is a diversified energy company engaged principally in the production, gathering, transportation, distributionstorage and marketingdistribution of natural gas. The Company operates an integrated business, with assets centered in western New York and Pennsylvania, being utilized for, and benefiting from, the production and transportation of natural gas from the Appalachian basin. Current development activities are focused primarily in the Marcellus and Utica Shale.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 Canada and the eastern United States.States and Canada. The Company's efforts in this regard are not limited to affiliated projects. The Company has also been designing and building pipeline projects for the transportation of natural gas for non-affiliated natural gas producerscustomers in the Appalachian basin. The Company also develops and produces oil reserves, primarily in California. The Company reports financial results for fivefour business segments. Refer to Item 1, Business, for a more detailed description of each of the segments.segments: Exploration and Production, Pipeline and Storage, Gathering, and Utility.
Corporate Responsibility
The Board of Directors and management recognize that the long-term interests of stockholders are served by considering the interests of customers, employees and the communities in which the Company operates. In addition, the Company strives to comply with all applicable legal and regulatory requirements and to adhere to high standards of ethics and integrity. The Board retains risk oversight and general oversight of corporate responsibility, including environmental, social and corporate governance (“ESG”) concerns, and any related health and safety issues that might arise from the Company’s operations. The Board directs managementBoard’s Nominating/Corporate Governance Committee oversees and provides guidance concerning the Company’s practices and reporting with respect to integrate these corporate responsibility concerns into decision-making throughout the organization. The Company takes very seriously its role as a corporate citizen and remains committedESG factors that are of significance to the welfareCompany and its stakeholders, and may also make recommendations to the Board regarding ESG initiatives and strategies, including the Company’s progress on integrating ESG factors into business strategy and decision-making.
Part of the areas in which it operates, as it has for over 100 years.
The Company recognizes the ongoing debate regarding climate change, including questions surrounding potential physical, technological, regulatory and social risks as well as corresponding opportunities. The Board and management consider these risks and opportunities in theirmanagement’s strategic and capital spending decision process includes identifying and assessing climate-related risks and opportunities. Management reports quarterly to the Board on critical and potentially emerging risks, including climate-related risks, as part of the Enterprise Risk Management process.
Further, since Since the Company operates an integrated business with assets being utilized for, and benefiting from, the production, transportation and transportationconsumption of natural gas, the Board and management consider physical and transitional climate risks, including policy and legal risks, technological developments, shifts in market conditions, including future natural gas usage, and reputational risks, and the impact of the climate change debatethose risks on future natural gas usage.
The U.S. Energy Information Administration (EIA) provides relevant data and projections in this regard. The EIA’s 2017 International Energy Outlook projects that worldwide natural gas consumption will increase 43% from 2015 through 2040. Natural gas is a versatile fuel and this increase is projected to transcend all sectors, with the largest increases seen in the industrial and electric generation sectors. The EIA’s 2017 Annual Energy Outlook further projects that, through 2040, U.S. natural gas consumption will increase more than any other fuel source. The EIA anticipates that shale gas production could potentially account for 70% of U.S. natural gas production in 2040 as companies leverage technological advances in horizontal drilling and hydraulic fracturing to develop previously uneconomic or unreachable reserves. The Board considers such projections in setting and reviewing the Company’s capital budget.
Thebusiness. In March 2022, the Company believes thatpublished its conservative approach to capital investments combined with its history, experience, assets,inaugural Climate Report, analyzing climate-related transitional and fully-integrated approach put it in a positionphysical risks, and describing our strategy for success in the current and evolving regulatory landscape. As recognized by the EIA, natural gas is a relatively clean fossil fuel compared to other fossil fuels such as oil or coal with respect to greenhouse gas emissions. The New York State Energy Research and Development Authority, in its 2016 New York State Greenhouse Gas Inventory Report, noted that from 1990 to 2014, “emissions from electricity generated in-State dropped 52 percent during this same period, acting as a major driver of the State’s decreasing GHG emissions. This drop is largely due to the significant decrease in the burning of coal and petroleum products in the electricity generation sector. Emissions from residential, commercial and industrial buildings also decreased, showing a reduction of approximately 15 percent from 1990-2014. This reduction in emissions was primarily the result of a decrease in the use of coal and petroleum and an increase in the use of natural gas.”
The Company recognizes that there exists an evolving landscape of international accords and federal, state and local laws and regulations regarding greenhouse gas emissions or climate change initiatives. Changing market conditions and new regulatory requirements,addressing those risks, as well as the unanticipated or inconsistent applicationresiliency of existing laws and regulations by administrative agencies, make it difficult to predictthat strategy under a long-term business impact across twenty or more years.carbon constrained scenario. The Company adjustsreviews and considers adjustments to its approach to capital investment approachin response to regulatory change. For instance, given what appears to be the imposition of unattainable regulatory standards by the current executive administration of one of the states in which the Company does business, the Company is shiftingthese transitional developments, with its investment focus away from that state with respect to new pipeline expansion projects.long-term, returns-focused approach.
While natural gas has relatively lower greenhouse gas emissions than other fossil fuels, the natural gas value chain does result in greenhouse gas emissions. The Company recognizes the important role of ongoing system modernization and efficiency in reducing greenhouse gas emissions.emissions and remains focused on reducing the Company’s carbon footprint, with these efforts positioning natural gas, and the Company’s related infrastructure, to remain an important part of the energy complex. In its Utility,2021, the Company directs capital spending to replacement and to other investments (such as the purchaseset methane intensity reduction targets at each of vehicles and equipment necessary for that activity) that support its statutory obligation to provide safe and reliable service. In its Pipeline and Storage businesses, a significant portion of the capital budget is spent on modernization. The Company’s replacement of aging natural gas infrastructure leads to fewer leaks and directly results in lower greenhouse gas emissions. For instance, as a result of system modernization, the Utility segment, since 2012, has seen a 13.5% reduction inan absolute greenhouse gas emissions reported toreduction target for the EPA under Subpart W of 40 CFR Part 98.consolidated Company, and greenhouse gas reduction targets associated with the Company’s utility delivery system. In 2022, the Company began measuring progress against these reduction targets. The Company also works with variousincorporated short-term and long-term executive compensation goals designed to incentivize and reward performance if reduction targets are met or exceeded. The Company's ability to estimate accurately the time, costs and resources necessary to meet these emissions reduction targets may change as environmental exposures and opportunities change, technology advances, and legislative and regulatory commissions to develop ratemaking initiatives to increase end use efficiency while reducing downside risk from demand fluctuation. In its Exploration and Production segment, the Company has implemented a number of initiatives and standardized a variety of practices throughout the drilling process thatupdates are aimed at minimizing greenhouse gas emissions and improving air quality, including green completion techniques and deploying leak detection technologies.issued.
Fiscal 20172022 Highlights
This Item 7, MD&A, provides information concerning:
| |
1. | The critical accounting estimates of the Company; |
| |
2. | Changes in revenues and earnings of the Company under the heading, “Results of Operations;” |
| |
3. | Operating, investing and financing cash flows under the heading “Capital Resources and Liquidity;” |
| |
4. | Off-Balance Sheet Arrangements; |
| |
5. | Contractual Obligations; and |
| |
6. | Other Matters, including: (a) 2017 and projected 2018 funding for the Company’s pension and other post-retirement benefits; (b) disclosures and tables concerning market risk sensitive instruments; (c) rate and regulatory matters in the Company’s New York, Pennsylvania and FERC-regulated jurisdictions; (d) environmental matters; and (e) new authoritative accounting and financial reporting guidance. |
1.The critical accounting estimates of the Company;
2.Changes in revenues and earnings of the Company under the heading, “Results of Operations;”
3.Operating, investing and financing cash flows under the heading “Capital Resources and Liquidity” and;
4.Other Matters, including: (a) 2022 and projected 2023 funding for the Company’s pension and other post-retirement benefits; (b) disclosures and tables concerning market risk sensitive instruments; (c) rate matters in the Company’s New York, Pennsylvania and FERC-regulated jurisdictions; (d) environmental matters; and (e) effects of inflation.
The information in MD&A should be read in conjunction with the Company’s financial statements in Item 8 of this report.
report, which includes a comparison of our Results of Operations and Capital Resources and Liquidity for fiscal 2022 and fiscal 2021. For a discussion of the Company's earnings, refer to the Results of Operations section below. A discussion of changes in the Company’s results of operations from fiscal 2020 to fiscal 2021 has been omitted from this Form 10-K, but may be found in Item 7, MD&A, of the Company’s Form 10-K for the fiscal year ended September 30, 2017 compared2021, filed with the SEC on November 19, 2021.
On June 30, 2022, the Company completed the sale of Seneca’s California assets to Sentinel Peak Resources California LLC for a total sale price of $253.5 million, consisting of $240.9 million in cash and contingent consideration valued at $12.6 million at closing. The Company pursued this sale given the strong commodity price environment and the Company's strategic focus in the Appalachian Basin. Under the terms of the purchase and sale agreement, the Company can receive up to three annual contingent payments between calendar year 2023 and calendar year 2025, not to exceed $10 million per year, with the amount of each annual payment calculated as $1.0 million for each $1 per barrel that the ICE Brent Average for each calendar year exceeds $95 per barrel up to $105 per barrel. The sale price, which reflected an effective date of April 1, 2022, was reduced for production revenues less expenses that were retained by Seneca from the effective date to the year ended September 30, 2016, the Company experienced an increase in earnings of $574.5 million primarily due to higher earnings in the Exploration and Production segment. During the year ended September 30, 2016, the Company recorded impairment charges of $948.3 million ($550.0 million after-tax) that did not recur during the year ended September 30, 2017. In the Company's Exploration and Production segment, oil and gas property acquisition, exploration and development costs are capitalized underclosing date. Under the full cost method of accounting. Such costs are subject to a quarterly ceiling test prescribed by SEC Regulation S-X Rule 4-10 that determines a limit, or ceiling, on the amount of property acquisition, exploration and development costs that can be capitalized. The book value of the Company's oil and gas properties exceeded the ceiling at the end of each of the four quarters of fiscal 2016 due to significant declines in crudeaccounting for oil and natural gas commodity prices overproperties, $220.7 million of the previous twelve months, resultingsale price at closing was accounted for as a reduction of capitalized costs since the disposition did not alter the relationship between capitalized costs and proved reserves of oil and gas attributable to the cost center. The remainder of the sale price ($32.8 million) was applied against assets that are not subject to the full cost method of accounting, with the Company recognizing a gain of $12.7 million on the sale of such assets. The majority of this gain related to the sale of emission allowances.
The Company has continued to pursue development projects to expand its Pipeline and Storage segment. One project on Supply Corporation's system, referred to as the FM100 Project, upgraded a 1950’s era pipeline in northwestern Pennsylvania and created approximately 330,000 Dth per day of additional transportation capacity in Pennsylvania from a receipt point with NFG Midstream Clermont, LLC in McKean County, Pennsylvania to the Transcontinental Gas Pipe Line Company, LLC ("Transco") system at Leidy, Pennsylvania. Construction activities on the expansion portion of the FM100 Project are complete and the project was placed into service in December 2021. This project will provide incremental annual transportation revenues of approximately $50 million. The FM100 Project is discussed in more detail in the impairment charges mentioned above during fiscal 2016.Capital Resources and Liquidity section that follows. For further discussion of the ceiling testPipeline and a sensitivity analysis concerning changes in crude oilStorage segment's revenues and natural gas commodity prices and their impact on the ceiling test, refer to the Critical Accounting Estimates section below. For further discussion of the Company’s earnings, refer to the Results of Operations section below.
On February 3, 2017,The Company's Exploration and Production segment continues to grow, as evidenced by an 8% growth in proved reserves from the Company, in its Pipeline and Storage segment, received FERC approvalprior year to a total of a project to move significant prospective Marcellus production from Seneca’s Western Development Area4,172 Bcfe at Clermont to an Empire interconnection with TransCanada Pipeline at Chippawa and an interconnection with Tennessee Gas Pipeline’s 200 Line in East Aurora, New York (“Northern Access 2016”). On April 7, 2017, the NYDEC issued a Notice of Denial of the federal Clean Water Act Section 401 Water Quality Certification and other state stream and wetland permits for the New York portion of the project (the Water Quality Certification for the Pennsylvania portion of the project was received on January 27, 2017). The Company remains committed to the project. On April 21, 2017, the Company appealed the NYDEC's decision with regard to the Water Quality Certification to the United States Court of Appeals for the Second Circuit, and on May 11, 2017, the Company commenced legal action in New York State Supreme Court challenging the NYDEC's actions with regard to various state permits. The Company also has pending with FERC a proceeding asserting, among other things, that the NYDEC exceeded the reasonable time frame to take action under the Clean Water Act and, therefore, waived its opportunity to approve or deny the Water Quality Certification. Approximately $75.8 million in costs have been incurred on this project through September 30, 2017, with the costs residing either in Construction Work in Progress, a component of Property, Plant and Equipment on the Consolidated Balance Sheet, or Deferred Charges. For further discussion of the Northern Access 2016 project, refer to Item 8 at Note I - Commitments and Contingencies.
Seneca has two downstream Canadian transportation contracts to move incremental volumes associated with the Northern Access 2016 project. One of the contracts has a term expiring on March 31, 2023 with a remaining commitment of approximately $27.0 million (using a 1.2468 Exchange Rate). The other transportation precedent
agreement was suspended until the Northern Access 2016 project has received all its necessary permits. Seneca paid $2.4 million associated with this suspension2022. Production increased 25.1 Bcfe during the quarterfiscal year ended September 30, 20172022 to a total of 352.5 Bcfe, and will be reimbursed this amount ifis expected to increase again in fiscal 2023. The December 2021 commencement of service for Seneca’s 330,000 Dth per day of incremental pipeline capacity on the Leidy South Project, which was the companion project is reinstated. As noted above,of the Company's FM100 Project, contributed to the production growth in fiscal 2022. This incremental pipeline capacity provides Seneca with the ability to reach premium Transco Zone 6 (Non-New York) markets.
On February 28, 2022, the Company remainsentered into a Credit Agreement (as amended from time to time, the "Credit Agreement") with a syndicate of twelve banks. The Credit Agreement replaced the previous Fourth Amended and Restated Credit Agreement and a previous 364-Day Credit Agreement. The Credit Agreement provides a $1.0 billion unsecured committed revolving credit facility with a maturity date of February 26, 2027.
On June 30, 2022, the Company entered into a new 364-Day Credit Agreement (the "364-Day Credit Agreement") with a syndicate of five banks, all of which are also lenders under the Credit Agreement. The 364-Day Credit Agreement provides an additional $250.0 million unsecured committed delayed draw term loan credit facility with a maturity date of June 29, 2023. The Company elected to draw $250.0 million under the Northern Access 2016 project. Seneca has mitigatedfacility on October 27, 2022. The Company is using the proceeds for general corporate purposes, which will include the redemption in November of a portion of the current capacity costs through capacity release arrangements.
From a financing perspective,Company's outstanding long-term debt maturing in September 2017, theMarch 2023. The Company issued $300.0 million of 3.95% notes due in September 2027. The proceeds of the debt issuance were useddoes not anticipate long-term refinancing for the October 2017 redemption of $300.0$250.0 million ofdrawn under the Company's 6.50% notes that were scheduled to mature in April 2018. The Company expects to use cash on hand and cash from operations to meet its capital expenditure needs for fiscal 2018 and may issue short-term and/facility or the maturing long-term debt during fiscal 2018 as needed.in March 2023.
CRITICAL ACCOUNTING ESTIMATES
The Company has prepared its consolidated financial statements in conformity with GAAP. The preparation of these financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. In the event estimates or assumptions prove to be different from actual results, adjustments are made in subsequent periods to reflect more current information. The following is a summary of the Company’s most critical accounting estimates, which are defined as those estimates whereby judgments or uncertainties could affect the application of accounting policies and materially different amounts could be reported under different conditions or using different assumptions. For a complete discussion of the Company’s significant accounting policies, refer to Item 8 at Note A — Summary of Significant Accounting Policies.
Oil and Gas Exploration and Development Costs. In the Company’sCompany's Exploration and Production segment, oilgas and gasoil property acquisition, exploration and development costs are capitalized under the full cost method of accounting.accounting, with natural gas properties in the Appalachian region being the primary component of these capitalized costs after the June 30, 2022 sale of the Company's California oil and natural gas properties. That sale is discussed in more detail in Item 8 at Note B — Asset Acquisitions and Divestitures. Under this accounting methodology, all costs associated with property acquisition, exploration and development activities are capitalized, including internal costs directly identified with acquisition, exploration and development activities. The internal costs that are capitalized do not include any costs related to production, general corporate overhead, or similar activities. The Company does not recognize any gain or loss on the sale or other disposition of oil and gas properties unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of oil and gas attributable to a cost center.
Proved reserves are estimated quantities of reserves that, based on geologic and engineering data, appear with reasonable certainty to be producible under existing economic and operating conditions. Such estimates of proved reserves are inherently imprecise and may be subject to substantial revisions as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. The estimates involved in determining proved reserves are critical accounting estimates because they serve as the basis over which capitalized costs are depleted under the full cost method of accounting (on a units-of-production basis). Unproved properties are excluded from the depletion calculation until proved reserves are found or it is determined that the unproved properties are impaired. All costs related to unproved properties are reviewed quarterly to determine if impairment has occurred. The amount of any impairment is transferred to the pool of capitalized costs being amortized.
In addition to depletion under the units-of-production method, proved reserves are a major component in the SEC full cost ceiling test. The full cost ceiling test is an impairment test prescribed by SEC Regulation S-X Rule 4-10. The ceiling test, which is performed each quarter, determines a limit, or ceiling, on the amount of property acquisition, exploration and development costs that can be capitalized. The ceiling under this test
represents (a) the present value of estimated future net cash flows, excluding future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, using a discount factor of 10%, which is computed by applying an unweighted arithmetic average of the first day of the month oil and gas prices for each month within the twelve-month period prior to the end of the reporting period (as adjusted for hedging) to estimated future production of proved oil and gas reserves as of the date of the latest balance sheet, less estimated future expenditures, plus (b) the cost of unevaluatedunproved properties not being depleted, less (c) income tax effects related to the differences between the book and tax basis of the properties. The estimates of future production and future
expenditures are based on internal budgets that reflect planned production from current wells and expenditures necessary to sustain such future production. The amount of the ceiling can fluctuate significantly from period to period because of additions to or subtractions from proved reserves and significant fluctuations in oil andnatural gas prices. The ceiling is then compared to the capitalized cost of oil and gas properties less accumulated depletion and related deferred income taxes. If the capitalized costs of oil and gas properties less accumulated depletion and related deferred taxes exceeds the ceiling at the end of any fiscal quarter, a non-cash impairment charge must be recorded to write down the book value of the reserves to their present value. This non-cash impairment cannot be reversed at a later date if the ceiling increases. It should also be noted that a non-cash impairment to write down the book value of the reserves to their present value in any given period causes a reduction in future depletion expense. At September 30, 2017,2022, the ceiling exceeded the book value of the oil and gas properties by approximately $286.4 million. The 12-month average of the first day of the month price for crude oil for each month during 2017, based on posted Midway Sunset prices, was $45.19 per Bbl.$3.2 billion. The 12-month average of the first day of the month price for natural gas for each month during 2017,2022, based on the quoted Henry Hub spot price for natural gas, was $3.00$6.13 per MMBtu. (Note — because actual pricing of the Company’s various producing properties variesvary depending on their location and hedging, the prices used to calculate the ceiling may differ from the Midway Sunset and Henry Hub prices,price, which areis only indicative of the 12-month average prices for 2017. Pricing differences would include2022. Actual realized pricing includes adjustments for regional market differentials, transportation fees and contractual arrangements.) The following table illustratesIn regard to the sensitivity of the ceiling test calculation to commodity price changes, specifically showing the amounts the ceiling would have exceeded the book value of the Company's oil and gas properties at September 30, 2017 (which would not have resulted in an impairment charge) if natural gas prices were $0.25 per MMBtu lower than the average prices used at September 30, 2017, if crude2022 in the ceiling test calculation, the ceiling would have exceeded the book value of the Company's oil prices were $5 per Bbl lower than the average prices used at September 30, 2017, and if both natural gas prices and crude oil prices were $0.25 per MMBtu and $5 per Bbl lower than the average prices used at September 30, 2017 (all amounts are presented after-tax). Theseproperties by approximately $2.9 billion (after-tax), which would not have resulted in an impairment charge. This calculated amounts areamount is based solely on price changes and dodoes not take into account any other changes to the ceiling test calculation, including, among others, changes in reserve quantities and future cost estimates.
Ceiling Testing Sensitivity to Commodity Price Changes
|
| | | | | | | | | | | |
| (Millions) | $0.25/MMBtu Decrease in Natural Gas Prices | | $5.00/Bbl Decrease in Crude Oil Prices | | $0.25/MMBtu Decrease in Natural Gas Prices and $5.00/Bbl Decrease in Crude Oil Prices |
| | | | | | |
| Excess of Ceiling over Book Value under Sensitivity Analysis | $ | 157.2 |
| | $ | 250.8 |
| | $ | 121.7 |
|
It is difficult to predict what factors could lead to future impairments under the SEC’s full cost ceiling test. As discussed above, fluctuations in or subtractions from proved reserves, increases in development costs for undeveloped reserves and significant fluctuations in oil andnatural gas prices have an impact on the amount of the ceiling at any point in time.
In accordance with the current authoritative guidance for asset retirement obligations, the Company records an asset retirement obligation for plugging and abandonment costs associated with the Exploration and Production segment’s crude oil and natural gas wells and capitalizes such costs in property, plant and equipment (i.e. the full cost pool). Under the current authoritative guidance for asset retirement obligations, since plugging and abandonment costs are already included in the full cost pool, the units-of-production depletion calculation excludes from the depletion base any estimate of future plugging and abandonment costs that are already recorded in the full cost pool.
As discussed above, the full cost method of accounting provides a ceiling to the amount of costs that can be capitalized in the full cost pool. In accordance with current authoritative guidance, the future cash outflows associated with plugging and abandoning wells are excluded from the computation of the present value of estimated future net revenues for purposes of the full cost ceiling calculation.
Regulation. The Company is subject to regulation by certain state and federal authorities. The Company, in its Utility and Pipeline and Storage segments, has accounting policies which conform to the FASB authoritative guidance regarding accounting for certain types of regulations, and which are in accordance with the accounting requirements and ratemaking practices of the regulatory authorities. The application of these accounting principles for certain types of rate-regulated activities provide that certain actual or anticipated costs that would otherwise be charged to expense can be deferred as regulatory assets, based on the expected recovery from customers in future rates. Likewise, certain actual or anticipated credits that would otherwise reduce expense can be deferred as regulatory liabilities, based on the expected flowback to customers in future rates. Management’s assessment of the probability of recovery or pass through of regulatory assets and liabilities requires judgment and interpretation of laws and regulatory commission orders. If, for any reason, the Company ceases to meet the criteria for application of regulatory accounting treatment for all or part of its operations, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the balance sheet and included in the income statement for the period in which the discontinuance of regulatory
accounting treatment occurs. Such amounts would be classified as an extraordinary item. For further discussion of the Company’s regulatory assets and liabilities, refer to Item 8 at Note CF — Regulatory Matters.
Accounting for Derivative Financial Instruments. The Company uses a variety of derivative financial instruments to manage a portion of the market risk associated with fluctuations in the price of natural gas and crude oil in its Exploration and Production and Energy Marketing segments. These instruments are categorized as price swap agreements and futures contracts. In accordance with the authoritative guidance for derivative instruments and hedging activities, the Company primarily accounts for these instruments as effective cash flow hedges or fair value hedges. In addition, the Company also enters into foreign exchange forward contracts to manage the risk of currency fluctuations associated with transportation costs denominated in Canadian currency in the Exploration and Production segment. These instruments are accounted for as cash flow hedges. Gains or losses associated with the derivative financial instruments that are accounted for as cash flow or fair value hedges are matched with gains or losses resulting from the underlying physical transaction that is being hedged. To the extent that such derivative financial instruments would ever be deemed to be ineffective based on effectiveness testing, mark-to-market gains or losses from such derivative financial instruments would be recognized in the income statement without regard to an underlying physical transaction. Refer to the “Market Risk Sensitive Instruments” section below for further discussion of the Company’s derivative financial instruments and refer to Item 8 at Note F— Fair Value Measurements for discussion of the determination of fair value for derivative financial instruments.
Pension and Other Post-Retirement Benefits. The amounts reported in the Company’s financial statements related to its pension and other post-retirement benefits are determined on an actuarial basis, which uses many assumptions in the calculation of such amounts. These assumptions include the discount rate, the expected return on plan assets, the rate of compensation increase and, for other post-retirement benefits, the expected annual rate of increase in per capita cost of covered medical and prescription benefits. Beginning in fiscal 2018, the Company refined the method used to determine the service and interest cost components of net periodic benefit cost. Using the refined method, known as the spot rate approach, the Company will use individual spot rates along the yield curve that correspond to the timing of each benefit payment to determine the discount rate. The individual spot rates along the yield curve will continue to be determined by an above mean methodology in that the coupon interest rates that are in the lower 50th percentile will be excluded based on the assumption that the Company would not utilize more expensive (i.e. lower yield) instruments to settle its liabilities. The impact on the benefit obligation, as of September 30, 2017, is immaterial. This change will provide a more precise measurement of service and interest costs by improving the correlation between projected cash outflows and corresponding spot rates on the yield curve. Compared to the previous method, the spot rate approach will decrease the service and interest components of net periodic benefit costs in fiscal 2018. The Company will account for this change prospectively as a change in accounting estimate. The expected return on plan assets assumption used by the Company reflects the anticipated long-term rate of return on the plan’s current and future assets. The Company utilizes historical investment data, projected capital market conditions, and the plan’s target asset class and investment manager allocations to set the assumption regarding the expected return on plan assets. Changes in actuarial assumptions and actuarial experience, including deviations between actual versus expected return on plan assets, could have a material impact on the amount of pension and post-retirement benefit costs and funding requirements experienced by the Company. However, the Company expects to recover a substantial portion of its net periodic pension and
other post-retirement benefit costs attributable to employees in its Utility and Pipeline and Storage segments in accordance with the applicable regulatory commission authorization, subject to applicable accounting requirements for rate-regulated activities, as discussed above under “Regulation.”
Changes in actuarial assumptions and actuarial experience could also have an impact on the benefit obligation and the funded status related to the Company’s pension and other post-retirement benefits and could impact the Company’s equity. For example, the discount rate used to determine benefit obligations of the Company's other post-retirement benefits changed from 3.70% in 2016 to 3.81% in 2017. The change in the discount rate from 2016 to 2017 decreased the accumulated post-retirement benefit obligation by $6.2 million. The discount rate used to determine benefit obligations of the Retirement Plan changed from 3.60% in 2016 to 3.77% in 2017. The change in the discount rate from 2016 to 2017 decreased the Retirement Plan projected benefit obligation by $20.5 million. Other examples include actual versus expected return on plan assets, which has an impact on the funded status of the plans, and actual versus expected benefit payments, which has an impact on the pension plan projected benefit obligation and the accumulated post-retirement benefit obligation. For 2017, the actual return on plan assets was higher than the expected return, which resulted in an increase to the funded status of the Retirement Plan ($24.6 million) as well as an increase to the funded status of the VEBA trusts and 401(h) accounts ($8.7 million). The actual versus expected benefit payments for 2017 caused a decrease of $2.1 million to the accumulated post-retirement benefit obligation. In addition, changes in per-capita claim costs, premiums, retiree contributions and retiree drug subsidy assumptions in order to better reflect anticipated experience based on actual experience resulted in a decrease to the accumulated post-retirement benefit obligation of $48.4 million. In calculating the projected benefit obligation for the Retirement Plan and the accumulated post-retirement obligation, the actuary takes into account the average remaining service life of active participants. The average remaining service life of active participants is 7 years for the Retirement Plan and 6 years for those eligible for other post-retirement benefits. For further discussion of the Company’s pension and other post-retirement benefits, refer to Other Matters in this Item 7, which includes a discussion of funding for the current year, and to Item 8 at Note H — Retirement Plan and Other Post Retirement Benefits.
RESULTS OF OPERATIONS
EARNINGS
20172022 Compared with 20162021
The Company's earnings were $283.5$566.0 million in 20172022 compared to a losswith earnings of $291.0$363.6 million in 2016.2021. The increase in earnings of $574.5$202.4 million was primarily a result of higher earnings in the Exploration and Production segment and Gathering segment. Lower earnings in the Pipeline and Storage segment, Utility segment and Energy Marketing segment, as well asall reportable segments, slightly offset by losses in the Corporate and All Other categories, partially offset these increases.categories. In the discussion that follows, all amounts used in the earnings discussions are after-tax amounts, unless otherwise noted. Earnings were impacted by the following events in 2016:2022 and 2021:
20162022 Events
Non-cash impairment charges•The reversal of $948.3 million ($550.0 million after tax) recorded during 2016 for the Exploration and Production segment’s oil and gas producing properties.
Joint development agreement professional feesa deferred tax valuation allowance of $4.6$24.9 million recorded in the Exploration and Production segment. The joint development agreement professional fees incurred wereand Gathering segments.
•A $28.4 million remeasurement of accumulated deferred income taxes, primarily in the Exploration and Production and Gathering segments, related to professional services associated with the Marcellus Shale drilling joint development agreement with IOG executed on December 1, 2015 and subsequently extended on June 13, 2016.
2016 Compared with 2015
The Company recorded a loss of $291.0 million in 2016 compared with a loss of $379.4 million in 2015. The reduction in lossthe Pennsylvania state corporate income tax rate that was primarilysigned into law in July 2022.
•A gain recognized on the resultsale of lower lossesSeneca's California assets of $12.7 million ($9.5 million after-tax) recorded during 2022 in the Exploration and Production segment related to a portion of the sale price that was applied to assets that were not subject to the full cost method of accounting.
•A loss of $44.6 million ($33.3 million after-tax) recorded during 2022 in the Exploration and Production segment related to the Corporate category. termination of this segment's remaining crude oil derivative contracts as a result of the sale of Seneca's California assets.
•Transaction and severance costs of $9.7 million ($7.2 million after-tax) incurred during 2022 in the Exploration and Production segment related to the sale of Seneca's California assets.
•The reduction of an OPEB regulatory liability that increased earnings by $18.5 million ($14.6 million after-tax) recorded during 2022 in the Utility segment Pipeline and Storage segment, Energy Marketing segment and Gathering segment experiencedin accordance with a declineregulatory proceeding in earnings, offset by higher earnings in the All Other category. Earnings were impacted by the 2016 events discussed above and the following events in 2015:Distribution Corporation's Pennsylvania service territory.
2021 Events
2015 Events
•Non-cash impairment charges of $1.1 billion$76.2 million ($650.255.2 million after tax)after-tax) recorded during 20152021 for the Exploration and Production segment’ssegment's oil and gas producing properties.
•A $4.7gain recognized on the sale of timber properties of $51.1 million reversal($37.0 million after-tax) recorded during 2021 in the Company's All Other category.
•A loss of stock-based compensation expense related to performance based restricted stock units since performance conditions, which do not include any market conditions, were not met. The $4.7$15.7 million was allocated across($11.4. million after-tax) recorded in the Exploration and Production segment, Pipeline and Storage segment, Utility segment andGathering segments during 2021 for the All Other and Corporate category.premium paid on early redemption of long-term debt.
Earnings (Loss) by Segment
| | | | | | | | | | | | | | | | | |
| | Year Ended September 30 |
| | 2022 | | 2021 | | 2020 |
| | (Thousands) |
| Exploration and Production | $ | 306,064 | | | $ | 101,916 | | | $ | (326,904) | |
| Pipeline and Storage | 102,557 | | | 92,542 | | | 78,860 | |
| Gathering | 101,111 | | | 80,274 | | | 68,631 | |
| Utility | 68,948 | | | 54,335 | | | 57,366 | |
| Total Reported Segments | 578,680 | | | 329,067 | | | (122,047) | |
| All Other | (9) | | | 37,645 | | | (269) | |
| Corporate | (12,650) | | | (3,065) | | | (1,456) | |
| Total Consolidated | $ | 566,021 | | | $ | 363,647 | | | $ | (123,772) | |
|
| | | | | | | | | | | |
| | Year Ended September 30 |
| | 2017 | | 2016 | | 2015 |
| | (Thousands) |
| Exploration and Production | $ | 129,326 |
| | $ | (452,842 | ) | | $ | (556,974 | ) |
| Pipeline and Storage | 68,446 |
| | 76,610 |
| | 80,354 |
|
| Gathering | 40,377 |
| | 30,499 |
| | 31,849 |
|
| Utility | 46,935 |
| | 50,960 |
| | 63,271 |
|
| Energy Marketing | 1,509 |
| | 4,348 |
| | 7,766 |
|
| Total Reported Segments | 286,593 |
| | (290,425 | ) | | (373,734 | ) |
| All Other | (342 | ) | | 778 |
| | (2 | ) |
| Corporate | (2,769 | ) | | (1,311 | ) | | (5,691 | ) |
| Total Consolidated | $ | 283,482 |
| | $ | (290,958 | ) | | $ | (379,427 | ) |
EXPLORATION AND PRODUCTION
Revenues
Exploration and Production Operating Revenues
| | | | Year Ended September 30 | | Year Ended September 30 |
| | 2017 | | 2016 | | 2015 | | 2022 | | 2021 | |
| | (Thousands) | | (Thousands) |
| Gas (after Hedging) | $ | 462,976 |
| | $ | 433,357 |
| | $ | 471,657 |
| Gas (after Hedging) | $ | 930,130 | | | $ | 705,326 | | |
| Oil (after Hedging) | 147,599 |
| | 169,263 |
| | 213,488 |
| |
| Oil (after Hedging)(1) | | Oil (after Hedging)(1) | 113,588 | | | 126,369 | | |
| Gas Processing Plant | 3,181 |
| | 2,411 |
| | 2,891 |
| Gas Processing Plant | 3,511 | | | 2,960 | | |
| Other | 843 |
| | 2,082 |
| | 5,405 |
| Other | (36,765) | | | 2,042 | | |
| Operating Revenues | $ | 614,599 |
| | $ | 607,113 |
| | $ | 693,441 |
| Operating Revenues | $ | 1,010,464 | | | $ | 836,697 | | |
Production
| | | | | | | | | | | | | |
| | Year Ended September 30 |
| | 2022 | | 2021 | | |
Gas Production (MMcf) | | | | | |
| Appalachia | 341,700 | | | 312,300 | | | |
| West Coast | 1,211 | | | 1,720 | | | |
| Total Production | 342,911 | | | 314,020 | | | |
Oil Production (Mbbl) | | | | | |
| Appalachia | 16 | | | 2 | | | |
| West Coast | 1,588 | | | 2,233 | | | |
| Total Production | 1,604 | | | 2,235 | | | |
|
| | | | | | | | |
| | Year Ended September 30 |
| | 2017 | | 2016 | | 2015 |
Gas Production (MMcf) | | | | | |
| Appalachia | 154,093 |
| | 140,457 |
| | 136,404 |
|
| West Coast | 2,995 |
| | 3,090 |
| | 3,159 |
|
| Total Production | 157,088 |
| | 143,547 |
| | 139,563 |
|
Oil Production (Mbbl) | | | | | |
| Appalachia | 4 |
| | 28 |
| | 30 |
|
| West Coast | 2,736 |
| | 2,895 |
| | 3,004 |
|
| Total Production | 2,740 |
| | 2,923 |
| | 3,034 |
|
Average Prices
|
| | | | | | | | | | | |
| | Year Ended September 30 |
| | 2017 | | 2016 | | 2015 |
| Average Gas Price/Mcf | | | | | |
| Appalachia | $ | 2.52 |
| | $ | 1.94 |
| | $ | 2.48 |
|
| West Coast | $ | 4.00 |
| | $ | 3.25 |
| | $ | 4.11 |
|
| Weighted Average | $ | 2.55 |
| | $ | 1.97 |
| | $ | 2.51 |
|
| Weighted Average After Hedging(1) | $ | 2.95 |
| | $ | 3.02 |
| | $ | 3.38 |
|
| Average Oil Price/Barrel (Bbl) | | | | | |
| Appalachia | $ | 48.27 |
| | $ | 52.15 |
| | $ | 57.44 |
|
| West Coast | $ | 46.14 |
| | $ | 35.26 |
| | $ | 51.37 |
|
| Weighted Average | $ | 46.18 |
| | $ | 35.42 |
| | $ | 51.43 |
|
| Weighted Average After Hedging(1) | $ | 53.87 |
| | $ | 57.91 |
| | $ | 70.36 |
|
| | | | | | | | | | | | | |
| | Year Ended September 30 |
| | 2022 | | 2021 | | |
| Average Gas Price/Mcf | | | | | |
| Appalachia | $ | 5.03 | | | $ | 2.46 | | | |
| West Coast | $ | 10.03 | | | $ | 6.34 | | | |
| Weighted Average | $ | 5.05 | | | $ | 2.49 | | | |
| Weighted Average After Hedging(2) | $ | 2.71 | | | $ | 2.25 | | | |
| Average Oil Price/Barrel (Bbl) | | | | | |
| Appalachia | $ | 97.82 | | | $ | 48.02 | | | |
| West Coast | $ | 94.06 | | | $ | 60.50 | | | |
| Weighted Average | $ | 94.10 | | | $ | 60.49 | | | |
| Weighted Average After Hedging(1)(2) | $ | 70.80 | | | $ | 56.54 | | | |
| |
(1) | Refer to further discussion of hedging activities below under “Market Risk Sensitive Instruments” and in Note G — Financial Instruments in Item 8 of this report. |
2017(1)Oil revenue and weighted average oil price after hedging for the year ended September 30, 2022 excludes a loss on discontinuance of crude oil cash flow hedges of $44.6 million. This loss is presented in other revenue in the table above.
(2)Refer to further discussion of hedging activities below under “Market Risk Sensitive Instruments” and in Note J — Financial Instruments in Item 8 of this report.
2022 Compared with 20162021
Operating revenues for the Exploration and Production segmentsegment increased $7.5$173.8 million in 2017in 2022 as compared with 2016.2021. Gas production revenue after hedging increased $29.6$224.8 million primarily due to a large increase in gas production partially offset by a $0.07$0.46 per Mcf decreaseincrease in the weighted average price of gas after hedging.hedging coupled with a 28.9 Bcf increase in gas production. The increase in gas production was largely due to new Marcellus and Utica wells in the Appalachian region. Oil production revenue after hedging decreased $12.8 million primarily due to a significant decrease in price-related curtailments during fiscal 2017 compared to fiscal 2016. This was partially offset by the impact of a joint development agreement with IOG - CRV Marcellus, LLC (IOG) (lower net revenue interest in producing wells), production declines on wells in the Eastern Development Area (Tioga and Lycoming counties in Pennsylvania) and the expected impact of changing from a 3-drilling rig program to a 1-drilling rig program. For further discussion of the joint development agreement with IOG, refer to Item 8 at Note A - Summary of Significant Accounting Policies under the heading "Property, Plant and Equipment." In addition, gas processing plant revenue increased $0.8 million due to an increase in price and volumes. These increases to operating revenues were partially offset by a decrease in oil production revenue after hedging of $21.7 million due to a631 Mbbl decrease in crude oil production, coupled withpartially offset by a $4.04$14.26 per Bbl decreaseincrease in the weighted average price of oil after hedging. The decrease in crude oil production was largely dueis mainly attributed to the current year impactsale of decreased steam operations and well workover activityCalifornia assets at its North Midway Sunset field in prior years (due to lower crude oil prices).June 30, 2022. In addition, other revenue decreased $1.2$38.8 million largely dueand plant revenue increased $0.6 million. The decrease in other revenue was primarily attributed to a loss on the discontinuance of crude oil cash flow hedges related to the impactsale of mark-to-market adjustments related to hedging ineffectiveness.California assets combined with royalty shut-in payments made in accordance with lease agreements. These were partially offset by a temporary capacity release of Leidy South and TC Pipeline transportation contracts. Finally, other revenue also increased from Highland Field Services water treatment plants acquired at the end of fiscal 2021.
Refer to further discussion of derivative financial instruments in the “Market Risk Sensitive Instruments” section that follows. Refer to the tables above for production and price information.
2016Earnings
2022 Compared with 20152021
Operating revenues for the Exploration and Production segment decreased $86.3 million in 2016 as compared with 2015. Gas production revenue after hedging decreased $38.3 million primarily due to a $0.36 per Mcf decrease in the weighted average price of gas after hedging partially offset by an increase in gas production. Oil production revenue after hedging decreased $44.2 million due to a $12.45 per Bbl decrease in the weighted average price of oil after hedging coupled with a decrease in crude oil production. In addition, other revenue decreased $3.3 million primarily due to the positive impact of mark-to-market adjustments related to hedging ineffectiveness that occurred during the year ended September 30, 2015, which did not recur during the year ended September 30, 2016.
Earnings
2017 Compared with 2016
The Exploration and Production segment’s earnings for 20172022 were $129.3$306.1 million, an increase of $582.1$204.2 million when compared with a lossearnings of $452.8$101.9 million for 2016.2021. The increase in earnings was primarily reflects the non-recurrence of the aforementioned impairment chargesattributable to higher natural gas prices after hedging ($550.0126.3 million). It also reflects, higher natural gas production ($26.651.3 million), and higher oil prices after hedging ($18.1 million). Additionally, a $55.2 million impairment was recorded during 2021 that did not recur during 2022. Certain deferred tax adjustments during 2022 also contributed to the earnings increase. The Exploration and Production segment reversed a valuation allowance ($28.6 million) on deferred tax assets related to certain state net operating loss and credit carryforwards as these deferred tax assets are now expected to be realized in the future. The Exploration and Production segment also recorded an income tax benefit ($16.2 million) from the remeasurement of deferred income taxes related to a state corporate income tax rate reduction in Pennsylvania that was signed into law in July 2022. The law
reduces the Pennsylvania corporate income tax rate to 8.99% for fiscal 2024, and starting with fiscal 2025, the rate is further reduced by 0.5% annually until it reaches 4.99% for fiscal 2032.
In addition to the factors discussed above, the Exploration and Production segment's earnings were also impacted by the following factors. Factors that increased earnings included a 2022 gain ($9.5 million) that was recognized on the sale of the Exploration and Production segment's California non-full cost pool assets as well as a 2021 loss ($10.7 million) recognized for this segment's share of the premium paid by the Company to redeem $500 million of the Company's 4.90% notes that were scheduled to mature in December 2021. Factors that reduced earnings included a loss related to the discontinuance of this segment's crude oil cash flow hedges ($33.3 million), which was driven by the sale of the California assets, lower crude oil production ($28.2 million), higher lease operating and transportation expenses ($13.1 million), higher depletion expense ($17.820.3 million), lowerhigher other operating expenses ($2.25.4 million), lower interest expensean unrealized loss on a derivative asset ($1.13.2 million), the non-recurrence of joint development agreement professional feeshigher other taxes ($4.62.5 million) and lower incomea higher effective tax expenserate ($10.66.3 million). The decrease in depletion expense was primarily due to a lower level of capitalizedCompany also recorded transaction and severance costs as a result($7.2 million) during 2022 associated with the sale of the impairment charges recognizedCalifornia assets. The increase in fiscal 2015lease operating and fiscal 2016. The decrease in other operatingtransportation expenses was primarily due to a decrease in personnelincreased gathering and transportation costs coupled with a decrease in plugging and abandonment expense (as a result of the sale of Upper Devonian wells in Pennsylvania in June 2016), which was partially offset by a contract suspension payment to TransCanada related to transportation services for Northern Access 2016 project. The decrease in interest expense was largely due to a decrease in the Exploration and Production segment’s intercompany short-term borrowings. The decrease in income tax expense was largely due to an increase in anticipated firm transportation of natural gas to delivery points outside of Pennsylvania as a result of forecasted deliveries to the Atlantic Sunrise Pipeline. This had the effect of decreasing the effective tax rate used in the calculation of deferred tax expense. Income tax expense also decreased due to an enhanced oil recovery tax credit related to Seneca's California properties, which was applicable this year as a result of relatively low domestic crude oil prices. The joint development agreement professional fees incurred were related to professional services associated with the Marcellus Shale drilling joint development agreement with IOG executed in December 2015 and extended in June 2016. These fees did not recur during fiscal 2017. These factors, which contributed to increased earnings during fiscal 2017 compared to fiscal 2016, were partiallyAppalachian region offset by lower crude oil prices after hedging ($7.2 million), lower natural gas prices after hedging ($7.3 million), lower crude oil production ($6.9 million), higher production costs ($7.9 million) and higher other taxes ($1.1 million). The increase in production costs was largely due to an increase in transportation costs associated with higher gas production volume (mostly transported by Midstream Corporation) coupled with increased well repairs, equipment rentals, contract labor and steam fuel costs in the West Coast region, which will support production in future years. These were partially offset by lower repair and maintenance costs associated with operating wells in Appalachia (impacted by the sale of Upper Devonian related wells in June 2016). The increase in other taxes was largely due to higher impact fees related to Appalachian production in fiscal 2017 compared to fiscal 2016. Impact fees were significantly lower in fiscal 2016 as a result of IOG's reimbursement of such costs for years prior to fiscal 2016. The increase in other taxes also reflects an increase in Appalachian franchise taxes, partially offset by a decrease in Kern, Ventura and Coalinga County taxes in the West Coast region due to lower crude oil prices.
2016 Compared with 2015
selling the assets on June 30, 2022. The Exploration and Production segment’s loss for 2016 was $452.8 million, compared with a loss of $557.0 million for 2015. The reduction in loss was attributed to lower impairment charges ($100.1 million), lower depletion expense ($64.9 million), higher natural gas production ($8.8 million), lower production costs ($9.0 million), lower income tax ($3.2 million), lower other taxes ($4.1 million) and lower other operating expenses ($3.3 million). The decreaseincrease in depletion expense was primarily due to the impact of impairment charges recognized in fiscal 2015 and fiscal 2016. The decreaseincrease in production, costs was largely due tocombined with a decrease in well repair costs and a decrease in steam fuel costs associated with crude oil production$0.03 per Mcfe increase in the West Coast region (due to lower fuel prices) coupled with a decrease in seasonal road maintenance (due to a milder winter) and decreases in equipment repair and rental costs, salt water disposal costs, and compressor and pumper costs in the Appalachian region.depletion rate. The decrease in income tax expense was primarily due to a solar tax credit received coupled with favorable benefits associated with the tax sharing agreement with affiliated companies. The decrease in other taxes was largely due to IOG being billed for its share of previously incurred impact fees in accordance with the joint development agreement executed in December 2015, coupled with a decrease in Kern and Ventura County taxes (due to a decrease in crude oil prices). The decreaseincrease in other operating expenses was primarily dueattributed to a decrease in emissions expense and personnelabandonment costs partially offset by higher stock-based compensation expense. These factors, which contributedrelated to lesscertain offshore Gulf of a loss in 2016 compared to 2015, were partially offsetMexico wells formally owned by the impact of joint development agreement professional fees ($4.6 million), lower crude oil prices after hedging ($23.6 million), lower natural gas
prices after hedging ($33.6 million), lower crude oil production ($5.1 million),Company. In addition, the impact of mark-to-market adjustments discussed above ($2.1 million), lower interest income ($1.1 million) and higher interest expense ($5.7 million). The joint development agreement professional fees incurred were relatedincrease in other operating expenses was attributed to professional servicesoperating costs associated with the Marcellus Shale drilling joint development agreement with IOG that was executed in December 2015 and extended in June 2016.Highland Field Services water treatment plants acquired at the end of fiscal 2021. The unrealized loss on a derivative asset represents an adjustment to the contingent consideration received for the sale of the California assets. The increase in interest expenseother taxes was largely duemainly attributed to the Exploration and Production segment's share of the Company's $450 million long-term debt issuance in June 2015. From an income tax perspective, there were favorable adjustments to Seneca’s deferred income tax liabilityincreased Impact Fees in the amount of $13.2 million in 2015 that did not recur in 2016. The deferred tax adjustments in 2015 were largely theAppalachian region as a result of an increase in firm transportation of natural gas to Canadian delivery points (with a corresponding decreaseprices. The Impact Fees are calculated annually based on calendar year NYMEX natural gas prices. The increase in the effective tax rate) and other adjustments.rate was primarily driven by a reduction to the valuation allowance recorded in fiscal 2021.
PIPELINE AND STORAGE
Revenues
Pipeline and Storage Operating Revenues
| | | | Year Ended September 30 | | Year Ended September 30 |
| | 2017 | | 2016 | | 2015 | | 2022 | | 2021 | |
| | (Thousands) | | (Thousands) |
| Firm Transportation | $ | 221,609 |
| | $ | 229,895 |
| | $ | 214,611 |
| Firm Transportation | $ | 287,486 | | | $ | 254,853 | | |
| Interruptible Transportation | 1,690 |
| | 3,995 |
| | 2,971 |
| Interruptible Transportation | 2,481 | | | 996 | | |
| | 223,299 |
| | 233,890 |
| | 217,582 |
| | 289,967 | | | 255,849 | | |
| Firm Storage Service | 69,963 |
| | 70,351 |
| | 70,732 |
| Firm Storage Service | 84,565 | | | 83,032 | | |
| Interruptible Storage Service | 19 |
| | 143 |
| | 3 |
| Interruptible Storage Service | — | | | 48 | | |
| | 69,982 |
| | 70,494 |
| | 70,735 |
| | 84,565 | | | 83,080 | | |
| Other | 1,144 |
| | 2,045 |
| | 3,023 |
| Other | 2,512 | | | 4,628 | | |
| | $ | 294,425 |
| | $ | 306,429 |
| | $ | 291,340 |
| | $ | 377,044 | | | $ | 343,557 | | |
Pipeline and Storage Throughput — (MMcf)
| | | | | | | | | | | | | |
| | Year Ended September 30 |
| | 2022 | | 2021 | | |
| Firm Transportation | 790,417 | | | 770,284 | | | |
| Interruptible Transportation | 5,612 | | | 1,460 | | | |
| 796,029 | | | 771,744 | | | |
|
| | | | | | | | |
| | Year Ended September 30 |
| | 2017 | | 2016 | | 2015 |
| Firm Transportation | 779,382 |
| | 740,875 |
| | 737,206 |
|
| Interruptible Transportation | 5,805 |
| | 23,548 |
| | 12,874 |
|
| | 785,187 |
| | 764,423 |
| | 750,080 |
|
20172022 Compared with 20162021
Operating revenues for the Pipeline and Storage segment decreased $12.0increased $33.5 million in 20172022 as compared with 2016.2021. The decreaseincrease in operating revenues was primarily due to a decreasean increase in transportation revenues of $10.6$34.1 million and an increase in storage revenues of $1.5 million, partially offset by a decrease in other revenue of $2.1 million. The declineincrease in transportation revenues was due partiallyprimarily attributable to a 2% reduction in Supply Corporation's rates effective November 1, 2015 and an additional 2% reduction in Supply Corporation's rates effective November 1, 2016, both of which were required by the rate case settlement approved by FERC on November 13, 2015. The decrease also reflects reductions in Empire's rates effective July 1, 2016 as required by the rate case settlement approved by FERC on December 13, 2016 combined with a decline innew demand charges for transportation services as a result of contract terminations and contract restructuring, as well as lower demand for short-term interruptible transportation service. Partially offsetting these decreases, transportation revenues benefited from a full year of revenueservice from Supply Corporation's Northern Access 2015 project, which was placed in service on an interim basis in November 2015 and became fully operational in December 2015, and transportation revenues also benefited from a full year of revenue from Empire's Tuscarora LateralFM100 Project, which was placed ininto service in December 2021. The increase from the FM100 Project includes the impact of a negotiated revenue step-up to Period 2 Rates that went into effect April 1, 2022, as specified in Supply Corporation's 2020 rate case settlement. This increase was partially offset by a decline in revenues associated with miscellaneous contract terminations and revisions. The increase in storage revenues was partially due to the Period 2 Rates that went into effect April 1, 2022 related to the FM100 Project, as discussed above. In addition, the Pipeline Safety and Greenhouse Gas Regulatory Costs (PS/GHG Regulatory Costs) surcharge that went into effect in November 2015.2020 associated with Supply Corporation's 2020 rate case settlement also contributed to the increase in both transportation and storage revenues. The decrease in other revenue primarily reflects the non-recurrence of revenue associated with a contract buyout that occurred during the quarter ended December 31, 2020, combined with lower electric surcharge true-up revenues, partially offset by higher cashout revenues. Revenues collected through the electric surcharge mechanism are completely offset by electric power costs recorded in operation and maintenance expense. Cashout revenues are completely offset by purchased gas expense.
Transportation volume increased by 20.824.3 Bcf in 20172022 as compared with 2016. The2021, primarily due to incremental volume from the FM100 Project, which was brought online in December 2021, as well as an increase in transportation volume primarily reflects the impact of a full year of transportation service from the Northern Access 2015 project
and the Tuscarora Lateral Project, both of which are discussed in the previous paragraph.short-term contracts. These were partially offset by lower capacity utilization with certain contract shippers. Volume fluctuations, other than those caused by the addition or deletiontermination 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.
2016 Compared with 2015
Operating revenuesThe majority of Supply Corporation's and Empire's transportation and storage contracts allow either party to terminate the contract upon six or twelve months' notice effective at the end of the primary term and include "evergreen" language that allows for annual term extension(s). The amount of firm transportation capacity contracted on the Pipeline and Storage segment increased $15.1 millionsegment's facilities is expected to decrease in 2016 as compared with 2015. The increase wasfiscal 2023, primarily due to an increase in transportation revenuesthe termination of $16.3 million.two long-term contracts with a nonaffiliated party totaling 300 MDth per day. Lower contracted quantities at the time of a future rate proceeding would be taken into account and would be the basis for setting new rates. The increase in transportation revenues was largely due to demand charges for transportation service from Supply Corporation’s Westside Expansion and Modernization Project andtiming of Supply Corporation's Northern Access 2015 project, which were both fully placed in service during the first quarter of fiscal 2016, and Empire's Tuscarora Lateral Project, which was placed in service in November 2015. The increase in transportation revenues was partially offset by a decrease in short-term seasonal contracts for both Empire and Supply Corporation. Operating revenues were also impacted by a 2% reduction in Supply Corporation's rates effective November 1, 2015 as required by thenext rate case settlement mentioned above.
Transportation volume increased by 14.3 Bcf in 2016 as compared with 2015. The increase in transportation volume primarily reflected the impact of the above mentioned expansion projects being placed in service.filing is discussed below under Rate Matters.
Earnings
20172022 Compared with 20162021
The Pipeline and Storage segment’s earnings in 20172022 were $68.4$102.6 million, a decreasean increase of $8.2$10.1 million when compared with earnings of $76.6$92.5 million in 2016.2021. The decreaseincrease in earnings was primarily due to the earnings impact of lower transportationhigher operating revenues of $6.9$26.5 million, as discussed above, combined with higher operating expenses ($4.4 million), an increase in property taxes ($0.8 million) and a decrease in the allowance for funds used during construction (equity component) of $0.5 million. The increase in operating expenses primarily reflects an increase in compressor station costs due primarily to costs associated with the overhaul of two compressor stations, higher pension and other post-retirement benefit costs and increased personnel costs. The decrease in allowance for funds used during construction reflects the completion of Supply Corporation’s Westside Expansion and Modernization Project, Supply Corporation's Northern Access 2015 project and Empire's Tuscarora Lateral Project in the first quarter of fiscal 2016. These earnings decreases werewhich was partially offset by a decrease in depreciation expense ($1.4 million) and lower income tax expense ($3.2 million). The decrease in depreciation expense was attributable to a decrease in Empire's depreciation rates effective July 1, 2016 associated with Empire's rate case settlement offset partially by the incremental depreciation expense related to expansion projects that were placed in service within the last year. Income tax expense was lower due to provision-to-return adjustments combined with lower state taxes, an increase in benefits associated with the tax sharing agreement with affiliated companies and the adoption of the new accounting guidance regarding stock-based compensation.
2016 Compared with 2015
The Pipeline and Storage segment’s earnings in 2016 were $76.6 million, a decrease of $3.8 million when compared with earnings of $80.4 million in 2015. The decrease in earnings was primarily due to higher operating expenses ($2.4 million), an increase in depreciation expense ($3.34.2 million), higher property taxes ($0.8 million), an increase in property taxesoperating expenses ($0.97.6 million), and higher interestincome tax expense ($3.72.3 million), higher income taxes ($2.7 million) and a decrease in the allowance for funds used during construction (equity component) of $0.9 million. The increase in operating expenses primarily reflected higher pension and other post-retirement benefit costs, higher pipeline integrity program expenses, higher compressor station expenses and higher stock-based compensation expense.. The increase in depreciation expense was attributableprimarily due to projects that were placedincremental depreciation from the FM100 Project going into service in service during fiscal 2016.December 2021. The increase in property taxes was attributableprimarily due to various expansion projects constructed over the last few years.first-time assessment of property taxes for the Empire North project's Farmington compressor station. The increase in interest expenseoperating expenses was largelyprimarily due to Supply Corporation's sharea decrease in the reserve for preliminary project costs recorded during fiscal 2021 that did not recur in fiscal 2022, as well as an increase in personnel and technology-related costs and higher vehicle fuel costs. This was partially offset by lower power costs related to Empire's electric motor drive compressor station. The Pipeline and Storage segment also experienced higher purchased gas costs ($0.7 million), largely related to Empire's natural gas-driven compressor stations. The electric power costs and purchased gas costs are offset by an equal amount of the Company's $450 million long-term debt issuance in June 2015.revenue, as discussed above. The increase in income taxestax expense was a result ofmainly due to a reduction in benefits associated with the tax sharing agreement with affiliated companies combined with Empire's provision-to-return adjustments. The decrease in allowance for funds used during construction was mainlyhigher state income tax expense due to the above mentioned expansion projects being placed in service in thehigher pre-tax earnings for fiscal 2022.
first quarter of fiscal 2016. The factors contributing to the earnings decrease were partially offset by the positive earnings impact of higher transportation revenues ($10.6 million), as discussed above.
GATHERING
Revenues
Gathering Operating Revenues
| | | | | | | | | | | | | |
| | Year Ended September 30 |
| | 2022 | | 2021 | | |
| | (Thousands) |
| Gathering | $ | 214,843 | | | $ | 193,264 | | | |
| | | | | |
| | | | | |
|
| | | | | | | | | | | |
| | Year Ended September 30 |
| | 2017 | | 2016 | | 2015 |
| | (Thousands) |
| Gathering | $ | 107,566 |
| | $ | 89,073 |
| | $ | 76,709 |
|
| Processing and Other Revenues | 115 |
| | 374 |
| | 497 |
|
| | $ | 107,681 |
| | $ | 89,447 |
| | $ | 77,206 |
|
Gathering Volume — (MMcf)
| | | | | | | | | | | | | |
| | Year Ended September 30 |
| | 2022 | | 2021 | | |
| Gathered Volume | 419,332 | | | 366,033 | | | |
|
| | | | | | | | |
| | Year Ended September 30 |
| | 2017 | | 2016 | | 2015 |
| Gathered Volume | 194,921 |
| | 161,955 |
| | 139,629 |
|
20172022 Compared with 20162021
Operating revenues for the Gathering segment increased $18.2$21.6 million in 20172022 as compared with 2016. This increase2021, which was due to an increase in gathering revenues driven primarily by a 33.053.3 Bcf increase in gathered volume. The overall increase in gathered volume was duecan be attributed primarily to a 22.5an increase in natural gas production on the Covington, Wellsboro, Clermont and Trout Run gathering systems, which recorded increases of 17.9 Bcf, 11.7 Bcf, 10.1 Bcf and 13.6 Bcf, respectively. The increase in gathered volume on Midstream Corporation’s Clermontcan be attributed to the increase in gross natural gas production in the Appalachian region by producers connected to the aforementioned gathering systems.
Earnings
2022 Compared with 2021
The Gathering System (Clermont), a 4.7 Bcfsegment’s earnings in 2022 were $101.1 million, an increase of $20.8 million when compared with earnings of $80.3 million in 2021. The increase in earnings was primarily attributable to higher gathering revenues ($17.0 million) driven by the increase in gathered volume on Midstream Corporation's Wellsboro Gathering System (Wellsboro), a 3.0 Bcf increase in gathered volume on Midstream Corporation's Trout Run Gathering System (Trout Run) and a 2.9 Bcf increase in gathered volume on Midstream Corporation's Covington Gathering System (Covington)(discussed above). The increases in the aforementioned volumes were largely due to increases in Seneca's Marcellus Shale production due to a significant decrease in price-related curtailments during fiscal 2017 compared to fiscal 2016.
2016 Compared with 2015
Operating revenues forAdditionally, the Gathering segment increased $12.2 million in 2016 as compared with 2015. This increase was due torecorded an increase in gathering revenues driven by a 22.3 Bcf increase in gathered volume. The overall increase in gathered volume was largely dueincome tax benefit ($11.9 million) from the remeasurement of deferred income taxes related to a 47.0 Bcf increasestate corporate income tax rate reduction in gathered volume on Clermont, largely attributable toPennsylvania that was signed into law in July 2022 (as discussed above, in the connection of additional wells to the gathering systemExploration and Production segment). Earnings also increased as a result of the completionGathering segment's recognition of a loss during the quarter end March 31, 2021 ($0.7 million) for its share of the Northern Access 2015 projectpremium paid by the Company to redeem $500 million of the Company's 4.90% notes that were scheduled to mature in November and December 2015. This increase in gathered volume was partially2021. However, the Gathering segment's earnings were negatively impacted by the recording of deferred income tax expense ($3.7 million) as an offset by a 21.8 Bcf decrease in gathered volume on Trout Run and a 3.1 Bcf decrease in gathered volume on Covington. These decreases were largely due to price-related curtailments of Seneca's Marcellus Shale production.
Earnings
2017 Compared with 2016
The Gathering segment’s earnings in 2017 were $40.4 million, an increase of $9.9 million when compared with earnings of $30.5 million in 2016. The increase in earnings was mainly due to an increase in gathering revenues ($12.0 million). The increase in gathering revenues was due to the increases in gathered volume discussed above. These were partiallyreversal of the valuation allowance recorded by the Exploration and Production segment during the quarter ended September 30, 2022. This offset byis a result of the Gathering and Exploration and Production segments' subsidiaries filing a combined state tax return. Earnings also decreased due to higher operating expenses ($1.83.2 million), higher depreciation expense ($1.3 million) and higher depreciationincome tax expense ($0.6 million). The increase in operating expenses werewas largely due to the ramp up inhigher costs for labor, major overhaul maintenance of compressor units at Trout Run gathering operations as a result of increases in Seneca's Marcellus Shale production. An increase in gas plant balances (mostly in Clermont), led to an increase in depreciation expense.
2016 Compared with 2015
The Gathering segment’s earnings in 2016 were $30.5 million, a decrease of $1.3 million when compared with earnings of $31.8 million in 2015. While gathering revenues increased $8.0 million, as discussed above, the increase in revenues was more than offset by higher interest expense ($4.7 million), higher depreciation expense ($2.9 million)system compressor stations during fiscal 2022 and higher operating expenses ($1.6 million).costs for material used to operate the compressor stations at the Trout Run, Covington and Clermont gathering systems. The increase in interestdepreciation expense was largely due to the Gathering segment's share of the Company's $450 million long-term debt issuance in June 2015 coupled with a decrease in capitalized interest, which was due to various Clermont projects being placed in service. A large increase inhigher plant balances (largely due to variousassociated with the Clermont projects being placed in service), partially offset by the non-recurrence of long-lived asset impairment charges recorded in March 2015 related to theand Covington gathering facilities at Tionesta, led to an overall increase in depreciation expense.systems. The increase in operating expensesincome tax expense was largely due to the significant growth of Clermont and its impact on maintenance expense.primarily driven by a higher effective state income tax rate.
UTILITY
Revenues
Utility Operating Revenues | | | | Year Ended September 30 | | Year Ended September 30 |
| | 2017 | | 2016 | | 2015 | | 2022 | | 2021 | |
| | (Thousands) | | (Thousands) |
| Retail Revenues: | | | | | | Retail Revenues: | | |
| Residential | $ | 435,357 |
| | $ | 360,648 |
| | $ | 480,163 |
| Residential | $ | 691,034 | | | $ | 497,244 | | |
| Commercial | 58,988 |
| | 44,994 |
| | 61,099 |
| Commercial | 95,120 | | | 63,954 | | |
| Industrial | 2,376 |
| | 1,785 |
| | 2,655 |
| Industrial | 4,913 | | | 3,089 | | |
| | 496,721 |
| | 407,427 |
| | 543,917 |
| | 791,067 | | | 564,287 | | |
| Off-System Sales | 3,997 |
| | 1,877 |
| | 11,773 |
| |
| | Transportation | 129,509 |
| | 124,120 |
| | 142,289 |
| Transportation | 111,072 | | | 108,213 | | |
| Other | 9,744 |
| | 10,723 |
| | 18,288 |
| Other | (3,918) | | | (5,249) | | |
| | $ | 639,971 |
| | $ | 544,147 |
| | $ | 716,267 |
| | $ | 898,221 | | | $ | 667,251 | | |
Utility Throughput — million cubic feet (MMcf)
| | | | Year Ended September 30 | | Year Ended September 30 |
| | 2017 | | 2016 | | 2015 | | 2022 | | 2021 | |
| Retail Sales: | | | | | | Retail Sales: | | | | |
| Residential | 52,394 |
| | 49,971 |
| | 59,600 |
| Residential | 64,011 | | | 61,038 | | |
| Commercial | 7,927 |
| | 7,247 |
| | 8,710 |
| Commercial | 9,621 | | | 8,741 | | |
| Industrial | 333 |
| | 244 |
| | 337 |
| Industrial | 541 | | | 475 | | |
| | 60,654 |
| | 57,462 |
| | 68,647 |
| | 74,173 | | | 70,254 | | |
| Off-System Sales | 1,301 |
| | 1,243 |
| | 3,787 |
| |
| | Transportation | 71,040 |
| | 70,847 |
| | 78,749 |
| Transportation | 65,993 | | | 66,012 | | |
| | 132,995 |
| | 129,552 |
| | 151,183 |
| | 140,166 | | | 136,266 | | |
Degree Days
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | Percent (Warmer)
Colder Than |
| Year Ended September 30 | | | Normal | | Actual | | Normal(1) | | Prior Year(1) |
| 2022 | Buffalo, NY | | 6,617 | | | 5,769 | | | (12.8) | % | | 0.7 | % |
| Erie, PA | | 6,147 | | | 5,368 | | | (12.7) | % | | 2.8 | % |
| 2021 | Buffalo, NY | | 6,617 | | | 5,731 | | | (13.4) | % | | (6.1) | % |
| Erie, PA | | 6,147 | | | 5,221 | | | (15.1) | % | | (4.2) | % |
| | | | | | | | | |
| | | | | | | | | |
|
| | | | | | | | | | | | | |
| | | | | | | | Percent (Warmer) Colder Than |
| Year Ended September 30 | | | Normal | | Actual | | Normal(1) | | Prior Year(1) |
| 2017 | Buffalo | | 6,617 |
| | 5,708 |
| | (13.7 | )% | | 1.7 | % |
| | Erie | | 6,147 |
| | 5,179 |
| | (15.7 | )% | | (0.1 | )% |
| 2016 | Buffalo | | 6,653 |
| (2) | 5,611 |
| | (15.7 | )% | | (19.5 | )% |
| | Erie | | 6,181 |
| (2) | 5,182 |
| | (16.2 | )% | | (21.3 | )% |
| 2015 | Buffalo | | 6,617 |
| | 6,968 |
| | 5.3 | % | | (1.7 | )% |
| | Erie | | 6,147 |
| | 6,586 |
| | 7.1 | % | | (2.3 | )% |
| |
(1) | Percents compare actual degree days to normal degree days and actual degree days to actual prior year degree days. |
| |
(2) | Normal degree day estimates changed to 6,653 for Buffalo and 6,181 for Erie as a result of updated information from the National Oceanic and Atmospheric Administration. In addition, normal degree days for 2016 reflect the fact that 2016 was a leap year. |
2017(1)Percents compare actual degree days to normal degree days and actual degree days to actual prior year degree days.
2022 Compared with 20162021
Operating revenues for the Utility segment increased $95.8$231.0 million in 20172022 compared with 2016.2021. The increase largely resulted from an $89.3a $226.8 million increase in retail gas sales revenues. In addition, thererevenues, which was primarily due to a $5.4 million increase in transportation revenues, and a $2.1 million increase in off-system sales (due to higher sales prices coupled with slightly higher volumes). The increase in retail gas sales revenues was largely a result of ansignificant increase in the cost of gas sold (per Mcf) coupled with an. In addition, there was a $2.9 million increase in volumes due to higher usage.transportation revenues and a $1.3 million increase in other revenues. The increase in transportation revenues, despite a small decrease in throughput, was largely due to thean increase in the price paid by marketers to cash-out their imbalancesmarketer sales cashouts and an increase in those imbalances owedthe system modernization tracker allocation to transportation customers, which was partially offset by the migration of residential transportation customers previously served by marketers to retail service provided by the Utility segment as transportation throughput was relatively flat. Due to profit sharing with retail customers, the margins related to off-system sales are minimal.
2016 Compared with 2015
Operating revenues for the Utility segment decreased $172.1 millionsegment. The increase in 2016 compared with 2015. This decrease largely resulted from a $136.5 million decrease in retail gas sales revenues. In addition, there was a $9.9 million decrease in off-system sales, an $18.2 million decrease in transportation revenues, and a $7.5 million decrease in other revenues. The decrease in retail gas sales revenue was largely a result of a decrease in the cost of gas sold (per Mcf) coupled with lower volumes due to warmer weather. The $18.2 million decrease in transportation revenues was primarily due to a 7.9 Bcf decrease in transportation throughput duehigher capacity release revenues and higher late payment charges billed to warmer weather experienced during the fiscal 2016 winter relative to the fiscal 2015 winter. The decrease in off-system sales was due to market conditions that have continued to reduce the volumes and the price at which off-system gas could be sold. Due to profit sharing with retail customers, the margins resulting from off-system sales are minimal. The decrease in other revenues was largely due to the non-recurrence of a regulatory adjustment recorded during fiscal 2015 to recognize an under collection of a New York State regulatory assessment from customers. In addition, a reversal of an accrual for an estimated sharing refund provision in New York did not recur in 2016.
Purchased Gas
The cost of purchased gas is one of the Company’s single largest operating expense.expenses. Annual variations in purchased gas costs are attributed directly to changes in gas sales volume, the price of gas purchased and the operation of purchased gas adjustment clauses. Distribution Corporation recorded $252.8 million, $166.2$498.0 million and $307.7$274.8 million of Purchased Gas expense during 2017, 20162022 and 2015,2021, respectively. Under its purchased gas adjustment clauses in New York and Pennsylvania, Distribution Corporation is not allowed to profit from fluctuations in gas costs. Purchased gasGas expense recorded on the consolidated income statement matches the revenues collected from customers, a component of Operating Revenues on the consolidated income statement. Under mechanisms approved by the NYPSC in New York and the PaPUC in Pennsylvania, any difference between
actual purchased gas costs and what has been collected from the customer is deferred on the consolidated balance sheet as either an asset, Unrecovered Purchased Gas Costs, or a liability, Amounts Payable to Customers. These deferrals are subsequently collected from the customer or passed back to the customer, subject to review by the NYPSC and the PaPUC. Absent disallowance of full recovery of Distribution Corporation’s purchased gas costs, such costs do not impact the profitability of the Company. Purchased gas costs impact cash flow from operations due to the timing of recovery of such costs versus the actual purchased gas costs incurred during a particular period. Distribution Corporation’s purchased gas adjustment clauses seek to mitigate this impact by adjusting revenues on either a quarterly or monthly basis.
Distribution Corporation contracts for firm long-term transportation and storage capacity with rights-of-first-refusal from nineten upstream pipeline companies including Supply Corporation for transportation and storage and Empire Pipeline, Inc. for transportation. Distribution Corporation contracts for firm gas supplies on term and spot bases with various producers, marketers and onetwo local distribution companycompanies to meet its gas purchase requirements. Additional discussion of the Utility segment’s gas purchases appears under the heading “Sources and Availability of Raw Materials” in Item 1.
Earnings
20172022 Compared with 20162021
The Utility segment’s earnings in 20172022 were $46.9$68.9 million, a decreasean increase of $4.1$14.6 million when compared with earnings of $51.0$54.3 million in 2016.2021. The increase was primarily attributable to the conclusion of a regulatory proceeding by the PaPUC in February 2022, which resulted in the reduction of an OPEB-related regulatory liability that increased earnings ($14.6 million). While the regulatory proceeding reduced base rates in Pennsylvania by $5.6 million, this impact was more than offset by a decrease in non-service post-retirement benefit costs ($11.5 million) as Distribution Corporation's Pennsylvania service territory recognized OPEB income during fiscal 2022, compared to the prior year when it recognized OPEB expenses to match against the OPEB amounts collected in base rates. Additional details related to the regulatory proceeding are discussed in Note F — Regulatory Matters.
Other factors contributing to the increase in earnings included the positive earnings impact of a system modernization tracker in New York ($3.6 million), which is a rate mechanism that provides recovery of qualified leak prone pipe replacement costs, higher usage and the impact of weather on customer margins ($2.9 million), and a decrease in income tax expense ($0.6 million). These increases were partially offset by higher operating expenses ($9.5 million), which were primarily the result of higher personnel costs, transportation fuel costs, and outside services partially offset by a decrease in the provision for uncollectible accounts. The decrease in the provision for uncollectible accounts reflects the recording of incremental expense in 2021 due to the potential for future customer non-payment as a result of the COVID-19 pandemic. In addition, earnings were negatively impacted by higher interest expense ($2.0 million), which was largely attributable tothe result of a higher operating expenses of $3.3 million (primarily due to higher personnel costs including the impact of post-implementation costs related to the replacement of the Utility segment’s legacy mainframe system),weighted average interest rate on intercompany short-term borrowings, and higher depreciation expense of $2.6 million (largely($1.8 million), primarily due to higher plant balances including the impact of the legacy mainframe system replacement), a decrease in the allowance for funds used during construction (equity component) of $0.9 million (due to the May 2016 completion of the Utility segment’s legacy mainframe system), higher income tax expense of $0.9 million (largely due to the aforementioned reduction in the allowance for funds used during construction in the current year which is non-taxable), lower interest income of $0.6 million (due to a lower balance in a regulatory asset and its impact on accrued income) and higher interest expense of $0.6 million (largely due to the impact of a regulatory adjustment coupled with a reduction in the allowance for borrowed funds used during construction due to the May 2016 completion of the Utility segment’s legacy mainframe system). These were partially offset by the positive earnings impact associated with higher usage ($2.5 million) and the impact of regulatory adjustments ($1.9 million, including the $1.5 million margin impact related to the new rate order issued by the NYPSC effective April 1, 2017). Usage refers to consumption after factoring out any impact that weather may have had on consumption.balances.
The impact of weather variations on earnings in the Utility segment’ssegment's New York rate jurisdiction is largely mitigated by that jurisdiction’sjurisdiction's weather normalization clause (WNC). The WNC in New York, which covers the eight-month period from October through May, has had a stabilizing effect on earnings for the New York rate jurisdiction. In addition, in periods of colder than normal weather, the WNC benefits the Utility segment’ssegment's New York customers. For 2017,2022, the WNC increasedcontributed approximately $4.8 million to earnings, by approximately $4.3 million as the weather was
warmer than normal. In 2016,2021, the WNC increasedcontributed approximately $4.5 million to earnings, by approximately $4.4 million as the weather was warmer than normal.
2016 Compared with 2015
The Utility segment’s earnings in 2016 were $51.0 million, a decrease of $12.3 million when compared with earnings of $63.3 million in 2015. The decrease in earnings was largely attributable to the impact of warmer weather in fiscal 2016 compared to fiscal 2015 ($12.5 million), a $2.0 million increase in depreciation expense (largely due to higher plant balances) and $3.4 million of regulatory adjustments, as discussed above. The negative earnings impact associated with these factors was partially offset by the positive earnings impact associated with a decrease in operating expenses of $5.6 million (primarily due to a reduction in personnel costs partially offset by higher stock-based compensation expense).
ENERGY MARKETING
Revenues
Energy Marketing Operating Revenues
|
| | | | | | | | | | | |
| | Year Ended September 30 |
| | 2017 | | 2016 | | 2015 |
| | (Thousands) |
| Natural Gas (after Hedging) | $ | 129,317 |
| | $ | 94,028 |
| | $ | 160,651 |
|
| Other | 63 |
| | 434 |
| | 55 |
|
| | $ | 129,380 |
| | $ | 94,462 |
| | $ | 160,706 |
|
Energy Marketing Volume
|
| | | | | | | | |
| | Year Ended September 30 |
| | 2017 | | 2016 | | 2015 |
| Natural Gas — (MMcf) | 38,901 |
| | 39,849 |
| | 46,752 |
|
2017 Compared with 2016
Operating revenues for the Energy Marketing segment increased $34.9 million in 2017 as compared with 2016. The increase was primarily due to an increase in gas sales revenue due to a higher average price of natural gas period over period, slightly offset by a decrease in volume sold to retail customers.
2016 Compared with 2015
Operating revenues for the Energy Marketing segment decreased $66.2 million in 2016 as compared with 2015. The decrease was primarily due to a decline in gas sales revenue due to a lower average price of natural gas period over period. A decrease in volume sold to retail customers as a result of warmer weather also contributed to the decline in operating revenues.
Earnings
2017 Compared with 2016
The Energy Marketing segment’s earnings in 2017 were $1.5 million, a decrease of $2.8 million when compared with earnings of $4.3 million in 2016. This decrease in earnings was primarily attributable to lower margin of $2.6 million. The decrease in margin largely reflects a decline in average margin per Mcf primarily due to stronger natural gas prices at local purchase points relative to NYMEX-based sales contracts, combined with the margin impact associated with the decrease in volume sold to retail customers during the year ended September 30, 2017 compared to the year ended September 30, 2016.
2016 Compared with 2015
The Energy Marketing segment’s earnings in 2016 were $4.3 million, a decrease of $3.5 million when compared with earnings of $7.8 million in 2015. This decrease in earnings was largely attributable to lower margin of $3.6 million. The decrease in margin largely reflected the margin impact associated with the decrease in volume sold to retail customers as a result of warmer weather during the year ended September 30, 2016 compared to the year ended September 30, 2015. Margin was also negatively impacted by changes in natural gas prices at local purchase points relative to NYMEX-based customer sales contracts. This decrease was partially offset by an increase to margin due to an increase in the benefit the Energy Marketing segment realized from its contracts for storage capacity.
ALL OTHER AND CORPORATE OPERATIONS
All Other and Corporate operations primarily includes the operations of Seneca’s Northeast Division and corporate operations. Seneca’s Northeast Division marketspreviously marketed timber from its New York and Pennsylvania land holdings. On December 10, 2020, the Company completed the sale of substantially all timber properties. Please refer to Item 8 at Note B — Asset Acquisitions and Divestitures for further discussion of the sale of timber properties.
Earnings
20172022 Compared with 20162021
All Other and Corporate operations recorded a loss of $3.1$12.7 million in 2017, which was $2.62022, a decrease of $47.3 million higher than the losswhen compared with earnings of $0.5$34.6 million in 2016.2021. The decrease was primarily attributable to the non-recurrence of a $51.1 million gain ($37.0 million gain after-tax) on the sale of timber properties recorded by Seneca’s Northeast Division in 2021. Changes in unrealized gains and losses on investments in equity securities also contributed to the decrease. In 2022, the Company recorded unrealized losses of $9.2 million, while in 2021, the Company recorded unrealized gains of $0.1 million.
OTHER INCOME (DEDUCTIONS)
Although most of the variances in Other Income (Deductions) are discussed in the earnings discussion by segment above, the following is a summary on a consolidated basis (amounts below are pre-tax amounts):
Net other deductions on the Consolidated Statement of Income decreased $13.7 million in 2022 as compared to 2021. This change is primarily attributable to non-service pension and post-retirement benefit income of $3.6 million for 2022 compared to non-service pension and post-retirement benefit costs of $31.3 million for 2021. As discussed above in the Utility segment, this is largely related to the February 2022 conclusion of the regulatory proceeding in Distribution Corporation's Pennsylvania service territory that addressed Distribution Corporation's recovery of OPEB expenses. In addition, there was an increase in lossother interest income of $1.7 million. This was partially offset by changes in unrealized gains and losses on investments in equity securities. During 2022, the Company recorded pre-tax unrealized losses of $13.8 million. During 2021, the Company recorded pre-tax unrealized gains of $0.2 million. Other income (deductions) was also impacted by a decrease in the cash surrender value of life insurance policies of $1.9 million, as well as a decrease in allowance for funds used during construction (equity component) of $2.5 million primarily due to higher operating expenses ($1.2 million) largely due to higher personnel costs, higher income tax expense ($0.5 million) and lower margins ($1.0 million)as a result of the FM100 Project being placed into service in December 2021. There was also a mark-to-market revaluation that decreased contingent consideration by $4.4 million from the sale of standing timber by Seneca’s land and timber division.
2016 Compared with 2015
All Other and Corporate operations recorded a loss of $0.5 million in 2016, which was $5.2 million lower than the loss of $5.7 million in 2015. The reduction in loss can be attributedSeneca's California assets. For further discussion, refer to a death benefit gain on life insurance of $1.7 million that was recognized during the year ended September 30, 2016 and was recorded in Other Income. In addition, lower operating expenses of $0.5 million (primarily due to a decrease in personnel costs partially offset by higher stock-based compensation expense), higher margins of $0.9 million (from the sale of standing timber and stumpage tracts by Seneca's land and timber division) and the impact of lower income tax expense of $1.6 million (primarily due to consolidated tax sharing adjustments) further reduced the loss during the year ended September 30, 2016.Note J — Financial Instruments.
INTEREST CHARGES
Although most of the variances in Interest Charges are discussed in the earnings discussion by segment above, the following is a summary on a consolidated basis (amounts below are pre-tax amounts):
Interest on long-term debt decreased $0.9$21.0 million in 20172022 as compared to 2016. This decrease2021. The Company redeemed $500.0 million of 4.90% notes in March 2021 and paid an early redemption premium of $15.7 million that was primarily due to an increase in the capitalization of interest costs (mostly in Midstream Corporation) which decreasedrecorded as interest expense foron long-term debt. The remaining decrease is due largely to a lower weighted average interest rate on long-term debt, stemming from the year ended September 30, 2017Company's issuance of $500.0 million of 2.95% notes in February 2021, which replaced $500.0 million of 4.90% notes that were retired in March 2021.
Other interest expense increased $5.0 million in 2022 as compared to the year ended September 30, 2016.
Interest on long-term debt increased $21.4 million in 2016 as compared to 2015. This2021. The increase was primarily due to additional long-termhigher average interest rates for 2022 combined with higher average short-term debt that was issuedbalances in fiscal 2015. The Company issued $450 million of 5.20% notes in June 2015. Additionally, capitalized interest decreased as a result of various projects being placed into service, which increased interest expense for the year ended September 30, 2016 as2022 compared to the year ended September 30, 2015.
2021.
CAPITAL RESOURCES AND LIQUIDITY
The primary sources and uses of cash during the last threetwo years are summarized in the following condensed statement of cash flows:
| | | | | | | | | | | | | |
| Year Ended September 30 |
| | 2022 | | 2021 | | |
| | (Millions) |
| Provided by Operating Activities | $ | 812.5 | | | $ | 791.6 | | | |
| Capital Expenditures | (811.8) | | | (751.7) | | | |
| Net Proceeds from Sale of Oil and Gas Producing Properties | 254.4 | | | — | | | |
| Net Proceeds from Sale of Timber Properties | — | | | 104.6 | | | |
| Sale of Fixed Income Mutual Fund Shares in Grantor Trust | 30.0 | | | — | | | |
| Other Investing Activities | 8.7 | | | 13.8 | | | |
| Reduction of Long-Term Debt | — | | | (515.7) | | | |
| Change in Notes Payable to Banks and Commercial Paper | (98.5) | | | 128.5 | | | |
| Net Proceeds from Issuance of Long-Term Debt | — | | | 495.3 | | | |
| Net Repurchases of Common Stock | (9.6) | | | (3.7) | | | |
| Dividends Paid on Common Stock | (168.1) | | | (163.1) | | | |
| | | | | |
| Net Increase in Cash, Cash Equivalents, and Restricted Cash | $ | 17.6 | | | $ | 99.6 | | | |
|
| | | | | | | | | | | |
| | Year Ended September 30 |
| | 2017 | | 2016 | | 2015 |
| | (Millions) |
| Provided by Operating Activities | $ | 684.3 |
| | $ | 589.0 |
| | $ | 853.6 |
|
| Capital Expenditures | (450.3 | ) | | (581.6 | ) | | (1,018.2 | ) |
| Net Proceeds from Sale of Oil and Gas Producing Properties | 26.6 |
| | 137.3 |
| | — |
|
| Other Investing Activities | 1.2 |
| | (9.2 | ) | | (6.6 | ) |
| Change in Notes Payable to Banks and Commercial Paper | — |
| | — |
| | (85.6 | ) |
| Net Proceeds from Issuance of Long-Term Debt | 295.2 |
| | — |
| | 444.6 |
|
| Net Proceeds from Issuance of Common Stock | 7.7 |
| | 13.8 |
| | 10.5 |
|
| Dividends Paid on Common Stock | (139.1 | ) | | (134.8 | ) | | (130.7 | ) |
| Excess Tax Benefits Associated with Stock-Based Compensation Awards | — |
| | 1.9 |
| | 9.1 |
|
| Net Increase in Cash and Temporary Cash Investments | $ | 425.6 |
| | $ | 16.4 |
| | $ | 76.7 |
|
The Company expects to have adequate amounts of cash available to meet both its short-term and long-term cash requirements for at least the next twelve months and for the foreseeable future thereafter. During 2023, cash provided by operating activities is expected to increase over the amount of cash provided by operating activities during 2022 and will be used to fund the Company's capital expenditures. There are two long-term debt maturities in March 2023, totaling $549 million. The Company expects to repay those securities through the use of cash on hand at the date of maturity and short-term borrowings. Looking at 2023 and 2024, based on current commodity prices, cash provided by operating activities is expected to exceed capital expenditures in each of those years. This is expected to provide the Company with the option to consider additional growth investments, further reductions in short-term or long-term debt, and increasing the amount of cash flow returned to shareholders, either through increases to the Company’s dividend or via repurchases of common stock. These cash flow projections do not reflect the impact of acquisitions or divestitures that may arise in the future.
OPERATING CASH FLOW
Internally generated cash from operating activities consists of net income available for common stock, adjusted for non-cash expenses, non-cash income, gains and losses associated with investing and financing activities, and changes in operating assets and liabilities. Non-cash items include depreciation, depletion and amortization, impairment of oil and gas producing properties, deferred income taxes, the reduction of an other post-retirement regulatory liability and stock-based compensation.
Cash provided by operating activities in the Utility and Pipeline and Storage segments may vary substantially from year to year because of the impact of rate cases. In the Utility segment, supplier refunds, over- or under-recovered purchased gas costs and weather may also significantly impact cash flow. The impact of weather on cash flow is tempered in the Utility segment’s New York rate jurisdiction by its WNC and in the Pipeline and Storage segment by the straight fixed-variable rate design used by Supply Corporation and Empire.
Cash provided by operating activities in the Exploration and Production segment may vary from year to year as a result of changes in the commodity prices of natural gas and crude oil as well as changes in production. The Company uses various derivative financial instruments, including price swap agreements and futures contractsno cost collars, in an attempt to manage this energy commodity price risk.
The Company, in its Utility segment and Exploration and Production segment, has entered into contractual commitments in the ordinary course of business, including commitments to purchase gas, transportation, and storage service to meet customer gas supply needs. Refer to Item 8 at Note L —
Commitments and Contingencies under the heading “Other” for additional discussion concerning these contractual commitments as well as the amounts of future gas purchase, transportation and storage contract commitments expected to be incurred during the next five years and thereafter. Also refer to Item 8 at Note D — Leases for a discussion of the Company’s operating lease arrangements and a schedule of lease payments during the next five years and thereafter.
Net cash provided by operating activities totaled $684.3$812.5 million in 2017,2022, an increase of $95.3$20.9 million compared with the $589.0$791.6 million provided by operating activities in 2016.2021. The increase in cash provided by operating activities primarily reflects higher cash provided by operating activities in the Exploration and Production segment and the Gathering segmentssegment, partially offset by lower cash provided by operating activities in the Utility segment. The increase in the Exploration and Production segment and the Gathering segment was primarily due to higher cash receipts from natural gas production and gathering services in the Appalachian region.
Net cash provided by operating activities totaled $589.0 million in 2016, a decrease of $264.6 million compared with the $853.6 million provided by operating activities in 2015. The decrease in cash provided by operating activities reflected lower cash provided by operating activities in the Exploration and ProductionUtility segment and the Utility segment. The decrease in the Exploration and Production segment wasis primarily due to lower cash receipts from crude oil and natural gas production as a result of lower crude oil and natural gas prices and curtailed production. The decreaserates in the Utility segment was primarily due tosegment's Pennsylvania service territory that went into effect October 1, 2021 combined with the timing of gas cost recovery.
recovery, timing of gas receivables and other regulatory true-ups. The rates that went into effect included a one-time customer bill credit of $25 million in October 2021 for previously overcollected OPEB expenses and the beginning of a 5-year pass back of an additional $29 million in previously overcollected OPEB expenses. Please refer to the Rate Matters section that follows for additional discussion of this matter.
INVESTING CASH FLOW
Expenditures for Long-Lived Assets
The Company’s expenditures for long-lived assets, including non-cash capital expenditures, totaled $462.1 million, $523.1$829.4 million and $1.0 billion$769.9 million in 2017, 20162022 and 2015,2021, respectively. The table below presents these expenditures:
|
| | | | | | | | | | | | | | |
| | Year Ended September 30 | |
| | 2017 | | | 2016 | | | 2015 | |
| | (Millions) | |
| Exploration and Production: | | | | | | | | |
| Capital Expenditures | $ | 253.1 |
| (1) | | $ | 256.1 |
| (2) | | $ | 557.3 |
| (3) |
| Pipeline and Storage: | | | | | | | | |
| Capital Expenditures | 95.3 |
| (1) | | 114.3 |
| (2) | | 230.2 |
| (3) |
| Gathering: | | | | | | | | |
| Capital Expenditures | 32.6 |
| (1) | | 54.3 |
| (2) | | 118.2 |
| (3) |
| Utility: | | | | | | | | |
| Capital Expenditures | 80.9 |
| (1) | | 98.0 |
| (2) | | 94.4 |
| (3) |
| All Other and Corporate: | | | | | | | | |
| Capital Expenditures | 0.2 |
| | | 0.4 |
| | | 0.4 |
| |
| Total Expenditures | $ | 462.1 |
| | | $ | 523.1 |
| | | $ | 1,000.5 |
| |
| | | | | | | | | | | | | | | | | | | | |
| | Year Ended September 30 | | | | |
| | 2022 | | | 2021 | | | | |
| | (Millions) | |
| Exploration and Production: | | | | | | | | |
| Capital Expenditures | $ | 565.8 | | (1) | | $ | 381.4 | | (2) | | | |
| Pipeline and Storage: | | | | | | | | |
| Capital Expenditures | 95.8 | | (1) | | 252.3 | | (2) | | | |
| Gathering: | | | | | | | | |
| Capital Expenditures | 55.5 | | (1) | | 34.7 | | (2) | | | |
| Utility: | | | | | | | | |
| Capital Expenditures | 111.0 | | (1) | | 100.8 | | (2) | | | |
| All Other and Corporate: | | | | | | | | |
| Capital Expenditures | 1.3 | | | | 0.5 | | | | | |
| Eliminations | — | | | | 0.2 | | | | | |
| Total Expenditures | $ | 829.4 | | | | $ | 769.9 | | | | | |
| |
(1) | 2017 capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment include $36.5 million, $25.1 million, $3.9 million and $6.7 million, respectively, of non-cash capital expenditures. The capital expenditures for the Exploration and Production segment do not include any proceeds received from the sale of oil and gas assets to IOG under the joint development agreement. |
| |
(2) | 2016 capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment include $25.2 million, $18.7 million, $5.3 million and $11.2 million, respectively, of non-cash capital expenditures. The capital expenditures for the Exploration and Production segment do not include any proceeds from the sale of oil and gas assets to IOG under the joint development agreement. |
| |
(3) | 2015 capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment include $46.2 million, $33.9 million, $22.4 million and $16.5 million, respectively, of non-cash capital expenditures. |
(1)2022 capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment include $83.0 million, $15.2 million, $10.7 million and $11.4 million, respectively, of non-cash capital expenditures.
(2)2021 capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment include $47.9 million, $39.4 million, $4.8 million and $10.6 million, respectively, of non-cash capital expenditures.
Exploration and Production
In 2017,2022, the Exploration and Production segment capital expenditures were primarily well drilling and completion expenditures and included approximately $213.8$547.1 million for the Appalachian region (including $168.2$161.4 million in the Marcellus Shale area and $370.6 million in the Utica Shale area) and $39.3$18.7 million for the West Coast region. These amounts included approximately $101.1$154.3 million spent to develop proved undeveloped reserves.
On December 1, 2015, Seneca and IOG - CRV Marcellus, LLC (IOG), an affiliate of IOG Capital, LP, and funds managed by affiliates of Fortress Investment Group, LLC, executed a joint development agreement that allows IOG to participate in the development of certain oil and gas interests owned by Seneca in Elk, McKean and Cameron Counties, Pennsylvania. On June 13, 2016, Seneca and IOG executed an extension of the joint development agreement. Under the terms of the extended agreement, Seneca and IOG will jointly participate in a program to develop up to 75 Marcellus wells, with Seneca serving as program operator. IOG will hold an 80% working interest in all of the joint development wells.
In total, IOG is expected to fund approximately $325 million for its 80% working interest in the 75 joint development wells. Of this amount, IOG has funded $262.6 million as of September 30, 2017, which includes $163.9 million of cash ($137.3 million in fiscal 2016 and $26.6 million in fiscal 2017) that Seneca had received in recognition of IOG funding that is due to Seneca for costs previously
incurred to develop a portion of the first 75 joint development wells. The cash proceeds were recorded by Seneca as a $163.9 million reduction of property, plant and equipment. The remainder funded joint development expenditures. For further discussion of the extended joint development agreement, refer to Item 8 at Note A - Summary of Significant Accounting Policies under the heading “Property, Plant and Equipment.”
On June 30, 2016, Seneca sold2021, the majority of its Upper Devonian wells in Pennsylvania. While the proceeds from the sale were not significant, it did result in a $58.4 million reduction of its Asset Retirement Obligation for the year ended September 30, 2016.
In 2016, the Exploration and Production segment capital expenditures were primarily well drilling and completion expenditures and included approximately $217.3$368.1 million for the Appalachian region (including $201.8$117.2 million in the Marcellus Shale area and $213.8 million in the Utica Shale area) and $38.8$13.3 million for the West Coast region. These amounts included approximately $92.8 million spent to develop proved undeveloped reserves.
In 2015, the Exploration and Production segment capital expenditures were primarily well drilling and completion expenditures and included approximately $500.2 million for the Appalachian region (including $458.6 million in the Marcellus Shale area) and $57.1 million for the West Coast region. These amounts included approximately $161.8$81.2 million spent to develop proved undeveloped reserves.
Pipeline and Storage
The majority of the Pipeline and Storage segment’s capital expenditures for 20172022 were related toprimarily for additions, improvements and replacements to this segment’ssegment's transmission and gas storage systems.systems, which included system modernization expenditures that enhance the reliability and safety of the systems and reduce emissions. In addition, the Pipeline and Storage segment capital expenditures for 20172022 include expenditures related to Empire and Supply Corporation's Northern Access 2016FM100 Project ($22.125.2 million). The FM100 Project upgraded a 1950's era pipeline in northwestern Pennsylvania and created approximately 330,000 Dth per day of additional transportation capacity in Pennsylvania from a receipt point with NFG Midstream Clermont, LLC in McKean County to the Transcontinental Gas Pipe Line Company, LLC (“Transco”) system at Leidy, Pennsylvania. Supply Corporation's Line D ExpansionCorporation and Transco executed a precedent agreement whereby Transco has leased this additional capacity as part of a Transco expansion project ("Leidy South"), creating incremental transportation capacity to Transco Zone 6 (Non-New York) markets. Seneca is an anchor shipper on Leidy South, which provides it with an outlet to premium markets from both its Eastern and Western development areas. Construction activities on the expansion portion of the FM100 Project ($14.4 million), as discussed below.are complete and the project commenced partial in-service on December 1, 2021, with full in-service on December 19, 2021. Abandonment activities on the project continue in calendar year 2022. As of September 30, 2022, approximately $211.3 million has been spent on the FM100 Project, all of which is included in Property, Plant and Equipment on the Consolidated Balance Sheet at September 30, 2022.
The majority of the Pipeline and Storage segment’s capital expenditures for 20162021 were mainlyprimarily for expenditures related to Empire and Supply Corporation's Northern Access 2016FM100 Project ($26.7 million), Supply Corporation's Northern Access 2015 Project ($13.1 million), Supply Corporation's Westside Expansion and Modernization Project ($11.1 million), Supply Corporation's Line D Expansion Project ($10.4 million) and Empire and Supply Corporation's Tuscarora Lateral Project ($7.6179.0 million). In addition, the Pipeline and Storage segment capital expenditures for 2016 also2021 included additions, improvements and replacements to this segment’s transmission and gas storage systems.
The majority of the Pipeline and Storage segment’s capital expenditures for 2015 were mainly for expenditures related to Supply Corporation's Westside Expansion and Modernization Project ($63.0 million), Empire and Supply Corporation's Tuscarora Lateral Project ($53.7 million), Supply Corporation's Northern Access 2015 Project ($40.4 million), Supply Corporation's Northern Access 2016 Project ($5.9 million) and Supply Corporation's Mercer Expansion Project ($5.4 million). In addition, the Pipeline and Storage segment capital expenditures for 2015 also included additions, improvements and replacements to this segment’ssegment's transmission and gas storage systems.
Gathering
The majority of the Gathering segment’ssegment's capital expenditures for 2017, 2016 and 2015 were for2022 included expenditures related to the construction and/or continued buildoutexpansion of Midstream Corporation’sCompany's Clermont, Gathering System, which isCovington, Trout Run and Wellsboro gathering systems, as discussed below. Midstream CorporationCompany spent $21.7$20.9 million, $27.0 million, $4.9 million and $2.3 million in 2017, $43.2 million in 2016 and $117.3 million in 2015 for2022 on the development of thisthe Clermont, Covington, Trout Run and Wellsboro gathering systems, respectively. These expenditures were largely attributable to the installation of new in-field gathering pipelines in the Clermont gathering system, as well as the continued expansion of centralized station facilities, including increased compression horsepower at the Clermont, Trout Run, and Wellsboro gathering systems. In the Tioga gathering system, which is part of Midstream Covington, expenditures were largely attributable to the installation of in-field gathering pipelines and upgraded station facilities related to new development.
The majority of the Gathering segment's capital expenditures for 2021 included expenditures related to the continued expansion of Midstream Company's Clermont, Covington and Wellsboro gathering systems. Midstream Company spent $23.1 million, $4.4 million and $3.7 million in 2021 on the development of the Clermont, Covington and Wellsboro gathering systems, respectively. These expenditures were largely attributable to new Clermont gathering pipelines, a new tie-in between the legacy Covington gathering system and the midstream gathering assets acquired from SWEPI LP, a subsidiary of Royal Dutch Shell plc ("Shell"), which is now referred to as the Tioga gathering system, as well as the continued development of centralized station facilities, including increased compression horsepower at the Clermont and Wellsboro gathering systems and additional dehydration on the Clermont gathering system.
Utility
The majority of the Utility segment’s capital expenditures for 2017, 20162022 and 20152021 were made for main and service line improvements and replacements as well asthat enhance the reliability and safety of the system and reduce emissions. Expenditures were also made for main extensions.
Other Investing Activities
On December 10, 2020, the Company completed the sale of substantially all timber properties in Pennsylvania to Lyme Emporium Highlands III LLC and Lyme Allegheny Land Company II LLC for net proceeds of $104.6 million. After purchase price adjustments and transaction costs, a gain of $51.1 million was recognized on the sale of these assets ($37.0 million after-tax). The capital expendituressale of the timber properties completed a reverse like-kind exchange pursuant to Section 1031 of the Internal Revenue Code, as amended (“Reverse 1031 Exchange”). On July 31, 2020, the Company completed its acquisition of certain upstream assets and midstream gathering assets in Pennsylvania from Shell for 2016total consideration of $506.3 million. The purchase and 2015 included $16.4sale agreement with Shell was structured, in part, as a Reverse 1031 Exchange. Refer to Item 8 at Note B — Asset Acquisitions and Divestitures for additional information concerning the Company’s acquisition of certain upstream assets and midstream gathering assets from Shell.
In October 2021, the Company sold $30 million of fixed income mutual fund shares held in a grantor trust that was established for the benefit of Pennsylvania ratepayers. The proceeds were used in the Utility segment’s Pennsylvania service territory to fund a one-time customer bill credit of $25 million in October 2021 for previously overcollected OPEB expenses and $18.4the first year installment of a 5-year pass back of an additional $29 million respectively,in previously overcollected OPEB expenses in accordance with new rates that went into effect on October 1, 2021. Please refer to the Rate Matters section that follows for additional discussion of this matter.
In March 2022, the Company completed the sale of certain oil and gas assets located in Tioga County, Pennsylvania, effective as of October 1, 2021. The Company received net proceeds of $13.5 million from this sale. Under the full cost method of accounting for oil and natural gas properties, the sale proceeds were accounted for as a reduction of capitalized costs. Since the disposition did not significantly alter the relationship between capitalized costs and proved reserves of oil and gas attributable to the cost center, the Company did not record any gain or loss from this sale.
On June 30, 2022, the Company completed the sale of Seneca’s California assets to Sentinel Peak Resources California LLC for a total sale price of $253.5 million, consisting of $240.9 million in cash and contingent consideration valued at $12.6 million at closing. The Company pursued this sale given the strong commodity price environment and the Company’s strategic focus in the Appalachian Basin. Under the terms of the purchase and sale agreement, the Company can receive up to three annual contingent payments between calendar year 2023 and calendar year 2025, not to exceed $10 million per year, with the amount of each annual payment calculated as $1.0 million for each $1 per barrel that the ICE Brent Average for each calendar year exceeds $95 per barrel up to $105 per barrel. The sale price, which reflected an effective date of April 1, 2022, was reduced for production revenues less expenses that were retained by Seneca from the effective date to the closing date. Under the full cost method of accounting for oil and natural gas properties, $220.7 million of the sale price at closing was accounted for as a reduction of capitalized costs since the disposition did not alter the relationship between capitalized costs and proved reserves of oil and gas attributable to the cost center. The remainder of the sale price ($32.8 million) was applied against assets that are not subject to the full cost method of accounting, with the Company recognizing a gain of $12.7 million on the sale of such assets. The majority of this gain related to the replacementsale of the Utility segment’s customer information system, which was placed in service in May 2016.emission allowances.
Estimated Capital Expenditures
The Company’s estimated capital expenditures for the next three years are:
|
| | | | | | | | | | | |
| | Year Ended September 30 |
| | 2018 | | 2019 | | 2020 |
| | (Millions) |
| Exploration and Production(1) | $ | 320 |
| | $ | 345 |
| | $ | 320 |
|
| Pipeline and Storage | 125 |
| | 215 |
| | 145 |
|
| Gathering | 70 |
| | 50 |
| | 30 |
|
| Utility | 95 |
| | 95 |
| | 95 |
|
| All Other | — |
| | — |
| | — |
|
| | $ | 610 |
| | $ | 705 |
| | $ | 590 |
|
| | | | | | | | | | | | | | | | | |
| | Year Ended September 30 |
| | 2023 | | 2024 | | 2025 |
| | (Millions) |
| Exploration and Production(1) | $ | 550 | | | $ | 525 | | | $ | 515 | |
| Pipeline and Storage | 120 | | | 105 | | | 90 | |
| Gathering | 95 | | | 110 | | | 95 | |
| Utility(2) | 120 | | | 135 | | | 135 | |
| All Other | — | | | — | | | — | |
| $ | 885 | | | $ | 875 | | | $ | 835 | |
| |
(1) | Includes estimated expenditures for the years ended September 30, 2018, 2019 and 2020 of approximately $186 million, $98 million and $28 million, respectively, to develop proved undeveloped reserves. The Company is committed to developing its proved undeveloped reserves within five years as required by the SEC’s final rule on Modernization of Oil and Gas Reporting. The capital expenditures for the Exploration and Production segment do not include any proceeds received from the sale of oil and gas assets to IOG under the joint development agreement. |
(1)Includes estimated expenditures for the years ended September 30, 2023, 2024 and 2025 of approximately $308 million, $95 million and $82 million, respectively, to develop proved undeveloped reserves. The Company is committed to developing its proved undeveloped reserves within five years as required by the SEC’s final rule on Modernization of Oil and Gas Reporting.
(2)Includes estimated expenditures for the years ended September 30, 2023, 2024, and 2025 of approximately $95 million, $100 million and $100 million, respectively, for system modernization and safety to enhance the reliability and safety of the system and reduce emissions.
Exploration and Production
Estimated capitalCapital expenditures in 2018 for the Exploration and Production segment include approximately $295 million forin 2023 through 2025 are expected to be primarily well drilling and completion expenditures in the Appalachian region and $25 million for the West Coast region.
Estimated capital expenditures in 2019 for the Exploration and Production segment include approximately $310 million for the Appalachian region and $35 million for the West Coast region.
Estimated capital expenditures in 2020 for the Exploration and Production segment include approximately $290 million for the Appalachian region and $30 million for the West Coast region.
Pipeline and Storage
Capital expenditures for the Pipeline and Storage segment in 20182023 through 20202025 are expected to include: construction of new pipelinethe replacement and compressor stations to support expansion projects, the replacementmodernization of transmission and storage lines,facilities, the reconditioning of storage wells, and improvements of compressor stations. Expansion projects where the Company has begunstations and emissions reduction initiatives.
In addition, due to make significant investments of preliminary survey and investigation costs and/or where shipper agreements have been executed are described below.
In light of the continuing demand for pipeline capacity to move natural gas from new wells being drilled in Appalachia, — specifically in the Marcellus and Utica Shale producing areas, — Supply Corporation and Empire have recently completed and are actively pursuing severalcontinue to pursue expansion projects designed to move anticipated Marcellus and Utica production gas to other interstate pipelines and to on-system markets, and markets beyond the Supply Corporation and Empire pipeline systems,systems. Capital expenditures in 2023 through 2025 include minimal capital expenditures related to system expansion and incurring preliminary survey and investigation costs, which are initially recorded as Deferred Charges on the Consolidated Balance Sheet. An offsetting reserve is established as those preliminary survey and investigation costs are incurred, which reduces the Deferred Charges balance and increases Operation and Maintenance Expense on the Consolidated Statement of Income. The Company reviews all projects on a quarterly basis, and, for those projects for which a reserve had been established, if it is determined that it is highly probable that the projectforecasted amounts will be built, the reserve is reversed. This reversal reduces Operation and Maintenance Expense and reestablishes the original balance in Deferred Charges. After the reversal of the reserve, the amounts remain in Deferred Charges until such time as capital expenditures for the project have been incurred and activities that are necessary to get the construction project ready for its intended use are in progress. At that point, the balance is transferred from Deferred Charges to Construction Work in Progress, a component of Property, Plant and Equipment on the Consolidated Balance Sheet. As of September 30, 2017, the
total amount reserved for the Pipeline and Storage segment’s preliminary survey and investigation costs was $7.1 million.
Supply Corporation and Empire are developing a project which would move significant prospective Marcellus production from Seneca's Western Development Area at Clermont to an Empire interconnection with TransCanada Pipeline at Chippawa and an interconnection with TGP's 200 Line in East Aurora, New York (“Northern Access 2016”). The Northern Access 2016 project would provide an outlet to Dawn-indexed markets in Canada and to the TGP line serving the U.S. Northeast. The Northern Access 2016 project involves the construction of approximately 99 miles of largely 24” pipeline and approximately 27,500 horsepower of compression on the two systems. The preliminary cost estimate for the Northern Access 2016 project is approximately $500 million. Supply Corporation, Empire and Seneca executed anchor shipper agreements for 350,000 Dth per day of firm transportation delivery capacity to Chippawa and 140,000 Dth per day of firm transportation capacity to a new interconnection with TGP's 200 Line on this project. On February 3, 2017, the Company received FERC approval of the project. On April 7, 2017, the NYDEC issued a Notice of Denial of the federal Clean Water Act Section 401 Water Quality Certification and other state stream and wetland permits for the New York portion of the project (the Water Quality Certification for the Pennsylvania portion of the project was received on January 27, 2017). The Company remains committed to the project. On April 21, 2017, the Company appealed the NYDEC's decision with regard to the Water Quality Certification to the United States Court of Appeals for the Second Circuit, and on May 11, 2017, the Company commenced legal action in New York State Supreme Court challenging the NYDEC's actions with regard to various state permits. The Company also has pending with FERC a proceeding asserting, among other things, that the NYDEC exceeded the reasonable time frame to take action under the Clean Water Act and, therefore, waived its opportunity to approve or deny the Water Quality Certification. In light of these pending legal actions, the Company has not yet determined a target in-service date. As of September 30, 2017, approximately $75.8 million has been spent on the Northern Access 2016 project, including $21.1 million that has been spent to study the project, for which no reserve has been established. The remaining $54.7 million spent on the project has been capitalized as Construction Work in Progress.
On November 21, 2014, Supply Corporation concluded an Open Season for an expansion of its Line D pipeline (“Line D Expansion”) that is intended to allow growing on-system markets to avail themselves of economical gas supply on the TGP 300 line, at an existing interconnect at Lamont, Pennsylvania, and provide increased capacity into the Erie, Pennsylvania market area. Supply Corporation has executed Service Agreements for a total of 77,500 Dth per day for terms of six to ten years. The project involves construction of a new 4,140 horsepower Keelor Compressor Station and modifications to the Bowen compressor station at an estimated capital cost of approximately $27.9 million. The project will also provide system modernization benefits. Supply Corporation filed on December 22, 2015 for authorization to construct this project under its FERC blanket certificate and completed the FERC notice period on February 26, 2016. Construction on both pieces of this project has been completed. The project went in-service on November 1, 2017. As of September 30, 2017, approximately $24.8 million has been capitalized as Construction Work in Progress for the Line D Expansion project. The remaining expenditures expected to be spent in fiscal 2018 are included in Pipeline and Storage estimated capital expendituresadjusted in the table above.
Empire concluded an Open Season on November 18, 2015, for a projectfuture to incorporate any new projects that would allow for the transportation of additional shale supplies from Millennium Pipeline at Corning, from Supply Corporation at Tuscarora, or from interconnections in Tioga County, Pennsylvania, to the TransCanada Pipeline, the TGP 200 Line and potentially other on-system points (“Empire North Project”). Empire has executed a Precedent Agreement with a foundation shipper for 150,000 Dth per day of transportation capacity and with two other shippers for 35,000 Dth per day and 5,000 Dth per day, respectively. Empire continues to negotiate precedent agreements with other prospective shippers. The project, which has a projected in-service date of November 1, 2019, is expected to be designed for up to 205,000 Dth per day; capital costs are expected to be approximately $135 million. These expenditures are included as Pipeline and Storage segment estimated capital expenditures indeveloped by the table above. As of September 30, 2017, approximately $0.9 million has been spent to study this project, all of which has been included in preliminary survey and investigation charges and has been fully reserved for at September 30, 2017.
Supply Corporation has entered into a foundation shipper Precedent Agreement to provide incremental natural gas transportation services from Line N to the ethylene cracker facility being constructed by Shell Chemical
Appalachia, LLC in Potter Township, Pennsylvania. Supply Corporation has completed an Open Season for the project and has secured incremental firm transportation capacity commitments totaling 133,000 Dth per day on Line N and on the proposed pipeline extension of approximately 4.5 miles from Line N to the facility. The proposed in-service date for this project is as early as July 1, 2019 and capital costs are expected to be $17 million. These expenditures are included as Pipeline and Storage segment estimated capital expenditures in the table above. As of September 30, 2017, approximately $0.2 million has been spent to study this project, all of which has been included in preliminary survey and investigation charges and has been fully reserved for at September 30, 2017.Company.
Gathering
The majority of the Gathering segment capital expenditures in 20182023 through 20202025, included in the table above, are expected to be for construction and expansion of gathering systems, as discussed below. The Gathering segment primarily invests capital to support Seneca's drilling and completion activity in their long-term development plan. Seneca has been in the process of shifting a larger share of its activity from its Western Development Area to Tioga County, Pennsylvania. As a result, the Gathering segment is expecting to see near-term increases in capital expenditures as it constructs the necessary infrastructure to support Seneca's activity in the region.
NFG Midstream Covington, LLC, a wholly-owned subsidiary of Midstream Company, operates its Covington gathering system as well as the Tioga gathering system acquired from Shell on July 31, 2020, both in Tioga County, Pennsylvania. The current Covington gathering system consists of two compressor stations and backbone and in-field gathering pipelines. The Tioga gathering system consists of 16 compressor stations and backbone and in-field gathering pipelines. Estimated capital expenditures in 2023 through 2025 include anticipated expenditures in the range of $150 million to $180 million for continued expansion of the Tioga gathering system.
NFG Midstream Clermont, LLC, a wholly ownedwholly-owned subsidiary of Midstream Corporation, is buildingCompany, 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 the shippers', including Seneca's long-term plans. AsEstimated capital expenditures in 2023 through 2025 include anticipated expenditures in the range of September 30, 2017, approximately $281.3$50 million has been spent onto $70 million for the continued expansion of the Clermont Gathering System, including approximately $21.7gathering system.
NFG Midstream Wellsboro, LLC, a wholly-owned subsidiary of Midstream Company, continues to develop its Wellsboro gathering system in Tioga County, Pennsylvania. The current system consists of one compressor station and backbone and in-field gathering pipelines. Estimated capital expenditures in 2023 through 2025 include anticipated expenditures in the range of $50 million spent duringto $60 million for the year ended September 30, 2017, allcontinued expansion of which is included in Property, Plant and Equipment on the Consolidated Balance Sheet at September 30, 2017.Wellsboro gathering system.
NFG Midstream Trout Run, LLC, a wholly ownedwholly-owned subsidiary of Midstream Corporation,Company, continues to develop its Trout Run Gathering Systemgathering system in Lycoming County, Pennsylvania. The Trout Run Gathering Systemgathering system was initially placed in service in May 2012. The current system consists of approximately 42 miles ofthree compressor stations and backbone and in-field gathering pipelines and two compressor stations.pipelines. Estimated capital expenditures in 20182023 through 20202025 include anticipated expenditures in the range of $50$15 million to $100$25 million for the continued expansion of the Trout Run Gathering System. As of September 30, 2017, the Company has spent approximately $177.4 million in costs related to this project, all of which is included in Property, Plant and Equipment on the Consolidated Balance Sheet at September 30, 2017.
NFG Midstream Wellsboro, LLC, a wholly owned subsidiary of Midstream Corporation, continues to develop its Wellsboro Gathering System in Tioga County, Pennsylvania. Estimated capital expenditures in 2018 through 2020 include anticipated expenditures in the range of $30 million to $60 million for the continued expansion of the Wellsboro Gathering System. The Company has spent approximately $6.7 million in costs related to this project, all of which is included in Property, Plant and Equipment on the Consolidated Balance Sheet at September 30, 2017.gathering system.
Utility
Capital expenditures for the Utility segment in 20182023 through 20202025 are expected to be concentrated in the areas of main and service line improvements and replacements and, to a lesser extent, the purchase of new equipment. Additionally, capital expenditures are expected to increase after 2023 largely due to the anticipated implementation of a Distribution System Improvement Charge (DSIC) mechanism in the Utility's Pennsylvania Division upon completion of the rate proceeding initiated on October 28, 2022.
Project Funding
TheOver the past two years, the Company has been financing the Pipeline and Storage segment and Gathering segment projects mentioned above, as well as the Exploration and Production segment capital expenditures with cash from operations, and both shortshort-term and long-term borrowings.debt, common stock, and proceeds from the sale of timber properties and the Company's California assets. During fiscal 2022, capital expenditures were funded with cash from operations, short-term debt and proceeds from the sale of the Company's California assets. The Company issued long-term debt and common stock in June 2020 to help finance the acquisition of upstream assets and midstream gathering assets from Shell. The financing of the asset acquisition from Shell was completed in December 2020 when the Company completed the sale of substantially all of its timber properties, through the completion of the Reverse 1031 Exchange discussed above. Going forward, while the Company expects to use cash on hand, and cash from operations as the first means of financing these projects, the Company may issueand short-term and/or long-term debt as necessary during fiscal 2018borrowings to help meet itsfinance capital expenditures needs.expenditures. The level of short-term and long-term borrowings will depend upon the amountsamount of cash provided by operations, which, in turn, will likely be most impacted by the timing of gas cost recovery in the Utility segment. It will also depend on natural gas production, and crude oil prices combinedthe associated commodity price realizations, as well as the level of hedging collateral deposits in the Exploration and Production segment.
In the Exploration and Production segment, the Company has entered into contractual obligations to support its development activities and operations in Pennsylvania, including hydraulic fracturing and other well completion services, well tending services, well workover activities, tubing and casing purchases, production equipment purchases, water hauling services and contracts for drilling rig services. Refer to Item 8 at Note L — Commitments and Contingencies under the heading “Other” for the amounts of contractual obligations expected to be incurred during the next five years and thereafter to support the Company’s exploration and development activities. These amounts are largely a subset of the estimated capital expenditures for the Exploration and Production segment shown above.
The Company, in its Pipeline and Storage segment, Gathering segment and Utility segment, has entered into several contractual commitments associated with production from existing wells. various pipeline, compressor and gathering system modernization and expansion projects. Refer to Item 8 at Note L — Commitments and Contingencies under the heading “Other” for the amounts of contractual commitments expected to be incurred during the next five years
and thereafter associated with the Company’s pipeline, compressor and gathering system modernization and expansion projects. These amounts are a subset of the estimated capital expenditures for the Pipeline and Storage segment, Gathering segment and Utility segment that are shown above.
The Company continuously evaluates capital expenditures and potential investments in corporations, partnerships, and other business entities. The amounts are subject to modification for opportunities such as the acquisition of attractive oil andnatural 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.capacities, regulated utility assets and other opportunities as they may arise. While the majority of capital expenditures in the Utility segment are necessitated by the continued need for replacement and upgrading of mains and service lines, the magnitude of future capital
expenditures or other investments in the Company’s other business segments depends, to a large degree, upon market conditions.and regulatory conditions as well as legislative actions.
FINANCING CASH FLOW
The Company did not have any consolidatedConsolidated short-term debt outstandingdecreased $98.5 million, to a total of $60.0 million, when comparing the balance sheet at September 30, 2017 or2022 to the balance sheet at September 30, 2016, nor was there any2021. The maximum amount of short-term debt outstanding during the year ended September 30, 2017. The2022 was $675.4 million. In addition to cash provided by operating activities, the Company continues to consider short-term debt (consisting of short-term notes payable to banks and commercial paper) an important source of cash for temporarily financing capital expenditures, gas-in-storage inventory, unrecovered purchased gas costs, margin calls on derivative financial instruments, exploration and development expenditures, other working capital needs and repayment of long-term debt. Fluctuations in these items can have a significant impact on the amount and timing of short-term debt. For example, elevated commodity prices relative to its existing portfolio of derivative financial instruments led to the Company posting margin of $91.7 million with a number of its derivative counterparties as of September 30, 2022. The maximum amount of margin posted during the year ended September 30, 2022 was $430.6 million. The Company's margin deposits are reflected on the balance sheet as a current asset titled Hedging Collateral Deposits. To meet these margin requirements and other near-term cash flow needs, the Company utilized short-term debt in the form of commercial paper and borrowings under its revolving credit facility. At September 30, 2022, the Company had outstanding short-term notes payable to banks of $60.0 million. The Company did not have any commercial paper outstanding at September 30, 2022.
On September 9, 2016,February 28, 2022, the Company entered into the Credit Agreement with a Thirdsyndicate of twelve banks. The Credit Agreement replaced the previous Fourth Amended and Restated Credit Agreement (Credit Agreement) withand a syndicate of what now numbers 13 banks. Thisprevious 364-Day Credit Agreement. The Credit Agreement provides a $750.0 million multi-year unsecured committed revolving credit facility through December 5, 2019. The Credit Agreement also provided a $500.0 million 364-day$1.0 billion unsecured committed revolving credit facility with 11a maturity date of February 26, 2027.
On June 30, 2022, the Company entered into the 364-Day Credit Agreement with a syndicate of five banks, all of which are also lenders under the Credit Agreement. The 364-Day Credit Agreement provides an additional $250.0 million unsecured committed delayed draw term loan credit facility with a maturity date of June 29, 2023. The Company elected to draw $250.0 million under the facility on October 27, 2022. The Company is using the proceeds for general corporate purposes, which will include the redemption in November of a portion of the 13 banks, which expired on September 8, 2017 and was not subsequently renewed. Company's outstanding long-term debt maturing in March 2023.
The Company also has a number of individual uncommitted or discretionary lines of credit with certain financial institutions for general corporate purposes. Borrowings under thethese uncommitted lines of credit arewould be made at competitive market rates. The uncommitted credit lines are revocable at the option of the financial institutionsinstitution 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 .675 at the last day of any fiscal quarter through September 30, 2017, or .65 at the last day of any fiscal quarter. For purposes of calculating the debt to capitalization ratio, the Company's total capitalization will be increased by adding back 50% of the aggregate after-tax amount of non-cash charges directly arising from any ceiling test impairment
occurring on or after July 1, 2018, not to exceed $400 million. Since July 1, 2018, the Company recorded non-cash, after-tax ceiling test impairments totaling $381.4 million. As a result, at September 30, 2022, $190.7 million was added back to the Company's total capitalization for purposes of the calculation under the Credit Agreement and 364-Day Credit Agreement. On May 3, 2022, the Company entered into Amendment No. 1 to the Credit Agreement with the same twelve banks under the initial Credit Agreement. The amendment further modified the definition of consolidated capitalization, for purposes of calculating the debt to capitalization ratio under the Credit Agreement, to exclude, beginning with the quarter from October 1, 2017 through December 5, 2019.ended June 30, 2022, all unrealized gains or losses on commodity-related derivative financial instruments and up to $10 million in unrealized gains or losses on other derivative financial instruments included in Accumulated Other Comprehensive Income (Loss) within Total Comprehensive Shareholders' Equity on the Company's consolidated balance sheet. Under the Credit Agreement, such unrealized losses will not negatively affect the calculation of the debt to capitalization ratio, and such unrealized gains will not positively affect the calculation. The 364-Day Credit Agreement includes the same debt to capitalization covenant and the same exclusions of unrealized gains or losses on derivative financial instruments as the Credit Agreement. At September 30, 2017,2022, the Company’s debt to capitalization ratio, (asas calculated under the facility)Credit Agreement and 364-Day Credit Agreement, was .58..49. The constraints specified in the Credit Agreement and 364-Day Credit Agreement would have permitted an additional $1.15$2.56 billion in short-term and/or long-term debt to be outstanding at September 30, 2022 (further limited by the indenture covenants discussed below) before the Company’s debt to capitalization ratio exceeded .675..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, including cash provided by operations.sources.
The Credit Agreement containsand 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. As of September 30, 2017, the Company did not have any debt outstanding under the Credit Agreement.
On September 18, 2017,February 24, 2021, the Company issued $300.0$500.0 million of 3.95%2.95% notes due September 15, 2027.March 1, 2031. After deducting underwriting discounts, commissions and other debt issuance costs, the net proceeds to the Company amounted to $295.2$495.3 million. The holders of the notes may require the Company to repurchase their notes at a price equal to 101% of the principal amount in the event of both a change in control and a ratings downgrade to a rating below investment grade. Additionally, the interest rate payable on the notes will be subject to adjustment from time to time, with a maximum adjustment of 2.00%, such that the coupon will not exceed 4.95%, if certain change of control events involving a material subsidiary result in a downgrade of the credit rating assigned to the notes to below investment grade (or if the credit rating assigned to the notes is subsequently upgraded). The proceeds of this debt issuance were used to redeem $300.0 million of
the Company's 6.50% notes on October 18, 2017. The 6.50% notes were scheduled to mature in April 2018 and were classified as Current Portion of Long-Term Debt at September 30, 2017. The Company redeemed the notes for $307.0 million, plus accrued interest.
On June 25, 2015, the Company issued $450.0 million of 5.20% notes due July 15, 2025. After deducting underwriting discounts and commissions, the net proceeds to the Company amounted to $444.6 million. The holders of the notes may require the Company to repurchase their notes at a price equal to 101% of the principal amount in the event of a change in control and a ratings downgrade to a rating below investment grade. A downgrade with a resulting increase to the coupon does not preclude the coupon from returning to its original rate if the Company's credit rating is subsequently upgraded. The proceeds of this debt issuance were used for general corporate purposes, including the reductionredemption of short-term debt.$500.0 million of the Company's 4.90% notes on March 11, 2021 that were scheduled to mature in December 2021. The Company redeemed those notes for $515.7 million, plus accrued interest.
As discussed above, theThe Current Portion of Long-Term Debt at September 30, 2017 consisted2022 consists of $300.0$500.0 million aggregate principal amount of 6.50%3.75% notes scheduled toand $49.0 million of 7.395% notes, that each mature in April 2018.March 2023. The Company does not anticipate long-term refinancing for these maturities. None of the Company’sCompany's long-term debt atas of September 30, 20162021 had a maturity date within the following twelve-month period. As of September 30, 2022, the future contractual obligations related to aggregate principal amounts of long-term debt, including interest expense, maturing during the next five years and thereafter are as follows: $654.1 million in 2023, $95.4 million in 2024, $589.4 million in 2025, $548.9 million in 2026, $340.4 million in 2027, and $863.5 million thereafter. Refer to Item 8
at Note H — Capitalization and Short-Term Borrowings, as well as the table under Interest Rate Risk in the Market Risk Sensitive Instruments section below, for the amounts excluding interest expense. Principal payments of long-term debt are a component of cash used in financing activities while interest payments on long-term debt are a component of cash used in operating activities.
The Company’s embedded cost of long-term debt was 5.34% and 5.53%4.48% at both September 30, 20172022 and September 30, 2016, respectively.2021. Refer to “Interest Rate Risk” in this Item for a more detailed breakdown of the Company’s embedded cost of long-term debt.
Under the Company’sCompany's existing indenture covenants at September 30, 2017,2022, the Company would have been permitted to issue up to a maximum of $126.0 millionapproximately $2.0 billion in additional unsubordinated long-term indebtedness at then current market interest rates, in addition to being able to issue new indebtedness to replace maturing debt. However, that amount does not take into account the October 18, 2017 redemption of the 6.50% notes discussed above. After the redemption, the Company would have been permitted to issue up to a maximum of $426.0 million in additional long-term indebtedness at then current market rates in addition to being able to issue new indebtedness to replace maturingexisting debt. The Company's present liquidity position is believed to be adequate to satisfy known demands. However, ifIt 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 were to experience a significant loss infrom issuing incremental unsubordinated long-term debt, or significantly limit the future (for example,amount of such debt that could be issued. Losses incurred as a result of an impairmentsignificant impairments of oil and gas properties), it is possible, depending on factors includingproperties have in the magnitude of the loss, that thesepast resulted in such temporary restrictions. The indenture covenants would restrict the Company's ability to issue additional long-term unsecured indebtedness for a period of up to nine calendar months, beginning with the fourth calendar month following the loss. This would not preclude the Company from issuing new indebtednesslong-term debt to replace maturingexisting 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 $98.7$99.0 million (or 4.1%3.7%) of the Company’s long-term debt (as of September 30, 2017)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.
OFF-BALANCE SHEET ARRANGEMENTS
The Company has entered into certain off-balance sheet financing arrangements. These financing arrangements are primarily operating leases. The Company’s consolidated subsidiaries have operating leases, the majority of which are with the Exploration and Production segment and Corporate operations, having a remaining lease commitment of approximately $24.7 million. These leases have been entered into for the use of compressors, drilling rigs, buildings and other items and are accounted for as operating leases.
CONTRACTUAL OBLIGATIONS
The following table summarizes the Company’s expected future contractual cash obligations as of September 30, 2017, and the twelve-month periods over which they occur:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Payments by Expected Maturity Dates |
| | 2018 | | 2019 | | 2020 | | 2021 | | 2022 | | Thereafter | | Total |
| | (Millions) |
| Long-Term Debt, including interest expense(1) | $ | 409.3 |
| | $ | 348.6 |
| | $ | 85.8 |
| | $ | 85.8 |
| | $ | 565.5 |
| | $ | 1,493.6 |
| | $ | 2,988.6 |
|
| Operating Lease Obligations | $ | 10.8 |
| | $ | 4.6 |
| | $ | 3.7 |
| | $ | 2.2 |
| | $ | 1.5 |
| | $ | 1.9 |
| | $ | 24.7 |
|
| Purchase Obligations: | | | | | | | | | | | | | |
| Gas Purchase Contracts(2) | $ | 198.6 |
| | $ | 21.0 |
| | $ | 12.5 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 232.1 |
|
| Transportation and Storage Contracts(3) | $ | 63.8 |
| | $ | 63.6 |
| | $ | 65.4 |
| | $ | 70.9 |
| | $ | 61.7 |
| | $ | 504.9 |
| | $ | 830.3 |
|
| Hydraulic Fracturing and Fuel Obligations | $ | 79.5 |
| | $ | 98.0 |
| | $ | 17.1 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 194.6 |
|
| Pipeline, Compressor and Gathering Projects | $ | 61.7 |
| | $ | 0.7 |
| | $ | 0.2 |
| | $ | 0.3 |
| | $ | 0.3 |
| | $ | 1.1 |
| | $ | 64.3 |
|
| Other | $ | 20.4 |
| | $ | 13.7 |
| | $ | 11.1 |
| | $ | 9.8 |
| | $ | 7.9 |
| | $ | 26.6 |
| | $ | 89.5 |
|
| |
(1) | Refer to Note E — Capitalization and Short-Term Borrowings, as well as the table under Interest Rate Risk in the Market Risk Sensitive Instruments section below, for the amounts excluding interest expense. As noted in Note E, the Company redeemed its $300.0 million 6.50% notes in October 2017. These notes were scheduled to mature in April 2018. The impact of the October redemption is reflected in the table. |
| |
(2) | Gas prices are variable based on the NYMEX prices adjusted for basis. |
| |
(3) | Transportation service contractual obligations include the following precedent agreements executed by the Exploration and Production segment for transportation of Appalachian gas: $20.1 million for 2018, $21.5 million for 2019, $21.6 million for 2020, $27.3 million for 2021, $33.2 million for 2022 and $453.7 million thereafter. |
The Company has other long-term obligations recorded on its Consolidated Balance Sheets that are not reflected in the table above. Such long-term obligations include pension and other post-retirement liabilities, asset retirement obligations, deferred income tax liabilities, various regulatory liabilities, derivative financial instrument liabilities and other deferred credits (the majority of which consist of liabilities for non-qualified benefit plans, deferred compensation liabilities, environmental liabilities and workers compensation liabilities).
The Company has made certain other guarantees on behalf of its subsidiaries. The guarantees relate primarily to: (i) obligations under derivative financial instruments, which are included on the Consolidated Balance Sheets in accordance with the authoritative guidance (see Item 7, MD&A under the heading “Critical Accounting Estimates - Accounting for Derivative Financial Instruments”); (ii) NFR obligations to purchase gas or to purchase gas transportation/storage services where the amounts due on those obligations each month are included on the Consolidated Balance Sheets as a current liability; and (iii) other obligations which are reflected on the Consolidated Balance Sheets. The Company believes that the likelihood it would be required to make payments under the guarantees is remote, and therefore has not included them in the table above.
OTHER MATTERS
In addition to the environmental and other matters discussed in this Item 7 and in Item 8 at Note IL — Commitments and Contingencies, the Company is involved in other litigation and regulatory matters arising in the normal course of business. These other matters may include, for example, negligence claims and tax, regulatory or other governmental audits, inspections, investigations or other proceedings. These matters may involve state and federal taxes, safety, compliance with regulations, rate base, cost of service and purchased gas cost issues, among other things. While these normal-course matters could have a material effect on earnings and cash flows
in the period in which they are resolved, they are not expected to change materially the Company’s present liquidity position, nor are they expected to have a material adverse effect on the financial condition of the Company.
Supply Corporation and Empire have developed a project which would move significant prospective Marcellus and Utica production from Seneca's Western Development Area at Clermont to an Empire interconnection with the TC Energy pipeline at Chippawa and an interconnection with TGP's 200 Line in East Aurora, New York (the “Northern Access project”). The Northern Access project would provide an outlet to Dawn-indexed markets in Canada and to the TGP line serving the U.S. Northeast. The Northern Access project involves the construction of approximately 99 miles of largely 24” pipeline and approximately 27,500 horsepower of compression on the two systems. Supply Corporation, Empire and Seneca executed anchor shipper agreements for 350,000 Dth per day of firm transportation delivery capacity to Chippawa and 140,000 Dth per day of firm transportation capacity to a new interconnection with TGP's 200 Line on this project. The Company remains committed to the project and, on June 29, 2022, received an extension of time from FERC, until December 31, 2024, to construct the project. The Company will update the $500 million preliminary cost estimate and expected in-service date for the project when there is further clarity on the timing of receipt of necessary regulatory approvals. As of September 30, 2022, approximately $55.8 million has been spent on the Northern Access project, including $24.2 million that has been spent to study the project. The remaining $31.6
million spent on the project is included in Property, Plant and Equipment on the Consolidated Balance Sheet at September 30, 2022.
The Company has a tax-qualified, noncontributory defined-benefit retirement plan (Retirement Plan). The Company has been making contributions to the Retirement Plan over the last several years and anticipates that it willmay continue making contributions to the Retirement Plan.Plan in the future. During 2017,2022, the Company contributed $17.1$20.4 million to the Retirement Plan. The Company anticipates that the annual contribution to the Retirement Plan in 20182023 will be in the range of $15.0 millionzero to $40.0$8.0 million. The Company expectsFor further discussion of the Company’s Retirement Plan, including actuarial assumptions, refer to Item 8 at Note K — Retirement Plan and Other Post-Retirement Benefits. As noted in that all subsidiaries having employees covered byfootnote, the Retirement Plan will make contributionshas been closed to new participants since 2003. In that regard, the average remaining service life of active participants in the Retirement Plan. The funding of such contributions will come from amounts collected in rates in the Utility and Pipeline and Storage segments or through cash on hand, cash from operations or short-term borrowings.Plan is approximately 6 years.
The Company provides health care and life insurance benefits (other post-retirement benefits) for a majority of its retired employees. The Company has established VEBA trusts and 401(h) accounts for its other post-retirement benefits. The Company has been making contributions to its VEBA trusts and/or 401(h) accounts over the last several years and anticipates that it will continuedoes not anticipate making contributions to the VEBA trusts and/or 401(h) accounts.accounts in the near term. However, this will be subject to future review. During 2017,2022, the Company contributed $3.8$2.8 million to its VEBA trusts. In addition, the Company made direct payments of $0.3 million to retirees not covered by the VEBA trusts and 401(h) accounts during 2022. The Company anticipates that the annual contributiondoes not expect to make any contributions to its VEBA trusts in 2018 will2023. For further discussion of the Company’s other post-retirement benefits, including actuarial assumptions, refer to Item 8 at Note K — Retirement Plan and Other Post-Retirement Benefits. As noted in that footnote, the other post-retirement benefits provided by the Company have been closed to new participants since 2003. In that regard, the average remaining service life of active participants is approximately 4 years for those eligible for other post-retirement benefits.
The Company has made certain guarantees on behalf of its subsidiaries. The guarantees relate primarily to: (i) obligations under derivative financial instruments, which are included on the Consolidated Balance Sheets in accordance with the authoritative guidance (see Item 7, MD&A under the heading “Critical Accounting Estimates - Accounting for Derivative Financial Instruments”); and (ii) other obligations which are reflected on the Consolidated Balance Sheets. The Company believes that the likelihood it would be inrequired to make payments under the range of $2.5 million to $4.0 million. The funding of such contributions will come from amounts collected in rates in the Utility and Pipeline and Storage segments.guarantees is remote.
MARKET RISK SENSITIVE INSTRUMENTS
Energy Commodity Price Risk
The Company uses various derivative financial instruments (derivatives), including price swap agreements and futures contracts,no cost collars, as part of the Company’s overall energy commodity price risk management strategy in its Exploration and Production and Energy Marketing segments.segment. Under this strategy, the Company manages a portion of the market risk associated with fluctuations in the price of natural gas, and crude oil, thereby attempting to provide more stability to operating results. The Company has operating procedures in place that are administered by experienced management to monitor compliance with the Company’s risk management policies. The derivatives are not held for trading purposes. The fair value of these derivatives, as shown below, represents the amount that the Company would receive from, or pay to, the respective counterparties at September 30, 20172022 to terminate the derivatives. However, the tables below and the fair value that is disclosed do not consider the physical side of the natural gas and crude oil transactions that are related to the financial instruments.
On July 21, 2010, the Dodd-Frank Act was signed into law. The Dodd-Frank Act required the CFTC, SEC and other regulatory agencies to promulgate rules and regulations implementing the legislation, and includes provisions related to the swaps and over-the-counter derivatives markets. Certain provisions of the Dodd-Frank Act relatedmarkets that are designed to derivatives became effective July 16, 2011, but other provisions related to derivativespromote transparency, mitigate systemic risk and protect against market abuse. Although regulators have or will become effective as federal agencies (including the CFTC, various banking regulators and the SEC) adopt rules to implement the law. Among other things, the Dodd-Frank Act (1) regulatesissued certain participants in the swaps markets, including new entities defined as “swap dealers” and “major swap participants,” (2) requires clearing and exchange-trading of certain swaps that the CFTC determines must be cleared, (3) requires reporting and recordkeeping of swaps, and (4) enhances the CFTC’s enforcement authority, including the authority to establish position limits on derivatives and increases penalties for violations of the Commodity Exchange Act. For purposes of the Dodd-Frank Act, under rules adopted by the SEC and/or CFTC, the Company believes that it qualifies as a non-financial end user of derivatives, that is, as a non-financial entity that uses derivatives to hedge or mitigate commercial risk. Nevertheless,regulations, other rules that may impact the Company have been adopted or are beingyet to be finalized. Rules developed could have a significant impact on the Company. For example, the CFTC has imposed numerous registration, swaps documentation, business conduct, reporting, and recordkeeping requirements on swap dealers and major swap participants, which frequently are counterparties to the Company’s derivative hedging transactions. While many of the final rules adopted 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 the final and proposed rules through higher transaction costs and prices or other direct or indirect costs. For example,Additionally, given the Dodd-Frank Act requires that certain swaps be cleared and traded on exchanges or swap execution facilities, with certain exceptions for swaps that end-users such as the Company useenforcement authority granted to hedge or mitigate commercial risk. While the Company expects to be excluded from these clearing and trading requirements for swaps used to
hedge its commercial risks, there may be increased transaction costs or decreased liquidity with respect to entering into such uncleared and non-exchange traded swaps. Also, during 2015, the bank regulators and the CFTC respectively, adopted final margin rules that apply to swap dealers and major swap participants with respect to uncleared swaps. While these rules do not impose a requirement on swap dealers and major swap participants to collect margin for uncleared swaps from non-financial end users such as the Company, the obligations may increase the costs of uncleared swaps. For example, among other things, to fulfill obligations imposed on them under the rules, swap dealers may seek to negotiate collateral or other credit arrangements in their swap agreements with counterparties, which would increase the cost of transactions in uncleared swaps and affect the Company’s liquidity and reduce our available cash. In 2016, the CFTC issued a reproposal to its position limit rules that would impose speculative position limits on positions in 28 core physical commodity contracts as well as economically equivalent futures, options and swaps. While the Company does not intend to enter into positions on a speculative basis, such rules could nevertheless impact the ability of the Company to enter into certain derivative hedging transactions with respect to such commodities. If we reduce our use of hedging transactions as a result of final regulations to be issued by the CFTC, our results of operations may become more volatile and our cash flows may be less predictable. The Dodd-Frank Act may also increase costs for derivative recordkeeping, reporting, documentation, position limit compliance, and other compliance; cause parties to materially alter the terms of derivative contracts; cause parties to restructure certain derivative contracts; reduce the availability of derivatives to protect against risks that the Company encounters or to optimize assets; reduce the Company’s ability to monetize or restructure existing derivative contracts; and increase the Company’s exposure to less creditworthy counterparties, all of which could increase the Company’s business costs. Finally, given the additional anti-market manipulation, anti-fraud and disruptive trading practices, regulations that prohibit, among other things, fraud and price manipulation in the physical commodities, futures, options and swaps markets, it is difficult to predict how the evolving
enforcement priorities of the CFTC will impact our business. Should wethe Company violate theany laws regulatingor regulations applicable to our hedging activities, or regulations promulgated by the CFTC, weit 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 ultimately have on its operations.
The accounting rulesauthoritative guidance for fair value measurements and disclosures require consideration of the impact of nonperformance risk (including credit risk) from a market participant perspective in the measurement of the fair value of assets and liabilities. At September 30, 2017,2022, the Company determined that nonperformance risk associated with the price swap agreements, no cost collars and foreign currency contracts would have no material impact on its financial position or results of operation. To assess nonperformance risk, the Company considered information such as any applicable collateral posted, master netting arrangements, and applied a market-based method by using the counterparty's (assuming the derivative is in a gain position) or the Company’s (assuming the derivative is in a loss position) credit default swaps rates.
The following tables disclose natural gas and crude oil price swap information by expected maturity dates for agreements in which the Company receives a fixed price in exchange for paying a variable price as quoted in various national natural gas publications or on the NYMEX. Notional amounts (quantities) are used to calculate the contractual payments to be exchanged under the contract. The weighted average variable prices represent the weighted average settlement prices by expected maturity date as of September 30, 2017.2022. At September 30, 2017,2022, the Company had not entered into any natural gas or crude oil price swap agreements extending beyond 2022 (the natural gas price swap agreements maturing in 2023 were insignificant).2026.
Natural Gas Price Swap Agreements
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Expected Maturity Dates |
| | 2018 | | 2019 | | 2020 | | 2021 | | 2022 | | Total |
| Notional Quantities (Equivalent Bcf) | 51.3 |
| | 33.8 |
| | 23.5 |
| | 5.3 |
| | 0.1 |
| | 114.0 |
|
| Weighted Average Fixed Rate (per Mcf) | $ | 3.44 |
| | $ | 3.26 |
| | $ | 3.17 |
| | $ | 3.13 |
| | $ | 3.05 |
| | $ | 3.32 |
|
| Weighted Average Variable Rate (per Mcf) | $ | 3.16 |
| | $ | 3.01 |
| | $ | 2.90 |
| | $ | 3.01 |
| | $ | 3.00 |
| | $ | 3.06 |
|
Of the total Bcf above, 1.6 Bcf is accounted for as fair value hedges at a weighted average fixed rate of $3.61 per Mcf. The remaining 112.4 Bcf are accounted for as cash flow hedges at a weighted average fixed rate of $3.18 per Mcf.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Expected Maturity Dates |
| | 2023 | | 2024 | | 2025 | | 2026 | | | | Total |
| Notional Quantities (Equivalent Bcf) | 112.8 | | | 65.7 | | | 26.8 | | | 2.0 | | | | | 207.3 | |
| Weighted Average Fixed Rate (per Mcf) | $ | 2.88 | | | $ | 3.07 | | | $ | 3.16 | | | $ | 3.18 | | | | | $ | 2.98 | |
| Weighted Average Variable Rate (per Mcf) | $ | 6.02 | | | $ | 4.86 | | | $ | 4.55 | | | $ | 4.32 | | | | | $ | 5.45 | |
At September 30, 2017, the Company had long (purchased) swaps covering 2.0 Bcf extending through 2022, at a weighted average fixed rate of $3.45 per Mcf and a weighted average settlement rate of $3.09 per Mcf. The Company had short (sold) swaps covering 112.0 Bcf extending through 2020 at a weighted average fixed rate of $3.31 per Mcf and a weighted average settlement rate of $3.06 per Mcf at September 30, 2017. At September 30, 2017, the Company would have received frompaid its respective counterparties an aggregate of approximately $27.3$512.3 million to terminate the natural gas price swap agreements outstanding at that date.
At September 30, 2016,2021, the Company had natural gas price swap agreements covering 158.6398.8 Bcf at a weighted average fixed rate of $3.68$2.84 per Mcf, which included long (purchased) swaps covering 2.3 Bcf extending through 2019 at aMcf.
No Cost Collars
The following table discloses the notional quantities, the weighted average fixed rate of $3.64 per Mcfceiling price and athe weighted average settlement rate of $3.13 per Mcf and short (sold) swaps covering 156.3 Bcffloor price for the no cost collars used by the Company to manage natural gas price risk. The no cost collars provide for the Company to receive monthly payments from (or make payments to) other parties when a variable price falls below an established floor price (the Company receives payment from the counterparty) or exceeds an established ceiling price (the Company pays the counterparty). At September 30, 2022, the Company had not entered into any natural gas no cost collars extending through 2021 at a weighted average fixed rate of $3.68 per Mcf and a weighted average settlement rate of $3.05 per Mcf.beyond 2027.
Crude Oil Price Swap Agreements
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | |
| | 2018 | | 2019 | | 2020 | | 2021 | | 2022 | | Total |
| Notional Quantities (Equivalent Bbls) | 1,755,000 |
| | 1,068,000 |
| | 324,000 |
| | 156,000 |
| | 156,000 |
| | 3,459,000 |
|
| Weighted Average Fixed Rate (per Bbl) | $ | 54.30 |
| | $ | 53.42 |
| | $ | 50.52 |
| | $ | 51.00 |
| | $ | 51.00 |
| | $ | 53.38 |
|
| Weighted Average Variable Rate (per Bbl) | $ | 52.04 |
| | $ | 51.13 |
| | $ | 50.59 |
| | $ | 50.58 |
| | $ | 50.82 |
| | $ | 51.50 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Expected Maturity Dates |
| 2023 | | 2024 | | 2025 | | 2026 | | 2027 | | Total |
| Natural Gas | | | | | | | | | | | |
| Notional Quantities (Equivalent Bcf) | 68.3 | | | 57.5 | | | 42.7 | | | 41.5 | | | 3.5 | | | 213.5 | |
| Weighted Average Ceiling Price (per Mcf) | $ | 3.75 | | | $ | 3.89 | | | $ | 4.79 | | | $ | 4.90 | | | $ | 4.90 | | | $ | 4.24 | |
| Weighted Average Floor Price (per Mcf) | $ | 3.20 | | | $ | 3.30 | | | $ | 3.60 | | | $ | 3.63 | | | $ | 3.63 | | | $ | 3.40 | |
At September 30, 2017,2022, the Company would have received from its respective counterpartieshad to pay an aggregate of approximately $6.4$270.5 million to terminate the crude oil price swap agreementsnatural gas no cost collars outstanding at that date.
At September 30, 2016,2021, the Company had crude oil price swapno cost collars agreements covering 1,755,000 Bbls20.9 Bcf at a weighted average fixed rate of $62.73 per Bbl.
Futures Contracts
The following table discloses the net contract volume purchased (sold), weighted average contract prices and weighted average settlement prices by expected maturity date for futures contracts used to manage natural gas price risk. At September 30, 2017, the Company did not hold any futures contracts with maturity dates extending beyond 2023.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Expected Maturity Dates |
| | 2018 | | 2019 | | 2020 | | 2021 | | 2022 | | 2023 | | Total |
Net Contract Volume Purchased (Sold) (Equivalent Bcf) | 4.4 |
| | 4.4 |
| | 1.4 |
| | 0.8 |
| | 0.7 |
| | 0.1 |
| | 11.8 |
|
| Weighted Average Contract Price (per Mcf) | $ | 3.41 |
| | $ | 3.12 |
| | $ | 3.08 |
| | $ | 2.99 |
| | $ | 2.99 |
| | $ | 2.99 |
| | $ | 3.32 |
|
| Weighted Average Settlement Price (per Mcf) | $ | 3.34 |
| | $ | 3.18 |
| | $ | 3.10 |
| | $ | 2.96 |
| | $ | 2.96 |
| | $ | 3.15 |
| | $ | 3.27 |
|
At September 30, 2017, the Company had long (purchased) contracts covering 15.3 Bcf of gas extending through 2023 at a weighted average contractceiling price of $3.15$3.25 per Mcf and a weighted average settlementfloor price of $3.16 per Mcf. All of this is accounted for as fair value hedges and are used by the Company’s Energy Marketing segment to hedge against rising prices, a risk to which this segment is exposed due to the fixed price gas sales commitments that it enters into with certain residential, commercial, industrial, public authority and wholesale customers. The Company would have received $0.1 million to terminate these contracts at September 30, 2017.
At September 30, 2017, the Company had short (sold) contracts covering 3.5 Bcf of gas extending through 2020 at a weighted average contract price of $3.47 per Mcf and a weighted average settlement price of $3.37 per Mcf. Of this amount, 2.4 Bcf is accounted for as cash flow hedges as these contracts relate to the anticipated sale of natural gas by the Company's Energy Marketing segment. The remaining 1.1 Bcf is accounted for as fair value hedges, the majority of which are used to hedge against falling prices, a risk to which the Energy Marketing segment
is exposed due to the fixed price gas purchase commitments that it enters into with certain natural gas suppliers. The Company would have received $0.4 million to terminate these contracts at September 30, 2017.
At September 30, 2016, the Company had long (purchased) contracts covering 10.5 Bcf of gas extending through 2019 at a weighted average contract price of $3.46 per Mcf and a weighted average settlement price of $3.39$2.81 per Mcf.
At September 30, 2016, the Company had short (sold) contracts covering 3.5 Bcf of gas extending through 2019 at a weighted average contract price of $3.71 per Mcf and a weighted average settlement price of $3.37 per Mcf.
Foreign Exchange Risk
The Company uses foreign exchange forward contracts to manage the risk of currency fluctuations associated with transportation costs denominated in Canadian currency in the Exploration and Production segment. All of these transactions are forecasted.
The following table discloses foreign exchange contract information by expected maturity dates. The Company receives a fixed price in exchange for paying a variable price as noted in the Canadian to U.S. dollar forward exchange rates. Notional amounts (Canadian dollars) are used to calculate the contractual payments to be exchanged under contract. The weighted average variable prices represent the weighted average settlement prices by expected maturity date as of September 30, 2017.2022. At September 30, 2017,2022, the Company had not entered into any foreign currency exchange contracts extending beyond 2026.2030.
| | | | Expected Maturity Dates | | Expected Maturity Dates |
| | 2018 | | 2019 | | 2020 | | 2021 | | 2022 | | Thereafter | | Total | | 2023 | | 2024 | | 2025 | | 2026 | | 2027 | | Thereafter | | Total |
| Notional Quantities (Canadian Dollar in millions) | $ | 14.4 |
| | $ | 14.4 |
| | $ | 14.4 |
| | $ | 11.1 |
| | $ | 11.1 |
| | $ | 23.8 |
| | $ | 89.2 |
| Notional Quantities (Canadian Dollar in millions) | $ | 14.7 | | | $ | 12.9 | | | $ | 10.9 | | | $ | 3.1 | | | $ | 2.4 | | | $ | 5.4 | | | $ | 49.4 | |
| Weighted Average Fixed Rate ($Cdn/$US) | $ | 1.25 |
| | $ | 1.25 |
| | $ | 1.24 |
| | $ | 1.30 |
| | $ | 1.29 |
| | $ | 1.27 |
| | $ | 1.26 |
| Weighted Average Fixed Rate ($Cdn/$US) | $ | 1.29 | | | $ | 1.29 | | | $ | 1.28 | | | $ | 1.32 | | | $ | 1.33 | | | $ | 1.34 | | | $ | 1.29 | |
| Weighted Average Variable Rate ($Cdn/$US) | $ | 1.24 |
| | $ | 1.25 |
| | $ | 1.25 |
| | $ | 1.27 |
| | $ | 1.26 |
| | $ | 1.26 |
| | $ | 1.25 |
| Weighted Average Variable Rate ($Cdn/$US) | $ | 1.34 | | | $ | 1.33 | | | $ | 1.32 | | | $ | 1.34 | | | $ | 1.34 | | | $ | 1.34 | | | $ | 1.33 | |
At September 30, 2017,2022, absent other positions with the same counterparties, the Company would have received frompaid to its respective counterparties an aggregate of $0.8$1.9 million to terminate these foreign exchange contracts.
Refer to Item 8 at Note GJ — Financial Instruments for a discussion of the Company’s exposure to credit risk related to its derivative financial instruments.
Interest Rate Risk
The fair value of long-term fixed rate debt is $2.5 billion at September 30, 2017.2022. This fair value amount is not intended to reflect principal amounts that the Company will ultimately be required to pay. The following table presents the principal cash repayments and related weighted average interest rates by expected maturity date for the Company’s long-term fixed rate debt:
| | | Principal Amounts by Expected Maturity Dates | | Principal Amounts by Expected Maturity Dates |
| | 2018 | | 2019 | | 2020 | | 2021 | | 2022 | | Thereafter | | Total | | 2023 | | 2024 | | 2025 | | 2026 | | 2027 | | Thereafter | | Total |
| | (Dollars in millions) | | (Dollars in millions) |
| Long-Term Fixed Rate Debt | $ | 300.0 |
| | $ | 250.0 |
| | $ | — |
| | $ | — |
| | $ | 500.0 |
| | $ | 1,349.0 |
| | $ | 2,399.0 |
| Long-Term Fixed Rate Debt | $ | 549.0 | | $ | — | | $ | 500.0 | | $ | 500.0 | | $ | 300.0 | | $ | 800.0 | | $ | 2,649.0 |
| Weighted Average Interest Rate Paid | 6.5 | % | | 8.8 | % | | — |
| | — |
| | 4.9 | % | | 4.5 | % | | 5.3 | % | Weighted Average Interest Rate Paid | 4.1% | | — | | 5.4% | | 5.5% | | 4.0% | | 3.6% | | 4.5% |
RATE AND REGULATORY MATTERS
Utility Operation
Delivery rates for both the New York and Pennsylvania divisions are regulated by the states’ respective public utility commissions and typically are changed only when approved through a procedure known as a “rate case.”
Although As noted below, the Pennsylvania division does not havecurrently has a rate case on file, see below for a description of the current rate proceedings affecting the New York division.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
On April 28, 2016, Distribution Corporation commenced a rate caseCorporation's current delivery rates in its New York jurisdiction were approved by filing proposed tariff amendments and supporting testimony requesting approval to increase its annual revenues by approximately $41.7 million. Distribution Corporation explainedthe NYPSC in the filing that its request for rate relief was necessitated by a revenue requirement driven primarily by rate base growth, higher operating expense and higher depreciation expense, among other things. On January 23, 2017, the administrative law judge assigned to the proceedingan order issued a recommended decision (RD) in the case. The RD, as revised on January 26, 2017, recommended a rate increase designed to provide additional annual revenues of $8.5 million, an equity ratio, subject to update of 42.3% based on the Company’s equity ratio, and a cost of equity, subject to update of 8.6%. On April 20, 2017 the NYPSC issued an Order adopting some provisions of the RD and modifying or rejecting others. The Order provides for an annual rate increase of $5.9 million. The rate increase becamewith rates becoming effective May 1, 2017. The Order further providesorder provided for a return on equity of 8.7%, and established an equity ratio of 42.9%. The Order also directsdirected the implementation of an earnings sharing mechanism to be in place beginning on April 1, 2018. The order also authorized the Company to recover approximately $15 million annually for pension and other post-employment benefit ("OPEB") expenses from customers. Because the Company's future pension and OPEB costs were projected to be satisfied with existing funds held in reserve, in July, Distribution Corporation made a filing with the NYPSC to effectuate a pension and OPEB surcredit to customers to offset these amounts being collected in base rates effective October 1, 2022. On September 16,
2022, the NYPSC issued an order approving the filing. With the implementation of this surcredit, Distribution Corporation will no longer be funding the pension from its New York jurisdiction and it will not be funding its VEBA trusts in its New York jurisdiction.
On July 28, 2017, Distribution Corporation filed an appeal with New York State Supreme Court, Albany County, seeking review of the Order. The appeal contends that portions of the Order should be invalidated because they fail to meet the applicable legal standard for agency decisions. On OctoberAugust 13, 2017,2021, the NYPSC filedissued an answerorder extending the date through which containedqualified 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 requestbase rate case that the appeal be transferredwould result in new rates becoming effective prior to the Appellate Division. The Company cannot predict the outcome of the appeal at this time.April 1, 2023.
Pennsylvania Jurisdiction
Distribution Corporation’s current delivery chargesrates in its Pennsylvania jurisdiction were approved by the PaPUC on November 30, 2006 as part of a settlement agreement that became effective January 1, 2007. On October 28, 2022, Distribution Corporation made a filing with the PaPUC seeking an increase in its annual base rate operating revenues of $28.1 million with a proposed effective date of December 27, 2022. The Company is also proposing, among other things, to implement a weather normalization adjustment mechanism and a new energy efficiency and conservation pilot program for residential customers. The filing will be suspended for seven months by operation of law unless directed otherwise by the PaPUC.
Effective October 1, 2021, pursuant to a tariff supplement filed with the PaPUC, Distribution Corporation reduced base rates by $7.7 million in order to stop collecting OPEB expenses from customers. It also began to refund to customers overcollected OPEB expenses in the amount of $50.0 million. Certain other matters in the tariff supplement were unresolved. These matters were resolved with the PaPUC's approval of an Administrative Law Judge's Recommended Decision on February 24, 2022. Concurrent with that decision, the Company discontinued regulatory accounting for OPEB expenses and recorded an $18.5 million adjustment during the quarter ended March 31, 2022 to reduce its regulatory liability for previously deferred OPEB income amounts through September 30, 2021 and to increase Other Income (Deductions) on the consolidated financial statements by a like amount. The Company also increased customer refunds of overcollected OPEB expenses from $50.0 million to 54.0 million. All refunds specified in the tariff supplement are being funded entirely by grantor trust assets held by the Company, most of which are included in a fixed income mutual fund that is a component of Other Investments on the Company's Consolidated Balance Sheet. With the elimination of OPEB expenses in base rates, Distribution Corporation is no longer funding the grantor trust or its VEBA trusts in its Pennsylvania jurisdiction.
Pipeline and Storage
Supply Corporation’s 2020 rate settlement provides that no party may make a rate filing for new rates to be effective before February 1, 2024, except that Supply Corporation currently has no activemay file an NGA general Section 4 rate case on file.to change rates if the corporate federal income tax rate is increased. If no case has been filed, Supply Corporation's currentCorporation must file for rates to be effective February 1, 2025.
Empire’s 2019 rate settlement requiresprovides that Empire must make a rate case filing no later than December 31, 2019.
Empire currently has no active rate case on file. Empire’s current rate settlement requires a rate case filing no later than JulyMay 1, 2021.2025.
ENVIRONMENTAL MATTERS
The Company is subject to various federal, state and local laws and regulations relating to the protection of the environment. The Company has established procedures for the ongoing evaluation of its operations to identify potential environmental exposures and comply with regulatory requirements. In 2021, the Company set methane intensity reduction targets at each of its businesses, an absolute greenhouse gas emissions reduction target for the consolidated Company, and greenhouse gas reduction targets associated with the Company’s utility delivery system. In 2022, the Company began measuring progress against these reduction targets. The Company's ability to estimate accurately the time, costs and resources necessary to meet emissions targets may change as environmental exposures and opportunities change and regulatory updates are issued.
For further discussion of the Company's environmental exposures, refer to Item 8 at Note IL — Commitments and Contingencies under the heading “Environmental Matters.”
While changes in environmental laws and regulatory measures to address climate change and greenhouse gas emissions are in various phases of discussion or implementation. Inregulations could have an adverse financial impact on the United States, these efforts include legislative proposals and EPA regulations at the federal level, actions at the state level, and private party litigation related to greenhouse gas emissions. While the U.S. Congress has from time to time considered legislation aimed at reducing emissions of greenhouse gases, Congress has not yet passed any federal climate change legislation and we cannot predict when or if Congress will pass such legislation and in what form. In the absence of such legislation, the EPA is regulating greenhouse gas emissions pursuant to the authority granted to it by the federal Clean Air Act. For example, in April 2012, the EPA adopted rules which restrict emissions associated with oil and natural gas drilling. The EPA previously adopted final regulations that set methane and volatile organic compound emissions standards for new or modified
oil and gas emissions sources. These rules impose more stringent leak detection and repair requirements, and further address reporting and control of methane and volatile organic compound emissions. The current administration has issued executive orders to roll back many of these regulations, and, in turn, litigation (not involving the Company) has been instituted to challenge the administration's efforts. The Company, must continue to comply with all applicable regulations. In addition, the U.S. Congress has from time to time considered bills that would establish a cap-and-trade program to reduce emissions of greenhouse gases. A number of states have adopted energy strategies or plans with goals that include the reduction of greenhouse gas emissions. New York’s State Energy Plan, which includes Reforming the Energy Vision (REV) initiatives, sets greenhouse gas emission reduction targets of 40% by 2030 and 80% by 2050. Additionally, the Plan targets that 50% of electric generation must come from renewable energy sources by 2030. With respect to its operations in California, the Company currently complies with California cap-and-trade guidelines, which increases the Company's cost of environmental compliance in its Exploration and Production segment operations. Legislation or regulation that aims to reduce greenhouse gas emissions could also include carbon taxes, restrictive permitting, increased efficiency standards, and incentives or mandates to conserve energy or use renewable energy sources. Federal, state or local governments may, for example, 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. These climate change and greenhouse gas initiatives could increase the Company’s cost of environmental compliance by requiring the Company to install new equipment to reduce emissions from larger facilities and/or purchase emission allowances. They could also delay or otherwise negatively affect efforts to obtain permits and other regulatory approvals with regard to existing and new facilities, impose additional monitoring and reporting requirements, and reduce demand for oil and natural gas. But legislation or regulation that sets a price on or otherwise restricts carbon emissions could also benefit the Company by increasing demand for natural gas, because substantially fewer carbon emissions per Btu of heat generated are associated with the use of natural gas than with certain alternate fuels such as coal and oil. The effect (material or not) on the Company of any new legislative or regulatory measures will depend on the particular provisions that are ultimately adopted.
NEW AUTHORITATIVE ACCOUNTING AND FINANCIAL REPORTING GUIDANCEEnvironmental Regulation
Legislative and regulatory measures to address climate change and greenhouse gas emissions are in various phases of discussion or implementation in the United States. These efforts include legislation, legislative proposals and new regulations at the state and federal level, and private party litigation related to greenhouse gas emissions. Legislation or regulation that aims to reduce greenhouse gas emissions could also include emissions limits, reporting requirements, carbon taxes, restrictive permitting, increased efficiency standards, and incentives or mandates to conserve energy or use renewable energy sources. For discussionexample, the Inflation Reduction Act of 2022 (IRA) legislation was signed into law on August 16, 2022. The IRA includes a methane charge that is expected to be applicable to the reported annual methane emissions of certain oil and gas facilities, above specified methane intensity thresholds, starting in calendar year 2024. This portion of the recently issued authoritative accountingIRA is to be administered by the EPA and potential fees will begin with emissions reported for calendar year 2024. The EPA regulates greenhouse gas emissions pursuant to the Clean Air Act. The regulations implemented by the EPA impose more stringent leak detection and repair requirements, and further address reporting and control of methane and volatile organic compound emissions. The Company must continue to comply with all applicable regulations. Additionally, a number of states have adopted energy strategies or plans with aggressive goals for the reduction of greenhouse gas emissions. Pennsylvania has a methane reduction framework with the stated goal of reducing methane emissions from well sites, compressor stations and pipelines. Pennsylvania's Governor also entered the Commonwealth into a cap-and-trade program known as the Regional Greenhouse Gas Initiative, however, the Commonwealth's participation is currently stayed due to ongoing litigation. Federal, state or local governments may provide tax advantages and other subsidies to support alternative energy sources, mandate the use of specific fuels or technologies, or promote research into new technologies to reduce the cost and increase the scalability of alternative energy sources. The NYPSC, for example, initiated a proceeding to consider climate-related financial disclosures at the utility operating company level, and the New York State legislature passed the CLCPA that mandates reducing greenhouse gas emissions by 40% from 1990 levels by 2030, and by 85% from 1990 levels by 2050, with the remaining emission reduction achieved by controlled offsets. The CLCPA also requires electric generators to meet 70% of demand with renewable energy by 2030 and 100% with zero emissions generation by 2040. These climate change and greenhouse gas initiatives could impact the Company's customer base and assets depending on the promulgation of final regulations and on regulatory treatment afforded in the process. Thus far, the only regulations promulgated in connection with the CLCPA are greenhouse gas emissions limits established by the NYDEC in 6 NYCRR Part 496, effective December 30, 2020. The NYDEC has until January 1, 2024 to issue further rules and regulations implementing the statute. The above-enumerated initiatives could also increase the Company’s cost of environmental compliance by increasing reporting guidance, referrequirements, 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 Item 8 at Note A — Summaryobtain permits and other regulatory approvals. Changing market conditions and new regulatory requirements, as well as unanticipated or inconsistent application of Significant Accounting Policies under the heading “New Authoritative Accountingexisting laws and Financial Reporting Guidance.”regulations by administrative agencies, make it difficult to predict a long-term business impact across twenty or more years.
EFFECTS OF INFLATION
Although the rate of inflation has been relatively low over the past few years, theThe Company’s operations remainare 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 naturebusinesses, recovery of increasing costs from customers can be delayed by the regulatory process of a significant portion of its business.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-K to make applicable and take advantage of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by, or on behalf of, the Company. Forward-looking statements include statements concerning plans, objectives, goals, projections, strategies, future events or performance, and underlying assumptions and other statements which are other than statements of historical facts. From time to time, the Company may publish or otherwise make available forward-looking statements of this nature. All such subsequent forward-looking statements, whether written or oral and whether made by or on behalf of the Company, are also expressly qualified by these cautionary statements. Certain statements contained in this report, including, without limitation, statements regarding future prospects, plans, objectives, goals, projections, estimates of oil and gas quantities, strategies, future events or performance and underlying assumptions, capital structure, anticipated capital expenditures, completion of construction projects, projections for pension and other post-retirement benefit obligations, impacts of the adoption of new authoritative accounting rules,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:
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1. | Delays or changes in costs or plans with respect to Company projects or related projects of other companies, including difficulties or delays in obtaining necessary governmental approvals, permits or orders or in obtaining the cooperation of interconnecting facility operators; |
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2. | Governmental/regulatory actions, initiatives and proceedings, including those involving rate cases (which address, among other things, target rates of return, rate design and retained natural gas), environmental/safety requirements, affiliate relationships, industry structure, and franchise renewal; |
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3. | 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; |
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4. | Impairments under the SEC’s full cost ceiling test for natural gas and oil reserves; |
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5. | Changes in the price of natural gas or oil; |
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6. | 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; |
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7. | Factors affecting the Company’s ability to successfully identify, drill for and produce economically viable natural gas and oil reserves, including among others geology, lease availability, title disputes, weather conditions, shortages, delays or unavailability of equipment and services required in drilling operations, insufficient gathering, processing and transportation capacity, the need to obtain governmental approvals and permits, and compliance with environmental laws and regulations; |
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8. | Increasing health care costs and the resulting effect on health insurance premiums and on the obligation to provide other post-retirement benefits; |
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9. | Changes in price differentials between similar quantities of natural gas or oil at different geographic locations, and the effect of such changes on commodity production, revenues and demand for pipeline transportation capacity to or from such locations; |
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10. | Other changes in price differentials between similar quantities of natural gas or oil having different quality, heating value, hydrocarbon mix or delivery date; |
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11. | The cost and effects of legal and administrative claims against the Company or activist shareholder campaigns to effect changes at the Company; |
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12. | Uncertainty of oil and gas reserve estimates; |
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13. | Significant differences between the Company’s projected and actual production levels for natural gas or oil; |
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14. | Changes in demographic patterns and weather conditions; |
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15. | Changes in the availability, price or accounting treatment of derivative financial instruments; |
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16. | 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; |
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;
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17. | Changes in economic conditions, including global, national or regional recessions, and their effect on the demand for, and customers’ ability to pay for, the Company’s products and services; |
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18. | The creditworthiness or performance of the Company’s key suppliers, customers and counterparties; |
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19. | Economic disruptions or uninsured losses resulting from major accidents, fires, severe weather, natural disasters, terrorist activities, acts of war, cyber attacks or pest infestation; |
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20. | Significant differences between the Company’s projected and actual capital expenditures and operating expenses; or |
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21. | Increasing costs of insurance, changes in coverage and the ability to obtain insurance. |
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;
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 SEC’s full cost ceiling test for natural gas reserves;
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.The Company's ability to successfully integrate acquired assets and achieve expected cost synergies;
13.Changes in price differentials between similar quantities of natural gas sold at different geographic locations, and the effect of such changes on commodity production, revenues and demand for pipeline transportation capacity to or from such locations;
14.The impact of information technology disruptions, cybersecurity or data security breaches;
15.Factors affecting the Company’s ability to successfully identify, drill for and produce economically viable natural gas reserves, including among others geology, lease availability and costs, title disputes, weather conditions, shortages, delays or unavailability of equipment and services required in drilling operations, insufficient gathering, processing and transportation capacity, the need to obtain governmental approvals and permits, and compliance with environmental laws and regulations;
16.Increasing health care costs and the resulting effect on health insurance premiums and on the obligation to provide other post-retirement benefits;
17.Other changes in price differentials between similar quantities of natural gas having different quality, heating value, hydrocarbon mix or delivery date;
18.The cost and effects of legal and administrative claims against the Company or activist shareholder campaigns to effect changes at the Company;
19.Negotiations with the collective bargaining units representing the Company's workforce, including potential work stoppages during negotiations;
20.Uncertainty of gas reserve estimates;
21.Significant differences between the Company’s projected and actual production levels for natural gas;
22.Changes in demographic patterns and weather conditions (including those related to climate change);
23.Changes in the availability, price or accounting treatment of derivative financial instruments;
24.Changes in laws, actuarial assumptions, the interest rate environment and the return on plan/trust assets related to the Company’s pension and other post-retirement benefits, which can affect future funding obligations and costs and plan liabilities;
25.Economic disruptions or uninsured losses resulting from major accidents, fires, severe weather, natural disasters, terrorist activities or acts of war, as well as economic and operational disruptions due to third-party outages;
26.Significant differences between the Company’s projected and actual capital expenditures and operating expenses; or
27.Increasing costs of insurance, changes in coverage and the ability to obtain insurance.
The Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date hereof.
Forward-looking and other statements in this Annual Report on Form 10-K 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.
INDUSTRY AND MARKET DATA DISCLOSURE
The market data and certain other statistical information used throughout this Form 10-K are based on independent industry publications, government publications or other published independent sources. Some data is also based on the Company's good faith estimates. Although the Company believes these third-party sources are reliable and that the information is accurate and complete, it has not independently verified the information.
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| Item 7A | Quantitative and Qualitative Disclosures About Market Risk |
Refer to the “Market Risk Sensitive Instruments” section in Item 7, MD&A.
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| Item 8 | Financial Statements and Supplementary Data |
Index to Financial Statements
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| Financial Statements: | |
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Financial Statements and Financial Statement Schedule: | |
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All other schedules are omitted because they are not applicable or the required information is shown in the Consolidated Financial Statements or Notes thereto.
Supplementary Data
Supplementary data that is included in Note K — Quarterly Financial Data (unaudited) and Note MN — Supplementary Information for Oil and Gas Producing Activities (unaudited), appears under this Item, and reference is made thereto.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRMReport of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholders of National Fuel Gas Company:Company
Opinions on the Financial Statements and Internal Control over Financial Reporting
We have audited the consolidated financial statements, including the related notes, of National Fuel Gas Company and its subsidiaries (the “Company”) as listed in the accompanying index (collectively referred to as the “consolidated financial statements”). We also have audited the Company's internal control over financial reporting as of September 30, 2022, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
In our opinion, the consolidatedfinancial statements listed in the accompanying index,referred to above present fairly, in all material respects, the financial position of National Fuel Gasthe Companyand its subsidiariesas ofSeptember 30, 20172022 and September 30, 2016,2021, and the results of theirits operations and theirits cash flows for each of the three years in the period ended September 30, 20172022 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the accompanying indexpresents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidatedfinancial statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of September 30, 2017,2022, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). COSO.
Basis for Opinions
The Company's management is responsible for these consolidated financial statements, and financial statement schedule, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in Management's Annual Report on Internal Control over Financial Reporting appearing under itemItem 9A. Our responsibility is to express opinions on thesethe Company’s consolidated financial statements on the financial statement schedule, and on the Company's internal control over financial reporting based on our integrated audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.
Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence supportingregarding the amounts and disclosures in the consolidated financial statements, assessingstatements. Our audits also included evaluating the accounting principles used and significant estimates made by management, andas well as evaluating the overall presentation of the consolidated financial statement presentation.statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.deteriorate.
Critical Audit Matters
The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
The Impact of Proved Natural Gas Reserves on Natural Gas Properties, Net
As described in Note A to the consolidated financial statements, the Exploration and Production segment includes capitalized costs relating to natural gas producing activities, net of depreciation, depletion, and amortization (DD&A) of $1.9 billion as of September 30, 2022. The Exploration and Production segment follows the full cost method of accounting. Under this method, all costs associated with property acquisition, exploration and development activities are capitalized and DD&A is computed based on quantities produced in relation to proved reserves using the units of production method. As disclosed by management, in addition to DD&A under the units-of-production method, proved reserves are a major component in the SEC full cost ceiling test. The ceiling test, which is performed each quarter, determines a limit, or ceiling, on the amount of property acquisition, exploration and development costs that can be capitalized. If capitalized costs, net of accumulated DD&A and related deferred income taxes, exceed the ceiling at the end of any quarter, a permanent impairment is required to be charged to earnings in that quarter. There were no ceiling test impairment charges for the year ended September 30, 2022. As of September 30, 2022, the ceiling exceeded the book value of the natural gas properties by approximately $3.2 billion. Estimates of the Company’s proved natural gas reserves and the future net cash flows from those reserves were prepared by the Company’s petroleum engineers and audited by independent petroleum engineers (together referred to as “management’s specialists”). Petroleum engineering involves significant assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. Estimates of economically recoverable natural gas reserves and of future net cash flows depend upon a number of variable factors and assumptions, including quantities of natural gas that are ultimately recovered, the timing of the recovery of natural gas reserves, the production and operating costs to be incurred, the amount and timing of future development and abandonment expenditures, and the price received for the production.
The principal considerations for our determination that performing procedures relating to the impact of proved natural gas reserves on natural gas properties, net is a critical audit matter are the significant judgment by management, including the use of management’s specialists, when developing the estimates of proved natural gas reserves, which in turn led to a high degree of auditor judgment, subjectivity and effort in performing procedures and evaluating evidence related to the data, methods, and assumptions used by management and its specialists in developing the estimates of quantities of proved natural gas that are ultimately recovered.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s estimates of proved natural gas reserves that are utilized in the DD&A expense and ceiling test calculations. These procedures also included, among others, evaluating the reasonableness of the significant assumptions used by management related to the quantities of natural gas that are ultimately recovered. Evaluating the reasonableness of the significant assumptions included evaluating information on additional development activity, production history, if the assumptions used were reasonable considering the past performance of the Company, and whether they were consistent with evidence obtained in other areas of the audit. The work of management’s specialists was used in performing the procedures to evaluate the reasonableness of the estimates of proved natural gas reserves. As a basis for using this work, the specialists’ qualifications and objectivity were understood and the Company’s relationship with the specialists assessed. The procedures performed also included evaluation of the methods and assumptions used by the specialists, tests of the data used by the specialists and an evaluation of the specialists’ findings.
/s/ PRICEWATERHOUSECOOPERS LLP
Buffalo, New York
November 17, 201718, 2022
We have served as the Company’s auditor since1941.
NATIONAL FUEL GAS COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND EARNINGS
REINVESTED IN THE BUSINESS
| | | | Year Ended September 30 | | Year Ended September 30 |
| | 2017 | | 2016 | | 2015 | | 2022 | | 2021 | | 2020 |
| | (Thousands of dollars, except per common share amounts) | | (Thousands of dollars, except per common share
amounts) |
| INCOME | | | | | | INCOME | |
| Operating Revenues: | | | | | | Operating Revenues: | |
| Utility and Energy Marketing Revenues | $ | 755,485 |
| | $ | 624,602 |
| | $ | 860,618 |
| Utility and Energy Marketing Revenues | $ | 897,916 | | | $ | 667,549 | | | $ | 728,336 | |
| Exploration and Production and Other Revenues | 617,666 |
| | 611,766 |
| | 696,709 |
| Exploration and Production and Other Revenues | 1,010,629 | | | 837,597 | | | 611,885 | |
| Pipeline and Storage and Gathering Revenues | 206,730 |
| | 216,048 |
| | 203,586 |
| Pipeline and Storage and Gathering Revenues | 277,501 | | | 237,513 | | | 206,070 | |
| | 1,579,881 |
| | 1,452,416 |
| | 1,760,913 |
| |
| | | | | | | | 2,186,046 | | | 1,742,659 | | | 1,546,291 | |
| Operating Expenses: | | | | | | Operating Expenses: | | | | | |
| Purchased Gas | 275,254 |
| | 147,982 |
| | 349,984 |
| Purchased Gas | 392,093 | | | 171,827 | | | 233,890 | |
| Operation and Maintenance: |
|
| |
|
| |
|
| Operation and Maintenance: | |
| Utility and Energy Marketing | 199,293 |
| | 192,512 |
| | 203,249 |
| Utility and Energy Marketing | 193,058 | | | 179,547 | | | 181,051 | |
| Exploration and Production and Other | 145,099 |
| | 160,201 |
| | 184,024 |
| Exploration and Production and Other | 191,572 | | | 173,041 | | | 148,856 | |
| Pipeline and Storage and Gathering | 98,200 |
| | 88,801 |
| | 82,730 |
| Pipeline and Storage and Gathering | 136,571 | | | 123,218 | | | 108,640 | |
| Property, Franchise and Other Taxes | 84,995 |
| | 81,714 |
| | 89,564 |
| Property, Franchise and Other Taxes | 101,182 | | | 94,713 | | | 88,400 | |
| Depreciation, Depletion and Amortization | 224,195 |
| | 249,417 |
| | 336,158 |
| Depreciation, Depletion and Amortization | 369,790 | | | 335,303 | | | 306,158 | |
| Impairment of Oil and Gas Producing Properties | — |
| | 948,307 |
| | 1,126,257 |
| Impairment of Oil and Gas Producing Properties | — | | | 76,152 | | | 449,438 | |
| | 1,027,036 |
| | 1,868,934 |
| | 2,371,966 |
| | 1,384,266 | | | 1,153,801 | | | 1,516,433 | |
| Operating Income (Loss) | 552,845 |
| | (416,518 | ) | | (611,053 | ) | |
| Gain on Sale of Assets | | Gain on Sale of Assets | 12,736 | | | 51,066 | | | — | |
| Operating Income | | Operating Income | 814,516 | | | 639,924 | | | 29,858 | |
| Other Income (Expense): | | | | | | Other Income (Expense): | |
| Other Income | 7,043 |
| | 9,820 |
| | 8,039 |
| |
| Interest Income | 4,113 |
| | 4,235 |
| | 3,922 |
| |
| | Other Income (Deductions) | | Other Income (Deductions) | (1,509) | | | (15,238) | | | (17,814) | |
| Interest Expense on Long-Term Debt | (116,471 | ) | | (117,347 | ) | | (95,916 | ) | Interest Expense on Long-Term Debt | (120,507) | | | (141,457) | | | (110,012) | |
| Other Interest Expense | (3,366 | ) | | (3,697 | ) | | (3,555 | ) | Other Interest Expense | (9,850) | | | (4,900) | | | (7,065) | |
| Income (Loss) Before Income Taxes | 444,164 |
| | (523,507 | ) | | (698,563 | ) | Income (Loss) Before Income Taxes | 682,650 | | | 478,329 | | | (105,033) | |
| Income Tax Expense (Benefit) | 160,682 |
| | (232,549 | ) | | (319,136 | ) | |
| Income Tax Expense | | Income Tax Expense | 116,629 | | | 114,682 | | | 18,739 | |
| Net Income (Loss) Available for Common Stock | 283,482 |
| | (290,958 | ) | | (379,427 | ) | Net Income (Loss) Available for Common Stock | 566,021 | | | 363,647 | | | (123,772) | |
| EARNINGS REINVESTED IN THE BUSINESS | | | | | | EARNINGS REINVESTED IN THE BUSINESS | | | | | |
| Balance at Beginning of Year | 676,361 |
| | 1,103,200 |
| | 1,614,361 |
| Balance at Beginning of Year | 1,191,175 | | | 991,630 | | | 1,272,601 | |
| | 959,843 |
| | 812,242 |
| | 1,234,934 |
| | 1,757,196 | | | 1,355,277 | | | 1,148,829 | |
| Dividends on Common Stock | (140,090 | ) | | (135,881 | ) | | (131,734 | ) | Dividends on Common Stock | (170,111) | | | (164,102) | | | (156,249) | |
Cumulative Effect of Adoption of Authoritative Guidance for Stock-Based Compensation | 31,916 |
| | — |
| | — |
| |
Cumulative Effect of Adoption of Authoritative Guidance for Hedging | | Cumulative Effect of Adoption of Authoritative Guidance for Hedging | — | | | — | | | (950) | |
| | Balance at End of Year | $ | 851,669 |
| | $ | 676,361 |
| | $ | 1,103,200 |
| Balance at End of Year | $ | 1,587,085 | | | $ | 1,191,175 | | | $ | 991,630 | |
| Earnings Per Common Share: | | | | | | |
| Earnings (Loss) Per Common Share: | | Earnings (Loss) Per Common Share: | | | | | |
| Basic: | | | | | | Basic: | |
| Net Income (Loss) Available for Common Stock | $ | 3.32 |
| | $ | (3.43 | ) | | $ | (4.50 | ) | Net Income (Loss) Available for Common Stock | $ | 6.19 | | | $ | 3.99 | | | $ | (1.41) | |
| Diluted: | | | | | | Diluted: | | | | | |
| Net Income (Loss) Available for Common Stock | $ | 3.30 |
| | $ | (3.43 | ) | | $ | (4.50 | ) | Net Income (Loss) Available for Common Stock | $ | 6.15 | | | $ | 3.97 | | | $ | (1.41) | |
| Weighted Average Common Shares Outstanding: | | | | | | Weighted Average Common Shares Outstanding: | | | | | |
| Used in Basic Calculation | 85,364,929 |
| | 84,847,993 |
| | 84,387,755 |
| Used in Basic Calculation | 91,410,625 | | | 91,130,941 | | | 87,968,895 | |
| Used in Diluted Calculation | 86,021,386 |
| | 84,847,993 |
| | 84,387,755 |
| Used in Diluted Calculation | 92,107,066 | | | 91,684,583 | | | 87,968,895 | |
See Notes to Consolidated Financial Statements
NATIONAL FUEL GAS COMPANY
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
|
| | | | | | | | | | | |
| | Year Ended September 30 |
| | 2017 | | 2016 | | 2015 |
| | (Thousands of dollars) |
| Net Income (Loss) Available for Common Stock | $ | 283,482 |
| | $ | (290,958 | ) | | $ | (379,427 | ) |
| Other Comprehensive Income (Loss), Before Tax: | | | | | |
| Increase (Decrease) in the Funded Status of the Pension and Other Post-Retirement Benefit Plans | 15,661 |
| | (21,378 | ) | | (31,538 | ) |
| Reclassification Adjustment for Amortization of Prior Year Funded Status of the Pension and Other Post-Retirement Benefit Plans | 13,433 |
| | 10,068 |
| | 9,217 |
|
| Unrealized Gain (Loss) on Securities Available for Sale Arising During the Period | 4,008 |
| | 1,524 |
| | (3,234 | ) |
| Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period | 5,347 |
| | 60,493 |
| | 381,018 |
|
| Reclassification Adjustment for Realized (Gains) Losses on Securities Available for Sale in Net Income | (1,575 | ) | | (1,374 | ) | | (591 | ) |
| Reclassification Adjustment for Realized (Gains) Losses on Derivative Financial Instruments in Net Income | (81,605 | ) | | (220,919 | ) | | (184,953 | ) |
| Other Comprehensive Income (Loss), Before Tax | (44,731 | ) | | (171,586 | ) | | 169,919 |
|
| Income Tax Expense (Benefit) Related to the Increase (Decrease) in the Funded Status of the Pension and Other Post-Retirement Benefit Plans | 6,175 |
| | (8,351 | ) | | (11,922 | ) |
| Reclassification Adjustment for Income Tax Benefit Related to the Amortization of the Prior Year Funded Status of the Pension and Other Post-Retirement Benefit Plans | 4,929 |
| | 3,723 |
| | 3,375 |
|
| Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) on Securities Available for Sale Arising During the Period | 1,505 |
| | 592 |
| | (1,195 | ) |
| Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period | 2,009 |
| | 18,648 |
| | 160,872 |
|
| Reclassification Adjustment for Income Tax Benefit (Expense) on Realized Losses (Gains) from Securities Available for Sale in Net Income | (580 | ) | | (527 | ) | | (217 | ) |
| Reclassification Adjustment for Income Tax Benefit (Expense) on Realized Losses (Gains) from Derivative Financial Instruments in Net Income | (34,286 | ) | | (86,659 | ) | | (78,345 | ) |
| Income Taxes — Net | (20,248 | ) | | (72,574 | ) | | 72,568 |
|
| Other Comprehensive Income (Loss) | (24,483 | ) | | (99,012 | ) | | 97,351 |
|
| Comprehensive Income (Loss) | $ | 258,999 |
| | $ | (389,970 | ) | | $ | (282,076 | ) |
| | | | | | | | | | | | | | | | | |
| | Year Ended September 30 |
| | 2022 | | 2021 | | 2020 |
| | (Thousands of dollars) |
| Net Income (Loss) Available for Common Stock | $ | 566,021 | | | $ | 363,647 | | | $ | (123,772) | |
| Other Comprehensive Income (Loss), Before Tax: | | | | | |
| Increase (Decrease) in the Funded Status of the Pension and Other Post-Retirement Benefit Plans | 9,561 | | | 17,862 | | | (19,214) | |
| Reclassification Adjustment for Amortization of Prior Year Funded Status of the Pension and Other Post-Retirement Benefit Plans | 11,054 | | | 16,229 | | | 15,361 | |
| | | | | |
| Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period | (1,050,831) | | | (665,371) | | | 9,862 | |
| | | | | |
| Reclassification Adjustment for Realized (Gains) Losses on Derivative Financial Instruments in Net Income | 882,581 | | | 83,711 | | | (93,295) | |
| Cumulative Effect of Adoption of Authoritative Guidance for Hedging | — | | | — | | | 1,313 | |
| Other Post-Retirement Adjustment for Regulatory Proceeding | (7,351) | | | — | | | — | |
| | | | | |
| Other Comprehensive Income (Loss), Before Tax | (154,986) | | | (547,569) | | | (85,973) | |
| Income Tax Expense (Benefit) Related to the Increase (Decrease) in the Funded Status of the Pension and Other Post-Retirement Benefit Plans | 2,169 | | | 4,072 | | | (4,357) | |
| Reclassification Adjustment for Income Tax Benefit Related to the Amortization of the Prior Year Funded Status of the Pension and Other Post-Retirement Benefit Plans | 2,574 | | | 3,762 | | | 3,566 | |
| | | | | |
| Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period | (287,608) | | | (179,028) | | | 2,578 | |
| | | | | |
| Reclassification Adjustment for Income Tax Benefit (Expense) on Realized Losses (Gains) from Derivative Financial Instruments in Net Income | 241,559 | | | 22,465 | | | (25,521) | |
| Income Tax Benefit (Expense) on Cumulative Effect of Adoption of Authoritative Guidance for Hedging | — | | | — | | | 363 | |
| Income Tax Expense (Benefit) Related to Other Post-Retirement Adjustment for Regulatory Proceeding | (1,544) | | | — | | | — | |
| | | | | |
| | | | | |
| Income Taxes — Net | (42,850) | | | (148,729) | | | (23,371) | |
| Other Comprehensive Income (Loss) | (112,136) | | | (398,840) | | | (62,602) | |
| Comprehensive Income (Loss) | $ | 453,885 | | | $ | (35,193) | | | $ | (186,374) | |
See Notes to Consolidated Financial Statements
NATIONAL FUEL GAS COMPANY
CONSOLIDATED BALANCE SHEETS
| | | | At September 30 | | At September 30 |
| | 2017 | | 2016 | | 2022 | | 2021 |
| | (Thousands of dollars) | | (Thousands of dollars) |
| ASSETS | ASSETS | ASSETS |
| Property, Plant and Equipment | $ | 9,945,560 |
| | $ | 9,539,581 |
| Property, Plant and Equipment | $ | 12,551,909 | | | $ | 13,103,639 | |
| Less — Accumulated Depreciation, Depletion and Amortization | 5,271,486 |
| | 5,085,099 |
| Less — Accumulated Depreciation, Depletion and Amortization | 5,985,432 | | | 6,719,356 | |
| | 4,674,074 |
| | 4,454,482 |
| | 6,566,477 | | | 6,384,283 | |
| | Current Assets | | | | Current Assets | | | |
| Cash and Temporary Cash Investments | 555,530 |
| | 129,972 |
| Cash and Temporary Cash Investments | 46,048 | | | 31,528 | |
| Hedging Collateral Deposits | 1,741 |
| | 1,484 |
| Hedging Collateral Deposits | 91,670 | | | 88,610 | |
| Receivables — Net of Allowance for Uncollectible Accounts of $22,526 and $21,109, Respectively | 112,383 |
| | 133,201 |
| |
| Receivables — Net of Allowance for Uncollectible Accounts of $40,228 and $31,639, Respectively | | Receivables — Net of Allowance for Uncollectible Accounts of $40,228 and $31,639, Respectively | 361,626 | | | 205,294 | |
| Unbilled Revenue | 22,883 |
| | 18,382 |
| Unbilled Revenue | 30,075 | | | 17,000 | |
| Gas Stored Underground | 35,689 |
| | 34,332 |
| Gas Stored Underground | 32,364 | | | 33,669 | |
| Materials and Supplies — at average cost | 33,926 |
| | 33,866 |
| |
| Materials, Supplies and Emission Allowances | | Materials, Supplies and Emission Allowances | 40,637 | | | 53,560 | |
| Unrecovered Purchased Gas Costs | 4,623 |
| | 2,440 |
| Unrecovered Purchased Gas Costs | 99,342 | | | 33,128 | |
| Other Current Assets | 51,505 |
| | 59,354 |
| Other Current Assets | 59,369 | | | 59,660 | |
| | 818,280 |
| | 413,031 |
| | 761,131 | | | 522,449 | |
| Other Assets | | | | Other Assets | | | |
| Recoverable Future Taxes | 181,363 |
| | 177,261 |
| Recoverable Future Taxes | 106,247 | | | 121,992 | |
| Unamortized Debt Expense | 1,159 |
| | 1,688 |
| Unamortized Debt Expense | 8,884 | | | 10,589 | |
| Other Regulatory Assets | 174,433 |
| | 320,750 |
| Other Regulatory Assets | 67,101 | | | 60,145 | |
| Deferred Charges | 30,047 |
| | 20,978 |
| Deferred Charges | 77,472 | | | 59,939 | |
| Other Investments | 125,265 |
| | 110,664 |
| Other Investments | 95,025 | | | 149,632 | |
| Goodwill | 5,476 |
| | 5,476 |
| Goodwill | 5,476 | | | 5,476 | |
| Prepaid Post-Retirement Benefit Costs | 56,370 |
| | 17,649 |
| |
| Prepaid Pension and Post-Retirement Benefit Costs | | Prepaid Pension and Post-Retirement Benefit Costs | 196,597 | | | 149,151 | |
| Fair Value of Derivative Financial Instruments | 36,111 |
| | 113,804 |
| Fair Value of Derivative Financial Instruments | 9,175 | | | — | |
| Other | 742 |
| | 604 |
| Other | 2,677 | | | 1,169 | |
| | 610,966 |
| | 768,874 |
| | 568,654 | | | 558,093 | |
| Total Assets | $ | 6,103,320 |
| | $ | 5,636,387 |
| Total Assets | $ | 7,896,262 | | | $ | 7,464,825 | |
| CAPITALIZATION AND LIABILITIES | CAPITALIZATION AND LIABILITIES | CAPITALIZATION AND LIABILITIES |
| Capitalization: | | | | Capitalization: | |
| Comprehensive Shareholders’ Equity | | | | Comprehensive Shareholders’ Equity | |
Common Stock, $1 Par Value; Authorized - 200,000,000 Shares; Issued and Outstanding - 85,543,125 Shares and 85,118,886 Shares, Respectively | $ | 85,543 |
| | $ | 85,119 |
| |
Common Stock, $1 Par Value; Authorized - 200,000,000 Shares; Issued and Outstanding - 91,478,064 Shares and 91,181,549 Shares, Respectively | | Common Stock, $1 Par Value; Authorized - 200,000,000 Shares; Issued and Outstanding - 91,478,064 Shares and 91,181,549 Shares, Respectively | $ | 91,478 | | | $ | 91,182 | |
| Paid In Capital | 796,646 |
| | 771,164 |
| Paid In Capital | 1,027,066 | | | 1,017,446 | |
| Earnings Reinvested in the Business | 851,669 |
| | 676,361 |
| Earnings Reinvested in the Business | 1,587,085 | | | 1,191,175 | |
| Accumulated Other Comprehensive Loss | (30,123 | ) | | (5,640 | ) | Accumulated Other Comprehensive Loss | (625,733) | | | (513,597) | |
| Total Comprehensive Shareholders’ Equity | 1,703,735 |
| | 1,527,004 |
| Total Comprehensive Shareholders’ Equity | 2,079,896 | | | 1,786,206 | |
| Long-Term Debt, Net of Current Portion and Unamortized Discount and Debt Issuance Costs | 2,083,681 |
| | 2,086,252 |
| Long-Term Debt, Net of Current Portion and Unamortized Discount and Debt Issuance Costs | 2,083,409 | | | 2,628,687 | |
| Total Capitalization | 3,787,416 |
| | 3,613,256 |
| Total Capitalization | 4,163,305 | | | 4,414,893 | |
| Current and Accrued Liabilities | | | | Current and Accrued Liabilities | | | |
| Notes Payable to Banks and Commercial Paper | — |
| | — |
| Notes Payable to Banks and Commercial Paper | 60,000 | | | 158,500 | |
| Current Portion of Long-Term Debt | 300,000 |
| | — |
| Current Portion of Long-Term Debt | 549,000 | | | — | |
| Accounts Payable | 126,443 |
| | 108,056 |
| Accounts Payable | 178,945 | | | 171,655 | |
| Amounts Payable to Customers | — |
| | 19,537 |
| Amounts Payable to Customers | 419 | | | 21 | |
| Dividends Payable | 35,500 |
| | 34,473 |
| Dividends Payable | 43,452 | | | 41,487 | |
| Interest Payable on Long-Term Debt | 35,031 |
| | 34,900 |
| Interest Payable on Long-Term Debt | 17,376 | | | 17,376 | |
| Customer Advances | 15,701 |
| | 14,762 |
| Customer Advances | 26,108 | | | 17,223 | |
| Customer Security Deposits | 20,372 |
| | 16,019 |
| Customer Security Deposits | 24,283 | | | 19,292 | |
| Other Accruals and Current Liabilities | 111,889 |
| | 74,430 |
| Other Accruals and Current Liabilities | 257,327 | | | 194,169 | |
| Fair Value of Derivative Financial Instruments | 1,103 |
| | 1,560 |
| Fair Value of Derivative Financial Instruments | 785,659 | | | 616,410 | |
| | 646,039 |
| | 303,737 |
| | 1,942,569 | | | 1,236,133 | |
| Deferred Credits | | | | |
| Other Liabilities | | Other Liabilities | | | |
| Deferred Income Taxes | 891,287 |
| | 823,795 |
| Deferred Income Taxes | 698,229 | | | 660,420 | |
| Taxes Refundable to Customers | 95,739 |
| | 93,318 |
| Taxes Refundable to Customers | 362,098 | | | 354,089 | |
| Cost of Removal Regulatory Liability | 204,630 |
| | 193,424 |
| Cost of Removal Regulatory Liability | 259,947 | | | 245,636 | |
| Other Regulatory Liabilities | 113,716 |
| | 99,789 |
| Other Regulatory Liabilities | 188,803 | | | 200,643 | |
| Pension and Other Post-Retirement Liabilities | 149,079 |
| | 277,113 |
| Pension and Other Post-Retirement Liabilities | 3,065 | | | 7,526 | |
| Asset Retirement Obligations | 106,395 |
| | 112,330 |
| Asset Retirement Obligations | 161,545 | | | 209,639 | |
| Other Deferred Credits | 109,019 |
| | 119,625 |
| |
| Other Liabilities | | Other Liabilities | 116,701 | | | 135,846 | |
| | 1,669,865 |
| | 1,719,394 |
| | 1,790,388 | | | 1,813,799 | |
| Commitments and Contingencies (Note I) | — |
| | — |
| |
| Commitments and Contingencies (Note L) | | Commitments and Contingencies (Note L) | — | | | — | |
| Total Capitalization and Liabilities | $ | 6,103,320 |
| | $ | 5,636,387 |
| Total Capitalization and Liabilities | $ | 7,896,262 | | | $ | 7,464,825 | |
See Notes to Consolidated Financial Statements
NATIONAL FUEL GAS COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
|
| | | | | | | | | | | |
| | Year Ended September 30 |
| | 2017 | | 2016 | | 2015 |
| | (Thousands of dollars) |
| Operating Activities | | | | | |
| Net Income (Loss) Available for Common Stock | $ | 283,482 |
| | $ | (290,958 | ) | | $ | (379,427 | ) |
| Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities: | | | | | |
| Impairment of Oil and Gas Producing Properties | — |
| | 948,307 |
| | 1,126,257 |
|
| Depreciation, Depletion and Amortization | 224,195 |
| | 249,417 |
| | 336,158 |
|
| Deferred Income Taxes | 117,975 |
| | (246,794 | ) | | (357,587 | ) |
| Excess Tax Benefits Associated with Stock-Based Compensation Awards | — |
| | (1,868 | ) | | (9,064 | ) |
| Stock-Based Compensation | 12,262 |
| | 5,755 |
| | 3,208 |
|
| Other | 16,476 |
| | 12,620 |
| | 9,823 |
|
| Change in: | | | | | |
| Hedging Collateral Deposits | (257 | ) | | 9,640 |
| | (8,390 | ) |
| Receivables and Unbilled Revenue | (3,380 | ) | | (6,408 | ) | | 51,638 |
|
| Gas Stored Underground and Materials and Supplies | (1,417 | ) | | (3,532 | ) | | 3,438 |
|
| Unrecovered Purchased Gas Costs | (2,183 | ) | | (2,440 | ) | | — |
|
| Other Current Assets | 7,849 |
| | 3,179 |
| | 3,150 |
|
| Accounts Payable | 17,192 |
| | (40,664 | ) | | 34,687 |
|
| Amounts Payable to Customers | (19,537 | ) | | (37,241 | ) | | 23,033 |
|
| Customer Advances | 939 |
| | (1,474 | ) | | (2,769 | ) |
| Customer Security Deposits | 4,353 |
| | (471 | ) | | 729 |
|
| Other Accruals and Current Liabilities | 27,004 |
| | 3,453 |
| | (7,173 | ) |
| Other Assets | (2,885 | ) | | 1,941 |
| | 2,696 |
|
| Other Liabilities | 2,183 |
| | (13,483 | ) | | 23,173 |
|
| Net Cash Provided by Operating Activities | 684,251 |
| | 588,979 |
| | 853,580 |
|
| Investing Activities | | | | | |
| Capital Expenditures | (450,335 | ) | | (581,576 | ) | | (1,018,179 | ) |
| Net Proceeds from Sale of Oil and Gas Producing Properties | 26,554 |
| | 137,316 |
| | — |
|
| Other | 1,216 |
| | (9,236 | ) | | (6,611 | ) |
| Net Cash Used in Investing Activities | (422,565 | ) | | (453,496 | ) | | (1,024,790 | ) |
| Financing Activities | | | | | |
| Change in Notes Payable to Banks and Commercial Paper | — |
| | — |
| | (85,600 | ) |
| Excess Tax Benefits Associated with Stock-Based Compensation Awards | — |
| | 1,868 |
| | 9,064 |
|
| Net Proceeds from Issuance of Long-Term Debt | 295,151 |
| | — |
| | 444,635 |
|
| Net Proceeds from Issuance of Common Stock | 7,784 |
| | 13,849 |
| | 10,540 |
|
| Dividends Paid on Common Stock | (139,063 | ) | | (134,824 | ) | | (130,719 | ) |
| Net Cash Provided by (Used in) Financing Activities | 163,872 |
| | (119,107 | ) | | 247,920 |
|
| Net Increase in Cash and Temporary Cash Investments | 425,558 |
| | 16,376 |
| | 76,710 |
|
| Cash and Temporary Cash Investments At Beginning of Year | 129,972 |
| | 113,596 |
| | 36,886 |
|
| Cash and Temporary Cash Investments At End of Year | $ | 555,530 |
| | $ | 129,972 |
| | $ | 113,596 |
|
| Supplemental Disclosure of Cash Flow Information | | | | | |
| Cash Paid For: | | | | | |
| Interest | $ | 116,894 |
| | $ | 119,563 |
| | $ | 90,747 |
|
| Income Taxes | $ | 34,826 |
| | $ | 34,240 |
| | $ | 18,657 |
|
| Non-Cash Investing Activities: | | | | | |
| Non-Cash Capital Expenditures | $ | 72,216 |
| | $ | 60,434 |
| | $ | 118,959 |
|
| Receivable from Sale of Oil and Gas Producing Properties | $ | — |
| | $ | 19,543 |
| | $ | — |
|
| | | | | | | | | | | | | | | | | |
| | Year Ended September 30 |
| | 2022 | | 2021 | | 2020 |
| (Thousands of dollars) |
| Operating Activities | | | | | |
| Net Income (Loss) Available for Common Stock | $ | 566,021 | | | $ | 363,647 | | | $ | (123,772) | |
| Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities: | | | | | |
| Gain on Sale of Assets | (12,736) | | | (51,066) | | | — | |
| Impairment of Oil and Gas Producing Properties | — | | | 76,152 | | | 449,438 | |
| Depreciation, Depletion and Amortization | 369,790 | | | 335,303 | | | 306,158 | |
| Deferred Income Taxes | 104,415 | | | 105,993 | | | 54,313 | |
| Premium Paid on Early Redemption of Debt | — | | | 15,715 | | | — | |
| | | | | |
| | | | | |
| Stock-Based Compensation | 19,506 | | | 17,065 | | | 14,931 | |
| Reduction of Other Post-Retirement Regulatory Liability | (18,533) | | | — | | | — | |
| Other | 31,983 | | | 10,896 | | | 6,527 | |
| Change in: | | | | | |
| | | | | |
| Receivables and Unbilled Revenue | (168,769) | | | (61,413) | | | (2,578) | |
| Gas Stored Underground and Materials, Supplies and Emission Allowances | 3,109 | | | (2,014) | | | (6,625) | |
| Unrecovered Purchased Gas Costs | (66,214) | | | (33,128) | | | 2,246 | |
| Other Current Assets | 291 | | | (11,972) | | | 49,367 | |
| Accounts Payable | 11,907 | | | 31,352 | | | (4,657) | |
| Amounts Payable to Customers | 398 | | | (10,767) | | | 6,771 | |
| Customer Advances | 8,885 | | | 1,904 | | | 2,275 | |
| Customer Security Deposits | 4,991 | | | 2,093 | | | 989 | |
| Other Accruals and Current Liabilities | 34,260 | | | 34,314 | | | 5,001 | |
| Other Assets | (58,924) | | | 1,250 | | | (24,203) | |
| Other Liabilities | (17,859) | | | (33,771) | | | 4,628 | |
| Net Cash Provided by Operating Activities | 812,521 | | | 791,553 | | | 740,809 | |
| Investing Activities | | | | | |
| Capital Expenditures | (811,826) | | | (751,734) | | | (716,153) | |
| Net Proceeds from Sale of Oil and Gas Producing Properties | 254,439 | | | — | | | — | |
| Net Proceeds from Sale of Timber Properties | — | | | 104,582 | | | — | |
| Sale of Fixed Income Mutual Fund Shares in Grantor Trust | 30,000 | | | — | | | — | |
| Acquisition of Upstream Assets and Midstream Gathering Assets | — | | | — | | | (506,258) | |
| Other | 8,683 | | | 13,935 | | | (1,205) | |
| Net Cash Used in Investing Activities | (518,704) | | | (633,217) | | | (1,223,616) | |
| Financing Activities | | | | | |
| Change in Notes Payable to Banks and Commercial Paper | (98,500) | | | 128,500 | | | (25,200) | |
| | | | | |
| Net Proceeds from Issuance of Long-Term Debt | — | | | 495,267 | | | 493,007 | |
| Reduction of Long-Term Debt | — | | | (515,715) | | | — | |
| Net Proceeds from Issuance (Repurchase) of Common Stock | (9,590) | | | (3,702) | | | 161,603 | |
| Dividends Paid on Common Stock | (168,147) | | | (163,089) | | | (153,322) | |
| Net Cash Provided by (Used in) Financing Activities | (276,237) | | | (58,739) | | | 476,088 | |
| Net Increase (Decrease) in Cash, Cash Equivalents, and Restricted Cash | 17,580 | | | 99,597 | | | (6,719) | |
| Cash, Cash Equivalents and Restricted Cash At Beginning of Year | 120,138 | | | 20,541 | | | 27,260 | |
| Cash, Cash Equivalents and Restricted Cash At End of Year | $ | 137,718 | | | $ | 120,138 | | | $ | 20,541 | |
| Supplemental Disclosure of Cash Flow Information | | | | | |
| Cash Paid (Refunded) For: | | | | | |
| Interest | $ | 124,312 | | | $ | 135,136 | | | $ | 103,479 | |
| Income Taxes | $ | 16,680 | | | $ | 6,374 | | | $ | (82,876) | |
| Non-Cash Investing Activities: | | | | | |
| Non-Cash Capital Expenditures | $ | 120,262 | | | $ | 102,700 | | | $ | 87,328 | |
| Non-Cash Contingent Consideration for Asset Sale | $ | 12,571 | | | $ | — | | | $ | — | |
| | | | | |
See Notes to Consolidated Financial Statements
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note A — Summary of Significant Accounting Policies
Principles of Consolidation
The Company consolidates all entities in which it has a controlling financial interest. All significant intercompany balances and transactions are eliminated. The Company uses proportionate consolidation when accounting for drilling arrangements related to oil and gas producing properties accounted for under the full cost method of accounting.
The preparation of the consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Reclassification
Certain prior year amounts have been reclassified to conform with current year presentation.
Regulation
The Company is subject to regulation by certain state and federal authorities. The Company has accounting policies which conform to GAAP, as applied to regulated enterprises, and are in accordance with the accounting requirements and ratemaking practices of the regulatory authorities. Reference is made to Note CF — Regulatory Matters for further discussion.
Revenue Recognition
The Company’s Exploration and Production segment records revenue based on entitlement, which means that revenue is recorded based on the actual amount of gas or oil that is delivered to a pipeline and the Company’s ownership interest in the producing well. If a production imbalance occurs between what was supposed to be delivered to a pipeline and what was actually produced and delivered, the Company accrues the difference as an imbalance.
The Company’s Pipeline and Storage segment records revenue for natural gas transportation and storage services. Revenue from reservation charges on firm contracted capacity is recognized through equal monthly charges over the contract period regardless of the amount of gas that is transported or stored. Commodity charges on firm contracted capacity and interruptible contracts are recognized as revenue when physical deliveries of natural gas are made at the agreed upon delivery point or when gas is injected or withdrawn from the storage field. The point of delivery into the pipeline or injection or withdrawal from storage is the point at which ownership and risk of loss transfers to the buyer of such transportation and storage services.
In the Company’s Gathering segment, revenue is recorded at the point at which gathered volumes are delivered into interstate pipelines.
The Company’s Utility segment records revenue for gas sales and transportation in the period that gas is delivered to customers. This includes the recording of receivables for gas delivered but not yet billed to customers based on the Company's estimate of the amount of gas delivered between the last meter reading date and the end of the accounting period. Such receivables are a component of Unbilled Revenue on the Consolidated Balance Sheets.
The Company’s Energy Marketing segment records revenue for gas sales in the period that gas is delivered to customers. This includes the recording of receivables for gas delivered but not yet billed to customers based on the Company's estimate of the amount of gas delivered between the last meter reading date and the end of the accounting period. Such receivables are a component of Unbilled Revenue on the Consolidated Balance Sheets.
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Allowance for Uncollectible Accounts
The allowance for uncollectible accounts is the Company’s best estimate of the amount of probable credit losses in the existing accounts receivable. The allowance, the majority of which is in the Utility segment, is determined based on historical experience, the age andof customer accounts, other specific information about customer accounts.accounts, and the economic and regulatory environment. Account balances are charged off against the allowance approximately twelve months after the account is final billed or when it is anticipated that the receivable will not be recovered.
Activity in the allowance for uncollectible accounts are as follows:
| | | | | | | | | | | | | | | | | |
| | Year Ended September 30 |
| | 2022 | | 2021 | | 2020 |
| | (Thousands) |
| Balance at Beginning of Year | $ | 31,639 | | | $ | 22,810 | | | $ | 25,788 | |
| Additions Charged to Costs and Expenses | 13,209 | | | 14,940 | | | 12,339 | |
| Add: Discounts on Purchased Receivables | 1,314 | | | 1,168 | | | 1,353 | |
| Deduct: Net Accounts Receivable Written-Off | 5,934 | | | 7,279 | | | 16,670 | |
| Balance at End of Year | $ | 40,228 | | | $ | 31,639 | | | $ | 22,810 | |
Regulatory Mechanisms
The Company’s rate schedules in the Utility segment contain clauses that permit adjustment of revenues to reflect price changes from the cost of purchased gas included in base rates. Differences between amounts currently recoverable and actual adjustment clause revenues, as well as other price changes and pipeline and storage company refunds not yet includable in adjustment clause rates, are deferred and accounted for as either unrecovered purchased gas costs or amounts payable to customers. Such amounts are generally recovered from (or passed back to) customers during the following fiscal year.
Estimated refund liabilities to ratepayers represent management’s current estimate of such refunds. Reference is made to Note CF — Regulatory Matters for further discussion.
The impact of weather on revenues in the Utility segment’s New York rate jurisdiction is tempered by a WNC, which covers the eight-month period from October through May. The WNC is designed to adjust the
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
rates of retail customers to reflect the impact of deviations from normal weather. Weather that is warmer than normal results in a surcharge being added to customers’ current bills, while weather that is colder than normal results in a refund being credited to customers’ current bills. Since the Utility segment’s Pennsylvania rate jurisdiction does not have a WNC, weather variations have a direct impact on the Pennsylvania rate jurisdiction’s revenues.
The impact of weather normalized usage per customer account in the Utility segment’s New York rate jurisdiction is tempered by a revenue decoupling mechanism. The effect of the revenue decoupling mechanism is to render the Company financially indifferent to throughput decreases resulting from conservation. Weather normalized usage per account that exceeds the average weather normalized usage per customer account results in a refund being credited to customers’ bills. Weather normalized usage per account that is below the average weather normalized usage per account results in a surcharge being added to customers’ bills. The surcharge or credit is calculated over a twelve-month period ending DecemberMarch 31st, and applied to customer bills annually, beginning MarchJuly 1st.
In the Pipeline and Storage segment, the allowed rates that Supply Corporation and Empire bill their customers are based on a straight fixed-variable rate design, which allows recovery of all fixed costs, including return on equity and income taxes, through fixed monthly reservation charges. Because of this rate design, changes in throughput due to weather variations do not have a significant impact on the revenues of Supply Corporation or Empire.
Asset Acquisition and Business Combination Accounting
In accordance with authoritative guidance issued by the FASB that clarifies the definition of a business, when the Company executes an acquisition, it will perform an initial screening test as of the acquisition date that, if met, results in the conclusion that the set of activities and assets is not a business. If the initial screening test is not met, the Company evaluates whether the set is a business based on whether there are inputs and a substantive process in place. The definition of a business impacts whether the Company consolidates an acquisition under business combination guidance or asset acquisition guidance.
When the Company acquires assets and liabilities deemed to be an asset acquisition, the fair value of the purchase consideration, including the transaction costs of the asset acquisition, is assumed to be equal to the fair value of the net assets acquired. The purchase consideration, including the transaction costs, is allocated to the individual assets and liabilities assumed based on their relative fair values. Transaction costs associated with asset acquisitions are capitalized as part of the costs of the group of assets acquired.
When the Company acquires assets and liabilities deemed to be a business combination, the acquisition method is applied. Goodwill is measured as the fair value of the consideration transferred less the net recognized fair value of the identifiable assets acquired and the liabilities assumed, all measured at the acquisition date. Transaction costs that the Company incurs in connection with a business combination, such as finders’ fees, legal fees, due diligence fees and other professional and consulting fees are expensed as incurred.
Property, Plant and Equipment
In the Company’s Exploration and Production segment, oil and gas property acquisition, exploration and development costs are capitalized under the full cost method of accounting. Under this methodology, all costs associated with property acquisition, exploration and development activities are capitalized, including internal costs directly identified with acquisition, exploration and development activities. The internal costs that are capitalized do not include any costs related to production, general corporate overhead, or similar activities. The Company does not recognize any gain or loss on the sale or other disposition of oil and gas properties unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of oil and gas attributable to a cost center. The Company's capitalized costs relating to oil and gas producing activities, net of accumulated depreciation, depletion and amortization, were $1.9 billion at September 30, 2022 and 2021.
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
For further discussion of capitalized costs, refer to Note MN — Supplementary Information for Oil and Gas Producing Activities.
Capitalized costs are subject to the SEC full cost ceiling test. The ceiling test, which is performed each quarter, determines a limit, or ceiling, on the amount of property acquisition, exploration and development costs
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
that can be capitalized. The ceiling under this test represents (a) the present value of estimated future net cash flows, excluding future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, using a discount factor of 10%, which is computed by applying prices of oil and gas (as adjusted for hedging) to estimated future production of proved oil and gas reserves as of the date of the latest balance sheet, less estimated future expenditures, plus (b) the cost of unevaluatedunproved properties not being depleted, less (c) income tax effects related to the differences between the book and tax basis of the properties. The natural gas and oil prices used to calculate the full cost ceiling are 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. If capitalized costs, net of accumulated depreciation, depletion and amortization and related deferred income taxes, exceed the ceiling at the end of any quarter, a permanent non-cash impairment is required to be charged to earnings in that quarter. At September 30, 2017,2022, the ceiling exceeded the book value of the oil and gas properties by $286.4 million.approximately $3.2 billion. In adjusting estimated future net cash flows for hedging under the ceiling test at September 30, 2017, 2016,2022, 2021 and 2015,2020, estimated future net cash flows were decreased by $1.0 billion, decreased by $76.1 million and increased by $30.5$180.0 million, $215.3 million and $194.5 million, respectively.
On December 1, 2015, Seneca and IOG - CRV Marcellus, LLC (IOG), an affiliate of IOG Capital, LP, and funds managed by affiliates of Fortress Investment Group, LLC, executed a joint development agreement that allows IOG to participate in the development of certain oil and gas interests owned by Seneca in Elk, McKean and Cameron Counties, Pennsylvania. On June 13, 2016, Seneca and IOG executed an extension of the joint development agreement. Under the terms of the extended agreement, Seneca and IOG will jointly participate in a program to develop up to 75 Marcellus wells, with Seneca serving as program operator. IOG will hold an 80% working interest in all of the joint development wells. In total, IOG is expected to fund approximately $325 million for its 80% working interest in the 75 joint development wells. Of this amount, IOG has funded $262.6 million as of September 30, 2017, which includes $163.9 million of cash ($137.3 million in fiscal 2016 and $26.6 million in fiscal 2017) that Seneca had received in recognition of IOG funding that is due to Seneca for costs previously incurred to develop a portion of the first 75 joint development wells. The cash proceeds were recorded by Seneca as a $163.9 million reduction of property, plant and equipment. The remainder funded joint development expenditures. As the fee-owner of the property’s mineral rights, Seneca retains a 7.5% royalty interest and the remaining 20% working interest (which results in a 26% net revenue interest) in 56 of the joint development wells. In the remaining 19 wells, Seneca retains a 20% working and net revenue interest. Seneca’s working interest under the agreement will increase to 85% after IOG achieves a 15% internal rate of return.
The principal assets of the Utility, and Pipeline and Storage and Gathering segments, consisting primarily of gas plant in service,distribution pipelines, transmission pipelines, storage facilities, gathering lines and compressor stations, are recorded at historical cost. There were no indications of any impairments to property, plant and equipment in the historical cost when originally devoted to service.Utility, Pipeline and Storage and Gathering segments at September 30, 2022.
Maintenance and repairs of property and replacements of minor items of property are charged directly to maintenance expense. The original cost of the regulated subsidiaries’ property, plant and equipment retired, and the cost of removal less salvage, are charged to accumulated depreciation.
Depreciation, Depletion and Amortization
For oil and gas properties, depreciation, depletion and amortization is computed based on quantities produced in relation to proved reserves using the units of production method. The cost of unproved oil and gas properties is excluded from this computation. InDepreciation, depletion and amortization expense for oil and gas properties was $202.4 million, $177.1 million and $166.8 million for the All Other category, for timber properties, depletion, determined on a property by property basis, is charged to operations based on the actual amount of timber cut in relation to the total amount of recoverable timber.years ended September 30, 2022, 2021 and 2020, respectively. For all other property, plant and equipment, depreciation and amortization is computed using the straight-line method in amounts sufficient to recover costs over the estimated service lives of property in service. The following is a summary of depreciable plant by segment:
| | | | | | | | | | | |
| | As of September 30 |
| | 2022 | | 2021 |
| | (Thousands) |
| Exploration and Production | $ | 6,088,476 | | | $ | 6,827,122 | |
| Pipeline and Storage | 2,747,948 | | | 2,467,891 | |
| Gathering | 971,665 | | | 932,583 | |
| Utility | 2,411,707 | | | 2,306,603 | |
| | | |
| All Other and Corporate | 13,712 | | | 13,585 | |
| $ | 12,233,508 | | | $ | 12,547,784 | |
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
|
| | | | | | | |
| | As of September 30 |
| | 2017 | | 2016 |
| | (Thousands) |
| Exploration and Production | $ | 4,925,409 |
| | $ | 4,645,226 |
|
| Pipeline and Storage | 2,002,736 |
| | 1,956,708 |
|
| Gathering | 484,768 |
| | 454,343 |
|
| Utility | 2,045,074 |
| | 1,998,605 |
|
| Energy Marketing | 3,564 |
| | 3,528 |
|
| All Other and Corporate | 109,128 |
| | 109,455 |
|
| | $ | 9,570,679 |
| | $ | 9,167,865 |
|
Average depreciation, depletion and amortization rates are as follows:
|
| | | | | | | | | | | |
| | Year Ended September 30 |
| | 2017 | | 2016 | | 2015 |
| Exploration and Production, per Mcfe(1) | $ | 0.65 |
| | $ | 0.87 |
| | $ | 1.52 |
|
| Pipeline and Storage | 2.2 | % | | 2.4 | % | | 2.4 | % |
| Gathering | 3.4 | % | | 4.0 | % | | 4.0 | % |
| Utility | 2.8 | % | | 2.7 | % | | 2.6 | % |
| Energy Marketing | 7.9 | % | | 7.9 | % | | 6.1 | % |
| All Other and Corporate | 1.3 | % | | 1.8 | % | | 1.4 | % |
| | | | | | | | | | | | | | | | | |
| | Year Ended September 30 |
| | 2022 | | 2021 | | 2020 |
| Exploration and Production, per Mcfe(1) | $ | 0.59 | | | $ | 0.56 | | | $ | 0.71 | |
| Pipeline and Storage | 2.7 | % | | 2.6 | % | | 2.4 | % |
| Gathering | 3.6 | % | | 3.6 | % | | 3.2 | % |
| Utility | 2.7 | % | | 2.7 | % | | 2.7 | % |
| | | | | |
| All Other and Corporate | 1.4 | % | | 3.4 | % | | 3.6 | % |
| |
(1) | Amounts include depletion of oil and gas producing properties as well as depreciation of fixed assets. As disclosed in Note M — Supplementary Information for Oil and Gas Producing Activities, depletion of oil and gas producing properties amounted to $0.63, $0.85 and $1.49 per Mcfe of production in 2017, 2016 and 2015, respectively. |
(1)Amounts include depletion of oil and gas producing properties as well as depreciation of fixed assets. As disclosed in Note N — Supplementary Information for Oil and Gas Producing Activities, depletion of oil and gas producing properties amounted to $0.57, $0.54 and $0.69 per Mcfe of production in 2022, 2021 and 2020, respectively.
Goodwill
The Company has recognized goodwill of $5.5 million as of September 30, 20172022 and 20162021 on its Consolidated Balance Sheets related to the Company’s acquisition of Empire in 2003. The Company accounts for goodwill in accordance with the current authoritative guidance, which requires the Company to test goodwill for impairment annually. At September 30, 2017, 20162022, 2021 and 2015,2020, the fair value of Empire was greater than its book value. As such, the goodwill was not considered impaired at those dates. Going back to the origination of the goodwill in 2003, the Company has never recorded an impairment of its goodwill balance.
Financial Instruments
Unrealized gains or losses from the Company’s investments in an equity mutual fund, a fixed income mutual fund and the stock of an insurance company (securities available for sale) are recorded as a component of accumulated other comprehensive income (loss). Reference is made to Note G — Financial Instruments for further discussion.
The Company uses a variety of derivative financial instruments to manage a portion of the market risk associated with fluctuations in the price of natural gas and crude oil and to manage a portion of the risk of currency fluctuations associated with transportation costs denominated in Canadian currency. These instruments include natural gas price swap agreements and futuresno cost collars and foreign currency forward contracts. The Company accounts for these instruments as either cash flow hedges or fair value hedges. In both cases,for which the fair value of the instrument is recognized on the Consolidated Balance Sheets as either an asset or a liability labeled Fair Value of Derivative Financial Instruments. Reference
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
is made to Note FI — Fair Value Measurements for further discussion concerning the fair value of derivative financial instruments.
For effective cash flow hedges, the offset to the asset or liability that is recorded is a gain or loss recorded in accumulated other comprehensive income (loss) on the Consolidated Balance Sheets. The gain or loss recorded in accumulated other comprehensive income (loss) remains there until the hedged transaction occurs, at which point the gains or losses are reclassified to operating revenues purchased gas expense or operation and maintenance expense on the Consolidated Statements of Income. Reference is made to Note G -J — Financial Instruments for further discussion concerning cash flow hedges.
For fair value hedges, the offset to the asset or liability that is recorded is a gain or loss recorded to operating revenues or purchased gas expense on the Consolidated Statements of Income. However, in the case of fair value hedges, the Company also records an asset or liability on the Consolidated Balance Sheets representing the change in fair value of the asset or firm commitment that is being hedged (see Other Current Assets section in this footnote). The offset to this asset or liability is a gain or loss recorded to operating revenues or purchased gas expense on the Consolidated Statements of Income as well. If the fair value hedge is effective, the gain or loss from the derivative financial instrument is offset by the gain or loss that arises from the change in fair value of the asset or firm commitment that is being hedged. Reference is made to Note G
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Financial Instruments for further discussion concerning fair value hedges.(Continued)
Accumulated Other Comprehensive Income (Loss)
The components of Accumulated Other Comprehensive Income (Loss) and changes for the yearyears ended September 30, 2017,2022 and 2021, net of related tax effect,effects, are as follows (amounts in parentheses indicate debits) (in thousands):
|
| | | | | | | | | | | | | | | |
| | Gains and Losses on Derivative Financial Instruments | | Gains and Losses on Securities Available for Sale | | Funded Status of the Pension and Other Post-Retirement Benefit Plans | | Total |
| Year Ended September 30, 2017 | | | | | | | |
| Balance at October 1, 2016 | $ | 64,782 |
| | $ | 6,054 |
| | $ | (76,476 | ) | | $ | (5,640 | ) |
| Other Comprehensive Gains and Losses Before Reclassifications | 3,338 |
| | 2,503 |
| | 9,486 |
| | 15,327 |
|
| Amounts Reclassified From Other Comprehensive Loss | (47,319 | ) | | (995 | ) | | 8,504 |
| | (39,810 | ) |
| Balance at September 30, 2017 | $ | 20,801 |
| | $ | 7,562 |
| | $ | (58,486 | ) | | $ | (30,123 | ) |
| | | | | | | | |
| Year Ended September 30, 2016 | | | | | | | |
| Balance at October 1, 2015 | $ | 157,197 |
| | $ | 5,969 |
| | $ | (69,794 | ) | | $ | 93,372 |
|
| Other Comprehensive Gains and Losses Before Reclassifications | 41,845 |
| | 932 |
| | (13,027 | ) | | 29,750 |
|
| Amounts Reclassified From Other Comprehensive Loss | (134,260 | ) | | (847 | ) | | 6,345 |
| | (128,762 | ) |
| Balance at September 30, 2016 | $ | 64,782 |
| | $ | 6,054 |
| | $ | (76,476 | ) | | $ | (5,640 | ) |
| | | | | | | | | | | | | | | | | | | |
| | Gains and Losses on Derivative Financial Instruments | | | | Funded Status of the Pension and Other Post-Retirement Benefit Plans | | Total |
| Year Ended September 30, 2022 | | | | | | | |
| Balance at October 1, 2021 | $ | (449,962) | | | | | $ | (63,635) | | | $ | (513,597) | |
| Other Comprehensive Gains and Losses Before Reclassifications | (763,223) | | | | | 7,392 | | | (755,831) | |
| Amounts Reclassified From Other Comprehensive Income (Loss) | 641,022 | | | | | 8,480 | | | 649,502 | |
| Other Post-Retirement Adjustment for Regulatory Proceeding | — | | | | | (5,807) | | | (5,807) | |
| | | | | | | |
| Balance at September 30, 2022 | $ | (572,163) | | | | | $ | (53,570) | | | $ | (625,733) | |
| Year Ended September 30, 2021 | | | | | | | |
| Balance at October 1, 2020 | $ | (24,865) | | | | | $ | (89,892) | | | $ | (114,757) | |
| Other Comprehensive Gains and Losses Before Reclassifications | (486,343) | | | | | 13,790 | | | (472,553) | |
| Amounts Reclassified From Other Comprehensive Income (Loss) | 61,246 | | | | | 12,467 | | | 73,713 | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| Balance at September 30, 2021 | $ | (449,962) | | | | | $ | (63,635) | | | $ | (513,597) | |
The amounts included in accumulated other comprehensive income (loss) related to the funded status of the Company’s pension and other post-retirement benefit plans consist of prior service costs and accumulated losses. The total amount for prior service cost was $1.2$0.4 million and $1.3$0.7 million at September 30, 20172022 and 2016,2021, respectively. The total amount for accumulated losses was $57.3$53.2 million and $75.2$62.9 million at September 30, 20172022 and 2016,2021, respectively.
During the quarter ended March 31, 2022, the PaPUC concluded a regulatory proceeding that addressed the recovery of OPEB expenses in Distribution Corporation's Pennsylvania service territory. As a result of that proceeding, Distribution Corporation discontinued regulatory accounting for OPEB expenses in Pennsylvania and a regulatory deferral of $7.4 million ($5.8 million after tax) related to the funded status of Distribution Corporation’s other post-retirement benefit plans in Pennsylvania was reclassified to accumulated other comprehensive loss. For further discussion of this regulatory proceeding, refer to Note F — Regulatory Matters under the heading “Pennsylvania Jurisdiction.”
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Reclassifications Out of Accumulated Other Comprehensive Income (Loss)
The details about the reclassification adjustments out of accumulated other comprehensive lossincome (loss) for the yearyears ended September 30, 20172022 and 2021 are as follows (amounts in parentheses indicate debits to the income statement) (in thousands):
|
| | | | | | | | | | |
Details About Accumulated Other Comprehensive Income (Loss) Components | | Amount of Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) for the Year Ended September 30, | | Affected Line Item in the Statement Where Net Income (Loss) is Presented |
| | | 2017 | | 2016 | | |
| Gains (Losses) on Derivative Financial Instrument Cash Flow Hedges: | | | | | | |
| Commodity Contracts | |
| $83,983 |
| |
| $216,823 |
| | Operating Revenues |
| Commodity Contracts | | (1,921 | ) | | 4,520 |
| | Purchased Gas |
| Foreign Currency Contracts | | (457 | ) | | (424 | ) | | Operation and Maintenance Expense |
| Gains (Losses) on Securities Available for Sale | | 1,575 |
| | 1,374 |
| | Other Income |
| Amortization of Prior Year Funded Status of the Pension and Other Post-Retirement Benefit Plans: | | | | | | |
| Prior Service Credit | | (288 | ) | | (333 | ) | | (1) |
| Net Actuarial Loss | | (13,145 | ) | | (9,735 | ) | | (1) |
| | | 69,747 |
| | 212,225 |
| | Total Before Income Tax |
| | | (29,937 | ) | | (83,463 | ) | | Income Tax Expense |
| | |
| $39,810 |
| |
| $128,762 |
| | Net of Tax |
| | | | | | | | | | | | | | | | | | | | |
Details About Accumulated Other
Comprehensive Income (Loss) Components | | Amount of Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) for the
Year Ended
September 30, | | Affected Line Item in the Statement Where Net Income is Presented |
| | 2022 | | 2021 | | |
| Gains (Losses) on Derivative Financial Instrument Cash Flow Hedges: | | | | | | |
| Commodity Contracts | | ($882,594) | | | ($83,973) | | | Operating Revenues |
| | | | | | |
| Foreign Currency Contracts | | 13 | | | 262 | | | Operating Revenues |
| Amortization of Prior Year Funded Status of the Pension and Other Post-Retirement Benefit Plans: | | | | | | |
| Prior Service Cost | | (103) | | | (208) | | | (1) |
| Net Actuarial Loss | | (10,951) | | | (16,021) | | | (1) |
| | | (893,635) | | | (99,940) | | | Total Before Income Tax |
| | | 244,133 | | | 26,227 | | | Income Tax Expense |
| | | ($649,502) | | | ($73,713) | | | Net of Tax |
| |
(1) | These accumulated other comprehensive income (loss) components are included in the computation of net periodic benefit cost. Refer to Note H — Retirement Plan and Other Post-Retirement Benefits for additional details. |
(1)These accumulated other comprehensive income (loss) components are included in the computation of net periodic benefit cost. Refer to Note K — Retirement Plan and Other Post-Retirement Benefits for additional details.
Gas Stored Underground
In the Utility segment, gas stored underground in the amount of $26.7$32.4 million is carried at lower of cost or net realizable value, on a LIFO method. Based upon the average price of spot market gas purchased in September 2017,2022, including transportation costs, the current cost of replacing this inventory of gas stored underground exceeded the amount stated on a LIFO basis by approximately $17.1$178.5 million at September 30, 2017. All other gas stored underground, which is in2022.
Materials, Supplies and Emission Allowances
The components of the Energy Marketing segment, is carried at an average cost method, subject to lower of cost or net realizable value adjustments.Company's materials, supplies and emission allowances are as follows:
| | | | | | | | | | | |
| Year Ended September 30 |
| 2022 | | 2021 |
| (Thousands) |
Materials and Supplies — at average cost | $ | 40,637 | | | $ | 34,880 | |
| Emission Allowances | — | | | 18,680 | |
| $ | 40,637 | | | $ | 53,560 | |
Unamortized Debt Expense
Costs associated with the reacquisition of debt related to rate-regulated subsidiaries are deferred and amortized over the remaining life of the issue or the life of the replacement debt in order to match regulatory treatment. At September 30, 2017, the remaining weighted average amortization period for such costs was approximately 2 years.
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
treatment. At September 30, 2022, the remaining weighted average amortization period for such costs was approximately 5 years.
Income Taxes
The Company and its subsidiaries file a consolidated federal income tax return. State tax returns are filed on a combined or separate basis depending on the applicable laws in the jurisdictions where tax returns are filed. The investment tax credit, prior to its repeal in 1986, was deferred and is being amortized over the estimated useful lives of the related property, as required by regulatory authorities having jurisdiction.
The Company follows the asset and liability approach in accounting for income taxes, which requires the recognition of deferred income taxes for the expected future tax consequences of net operating losses, credits and temporary differences between the financial statement carrying amounts and the tax basis of assets and liabilities. A valuation allowance is provided on deferred tax assets if it is determined, within each taxing jurisdiction, that it is more likely than not that the asset will not be realized.
The Company reports a liability or a reduction of deferred tax assets for unrecognized tax benefits resulting from uncertain tax positions taken or expected to be taken in a tax return. When applicable, the Company recognizes interest relating to uncertain tax positions in Other Interest Expense and penalties in Other Income.Income (Deductions).
Consolidated Statement of Cash Flows
For purposesThe components, as reported on the Company's Consolidated Balance Sheets, of the Consolidatedtotal cash, cash equivalents, and restricted cash presented on the Statement of Cash Flows theare as follows (in thousands):
| | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended September 30 |
| | 2022 | | 2021 | | 2020 | | 2019 |
| Cash and Temporary Cash Investments | $ | 46,048 | | | $ | 31,528 | | | $ | 20,541 | | | $ | 20,428 | |
| Hedging Collateral Deposits | 91,670 | | | 88,610 | | | — | | | 6,832 | |
| Cash, Cash Equivalents, and Restricted Cash | $ | 137,718 | | | $ | 120,138 | | | $ | 20,541 | | | $ | 27,260 | |
The Company considers all highly liquid debt instruments purchased with a maturity date of generally three months or less to be cash equivalents.
The Company’s restricted cash is composed entirely of amounts reported as Hedging Collateral Deposits
This on the Consolidated Balance Sheets. Hedging Collateral Deposits is an account title for cash held in margin accounts funded by the Company to serve as collateral for hedging positions.derivative financial instruments in an unrealized loss position. In accordance with its accounting policy, the Company does not offset hedging collateral deposits paid or received against related derivative financial instrumentinstruments liability or asset balances.
Other Current Assets
The components of the Company’s Other Current Assets are as follows:
| | | | | | | | | | | |
| | Year Ended September 30 |
| 2022 | | 2021 |
| | (Thousands) |
| Prepayments | $ | 17,757 | | | $ | 14,164 | |
| Prepaid Property and Other Taxes | 14,321 | | | 14,788 | |
| | | |
| State Income Taxes Receivable | 5,933 | | | 1,502 | |
| | | |
| Regulatory Assets | 21,358 | | | 29,206 | |
| $ | 59,369 | | | $ | 59,660 | |
|
| | | | | | | |
| | Year Ended September 30 |
| | 2017 | | 2016 |
| | (Thousands) |
| Prepayments | $ | 10,927 |
| | $ | 10,919 |
|
| Prepaid Property and Other Taxes | 13,974 |
| | 13,138 |
|
| Federal Income Taxes Receivable | — |
| | 11,758 |
|
| State Income Taxes Receivable | 9,689 |
| | 3,961 |
|
| Fair Values of Firm Commitments | 1,031 |
| | 3,962 |
|
| Regulatory Assets | 15,884 |
| | 15,616 |
|
| | $ | 51,505 |
| | $ | 59,354 |
|
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Other Accruals and Current Liabilities
The components of the Company’s Other Accruals and Current Liabilities are as follows:
| | | | Year Ended September 30 | | Year Ended September 30 |
| | 2017 | | 2016 | | 2022 | | 2021 |
| | (Thousands) | | (Thousands) |
| Accrued Capital Expenditures | $ | 37,382 |
| | $ | 26,796 |
| Accrued Capital Expenditures | $ | 64,720 | | | $ | 42,541 | |
| Regulatory Liabilities | 34,059 |
| | 14,725 |
| Regulatory Liabilities | 31,293 | | | 60,860 | |
| Federal Income Taxes Payable | 1,775 |
| | — |
| |
| | Liability for Royalty and Working Interests | | Liability for Royalty and Working Interests | 86,206 | | | 31,483 | |
| Non-Qualified Benefit Plan Liability | | Non-Qualified Benefit Plan Liability | 17,474 | | | 15,408 | |
| Other | 38,673 |
| | 32,909 |
| Other | 57,634 | | | 43,877 | |
| | $ | 111,889 |
| | $ | 74,430 |
| | $ | 257,327 | | | $ | 194,169 | |
Customer Advances
The Company’sCompany, primarily in its Utility and Energy Marketing segments havesegment, has balanced billing programs whereby customers pay their estimated annual usage in equal installments over a twelve-month period. Monthly payments under the balanced billing programs are typically higher than current month usage during the summer months. During the winter months, monthly payments under the balanced billing programs are typically lower than current month usage. At September 30, 20172022 and 2016,2021, customers in the balanced billing programs had advanced excess funds of $15.7$26.1 million and $14.8$17.2 million, respectively.
Customer Security Deposits
The Company, primarily in its Utility and Pipeline and Storage and Energy Marketing segments, often timesoftentimes requires security deposits from marketers, producers, pipeline companies, and commercial and industrial customers before providing services to such customers. At September 30, 20172022 and 2016,2021, the Company had received customer security deposits amounting to $20.4$24.3 million and $16.0$19.3 million, respectively.
Earnings Per Common Share
Basic earnings per common share is computed by dividing income or loss by the weighted average number of common shares outstanding for the period. Diluted earnings per common share reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock. For purposes of determining earnings per common share, the potentially dilutive securities the Company hashad outstanding are stock options,were SARs, restricted stock units and performance shares. For the yearyears ended September 30, 2017,2022 and September 30, 2021, the diluted weighted average shares outstanding shown on the Consolidated Statements of Income reflects the potential dilution as a result of these securities as determined using the Treasury Stock Method. Stock options, SARs, restricted stock units and performance shares that are antidilutive are excluded from the calculation of diluted earnings per common share. There were 157,649 shares2,858 securities excluded as being antidilutive for the year ended September 30, 2017.2022 and 320,222 securities excluded as being antidilutive for the year ended September 30, 2021. As the Company recognized a net lossesloss for the yearsyear ended September 30, 2016 and 2015,2020, the aforementioned potentially dilutive securities, amounting to 431,408 shares and 709,063 shares, respectively,411,890 securities, were not recognized in the diluted earnings per share calculation for 2016 and 2015.2020.
Stock-Based Compensation
The Company has various stock option and stock award plans which provide or provided for the issuance of one or more of the following to key employees: SARs, incentive stock options, nonqualified stock options, SARs, restricted stock, restricted stock units, performance units or performance shares. The Company follows authoritative guidance which requires the measurement and recognition of compensation cost at fair value for all share-based payments. Stock options and SARs under all plans have exercise prices equal to the average market price of Company common stock on the date of grant, and generally no stock option or SAR is exercisable less than one year or more than ten years after the date of each grant. The Company has chosen the Black-Scholes-Merton closed
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
the date of each grant. The Company has chosen the Black-Scholes-Merton closed form model to calculate the compensation expense associated with stock options and SARs. For all Company stock awards, forfeitures are recognized as they occur.
Restricted stock is subject to restrictions on vesting and transferability. Restricted stock awards entitle the participants to full dividend and voting rights. The market value of restricted stock on the date of the award is recorded as compensation expense over the vesting period. Certificates for shares of restricted stock awarded under the Company’s stock option and stock award plans are held by the Company during the periods in which the restrictions on vesting are effective. Restrictions on restricted stock awards generally lapse ratably over a period of not more than ten years after the date of each grant. Restricted stock units also are subject to restrictions on vesting and transferability. Restricted stock units both performance and non-performance based, represent the right to receive shares of common stock of the Company (or the equivalent value in cash or a combination of cash and shares of common stock of the Company, as determined by the Company) at the end of a specified time period. The performance based and non-performance based restricted stock units do not entitle the participants to dividend and voting rights. The accounting for performance based and non-performance based restricted stock units is the same as the accounting for restricted share awards, except that the fair value at the date of grant of the restricted stock units (represented by the market value of Company common stock on the date of the award) must be reduced by the present value of forgone dividends over the vesting term of the award. The fair value of restricted stock units on the date of award is recorded as compensation expense over the vesting period.
Performance shares are an award constituting units denominated in common stock of the Company, the number of which may be adjusted over a performance cycle based upon the extent to which performance goals have been satisfied. Earned performance shares may be distributed in the form of shares of common stock of the Company, an equivalent value in cash or a combination of cash and shares of common stock of the Company, as determined by the Company. The performance shares do not entitle the participant to receive dividends during the vesting period. For performance shares based on a return on capital goal and greenhouse gas emissions reductions, the fair value at the date of grant of the performance shares is determined by multiplying the expected number of performance shares to be issued by the market value of Company common stock on the date of grant reduced by the present value of forgone dividends. For performance shares based on a total shareholder return goal, the Company uses the Monte Carlo simulation technique to estimate the fair value price at the date of grant.
Refer to Note EH — Capitalization and Short-Term Borrowings under the heading “Stock Option and Stock Award Plans” for additional disclosures related to stock-based compensation awards for all plans.
Note B — Asset Acquisitions and Divestitures
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 Company pursued this sale given the strong commodity price environment and the Company’s strategic focus in the Appalachian Basin. Under the terms of the purchase and sale agreement, the Company can receive up to three annual contingent payments between calendar year 2023 and calendar year 2025, not to exceed $10 million per year, with the amount of each annual payment calculated as $1.0 million for each $1 per barrel that the ICE Brent Average for each calendar year exceeds $95 per barrel up to $105 per barrel. The sale price, which reflected an effective date of April 1, 2022, was reduced for production revenues less expenses that were retained by Seneca from the effective date to the closing date. Under the full cost method of accounting for oil and natural gas properties, $220.7 million of the sale price at closing was accounted for as reduction of capitalized costs since the disposition did not alter the relationship between capitalized costs and proved reserves of oil and gas attributable to the cost center. The remainder of the sale price ($32.8 million) was applied against assets that are not subject to the full cost method of accounting, with the Company recognizing a gain of $12.7 million on the sale of such assets. The majority of this gain related to the sale of emission allowances. The Company also eliminated the asset retirement obligation associated with Seneca’s California oil and gas assets. This obligation amounted to $50.1 million and was accounted for as a reduction of capitalized costs under the full cost method of accounting.
On July 31, 2020, the Company completed its acquisition of certain upstream assets and midstream gathering assets in Pennsylvania from SWEPI LP, a subsidiary of Royal Dutch Shell plc (“Shell”) for total consideration of $506.3 million. The purchase price, which reflected an effective date of January 1, 2020, was reduced for production revenues less expenses that were retained by Shell from the effective date to the closing
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
date. As part of the transaction, the Company acquired over 400,000 net acres in Appalachia, including approximately 200,000 net acres in Tioga County, Pennsylvania. The proved developed and undeveloped natural gas reserves associated with this acquisition amounted to 684,141 MMcf. In addition, the Company acquired gathering pipelines and related compression, water pipelines, and associated water handling infrastructure, all of which support the acquired Tioga County production operations. These gathering facilities are interconnected with various interstate pipelines, including the Company’s Empire pipeline system, with the potential to tie into the Company’s existing Covington gathering system. Post-closing, the Company has integrated the assets into its existing operations in Tioga County, which has resulted in cost synergies. This transaction was accounted for as an asset acquisition as substantially all the fair value of the gross assets acquired is concentrated in a single asset under the screen test comprised of Proved Developed Producing Reserves and the attached Gathering Property, Plant and Equipment. The purchase consideration, including the transaction costs, has been allocated to the individual assets acquired based on their relative fair values. The following is a summary of the asset acquisition (in thousands):
| | | | | | | | | | | | | | | | | |
| Purchase Price | $ | 503,908 | |
| Transaction Costs | 2,350 | |
| Total Consideration | $ | 506,258 | |
| | | | | |
| Allocation of Cost of Asset Acquisition: | | |
| Exploration and Production Reporting Segment | | Gathering Reporting Segment | | Total |
| Property, Plant and Equipment | $ | 281,648 | | (1)(2) | $ | 223,369 | | (2) | $ | 505,017 | |
| Inventory | 1,132 | | | 109 | | | 1,241 | |
| Total Accounting | $ | 282,780 | | | $ | 223,478 | | | $ | 506,258 | |
(1)Includes $241,134 in Proved Developed Producing Properties and $277,832 capitalized in the full cost pool.
(2)The Company utilized an income approach and market based approach to determine the fair value of the acquired property, plant and equipment in the Exploration and Production reporting segment. The Company utilized a cost approach and an income approach to determine the fair value of the acquired property, plant and equipment in the Gathering reporting segment.
The acquisition of the upstream assets and midstream gathering assets from Shell was financed with a combination of debt and equity, as discussed in Note H — Capitalization and Short-Term Borrowings. The purchase and sale agreement with Shell was structured, in part, as a reverse like-kind exchange pursuant to Section 1031 of the Internal Revenue Code, as amended (“Reverse 1031 Exchange”).
On December 10, 2020, the Company completed the sale of substantially all timber properties in Pennsylvania to Lyme Emporium Highlands III LLC and Lyme Allegheny Land Company II LLC for net proceeds of $104.6 million. These assets were a component of the Company’s All Other category and did not have a major impact on the Company’s operations or financial results. After purchase price adjustments and transaction costs, a gain of $51.1 million was recognized on the sale of these assets. Since the sale did not represent a strategic shift in focus for the Company, the financial results associated with operating these assets as well as the gain on sale have not been reported as discontinued operations.
The sale of the timber properties completed the Reverse 1031 Exchange related to the Company’s acquisition of certain upstream assets and midstream gathering assets in Pennsylvania from Shell, as discussed above. In connection with the Reverse 1031 Exchange, the Company, through a subsidiary, assigned the rights
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
to acquire legal title to certain oil and natural gas properties to a Variable Interest Entity ("VIE") formed by an exchange accommodation titleholder. The Company evaluated the VIE to determine whether the Company should be considered as the primary beneficiary having a controlling financial interest. It was determined that the Company had the power to direct the activities of the VIE and the obligation to absorb significant losses of that entity or the right to receive significant benefits from that entity. Therefore, the Company was considered to be the primary beneficiary. From July 31, 2020 to December 10, 2020, a subsidiary of the Company operated the properties pursuant to a lease agreement with the VIE. As the Company was deemed to be the primary beneficiary of the VIE, the VIE was included in the consolidated financial statements of the Company. Upon completion of the sale of the timber properties on December 10, 2020, the affected properties were conveyed to the Company and the VIE structure was terminated.
On August 1, 2020, the Company completed the sale of NFR’s commercial and industrial gas contracts in New Authoritative AccountingYork and Financial Reporting GuidancePennsylvania and certain other assets to Marathon Power LLC. This sale, in conjunction with the turn back of NFR's residential customers to Distribution Corporation, effectively ended NFR's operations. The sale did not have a material impact to the Company’s financial statements. The divestiture reflects the Company’s decision to focus on other strategic areas of the energy market.
Note C — Revenue from Contracts with Customers
The following tables provide a disaggregation of the Company's revenues for the years ended September 30, 2022 and 2021, presented by type of service from each reportable segment.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended September 30, 2022 |
| Revenues by Type of Service | Exploration
and
Production | | Pipeline
and
Storage | | Gathering | | Utility | | Total
Reportable
Segments | | All
Other | | Corporate
and
Intersegment
Eliminations | | Total
Consolidated |
| | (Thousands) |
| Production of Natural Gas | $ | 1,730,723 | | | $ | — | | | $ | — | | | $ | — | | | $ | 1,730,723 | | | $ | — | | | $ | — | | | $ | 1,730,723 | |
| Production of Crude Oil | 150,957 | | | — | | | — | | | — | | | 150,957 | | | — | | | — | | | 150,957 | |
| Natural Gas Processing | 3,511 | | | — | | | — | | | — | | | 3,511 | | | — | | | — | | | 3,511 | |
| Natural Gas Gathering Service | — | | | — | | | 214,843 | | | — | | | 214,843 | | | — | | | (202,757) | | | 12,086 | |
| Natural Gas Transportation Service | — | | | 289,967 | | | — | | | 106,495 | | | 396,462 | | | — | | | (74,749) | | | 321,713 | |
| Natural Gas Storage Service | — | | | 84,565 | | | — | | | — | | | 84,565 | | | — | | | (36,382) | | | 48,183 | |
| Natural Gas Residential Sales | — | | | — | | | — | | | 688,271 | | | 688,271 | | | — | | | — | | | 688,271 | |
| Natural Gas Commercial Sales | — | | | — | | | — | | | 95,114 | | | 95,114 | | | — | | | — | | | 95,114 | |
| Natural Gas Industrial Sales | — | | | — | | | — | | | 4,902 | | | 4,902 | | | — | | | — | | | 4,902 | |
| Other | 7,867 | | | 2,512 | | | — | | | (3,918) | | | 6,461 | | | 6 | | | (644) | | | 5,823 | |
| Total Revenues from Contracts with Customers | 1,893,058 | | | 377,044 | | | 214,843 | | | 890,864 | | | 3,375,809 | | | 6 | | | (314,532) | | | 3,061,283 | |
| Alternative Revenue Programs | — | | | — | | | — | | | 7,357 | | | 7,357 | | | — | | | — | | | 7,357 | |
| Derivative Financial Instruments | (882,594) | | | — | | | — | | | — | | | (882,594) | | | — | | | — | | | (882,594) | |
| Total Revenues | $ | 1,010,464 | | | $ | 377,044 | | | $ | 214,843 | | | $ | 898,221 | | | $ | 2,500,572 | | | $ | 6 | | | $ | (314,532) | | | $ | 2,186,046 | |
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended September 30, 2021 |
| Revenues by Type of Service | Exploration
and
Production | | Pipeline
and
Storage | | Gathering | | Utility | | Total
Reportable
Segments | | All
Other | | Corporate
and
Intersegment
Eliminations | | Total
Consolidated |
| | (Thousands) |
| Production of Natural Gas | $ | 780,477 | | | $ | — | | | $ | — | | | $ | — | | | $ | 780,477 | | | $ | — | | | $ | — | | | $ | 780,477 | |
| Production of Crude Oil | 135,191 | | | — | | | — | | | — | | | 135,191 | | | — | | | — | | | 135,191 | |
| Natural Gas Processing | 2,960 | | | — | | | — | | | — | | | 2,960 | | | — | | | — | | | 2,960 | |
| Natural Gas Gathering Service | — | | | — | | | 193,264 | | | — | | | 193,264 | | | — | | | (190,148) | | | 3,116 | |
| Natural Gas Transportation Service | — | | | 255,849 | | | — | | | 103,141 | | | 358,990 | | | — | | | (72,920) | | | 286,070 | |
| Natural Gas Storage Service | — | | | 83,080 | | | — | | | — | | | 83,080 | | | — | | | (35,841) | | | 47,239 | |
| Natural Gas Residential Sales | — | | | — | | | — | | | 492,567 | | | 492,567 | | | — | | | — | | | 492,567 | |
| Natural Gas Commercial Sales | — | | | — | | | — | | | 62,634 | | | 62,634 | | | — | | | — | | | 62,634 | |
| Natural Gas Industrial Sales | — | | | — | | | — | | | 3,071 | | | 3,071 | | | — | | | — | | | 3,071 | |
| Natural Gas Marketing | — | | | — | | | — | | | — | | | — | | | 678 | | | (49) | | | 629 | |
| Other | 2,042 | | | 4,628 | | | — | | | (5,249) | | | 1,421 | | | 544 | | | (374) | | | 1,591 | |
| Total Revenues from Contracts with Customers | 920,670 | | | 343,557 | | | 193,264 | | | 656,164 | | | 2,113,655 | | | 1,222 | | | (299,332) | | | 1,815,545 | |
| Alternative Revenue Programs | — | | | — | | | — | | | 11,087 | | | 11,087 | | | — | | | — | | | 11,087 | |
| Derivative Financial Instruments | (83,973) | | | — | | | — | | | — | | | (83,973) | | | — | | | — | | | (83,973) | |
| Total Revenues | $ | 836,697 | | | $ | 343,557 | | | $ | 193,264 | | | $ | 667,251 | | | $ | 2,040,769 | | | $ | 1,222 | | | $ | (299,332) | | | $ | 1,742,659 | |
The Company records revenue related to its derivative financial instruments in the Exploration and Production segment. The Company also records revenue related to alternative revenue programs in its Utility segment. Revenue related to derivative financial instruments and alternative revenue programs are excluded from the scope of the authoritative guidance regarding revenue recognition since they are accounted for under other existing accounting guidance.
Exploration and Production Segment Revenue
The Company’s Exploration and Production segment records revenue from the sale of the natural gas and oil that it produces and natural gas liquids (NGLs) processed based on entitlement, which means that revenue is recorded based on the actual amount of natural gas or oil that is delivered to a pipeline, or upon pick-up in the case of NGLs, and the Company’s ownership interest. Prior to the completion of the sale of the Company’s California assets on June 30, 2022, natural gas production occurred primarily in the Appalachian region of the United States and crude oil production occurred primarily in the West Coast region of the United States. Subsequent to June 30, 2022, substantially all Exploration and Production segment production consists of natural gas production from the Appalachian region of the United States. If a production imbalance occurs between what was supposed to be delivered to a pipeline and what was actually produced and delivered, the Company accrues the difference as an imbalance. The sales contracts generally require the Company to deliver a specific quantity of a commodity per day for a specific number of days at a price that is either fixed or variable and considers the delivery of each unit (MMBtu or Bbl) to be a separate performance obligation that is satisfied upon delivery.
The transaction price for the sale of natural gas, oil and NGLs is contractually agreed upon based on prevailing market pricing (primarily tied to a market index with certain adjustments based on factors such as delivery location and prevailing supply and demand conditions) or fixed pricing. The Company allocates the transaction price to each performance obligation on the basis of the relative standalone selling price of each distinct unit sold. Revenue is recognized at a point in time when the transfer of the commodity occurs at the delivery point per the contract. The amount billable, as determined by the contracted quantity and price, indicates the value to the customer, and is used for revenue recognition purposes by the Exploration and Production segment as specified by the “invoice practical expedient” (the amount that the Exploration and
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Production segment has the right to invoice) under the authoritative guidance for revenue recognition. The contracts typically require payment within 30 days of the end of the calendar month in which the natural gas and oil is delivered, or picked up in the case of NGLs.
The Company uses derivative financial instruments to manage commodity price risk in the Exploration and Production segment related to sales of the natural gas that it produces. Gains or losses on such derivative financial instruments are recorded as adjustments to revenue; however, they are not considered to be revenue from contracts with customers.
Pipeline and Storage Segment Revenue
The Company’s Pipeline and Storage segment records revenue for natural gas transportation and storage services in New York and Pennsylvania at tariff-based rates regulated by the FERC. Customers secure their own gas supply and the Pipeline and Storage segment provides transportation and/or storage services to move the customer-supplied gas to the intended location, including injections into or withdrawals from the storage field. This performance obligation is satisfied over time. The rate design for the Pipeline and Storage segment’s customers generally includes a combination of volumetric or commodity charges as well as monthly “fixed” charges (including charges commonly referred to as capacity charges, demand charges, or reservation charges). These types of fixed charges represent compensation for standing ready over the period of the month to deliver quantities of gas, regardless of whether the customer takes delivery of any quantity of gas. The performance obligation under these circumstances is satisfied based on the passage of time and meter reads, if applicable, which correlates to the period for which the charges are eligible to be invoiced. The amount billable, as determined by the meter read and the “fixed” monthly charge, indicates the value to the customer, and is used for revenue recognition purposes by the Pipeline and Storage segment as specified by the “invoice practical expedient” (the amount that the Pipeline and Storage segment has the right to invoice) under the authoritative guidance for revenue recognition. Customers are billed after the end of each calendar month, with payment typically due by the 25th day of the month in which the invoice is received.
The Company’s Pipeline and Storage segment expects to recognize the following revenue amounts in future periods related to “fixed” charges associated with remaining performance obligations for transportation and storage contracts: $212.4 million for fiscal 2023; $191.0 million for fiscal 2024; $166.9 million for fiscal 2025; $143.8 million for fiscal 2026; $121.1 million for fiscal 2027; and $691.7 million thereafter.
Gathering Segment Revenue
The Company’s Gathering segment provides gathering and processing services in the Appalachian region of Pennsylvania, primarily for Seneca. The Gathering segment’s primary performance obligation is to deliver gathered natural gas volumes from Seneca’s wells, and to a lesser extent, other producers' wells, into interstate pipelines at contractually agreed upon per unit rates. This obligation is satisfied over time. The performance obligation is satisfied based on the passage of time and meter reads, which correlates to the period for which the charges are eligible to be invoiced. The amount billable, as determined by the meter read and the contracted volumetric rate, indicates the value to the customer, and is used for revenue recognition purposes by the Gathering segment as specified by the “invoice practical expedient” (the amount that the Gathering segment has the right to invoice) under the authoritative guidance for revenue recognition. Customers are billed after the end of each calendar month, with payment typically due by the 10th day after the invoice is received.
Utility Segment Revenue
The Company’s Utility segment records revenue for natural gas sales and natural gas transportation services in western New York and northwestern Pennsylvania at tariff-based rates regulated by the NYPSC and the PaPUC, respectively. Natural gas sales and transportation services are provided largely to residential, commercial and industrial customers. The Utility segment’s performance obligation to its customers is to deliver natural gas, an obligation which is satisfied over time. This obligation generally remains in effect as long as the customer consumes the natural gas provided by the Utility segment. The Utility segment recognizes
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
revenue when it satisfies its performance obligation by delivering natural gas to the customer. Natural gas is delivered and consumed by the customer simultaneously. The satisfaction of the performance obligation is measured by the turn of the meter dial. The amount billable, as determined by the meter read and the tariff-based rate, indicates the value to the customer, and is used for revenue recognition purposes by the Utility segment as specified by the “invoice practical expedient” (the amount that the Utility segment has the right to invoice) under the authoritative guidance for revenue recognition. Since the Utility segment bills its customers in cycles having billing dates that do not generally coincide with the end of a calendar month, a receivable is recorded for natural gas delivered but not yet billed to customers based on an estimate of the amount of natural gas delivered between the last meter reading date and the end of the accounting period. Such receivables are a component of Unbilled Revenue on the Consolidated Balance Sheets. The Utility segment’s tariffs allow customers to utilize budget billing. In May 2014,this situation, since the FASB issuedamount billed may differ from the amount of natural gas delivered to the customer in any given month, revenue is recognized monthly based on the amount of natural gas consumed. The differential between the amount billed and the amount consumed is recorded as a component of Receivables or Customer Advances on the Consolidated Balance Sheets. All receivables or advances related to budget billing are settled within one year.
Utility Segment Alternative Revenue Programs
As indicated in the revenue table shown above, the Company’s Utility segment has alternative revenue programs that are excluded from the scope of the authoritative guidance regarding revenue recognition. The authoritative guidance provides a single, comprehensiveNYPSC has authorized alternative revenue recognition modelprograms that are designed to mitigate the impact that weather and conservation have on margin. The NYPSC has also authorized additional alternative revenue programs that adjust billings for all contractsthe effects of broad external factors or to compensate the Company for demand-side management initiatives. These alternative revenue programs primarily allow the Company and customer to share in variances from imputed margins due to migration of transportation customers, allow for adjustments to the gas cost recovery mechanism for fluctuations in uncollectible expenses associated with gas costs, and allow the Company to pass on to customers costs associated with customer energy efficiency programs. In general, revenue is adjusted monthly for these programs and is collected from or passed back to improve comparability. The revenue standard contains principles that an entity will apply to determine the measurement of revenue and timing of when it is recognized. The original effective date of this authoritative guidance was ascustomers within 24 months of the Company's first quarter of fiscal 2018. However, the FASB has delayed the effective date of the new revenue standard by one year, and the guidance will now be effective as of the Company's first quarter of fiscal 2019. Working towards this implementation date, the Company is currently evaluating the guidance and the various issues identified by industry based revenue recognition task forces. The Company does not believe that its revenue recognition policies will change materially, although the Company is still assessing the impact. The Company will need to enhance its financial statement disclosures to comply with the new authoritative guidance.annual reconciliation period.
In May 2015, the FASB issued authoritative guidance related to the presentation of investments for which fair value was measured using net asset value per share (or its equivalent). In fiscal 2017,
Note D — Leases
On October 1, 2019, the Company adopted this authoritative guidance. As a result, the presentation of Retirement Plan Investments and Other Post-Retirement Benefit Assets has been adjusted (see tables in Note H — Retirement Plan and Other Post-Retirement Benefits).
In February 2016, the FASB issued authoritative guidance requiring organizationsregarding lease accounting, which requires entities that lease assetsthe use of property, plant and equipment to recognize on the balance sheet the assets and liabilities for the rights and obligations created by all leases, regardlessincluding leases classified as operating leases. The Company implemented the new standard using the optional transition method and elected to apply the following practical expedients provided in the authoritative guidance:
1.For contracts that commenced prior to and existed as of October 1, 2019, a package of practical expedients to not reassess whether a contract is or contains a lease, lease classification, and initial direct costs under the new authoritative guidance;
2.An election not to apply the recognition requirements in the new authoritative guidance to short-term leases (a lease that at commencement date has a lease term of one year or less);
3.A practical expedient to not reassess certain land easements that existed prior to October 1, 2019 and were not previously accounted for as leases under the prior authoritative guidance; and
4.A practical expedient that permits combining lease and non-lease components in a contract and accounting for the combination as a lease (elected by asset-class).
Upon adoption, the Company increased assets and liabilities on its Consolidated Balance Sheet by $19.7 million. The adoption did not result in a cumulative effect adjustment to earnings reinvested in the business or have a material impact on the Company’s Consolidated Statement of Income or Consolidated
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Statement of Cash Flows. Comparative periods, including disclosures relating to those periods, were not restated.
Nature of whether they are considered to be capitalLeases
The Company primarily leases or operating leases.building space and drilling rigs, and on a limited basis, compressor equipment and other miscellaneous assets. The FASB’s previous authoritative guidance required organizationsCompany determines if an arrangement is a lease at the inception of the arrangement. To the extent that an arrangement represents a lease, the Company classifies that lease assets to recognize onas an operating or a finance lease in accordance with the balance sheetauthoritative guidance. The Company did not have any material finance leases as of September 30, 2022 or September 30, 2021. Aside from a sublease of office space at the assetsCompany’s corporate headquarters, which terminated April 30th, 2022, the Company does not have any material arrangements where the Company is the lessor.
Buildings and liabilitiesProperty
The Company enters into building and property rental agreements with third parties for office space, certain field locations and other properties used in the rightsCompany’s operations. Building and obligations created by capitalproperty leases while excluding operating leases from balance sheet recognition.include the Company’s corporate headquarters in Williamsville, New York, and Exploration and Production segment offices in Houston, Texas, and Pittsburgh, Pennsylvania. The new authoritative guidance will be effective asprimary non-cancelable terms of the Company’s first quarter of fiscal 2020,building and property leases range from two months to seventeen years. Most building leases include one or more options to renew, generally at the Company’s sole discretion, with early adoption permitted. renewal terms that can extend the lease terms from one year to eighteen years. Renewal options are included in the lease term if they are reasonably certain to be exercised. The agreements do not contain any material restrictive covenants.
Drilling Rigs
The Company enters into contracts for drilling rig services with third party contractors to support Seneca’s development activities in Pennsylvania. Seneca’s drilling rig arrangements are structured with a non-cancelable primary term that exceeds one year. Upon mutual agreement with the contractor, Seneca has the option to extend contracts with amended terms and conditions, including a renegotiated day rate fee.
Drilling rig lease costs are capitalized as part of natural gas properties on the Consolidated Balance Sheet when incurred.
Compressor Equipment
The Company enters into contracts for compressor services with third parties primarily to support its gathering system in Pennsylvania. The primary non-cancelable terms of the Company's compressor equipment leases range from 21 months to 4 years. Most compressor equipment leases include one or more options to renew or to continue past the primary term on a month-to-month basis, generally at the Company's sole discretion. Renewal options are included in the lease term if they are reasonably certain to be exercised.
Significant Judgments
Lease Identification
The Company uses judgment when determining whether or not an arrangement is or contains a lease. A contract is or contains a lease if the contract conveys the right to use an explicitly or implicitly identified asset that is physically distinct and the Company has the right to control the use of the identified asset for a period of time. When determining right of control, the Company evaluates whether it directs the use of the asset and obtains substantially all of the economic benefits from the use of the asset.
Discount Rate
The Company uses a discount rate to calculate the present value of lease payments in order to determine lease classification and measurement of the lease asset and liability. In the absence of a rate of interest that is
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
readily determinable in the contract, the Company estimates the incremental borrowing rate (IBR) for each lease. The IBR reflects the rate of interest that the Company would pay on the lease commencement date to borrow an amount equal to the lease payments on a collateralized basis over a similar term in similar economic environments.
Firm Transportation and Storage Contracts
The Company’s subsidiaries enter into long-term arrangements to both reserve firm transportation capacity on third party pipelines and provide firm transportation and storage services to third party shippers. The Company’s firm capacity contracts with non-affiliated entities do not provide rights to use substantially all of the underlying pipeline or storage asset. As such, the Company has concluded that these arrangements are not leases under the authoritative guidance.
Gas Leases
The authoritative guidance does not anticipate early adoptionapply to leases to explore for or use natural gas resources, including the right to explore for those resources and is currently evaluatingrights to use the provisionsland in which those resources are contained. As such, the Company has concluded that its gas exploration and production leases and gas storage leases are not leases under the authoritative guidance.
Amounts Recognized in the Financial Statements
Operating lease costs, excluding those relating to drilling rig leases that are capitalized as part of oil and natural gas properties under full cost pool accounting, are presented in Operations and Maintenance expense on the Consolidated Statement of Income. The following table summarizes the components of the revised guidance.Company’s total operating lease costs (in thousands):
In March 2016, | | | | | | | | | | | |
| Year Ended September 30 |
| 2022 | | 2021 |
| Operating Lease Expense | $ | 4,909 | | | $ | 5,268 | |
| Variable Lease Expense(1) | 462 | | | 537 | |
| Short-Term Lease Expense(2) | 461 | | | 1,279 | |
| Sublease Income | (166) | | | (356) | |
| Total Lease Expense | $ | 5,666 | | | $ | 6,728 | |
| | | |
| Lease Costs Recorded to Property, Plant and Equipment(3) | $ | 19,839 | | | $ | 14,188 | |
(1)Variable lease payments that are not dependent on an index or rate are not included in the FASB issued authoritative guidance simplifying several aspectslease liability.
(2)Short-term lease costs exclude expenses related to leases with a lease term of one month or less.
(3)Lease costs relating to drilling rig leases that are capitalized as part of oil and natural gas properties under full cost pool accounting as well as certain equipment leases used on construction projects.
Right-of-use assets and lease liabilities are recognized at the accounting for stock-based compensation.commencement date of a leasing arrangement based on the present value of lease payments over the lease term. The Company adopted this guidance effectiveweighted average remaining lease term was 6.0 years and 8.8 years as of October 1, 2016, recognizingSeptember 30, 2022 and 2021, respectively. The weighted average discount rate was 3.92% and 4.24% as of September 30, 2022 and 2021, respectively.
The Company’s right-of-use operating lease assets are reflected as Deferred Charges on the Consolidated Balance Sheet. The corresponding operating lease liabilities are reflected in Other Accruals and Current Liabilities (current) and Other Liabilities (noncurrent). Short-term leases that have a cumulative effect adjustment that increased retained earnings by $31.9 million. lease term of one year or less are not recorded on the Consolidated Balance Sheet.
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The cumulative effect representsfollowing amounts related to operating leases were recorded on the tax benefit of previously unrecognized tax deductions in excess of stock compensation recordedCompany’s Consolidated Balance Sheet (in thousands):
| | | | | | | | | | | |
| Year Ended September 30 |
| 2022 | | 2021 |
| Assets: | | | |
| Deferred Charges | $ | 37,120 | | | $ | 23,601 | |
| | | |
| Liabilities: | | | |
| Other Accruals and Current Liabilities | $ | 14,239 | | | $ | 3,963 | |
| Other Liabilities | $ | 22,881 | | | $ | 19,638 | |
Cash paid for financial reporting purposes. On a prospective basis, the tax effect of all future differences between stock compensation recorded for financial reporting purposeslease liabilities, and actual tax deductions for stock compensation will be recognized upon vesting or settlement as income tax expense or benefit in the income statement. From a statement of cash flows perspective, the tax benefits relating to differences between stock compensation recorded for financial reporting purposes and actual tax deductions for stock compensation are now includedreported in cash provided by operating activities instead of cash provided by financing activities. The changes to the statement of cash flows have been applied prospectively and prior periods have not been adjusted.
In March 2017, the FASB issued authoritative guidance related to the presentation of net periodic pension cost and net periodic postretirement benefit cost. The new guidance requires segregation of the service cost component from the other components of net periodic pension cost and net periodic postretirement benefit cost for financial reporting purposes. The service cost component is to be presented on the income statementCompany’s Consolidated Statement of Cash Flows, was $5.7 million and $6.7 million for the years ended September 30, 2022 and 2021, respectively. The Company did not record any right-of-use assets in exchange for new lease liabilities during the same line items as other compensation costs included within Operating Expenses andyears ended September 30, 2022 or 2021.
The following schedule of operating lease liability maturities summarizes the other components of net periodic pension cost and net periodic postretirement benefit cost areundiscounted lease payments owed by the Company to be presented on the income statement below the subtotal labeled Operating Income (Loss). Under this guidance, the service cost component shall be the only component eligiblelessors pursuant to be capitalized as part of the cost of inventory or property, plant and equipment. The new guidance will be effectivecontractual agreements in effect as of the Company’s first quarter of fiscal 2019, with early adoption permitted. The Company does not anticipate early adoption and is currently evaluating the interaction of this authoritative guidance with the various regulatory provisions concerning pension and postretirement benefit costs in the Company’s Utility and Pipeline and Storage segments.September 30, 2022 (in thousands):
| | | | | |
| At September 30, 2022 |
| 2023 | $ | 14,420 | |
| 2024 | 5,353 | |
| 2025 | 4,828 | |
| 2026 | 3,578 | |
| 2027 | 2,889 | |
| Thereafter | 11,656 | |
| Total Lease Payments | 42,724 | |
| Less: Interest | (5,604) | |
| Total Lease Liability | $ | 37,120 | |
Note BE — Asset Retirement Obligations
The Company accounts for asset retirement obligations in accordance with the authoritative guidance that requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. An asset retirement obligation is defined as a legal obligation associated with the retirement of a tangible long-lived asset in which the timing and/or method of settlement may or may not be conditional on a future event that may or may not be within the control of the Company. When the liability is initially recorded, the entity capitalizes the estimated cost of retiring the asset as part of the carrying amount of the related long-lived asset. Over time, the liability is adjusted to its present value each period and the capitalized cost is depreciated over the useful life of the related asset. The Company estimates the fair value of its asset retirement obligations based on the discounting of expected cash flows using various estimates, assumptions and judgments regarding certain factors such as the existence of a legal obligation for an asset retirement obligation; estimated amounts and timing of settlements; the credit-adjusted risk-free rate to be used; and inflation rates. Asset retirement obligations incurred in the current period were Level 3 fair value measurements as the inputs used to measure the fair value are unobservable.
The Company has recorded an asset retirement obligation representing plugging and abandonment costs associated with the Exploration and Production segment’s crude oil and natural gas wells and has capitalized such costs in property, plant and equipment (i.e. the full cost pool).
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
property, plant and equipment (i.e. the full cost pool). During fiscal 2021, this segment’s Appalachian operations were required to implement additional water testing on a portion of its assets, which contributed to an increase in the asset retirement obligation. This increase is the primary component of the Revisions of Estimates amount for fiscal 2021 shown in the table below.
In addition to the asset retirement obligation recorded in the Exploration and Production segment, the Company has recorded future asset retirement obligations associated with the plugging and abandonment of natural gas storage wells in the Pipeline and Storage segment and the removal of asbestos and asbestos-containing material in various facilities in the Utility and Pipeline and Storage segments. Asset retirement obligation costs related to storage tanks have been recorded in the Utility, Pipeline and Storage, and Gathering segments. The Company has also recorded asset retirement obligations for certain costs connected with the retirement of the distribution mains, services and servicesother components of the pipeline system in the Utility segment, the transmission mains and other components in the pipeline system in the Pipeline and Storage segment, and the gathering lines and other components in the Gathering segment. The retirement costs within the distribution, transmission and gathering systems are primarily for the capping and purging of pipe, which are generally abandoned in place when retired, as well as for the clean-up of PCB contamination associated with the removal of certain pipe.
OnAs discussed in Note B — Asset Acquisitions and Divestitures, on June 30, 2016, Seneca sold2022, the majority of its Upper Devonian wells in Pennsylvania. While the proceeds fromCompany completed the sale were not significant, it did resultof Seneca’s California oil and gas assets to Sentinel Peak Resources California LLC. With the divestiture of these assets, the Company reduced its Asset Retirement Obligation at June 30, 2022 by $50.1 million. This reduction is reflected in a $58.4Liabilities Settled in the table below.
As discussed in Note B — Asset Acquisitions and Divestitures, on July 31, 2020, the Company completed its acquisition of certain upstream assets and midstream gathering assets in Pennsylvania from Shell. With the acquisition of these assets, the Company recorded an additional $57.2 million reduction ofto its Asset Retirement Obligation at September 30, 2016,2020, which is reflected in Liabilities SettledIncurred in the table below. The following is a reconciliation of the change in the Company’s asset retirement obligations:
| | | | | | | | | | | | | | | | | |
| | Year Ended September 30 |
| | 2022 | | 2021 | | 2020 |
| | (Thousands) |
| Balance at Beginning of Year | $ | 209,639 | | | $ | 192,228 | | | $ | 127,458 | |
| Liabilities Incurred | 2,401 | | | 7,035 | | | 61,246 | |
| Revisions of Estimates | 10,700 | | | 14,509 | | | 3,267 | |
| Liabilities Settled | (71,171) | | | (14,270) | | | (7,268) | |
| Accretion Expense | 9,976 | | | 10,137 | | | 7,525 | |
| Balance at End of Year | $ | 161,545 | | | $ | 209,639 | | | $ | 192,228 | |
|
| | | | | | | | | | | |
| | Year Ended September 30 |
| | 2017 | | 2016 | | 2015 |
| | (Thousands) |
| Balance at Beginning of Year | $ | 112,330 |
| | $ | 156,805 |
| | $ | 117,713 |
|
| Liabilities Incurred | 2,963 |
| | 2,719 |
| | 4,433 |
|
| Revisions of Estimates | (10,578 | ) | | 16,721 |
| | 33,717 |
|
| Liabilities Settled | (4,967 | ) | | (72,215 | ) | | (6,825 | ) |
| Accretion Expense | 6,647 |
| | 8,300 |
| | 7,767 |
|
| Balance at End of Year | $ | 106,395 |
| | $ | 112,330 |
| | $ | 156,805 |
|
NATIONAL FUEL GAS COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note CF — Regulatory Matters
Regulatory Assets and Liabilities
The Company has recorded the following regulatory assets and liabilities:
| | | | At September 30 | | At September 30 |
| | 2017 | | 2016 | | 2022 | | 2021 |
| | (Thousands) | | (Thousands) |
| Regulatory Assets(1): | | | | Regulatory Assets(1): | |
| Pension Costs(2) (Note H) | $ | 125,175 |
| | $ | 203,755 |
| |
| Post-Retirement Benefit Costs(2) (Note H) | 13,886 |
| | 74,802 |
| |
| Recoverable Future Taxes (Note D) | 181,363 |
| | 177,261 |
| |
| Environmental Site Remediation Costs(2) (Note I) | 19,665 |
| | 23,392 |
| |
| Asset Retirement Obligations(2) (Note B) | 12,764 |
| | 12,490 |
| |
| Pension Costs(2) (Note K) | | Pension Costs(2) (Note K) | $ | 11,677 | | | $ | 21,655 | |
| Post-Retirement Benefit Costs(2) (Note K) | | Post-Retirement Benefit Costs(2) (Note K) | 6,814 | | | 10,075 | |
| Recoverable Future Taxes (Note G) | | Recoverable Future Taxes (Note G) | 106,247 | | | 121,992 | |
| Environmental Site Remediation Costs(2) (Note L) | | Environmental Site Remediation Costs(2) (Note L) | 3,646 | | | 7,256 | |
| Asset Retirement Obligations(2) (Note E) | | Asset Retirement Obligations(2) (Note E) | 18,517 | | | 16,799 | |
| Unamortized Debt Expense (Note A) | 1,159 |
| | 1,688 |
| Unamortized Debt Expense (Note A) | 8,884 | | | 10,589 | |
| Other(3) | 18,827 |
| | 21,927 |
| Other(3) | 47,805 | | | 33,566 | |
| Total Regulatory Assets | 372,839 |
| | 515,315 |
| Total Regulatory Assets | 203,590 | | | 221,932 | |
| Less: Amounts Included in Other Current Assets | (15,884 | ) | | (15,616 | ) | Less: Amounts Included in Other Current Assets | (21,358) | | | (29,206) | |
| Total Long-Term Regulatory Assets | $ | 356,955 |
| | $ | 499,699 |
| Total Long-Term Regulatory Assets | $ | 182,232 | | | $ | 192,726 | |
| | | | | | | | | | | |
| | At September 30 |
| | 2022 | | 2021 |
| | (Thousands) |
| Regulatory Liabilities: | | | |
| Cost of Removal Regulatory Liability | $ | 259,947 | | | $ | 245,636 | |
| Taxes Refundable to Customers (Note G) | 362,098 | | | 354,089 | |
| Post-Retirement Benefit Costs(5) (Note K) | 167,305 | | | 213,112 | |
| Pension Costs(4) (Note K) | 8,242 | | | — | |
| Amounts Payable to Customers (See Regulatory Mechanisms in Note A) | 419 | | | 21 | |
| Other(6) | 44,549 | | | 48,391 | |
| Total Regulatory Liabilities | 842,560 | | | 861,249 | |
| Less: Amounts included in Current and Accrued Liabilities | (31,712) | | | (60,881) | |
| Total Long-Term Regulatory Liabilities | $ | 810,848 | | | $ | 800,368 | |
(1)The Company recovers the cost of its regulatory assets but generally does not earn a return on them. There are a few exceptions to this rule. For example, the Company does earn a return on Unrecovered Purchased Gas Costs and, in the New York jurisdiction of its Utility segment, earns a return, within certain parameters, on the excess of cumulative funding to the pension plan over the cumulative amount collected in rates.
(2)Included in Other Regulatory Assets on the Consolidated Balance Sheets.
(3)$21,358 and $29,206 are included in Other Current Assets on the Consolidated Balance Sheets at September 30, 2022 and 2021, respectively, since such amounts are expected to be recovered from ratepayers in the next 12 months. $26,447 and $4,360 are included in Other Regulatory Assets on the Consolidated Balance Sheets at September 30, 2022 and 2021, respectively.
(4)Included in Other Regulatory Liabilities on the Consolidated Balance Sheets.
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(5)$5,800 and $30,000 are included in Other Accruals and Current Liabilities on the Consolidated Balance Sheets at September 30, 2022 and 2021, respectively, since such amounts are expected to be passed back to ratepayers in the next 12 months. $161,505 and $183,112 are included in Other Regulatory Liabilities on the Consolidated Balance Sheets at September 30, 2022 and 2021, respectively.
(6)$25,493 and $30,860 are included in Other Accruals and Current Liabilities on the Consolidated Balance Sheets at September 30, 2022 and 2021, respectively, since such amounts are expected to be passed back to ratepayers in the next 12 months. $19,056 and $17,531 are included in Other Regulatory Liabilities on the Consolidated Balance Sheets at September 30, 2022 and 2021, respectively.
|
| | | | | | | |
| | At September 30 |
| | 2017 | | 2016 |
| | (Thousands) |
| Regulatory Liabilities: | | | |
| Cost of Removal Regulatory Liability | $ | 204,630 |
| | $ | 193,424 |
|
| Taxes Refundable to Customers (Note D) | 95,739 |
| | 93,318 |
|
| Post-Retirement Benefit Costs (Note H) | 102,891 |
| | 67,204 |
|
| Amounts Payable to Customers (See Regulatory Mechanisms in Note A) | — |
| | 19,537 |
|
| Other(4) | 44,884 |
| | 47,310 |
|
| Total Regulatory Liabilities | 448,144 |
| | 420,793 |
|
| Less: Amounts included in Current and Accrued Liabilities | (34,059 | ) | | (34,262 | ) |
| Total Long-Term Regulatory Liabilities | $ | 414,085 |
| | $ | 386,531 |
|
| |
(1) | The Company recovers the cost of its regulatory assets but generally does not earn a return on them. There are a few exceptions to this rule. For example, the Company does earn a return on Unrecovered Purchased Gas Costs and, in the New York jurisdiction of its Utility segment, earns a return, within certain parameters, on the excess of cumulative funding to the pension plan over the cumulative amount collected in rates. |
| |
(2) | Included in Other Regulatory Assets on the Consolidated Balance Sheets. |
| |
(3) | $15,884 and $15,616 are included in Other Current Assets on the Consolidated Balance Sheets at September 30, 2017 and 2016, respectively, since such amounts are expected to be recovered from ratepayers in the next 12 months. $2,943 and $6,311 are included in Other Regulatory Assets on the Consolidated Balance Sheets at September 30, 2017 and 2016, respectively. |
| |
(4) | $34,059 and $14,725 are included in Other Accruals and Current Liabilities on the Consolidated Balance Sheets at September 30, 2017 and 2016, respectively, since such amounts are expected to be recovered from ratepayers in the next 12 months. $10,825 and $32,585 are included in Other Regulatory Liabilities on the Consolidated Balance Sheets at September 30, 2017 and 2016, respectively. |
If for any reason the Company ceases to meet the criteria for application of regulatory accounting treatment for all or part of its operations, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the Consolidated Balance Sheets and included in income of the period in which the discontinuance of regulatory accounting treatment occurs.
Cost of Removal Regulatory Liability
In the Company’s Utility and Pipeline and Storage segments, costs of removing assets (i.e. asset retirement costs) are collected from customers through depreciation expense. These amounts are not a legal retirement obligation as discussed in Note BE — Asset Retirement Obligations. Rather, they are classified as a regulatory liability in recognition of the fact that the Company has collected dollars from the customercustomers that will be used in the future to fund asset retirement costs.
New York Jurisdiction
Distribution Corporation's current delivery rates in its New York jurisdiction were approved by the NYPSC Rate Proceeding
On April 28, 2016, Distribution Corporation commenced a rate case by filing proposed tariff amendments and supporting testimony requesting approval to increase its annual revenues by approximately $41.7 million. Distribution Corporation explained in the filing that its request for rate relief was necessitated by a revenue requirement driven primarily by rate base growth, higher operating expense and higher depreciation expense, among other things. On January 23, 2017, the administrative law judge assigned to the proceedingan order issued a recommended decision (RD) in the case. The RD, as revised on January 26, 2017, recommended a rate increase
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
designed to provide additional annual revenues of $8.5 million, an equity ratio, subject to update of 42.3% based on the Company’s equity ratio, and a cost of equity, subject to update of 8.6%. On April 20, 2017 the NYPSC issued an Order adopting some provisions of the RD and modifying or rejecting others. The Order provides for an annual rate increase of $5.9 million. The rate increase becamewith rates becoming effective May 1, 2017. The Order further providesorder provided for a return on equity of 8.7%, and established an equity ratio of 42.9%. The Order also directsdirected the implementation of an earnings sharing mechanism to be in place beginning on April 1, 2018.
On 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, 28, 2017, Distribution Corporation filedmade a filing with the NYPSC to effectuate a pension and OPEB surcredit to customers to offset these amounts being collected in base rates effective October 1, 2022. On September 16, 2022, the NYPSC issued an appeal withorder approving the filing. With the implementation of this surcredit, Distribution Corporation will no longer be funding the pension from its New York State Supreme Court, Albany County, seeking reviewjurisdiction and it will not be funding its VEBA trusts in its New York jurisdiction.
Pennsylvania Jurisdiction
Distribution Corporation’s current delivery rates in its Pennsylvania jurisdiction were approved by the PaPUC on November 30, 2006 as part of the Order. The appeal contendsa settlement agreement that portions of the Order should be invalidated because they fail to meet the applicable legal standard for agency decisions.became effective January 1, 2007. On October 13, 2017,28, 2022, Distribution Corporation made a filing with the NYPSC filedPaPUC seeking an answer which containedincrease in its annual base rate operating revenues of $28.1 million with a request that the appeal be transferred to the Appellate Division.proposed effective date of December 27, 2022. The Company cannot predictis also proposing, among other things, to implement a weather normalization adjustment mechanism and a new energy efficiency and conservation pilot program for residential customers. The filing will be suspended for seven months by operation of law unless directed otherwise by the outcomePaPUC.
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 customers overcollected OPEB expenses in the amount of $50.0 million. Certain other matters in the appeal at this time.tariff supplement were unresolved. These matters were resolved with the PaPUC’s approval of an Administrative Law Judge’s Recommended Decision on February 24, 2022. Concurrent with that decision, the Company discontinued regulatory accounting for OPEB expenses and recorded an $18.5 million adjustment during the quarter ended March 31, 2022 to reduce its regulatory liability for previously deferred OPEB income
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
amounts through September 30, 2021 and to increase Other Income (Deductions) on the consolidated financial statements by a like amount. The Company also increased customer refunds of overcollected OPEB expenses from $50.0 million to $54.0 million. All refunds specified in the tariff supplement are being funded entirely by grantor trust assets held by the Company, most of which are included in a fixed income mutual fund that is a component of Other Investments on the Company’s Consolidated Balance Sheet. With the elimination of OPEB expenses in base rates, Distribution Corporation is no longer funding the grantor trust or its VEBA trusts in its Pennsylvania jurisdiction.
FERC Rate ProceedingsJurisdiction
Supply Corporation’s 2020 rate settlement provides that no party may make a rate filing for new rates to be effective before February 1, 2024, except that Supply Corporation currently has no activemay file an NGA general Section 4 rate case on file.to change rates if the corporate federal income tax rate is increased. If no case has been filed, Supply Corporation's currentCorporation must file for rates to be effective February 1, 2025.
Empire’s 2019 rate settlement requiresprovides that Empire must make a rate case filing no later than December 31, 2019.May 1, 2025.
Empire currently has no active rate case on file. Empire’s current rate settlement requires a rate case filing no later than July 1, 2021.
Note DG — Income Taxes
The components of federal and state income taxes included in the Consolidated Statements of Income are as follows:
| | | | | | | | | | | | | | | | | |
| | Year Ended September 30 |
| | 2022 | | 2021 | | 2020 |
| | (Thousands) |
| Current Income Taxes — | | | | | |
| Federal | $ | — | | | $ | (10) | | | $ | (42,548) | |
| State | 12,214 | | | 8,699 | | | 6,974 | |
| Deferred Income Taxes — | | | | | |
| Federal | 137,025 | | | 90,970 | | | 4,538 | |
| State | (32,610) | | | 15,023 | | | 49,775 | |
| Total Income Taxes | $ | 116,629 | | | $ | 114,682 | | | $ | 18,739 | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
|
| | | | | | | | | | | |
| | Year Ended September 30 |
| | 2017 | | 2016 | | 2015 |
| | (Thousands) |
| Current Income Taxes — | | | | | |
| Federal | $ | 32,034 |
| | $ | (6,658 | ) | | $ | 25,064 |
|
| State | 10,673 |
| | 20,903 |
| | 13,387 |
|
| Deferred Income Taxes — | | | | | |
| Federal | 103,046 |
| | (164,818 | ) | | (244,336 | ) |
| State | 14,929 |
| | (81,976 | ) | | (113,251 | ) |
| | 160,682 |
| | (232,549 | ) | | (319,136 | ) |
| Deferred Investment Tax Credit | (173 | ) | | (348 | ) | | (414 | ) |
| Total Income Taxes | $ | 160,509 |
| | $ | (232,897 | ) | | $ | (319,550 | ) |
| Presented as Follows: | | | | | |
| Other Income | $ | (173 | ) | | $ | (348 | ) | | $ | (414 | ) |
| Income Tax Expense (Benefit) | 160,682 |
| | (232,549 | ) | | (319,136 | ) |
| Total Income Taxes | $ | 160,509 |
| | $ | (232,897 | ) | | $ | (319,550 | ) |
On July 8, 2022, House Bill 1342 was signed into law in Pennsylvania. The law reduces the corporate income tax rate to 8.99% for fiscal 2024. Starting with fiscal 2025, the rate is reduced by 0.5% annually until it reaches 4.99% for fiscal 2032. Under GAAP, the tax effects of a change in tax law must be recognized in the period in which the law is enacted. GAAP also requires deferred income tax assets and liabilities to be measured at the enacted tax rate expected to apply when temporary differences are to be realized or settled. The Company's deferred income taxes were re-measured based upon the new tax rates. For the Company's non-rate regulated activities, the change in deferred income taxes was $28.4 million as of the enactment date and was recorded as a reduction to income tax expense. For the Company's rate regulated activities, the reduction in deferred income taxes of $37.2 million was recorded as a decrease to Recoverable Future Taxes of $19.8 million and an increase to Taxes Refundable to Customers of $17.4 million.
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
On August 16, 2022, the "Inflation Reduction Act" (IRA) was signed into law. The IRA, among other things, includes provisions to expand energy incentives and impose a corporate minimum tax. The provisions of the IRA did not have a material impact on the fiscal 2022 financial statements, although some of the provisions may be applicable in future years.
Total income taxes as reported differ from the amounts that were computed by applying the federal income tax rate to income (loss) before income taxes. The following is a reconciliation of this difference:
| | | | | | | | | | | | | | | | | |
| | Year Ended September 30 |
| | 2022 | | 2021 | | 2020 |
| | (Thousands) |
| U.S. Income (Loss) Before Income Taxes (1) | $ | 682,650 | | | $ | 478,327 | | | $ | (105,046) | |
Income Tax Expense (Benefit), Computed at U.S. Federal Statutory Rate of 21% | $ | 143,357 | | | $ | 100,449 | | | $ | (22,060) | |
| State Valuation Allowance (2) | (24,850) | | | (5,560) | | | 63,205 | |
| State Income Taxes (Benefit) (3) | 8,736 | | | 24,300 | | | (18,374) | |
| | | | | |
| Amortization of Excess Deferred Federal Income Taxes | (5,184) | | | (5,215) | | | (4,749) | |
| Plant Flow Through Items | (814) | | | (1,503) | | | (2,848) | |
| Stock Compensation | 820 | | | 2,239 | | | 3,867 | |
| Federal Tax Credits | (5,701) | | | (310) | | | (217) | |
| | | | | |
| Miscellaneous | 265 | | | 282 | | | (85) | |
| Total Income Taxes | $ | 116,629 | | | $ | 114,682 | | | $ | 18,739 | |
|
| | | | | | | | | | | |
| | Year Ended September 30 |
| | 2017 | | 2016 | | 2015 |
| | (Thousands) |
| U.S. Income (Loss) Before Income Taxes | $ | 443,991 |
| | $ | (523,855 | ) | | $ | (698,977 | ) |
| Income Tax Expense (Benefit), Computed at U.S. Federal Statutory Rate of 35% | $ | 155,397 |
| | $ | (183,349 | ) | | $ | (244,642 | ) |
| State Income Taxes (Benefit) | 16,641 |
| | (39,697 | ) | | (64,912 | ) |
| Federal Tax Credits | (6,679 | ) | | (3,262 | ) | | (732 | ) |
| Miscellaneous | (4,850 | ) | | (6,589 | ) | | (9,264 | ) |
| Total Income Taxes | $ | 160,509 |
| | $ | (232,897 | ) | | $ | (319,550 | ) |
(1)Amounts include the impact of deferred investment tax credits reported in Other Income (Deductions) on the Consolidated Statements of Income.
(2)During fiscal 2020, a valuation allowance was recorded against certain state deferred tax assets. During fiscal 2022, the valuation allowance was removed. See discussion below.
(3)The 2017 state income taxestax expense (benefit) shown above includes income tax benefits relatedadjustments to state enhanced oil recovery tax credits and a decrease in the estimated state effective tax rates utilized in the calculation of deferred income taxes.taxes, including the Pennsylvania rate change discussed above.
Significant components of the Company’s deferred tax liabilities and assets were as follows:
| | | | | | | | | | | |
| | At September 30 |
| | 2022 | | 2021 |
| | (Thousands) |
| Deferred Tax Liabilities: | | | |
| Property, Plant and Equipment | $ | 954,757 | | | $ | 920,692 | |
| Pension and Other Post-Retirement Benefit Costs | 30,132 | | | 23,240 | |
| Other | 48,893 | | | 35,081 | |
| Total Deferred Tax Liabilities | 1,033,782 | | | 979,013 | |
| Deferred Tax Assets: | | | |
| Unrealized Hedging Losses | (215,187) | | | (170,155) | |
| Tax Loss and Credit Carryforwards | (50,686) | | | (120,725) | |
| Pension and Other Post-Retirement Benefit Costs | (37,250) | | | (53,765) | |
| Other | (32,430) | | | (31,593) | |
| Total Gross Deferred Tax Assets | (335,553) | | | (376,238) | |
| Valuation Allowance | — | | | 57,645 | |
| Total Deferred Tax Assets | (335,553) | | | (318,593) | |
| Total Net Deferred Income Taxes | $ | 698,229 | | | $ | 660,420 | |
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
|
| | | | | | | |
| | At September 30 |
| | 2017 | | 2016 |
| | (Thousands) |
| Deferred Tax Liabilities: | | | |
| Property, Plant and Equipment | $ | 1,141,432 |
| | $ | 1,049,100 |
|
| Pension and Other Post-Retirement Benefit Costs | 79,516 |
| | 151,903 |
|
| Unrealized Hedging Gains | 19,127 |
| | 50,179 |
|
| Other | 57,919 |
| | 55,457 |
|
| Total Deferred Tax Liabilities | 1,297,994 |
| | 1,306,639 |
|
| Deferred Tax Assets: | | | |
| Pension and Other Post-Retirement Benefit Costs | (123,532 | ) | | (195,829 | ) |
| Tax Loss and Credit Carryforwards | (200,344 | ) | | (194,875 | ) |
| Other | (82,831 | ) | | (92,140 | ) |
| Total Deferred Tax Assets | (406,707 | ) | | (482,844 | ) |
| Total Net Deferred Income Taxes | $ | 891,287 |
| | $ | 823,795 |
|
As explainedThe following is a summary of changes in Note A - Summary of Significant Accounting Policies under the heading "New Authoritative Accounting and Financial Reporting Guidance," the Company adopted authoritative guidance issued by the FASB simplifying several aspects of the accountingvaluation allowances for stock-based compensation effective as of October 1, 2016. Under this guidance, the Company recognizes excess tax benefits as incurred. As of September 30, 2016, the table of deferred tax liabilities and assets shown above does not includeassets:
| | | | | | | | | | | | | | | | | |
| | Year Ended September 30 |
| | 2022 | | 2021 | | 2020 |
| | (Thousands) |
| Balance at Beginning of Year | $ | 57,645 | | | $ | 63,205 | | | $ | — | |
| Additions | — | | | — | | | 63,205 | |
| Deductions | 57,645 | | | 5,560 | | | — | |
| Balance at End of Year | $ | — | | | $ | 57,645 | | | $ | 63,205 | |
A valuation allowance for deferred tax assets, including net operating losses and tax credits, is recognized when it is more likely than not that some or all of $31.9 million that arose directlythe benefit from excessthe deferred tax benefitsassets will not be realized. The Company, at each reporting date, assesses the realizability of its deferred tax assets, including factors such as future taxable income, reversal of existing temporary differences, and tax planning strategies. The Company considers both positive and negative evidence related to stock-based compensation in prior periods. This amountthe likelihood of the realization of the deferred tax assets. As of March 31, 2020, the Company recorded a valuation allowance against certain state deferred tax assets based on its conclusion, considering all available objective evidence and the Company’s history of subsidiary state tax losses, that it was recognizedmore likely than not that the deferred tax assets would not be realized. On June 30, 2022, the Company completed the sale of Seneca's California oil and gas assets to Sentinel Peak Resources California, LLC. As a result of the sale of the California oil and gas assets, the remaining deferred tax assets and valuation allowance of approximately $27.2 million related to the California net operating loss and tax credit carryforwards were written off. The deferred tax assets and valuation allowance were written off as the Company determined that there was a remote possibility for use as the Company no longer has California operations. During the quarter ended September 30, 2022, the valuation allowance was adjusted because of the Pennsylvania corporate income tax rate change remeasurement described above and for current activity for a cumulative effect adjustment increasing retainedof $5.5 million. In addition, the Company determined there was sufficient positive evidence, despite a prior history of subsidiary tax losses, to conclude that it was more likely than not that the remaining state deferred tax assets would be realized. The conclusion was primarily related to the use of net operating losses in Pennsylvania in the current year due to sustained strong operating results as well as the expectation for future forecasted earnings at October 1, 2016.in Pennsylvania due to increased natural gas prices. The sale of California assets will also result in higher apportionment of income to Pennsylvania on a prospective basis, further supporting realization of existing Pennsylvania net operating loss deferred tax assets. Accordingly, the Company reversed the remaining valuation allowance and recognized an income tax benefit of approximately $24.9 million.
Regulatory liabilities representing the reduction of previously recorded deferred incomeincome taxes associated with rate-regulated activities that are expected to be refundable to customers amounted to $95.7$362.1 million and $93.3$354.1 million at September 30, 20172022 and 2016,2021, respectively. Also, regulatory assets representing future amounts collectible from customers, corresponding to additional deferred income taxes not previously recorded because of ratemaking practices, amountedamounted to $181.4$106.2 million and $177.3 $122.0 million at September 30, 20172022 and 2016,2021, respectively. Included
The Company is in the aboveBridge Phase of the IRS Compliance Assurance Process (“CAP”) for fiscal 2022. The Bridge Phase is intended for taxpayers with a low risk of non-compliance who are regulatory liabilitiescooperative and assets relatingtransparent with few, if any, material issues that require resolution. The IRS will not accept any disclosures, conduct any reviews, or provide any letters of assurance for the Bridge year. The federal statute of limitations remains open for fiscal 2019 and later years. The Company is also subject to various routine state income tax examinations. The Company’s principal subsidiaries have state statutes of limitations that generally expire between three to four years from the date of filing of the income tax accounting method change noted below.return. Net operating losses being carried forward from prior years remain subject to examination on a future return until they are utilized, upon which
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
time the statute of limitation begins. The amounts are as follows: regulatory liabilities of $52.6 millionCompany has no unrecognized tax benefits as of September 30, 2017 and 2016 and regulatory assets of $99.4 million and $94.2 million as of September 30, 2017 and 2016, respectively.2022, 2021, or 2020.
The following is a reconciliation of the change in unrecognized tax benefits:
|
| | | | | | | | | | | |
| | Year Ended September 30 |
| | 2017 | | 2016 | | 2015 |
| | (Thousands) |
| Balance at Beginning of Year | $ | 396 |
| | $ | 5,085 |
| | $ | 3,147 |
|
| Additions for Tax Positions of Prior Years | 1,251 |
| | 396 |
| | 2,504 |
|
| Reductions for Tax Positions of Prior Years | (396 | ) | | (1,314 | ) | | (566 | ) |
| Reductions Related to Settlements with Taxing Authorities | — |
| | (3,771 | ) | | — |
|
| Balance at End of Year | $ | 1,251 |
| | $ | 396 |
| | $ | 5,085 |
|
As a result of certain examinations in progress (discussed below), the Company anticipates the balance of unrecognized tax benefits could be reduced during the next 12 months. As of September 30, 2017, the entire balance of unrecognized tax benefits would favorably impact the effective tax rate, if recognized.
The IRS is currently conducting examinations of the Company for fiscal 2017 in accordance with the Compliance Assurance Process (“CAP”). The CAP audit employs a real time review of the Company’s books and tax records by the IRS that is intended to permit issue resolution prior to the filing of the tax return. The federal statute of limitations remains open forDuring fiscal 2009, and later years. During fiscal 2009,preliminary consent was received from the IRS National Office approving the Company’s application to change its tax method of accounting for certain capitalized costs relating to its utility property. While local IRS examiners issued no-change reports for fiscal 2009 through 2016,property, subject to final guidance. The Company is awaiting the IRS has reserved the right to re-examine these years, pending the anticipated issuance of IRS guidance addressing the issue for natural gas utilities.
The Company is also subjectTax carryforwards available, prior to various routine state income tax examinations. The Company’s principal subsidiaries operate mainly in four states which have statutes of limitations that generally expire between three to four years from the date of filing of the income tax return.
As ofvaluation allowance, at September 30, 2017, the Company has the following carryforwards available:2022, were as follows:
| | | | | | | | | | | | | | | | | | | | |
| Jurisdiction | | Tax Attribute | | Amount
(Thousands) | | Expires |
| | | | | | |
| | | | | | |
| Pennsylvania | | Net Operating Loss | | $ | 378,631 | | | 2030-2042 |
| | | | | | |
| | | | | | |
| | | | | | |
| Federal | | General Business Credits | | 20,677 | | | 2035-2042 |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
|
| | | | | | | | |
| Jurisdiction | | Tax Attribute | | Amount (Thousands) | | Expires |
| Federal | | Net Operating Loss | | $ | 184,289 |
| | 2028-2033 |
| Pennsylvania | | Net Operating Loss | | 324,572 |
| | 2030-2035 |
| California | | Net Operating Loss | | 169,723 |
| | 2029-2035 |
| Federal | | Alternative Minimum Tax Credit | | 81,683 |
| | Unlimited |
| California | | Alternative Minimum Tax Credit | | 5,873 |
| | Unlimited |
| Federal | | Enhanced Oil Recovery Credit | | 10,502 |
| | 2029-2037 |
| California | | Enhanced Oil Recovery Credit | | 5,061 |
| | 2021-2037 |
| Federal | | R&D Tax Credit | | 5,694 |
| | 2031-2036 |
Approximately $1.8 million of the federal Net Operating Loss carryforward is subject to certain annual limitations.
Subsequent to year-end, federal tax reform legislation was introduced which could have a material effect on the Company if enacted into law.
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note EH — Capitalization and Short-Term Borrowings
Summary of Changes in Common Stock Equity
|
| | | | | | | | | | | | | | | | | | |
| | Common Stock | | Paid In Capital | | Earnings Reinvested in the Business | | Accumulated Other Comprehensive Income (Loss) |
| Shares | | Amount | |
| | (Thousands, except per share amounts) |
| Balance at September 30, 2014 | 84,157 |
| | $ | 84,157 |
| | $ | 716,144 |
| | $ | 1,614,361 |
| | $ | (3,979 | ) |
| Net Income (Loss) Available for Common Stock | | | | | | | (379,427 | ) | | |
| Dividends Declared on Common Stock ($1.56 Per Share) | | | | | | | (131,734 | ) | | |
| Other Comprehensive Income, Net of Tax | | | | | | | | | 97,351 |
|
| Share-Based Payment Expense(2) | | | | | 2,207 |
| | | | |
| Common Stock Issued Under Stock and Benefit Plans(1) | 437 |
| | 437 |
| | 25,923 |
| | | | |
| Balance at September 30, 2015 | 84,594 |
| | 84,594 |
| | 744,274 |
| | 1,103,200 |
| | 93,372 |
|
| Net Income (Loss) Available for Common Stock | | | | | | | (290,958 | ) | | |
| Dividends Declared on Common Stock ($1.60 Per Share) | | | | | | | (135,881 | ) | | |
| Other Comprehensive Loss, Net of Tax | | | | | | | | | (99,012 | ) |
| Share-Based Payment Expense(2) | | | | | 4,843 |
| | | | |
| Common Stock Issued Under Stock and Benefit Plans(1) | 525 |
| | 525 |
| | 22,047 |
| | | | |
| Balance at September 30, 2016 | 85,119 |
| | 85,119 |
| | 771,164 |
| | 676,361 |
| | (5,640 | ) |
| Net Income Available for Common Stock | | | | | | | 283,482 |
| | |
| Dividends Declared on Common Stock ($1.64 Per Share) | | | | | | | (140,090 | ) | | |
| Cumulative Effect of Adoption of Authoritative Guidance for Stock-Based Compensation | | | | | | | 31,916 |
| | |
| Other Comprehensive Loss, Net of Tax | | | | | | | | | (24,483 | ) |
| Share-Based Payment Expense(2) | | | | | 10,902 |
| | | | |
| Common Stock Issued Under Stock and Benefit Plans | 424 |
| | 424 |
| | 14,580 |
| | | | |
| Balance at September 30, 2017 | 85,543 |
| | $ | 85,543 |
| | $ | 796,646 |
| | $ | 851,669 |
| (3) | $ | (30,123 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Common Stock | | Paid In
Capital | | Earnings
Reinvested
in the
Business | | Accumulated
Other
Comprehensive
Loss |
| Shares | | Amount | |
| | (Thousands, except per share amounts) |
| Balance at September 30, 2019 | 86,315 | | | $ | 86,315 | | | $ | 832,264 | | | $ | 1,272,601 | | | $ | (52,155) | |
| Net Loss Available for Common Stock | | | | | | | (123,772) | | | |
| Dividends Declared on Common Stock ($1.76 Per Share) | | | | | | | (156,249) | | | |
| Cumulative Effect of Adoption of Authoritative Guidance for Hedging | | | | | | | (950) | | | |
| | | | | | | | | |
| Other Comprehensive Loss, Net of Tax | | | | | | | | | (62,602) | |
| Share-Based Payment Expense(1) | | | | | 13,180 | | | | | |
| Common Stock Issued from Sale of Common Stock | 4,370 | | | 4,370 | | | 161,399 | | | | | |
| Common Stock Issued (Repurchased) Under Stock and Benefit Plans | 270 | | | 270 | | | (2,685) | | | | | |
| Balance at September 30, 2020 | 90,955 | | | 90,955 | | | 1,004,158 | | | 991,630 | | | (114,757) | |
| Net Income Available for Common Stock | | | | | | | 363,647 | | | |
| Dividends Declared on Common Stock ($1.80 Per Share) | | | | | | | (164,102) | | | |
| | | | | | | | | |
| Other Comprehensive Loss, Net of Tax | | | | | | | | | (398,840) | |
| Share-Based Payment Expense(1) | | | | | 15,297 | | | | | |
| | | | | | | | | |
| Common Stock Issued (Repurchased) Under Stock and Benefit Plans | 227 | | | 227 | | | (2,009) | | | | | |
| Balance at September 30, 2021 | 91,182 | | | 91,182 | | | 1,017,446 | | | 1,191,175 | | | (513,597) | |
| Net Income Available for Common Stock | | | | | | | 566,021 | | | |
| Dividends Declared on Common Stock ($1.86 Per Share) | | | | | | | (170,111) | | | |
| Other Comprehensive Loss, Net of Tax | | | | | | | | | (112,136) | |
| Share-Based Payment Expense(1) | | | | | 17,699 | | | | | |
| Common Stock Issued (Repurchased) Under Stock and Benefit Plans | 296 | | | 296 | | | (8,079) | | | | | |
| Balance at September 30, 2022 | 91,478 | | | $ | 91,478 | | | $ | 1,027,066 | | | $ | 1,587,085 | | (2) | $ | (625,733) | |
| |
(1) | Paid in Capital includes tax benefits of $1.9 million and $9.1 million for September 30, 2016 and 2015, respectively, related to stock-based compensation. |
| |
(2) | Paid in Capital includes compensation costs associated with stock option, SARs, performance share and/or restricted stock awards. The expense is included within Net Income Available For Common Stock, net of tax benefits. |
| |
(3) | The availability of consolidated earnings reinvested in the business for dividends payable in cash is limited under terms of the indentures covering long-term debt. At September 30, 2017, $707.5 million of accumulated earnings was free of such limitations. |
(1)Paid in Capital includes compensation costs associated with performance shares and/or restricted stock awards. The expense is included within Net Income Available for Common Stock, net of tax benefits.
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(2)The availability of consolidated earnings reinvested in the business for dividends payable in cash is limited under terms of the indentures covering long-term debt. At September 30, 2022, $1.4 billion of accumulated earnings was free of such limitations.
Common Stock
The Company has various plans which allow shareholders, employees and others to purchase shares of the Company common stock. The National Fuel Gas Company Direct Stock Purchase and Dividend Reinvestment Plan allows shareholders to reinvest cash dividends and make cash investments in the Company’s
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
common stock and provides investors the opportunity to acquire shares of the Company common stock without the payment of any brokerage commissions in connection with such acquisitions. The 401(k) Plans allow employees the opportunity to invest in the Company common stock, in addition to a variety of other investment alternatives. Generally, at the discretion of the Company, shares purchased under these plans are either original issue shares purchased directly from the Company or shares purchased on the open market by an independent agent. During 2017,2022, the Company issued 180,247did not issue any original issue shares of common stock for the Direct Stock Purchase and Dividend Reinvestment Plan and 103,602 original issue shares of common stock foror the Company's 401(k) plans.
During 2017,2022, the Company issued 45,91230,769 original issue shares of common stock as a result of stock option and SARs exercises, 80,530129,169 original issue shares of common stock for restricted stock units that vested and 43,484265,607 original issue shares of common stock for performance shares that vested. Holders of stock options, SARs, restricted sharestock-based compensation awards or restricted stock units will often tender shares of common stock to the Company for payment of option exercise prices and/or applicable withholding taxes. During 2017, 53,5642022, 157,812 shares of common stock were tendered to the Company for such purposes. The Company considers all shares tendered as cancelled shares restored to the status of authorized but unissued shares, in accordance with New Jersey law.
The Company also has a director stock program under which it issues shares of Company common stock to the non-employee directors of the Company who receive compensation under the Company’s 2009 Non-Employee Director Equity Compensation Plan, including the reinvestment of dividends for certain non-employee directors who elected to defer their shares pursuant to the dividend reinvestment feature of the Company's Deferred Compensation Plan for Directors and Officers, as partial consideration for the directors’ services during the fiscal year. Under this program, the Company issued 24,02828,782 original issue shares of common stock during 2017.2022.
Shareholder Rights Plan
In 1996, the Company’s Board of Directors adopted a shareholder rights plan (Plan). The Plan has been amended several times since it was adopted and is now embodied in an Amended and Restated Rights Agreement effective December 4, 2008, a copy of which was included as an exhibit to the Form 8-K filed byOn June 2, 2020, the Company on December 4, 2008.
Pursuant to the Plan, the holderscompleted a public offering and sale of 4,370,000 shares of the Company’sCompany's common stock, have one right (Right) for each of their shares. Each Right is initially evidenced by the Company’s common stock certificates representing the outstanding shares of common stock.
The Rights have anti-takeover effects because they will cause substantial dilution of the Company’s common stock if a person (an Acquiring Person) attempts to acquire the Company on terms not approved by the Board of Directors.
The Rights become exercisable upon the occurrence of a Distribution Date as described below, but after a Distribution Date, Rights that are owned by an Acquiring Person will be null and void. At any time following a Distribution Date, each holder of a Right may exercise its right to receive, upon payment of an amount calculated under the Rights Agreement, common stock of the Company (or, under certain circumstances, other securities or assets of the Company) having apar value equal to two times the amount paid to exercise the Right. However, the Rights are subject to redemption or exchange by the Company prior to their exercise as described below.
A Distribution Date would occur upon the earlier of (i) ten days after the public announcement that a person or group has acquired, or obtained the right to acquire, beneficial ownership of the Company’s common stock or other voting stock (including Synthetic Long Positions as defined in the Plan) having 10% or more of the total voting power of the Company’s common stock and other voting stock or (ii) ten days after the commencement or announcement by a person or group of an intention to make a tender or exchange offer that would result in that person acquiring, or obtaining the right to acquire, beneficial ownership of the Company’s common stock or other
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
voting stock having 10% or more of the total voting power of the Company’s common stock and other voting stock.
In certain situations after a person or group has acquired beneficial ownership of 10% or more of the total voting power of the Company’s stock as described above, each holder of a Right will have the right to receive, upon exercise of the Right, common stock of the acquiring company having a value equal to two times the amount paid to exercise the Right. These situations would arise if the Company is acquired in a merger or other business combination or if 50% or more of the Company’s assets or earning power is sold or transferred.
At any time prior to the end of the business day on the tenth day following the Distribution Date, the Company may redeem the Rights in whole, but not in part,$1.00 per share, at a price of $0.005$39.50 per Right, payable in cash or stock. A decisionshare. After deducting fees, commissions and other issuance costs, the net proceeds to redeem the Rights requires the voteCompany amounted to $165.8 million. The proceeds of 75%this issuance were used to fund a portion of the Company’s full Board of Directors. Also, at any time following the Distribution Date, 75%purchase price of the Company’s full Boardacquisition of Directors may vote to exchange the Rights,Shell's upstream assets and midstream gathering assets in whole or in part, at an exchange rate of one share of common stock, or other property deemed to have the same value, per Right, subject to certain adjustments.
Upon exercise of the Rights, the Company may need additional regulatory approvals to satisfy the requirements of the Rights Agreement. The Rights will expirePennsylvania that closed on July 31, 2018, unless earlier than that date, they are exchanged or redeemed or the Plan is amended2020. Refer to extend the expiration date.Note B — Asset Acquisitions and Divestitures for further discussion.
Stock Option and Stock Award Plans
The Company has various stock option and stock award plans which provide or provided for the issuance of one or more of the following to key employees: SARs, incentive stock options, nonqualified stock options, SARs, restricted stock, restricted stock units, performance units or performance shares.
Stock-based compensation expense for the years ended September 30, 2017, 20162022, 2021 and 20152020 was approximately $10.8$17.6 million, $4.8$15.2 million and $2.1$13.1 million, respectively. Stock-based compensation expense is included in operation and maintenance expense on the Consolidated Statements of Income. The total income tax benefit related to stock-based compensation expense during the years ended September 30, 2017, 20162022, 2021 and 20152020 was approximately $4.4$2.5 million, $1.9$2.4 million and $0.9$2.1 million, respectively. A portion of stock-based compensation expense is subject to capitalization under IRS uniform capitalization rules. Stock-based compensation of $0.1 million $0.1 million and $0.1 million was capitalized under these rules during each of the years ended September 30, 2017, 20162022, 2021 and 2015, respectively.2020. The tax benefit recognized fromrelated to stock-based compensation exercises and vestings was $0.5$0.6 million for the year ended September 30, 2017.2022.
Pursuant to registration statements for these plans, there were 2,149,203 shares available for future grant at September 30, 2022. These shares include shares available for future options, SARs, restricted stock and performance share grants.
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Stock Options
Transactions involving option shares for all plans are summarized as follows:
|
| | | | | | | | | | | | | |
| | Number of Shares Subject to Option | | Weighted Average Exercise Price | | Weighted Average Remaining Contractual Life (Years) | | Aggregate Intrinsic Value (In thousands) |
| Outstanding at September 30, 2016 | 19,000 |
| | $ | 39.48 |
| | | | |
| Granted in 2017 | — |
| | $ | — |
| | | | |
| Exercised in 2017 | (19,000 | ) | | $ | 39.48 |
| | | | |
| Forfeited in 2017 | — |
| | $ | — |
| | | | |
| Outstanding at September 30, 2017 | — |
| | $ | — |
| | — |
| | $ | — |
|
| Option shares exercisable at September 30, 2017 | — |
| | $ | — |
| | — |
| | $ | — |
|
| Shares available for future grant at September 30, 2017(1) | 2,182,243 |
| | | | | | |
| |
(1) | Includes shares available for options, SARs, restricted stock and performance share grants. |
The total intrinsic value of stock options exercised during the years ended September 30, 2017, 2016 and 2015 totaled approximately $0.3 million, $4.1 million, and $5.1 million, respectively. For 2017, 2016 and 2015, the amount of cash received by the Company from the exercise of such stock options was approximately $0.8 million, $8.0 million, and $5.6 million, respectively. The Company last granted stock options in fiscal 2007 and all stock options have been fully vested since fiscal 2010.
SARs
Transactions for 2022 involving SARs for all plans are summarized as follows:
|
| | | | | | | | | | | | |
| | Number of Shares Subject To Option | | Weighted Average Exercise Price | | Weighted Average Remaining Contractual Life (Years) | | Aggregate Intrinsic Value (In thousands) |
| Outstanding at September 30, 2016 | 1,590,988 |
| | $ | 48.19 |
| | | | |
| Granted in 2017 | — |
| | $ | — |
| | | | |
| Exercised in 2017 | (82,077 | ) | | $ | 39.77 |
| | | | |
| Forfeited in 2017 | — |
| | $ | — |
| | | | |
| Expired in 2017 | (3,000 | ) | | $ | 52.10 |
| | | | |
| Outstanding at September 30, 2017 | 1,505,911 |
| | $ | 48.64 |
| | 2.52 | | $ | 13,144 |
|
| SARs exercisable at September 30, 2017 | 1,505,911 |
| | $ | 48.64 |
| | 2.52 | | $ | 13,144 |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Number of
Shares Subject
To Option | | Weighted
Average
Exercise Price | | Weighted
Average
Remaining
Contractual
Life (Years) | | Aggregate
Intrinsic
Value
(In thousands) |
| Outstanding at September 30, 2021 | 318,445 | | | $ | 53.60 | | | | | |
| Granted in 2022 | — | | | $ | — | | | | | |
| Exercised in 2022 | (241,437) | | | $ | 55.73 | | | | | |
| Forfeited in 2022 | — | | | $ | — | | | | | |
| Expired in 2022 | (5,000) | | | $ | 55.09 | | | | | |
| | | | | | | |
| Outstanding at September 30, 2022 | 72,008 | | | $ | 53.05 | | | 0.22 | | $ | 612 | |
| SARs exercisable at September 30, 2022 | 72,008 | | | $ | 53.05 | | | 0.22 | | $ | 612 | |
| | | | | | | |
The Company did not grant any SARs during the years ended September 30, 20162021 and 2015.2020. The Company’s SARs include both performance based and non-performance basednonperformance-based SARs, but the performance conditions associated with the performance based SARs at the time of grant have all been subsequently met. The SARs are considered equity awards under the current authoritative guidance for stock-based compensation. The accounting for SARs is the same as the accounting for stock options.
The total intrinsic value of SARs exercised during the years ended September 30, 2017, 2016 and 20152022 totaled approximately $1.6 million, $0.4 million, and $2.0 million, respectively. Formillion. During the years ended September 30, 2017, 20162021 and 2015, 5,0002020, no SARs 113,082 SARs and 157,386 SARs, respectively, became fully vested. The total
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
fair value of thewere exercised. There were no SARs that became fully vested during each of the years ended September 30, 2017, 2016 and 2015 was approximately $0.1 million, $1.2 million and $1.7 million, respectively.
Restricted Share Awards
Transactions involving restricted share awards for all plans are summarized as follows:
|
| | | | | | |
| | Number of Restricted Share Awards | | Weighted Average Fair Value per Award |
| Outstanding at September 30, 2016 | 20,000 |
| | $ | 47.46 |
|
| Granted in 2017 | — |
| | $ | — |
|
| Vested in 2017 | — |
| | $ | — |
|
| Forfeited in 2017 | — |
| | $ | — |
|
| Outstanding at September 30, 2017 | 20,000 |
| | $ | 47.46 |
|
The Company did not grant any restricted share awards (non-vested stock as defined by the current accounting literature) during the years ended September 30, 20162022, 2021 and 2015. As of September 30, 2017, unrecognized compensation expense related to restricted share awards totaled approximately $0.3 million, which will be recognized over a weighted average period of 3.1 years.
Vesting restrictions for the 20,0002020, and all SARs outstanding shares of non-vested restricted stock at September 30, 2017 will lapse in 2021.have been fully vested since fiscal 2017.
Restricted Stock Units
Transactions for 2022 involving non-performance basednonperformance-based restricted stock units for all plans are summarized as follows:
| | | | | | | | | | | |
| Number of
Restricted
Stock Units | | Weighted Average
Fair Value per
Award |
| Outstanding at September 30, 2021 | 365,481 | | | $ | 41.45 | |
| Granted in 2022 | 128,950 | | | $ | 54.10 | |
| Vested in 2022 | (129,169) | | | $ | 45.24 | |
| Forfeited in 2022 | (17,835) | | | $ | 44.61 | |
| Outstanding at September 30, 2022 | 347,427 | | | $ | 44.58 | |
|
| | | | | | |
| | Number of Restricted Stock Units | | Weighted Average Fair Value per Award |
| Outstanding at September 30, 2016 | 239,151 |
| | $ | 49.67 |
|
| Granted in 2017 | 87,143 |
| | $ | 52.13 |
|
| Vested in 2017 | (80,530 | ) | | $ | 53.38 |
|
| Forfeited in 2017 | (12,565 | ) | | $ | 53.75 |
|
| Outstanding at September 30, 2017 | 233,199 |
| | $ | 48.99 |
|
The Company also granted 101,943172,513 and 88,899 non-performance based150,839 nonperformance-based restricted stock units during the years ended September 30, 20162021 and 2015,2020, respectively. The weighted average fair value of such non-performance basednonperformance-based restricted stock units granted in 20162021 and 20152020 was $35.89$37.98 per share and $64.04$40.38 per share, respectively. As of September 30, 2017,2022, unrecognized compensation expense related to non-performance basednonperformance-based restricted stock units totaled approximately $4.7$6.4 million, which will be recognized over a weighted average period of 2.2 years.
Vesting restrictions for the non-performance basednonperformance-based restricted stock units outstanding at September 30, 20172022 will lapse as follows: 20182023 — 73,819119,612 units; 20192024 — 65,26597,614 units; 20202025 — 52,64173,797 units; 2021 - 27,9762026 — 37,052 units; and 2022 - 13,4982027 — 19,352 units.
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Performance Shares
Transactions for 2022 involving performance shares for all plans are summarized as follows:
|
| | | | | | |
| | Number of Performance Shares | | Weighted Average Fair Value per Award |
| Outstanding at September 30, 2016 | 438,234 |
| | $ | 44.98 |
|
| Granted in 2017 | 184,148 |
| | $ | 56.39 |
|
| Vested in 2017 | (43,484 | ) | | $ | 69.13 |
|
| Forfeited in 2017 | (51,150 | ) | | $ | 60.74 |
|
| Outstanding at September 30, 2017 | 527,748 |
| | $ | 45.44 |
|
| | | | | | | | | | | |
| Number of
Performance
Shares | | Weighted Average
Fair Value per
Award |
| Outstanding at September 30, 2021 | 600,634 | | | $ | 45.13 | |
| Granted in 2022 | 195,397 | | | $ | 65.39 | |
| Vested in 2022 | (265,607) | | | $ | 55.93 | |
| Forfeited in 2022 | (23,414) | | | $ | 49.84 | |
| Change in Units Based on Performance Achieved | 100,169 | | | $ | 56.36 | |
| Outstanding at September 30, 2022 | 607,179 | | | $ | 48.60 | |
The Company also granted 309,996309,470 and 107,044254,608 performance shares during the years ended September 30, 20162021 and 2015,2020, respectively. The weighted average grant date fair value of such performance shares granted in 20162021 and 20152020 was $30.71$39.19 per share and $65.26$43.32 per share, respectively. As of September 30, 2017,2022, unrecognized compensation expense related to performance shares totaled approximately $10.1$11.3 million, which will be recognized over a weighted average period of 1.71.8 years. Vesting restrictions for the outstanding performance shares at September 30, 20172022 will lapse as follows: 2018 - 88,1322023 — 199,842 shares; 2019 - 255,4682024 — 220,914 shares; and 2020 - 184,1482025 — 186,423 shares.
Half of theThe performance shares granted during the yearyears ended September 30, 20172022, 2021 and 2020 include awards that must meet a performance goal related to either relative return on capital over thea three-year performance cycle of October 1, 2016 to September 30, 2019. In addition, half of("ROC performance shares"), methane intensity and greenhouse gas emissions reductions over a three-year performance cycle ("ESG performance shares") or relative shareholder return over a three-year performance cycle ("TSR performance shares"). The performance goal over the respective performance cycles for the ROC performance shares granted during the year ended September 30, 2016 must meet a performance goal related to relative return on capital over the performance cycle of October 1, 2015 to September 30, 2018,2022, 2021 and half of the performance shares granted during the year ended September 30, 2015 must meet a performance goal related to relative return on capital over the performance cycle of October 1, 2014 to September 30, 2017. The performance goals over their respective performance cycles for these performance shares granted during 2017, 2016 and 20152020 is the Company’s total return on capital relative to the total return on capital of other companies in a group selected by the Compensation Committee (“Report Group”). Total return on capital for a given company means the average of the Report Group companies’ returns on capital for each twelve monthtwelve-month period corresponding to each of the Company’s fiscal years during the performance cycle, based on data reported for the Report Group companies in the Bloomberg database. The number of these ROC performance shares that will vest and be paid will depend upon the Company’s performance relative to the Report Group and not upon the absolute level of return achieved by the Company. The fair value of thesethe ROC performance shares is calculated by multiplying the expected number of shares that will be issued by the average market price of Company common stock on the date of grant reduced by the present value of forgone dividends over the vesting term of the award. The fair value is recorded as compensation expense over the vesting term of the award.
The other half ofperformance goal over the performance cycle for the ESG performance shares granted during 2022 consists of two parts: reductions in the year ended September 30, 2017 must meet arates of intensity of methane emissions for each of the Company's operating segments, and reduction of the consolidated Company's total greenhouse gas emissions. The Company's Compensation Committee set specific target levels for methane intensity rates and total greenhouse gas emissions, and the performance goal relatedis intended to relativeincentivize and reward performance that helps position the Company to meet or exceed its 2030 methane intensity and greenhouse gas reduction targets. The number of these ESG performance shares that will vest and be paid out will depend upon the number of methane intensity segment targets achieved and whether the Company meets the total shareholder returngreenhouse gas emissions target. The fair value of these ESG performance shares is calculated by multiplying the expected number of shares that will be issued by the average market price of Company common stock on the date of grant reduced by the present value of forgone dividends over the performance cycle of October 1, 2016 to September 30, 2019. In addition, the other halfvesting term of the award. The fair value is recorded as compensation expense over the vesting term of the award. There were no ESG performance shares granted in 2021 and 2020.
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The performance goal over the respective performance cycles for the TSR performance shares granted during the year ended September 30, 2016 must meet a performance goal related to relative total shareholder return over the performance cycle of October 1, 2015 to September 30, 2018,2022, 2021 and the other half of the performance shares granted during the year ended September 30, 2015 must meet a performance goal related to relative total shareholder return over the performance cycle of October 1, 2014 to September 30, 2017. The performance goals over their respective performance cycles for these total shareholder return performance shares ("TSR performance shares") granted during 2017, 2016 and 20152020 is the Company’s three-year total shareholder return relative to the three-year total shareholder return of the other companies in the Report Group. Three-year total shareholder return for a given company will be based on the data reported for that company (with the starting and ending stock prices over the performance cycle calculated as the average closing stock price for the prior calendar month and with dividends reinvested in that company’s securities at each ex-dividend date) in the Bloomberg database. The number of these TSR
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
performance shares that will vest and be paid will depend upon the Company’s performance relative to the Report Group and not upon the absolute level of return achieved by the Company. The fair value price at the date of grant for the TSR performance shares is determined using a Monte Carlo simulation technique, which includes a reduction in value for the present value of forgone dividends over the vesting term of the award. This price is multiplied by the number of TSR performance shares awarded, the result of which is recorded as compensation expense over the vesting term of the award. In calculating the fair value of the award, the risk-free interest rate is based on the yield of a Treasury Note with a term commensurate with the remaining term of the TSR performance shares. The remaining term is based on the remainder of the performance cycle as of the date of grant. The expected volatility is based on historical daily stock price returns. For the TSR performance shares, it was assumed that there would be no forfeitures, based on the vesting term and the number of grantees. The following assumptions were used in estimating the fair value of the TSR performance shares at the date of grant:
| | | | Year Ended September 30 | | Year Ended September 30 |
| | 2017 | | 2016 | | 2015 | | 2022 | | 2021 | | 2020 |
| Risk-Free Interest Rate | 1.54 | % | | 1.26 | % | | 1.01 | % | Risk-Free Interest Rate | 0.85 | % | | 0.19 | % | | 1.63 | % |
| Remaining Term at Date of Grant (Years) | 2.79 |
| | 2.79 |
| | 2.78 |
| Remaining Term at Date of Grant (Years) | 2.80 | | 2.80 | | 2.81 |
| Expected Volatility | 22.6 | % | | 20.5 | % | | 20.1 | % | Expected Volatility | 29.7 | % | | 29.1 | % | | 19.3 | % |
| Expected Dividend Yield (Quarterly) | N/A |
| | N/A |
| | N/A |
| Expected Dividend Yield (Quarterly) | N/A | | N/A | | N/A |
Redeemable Preferred Stock
As of September 30, 2017,2022, there were 10,000,000 shares of $1 par value Preferred Stock authorized but unissued.
Long-Term Debt
The outstanding long-term debt is as follows:
|
| | | | | | | |
| | At September 30 |
| | 2017 | | 2016 |
| | (Thousands) |
| Medium-Term Notes(1): | | | |
| 7.4% due March 2023 to June 2025 | $ | 99,000 |
| | $ | 99,000 |
|
| Notes(1)(3)(4): | | | |
| 3.75% to 8.75% due April 2018 to September 2027 | 2,300,000 |
| | 2,000,000 |
|
| Total Long-Term Debt | 2,399,000 |
| | 2,099,000 |
|
| Less Unamortized Discount and Debt Issuance Costs | 15,319 |
| | 12,748 |
|
| Less Current Portion(2) | 300,000 |
| | — |
|
| | $ | 2,083,681 |
| | $ | 2,086,252 |
|
| | | | | | | | | | | |
| | At September 30 |
| | 2022 | | 2021 |
| | (Thousands) |
| Medium-Term Notes(1): | | | |
| 7.4% due March 2023 to June 2025 | $ | 99,000 | | | $ | 99,000 | |
| Notes(1)(2)(3): | | | |
| 2.95% to 5.50% due March 2023 to March 2031 | 2,550,000 | | | 2,550,000 | |
| Total Long-Term Debt | 2,649,000 | | | 2,649,000 | |
| Less Unamortized Discount and Debt Issuance Costs | 16,591 | | | 20,313 | |
| Less Current Portion(4) | 549,000 | | | — | |
| $ | 2,083,409 | | | $ | 2,628,687 | |
| |
(1) | The Medium-Term Notes and Notes are unsecured. |
| |
(2) | Current Portion of Long-Term Debt at September 30, 2017 consisted of $300.0 million of 6.50% notes scheduled to mature in April 2018. The Company redeemed these notes on October 18, 2017 for $307.0 million, plus accrued interest. The call premium was recorded to Unamortized Debt Expense on the Consolidated Balance Sheet in October 2017. |
| |
(3) | The holders of these notes may require the Company to repurchase their notes at a price equal to 101% of the principal amount in the event of both a change in control and a ratings downgrade to a rating below investment grade. |
(1)The Medium-Term Notes and Notes are unsecured.
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
| |
(4) | The interest rate payable on $300.0 million of 3.95% notes will be subject to adjustment from time to time, with a maximum of 2.00%, if certain change of control events involving a material subsidiary result in a downgrade of the credit rating assigned to the notes to below investment grade (or if the credit rating assigned to the notes is subsequently upgraded). |
On September 18, 2017,(2)The holders of these notes may require the Company issuedto repurchase their notes at a price equal to 101% of the principal amount in the event of both a change in control and a ratings downgrade to a rating below investment grade.
(3)The interest rate payable on $300.0 million of 4.75% notes, $300.0 million of 3.95% notes and $500.0 million of 2.95% notes will be subject to adjustment from time to time, with a maximum of 2.00%, if certain change of control events involving a material subsidiary result in a downgrade of the credit rating assigned to the notes to below investment grade (or if the credit rating assigned to the notes is subsequently upgraded). The interest rate payable on $500.0 million of 5.50% notes will be subject to adjustment from time to time, with a maximum adjustment of 2.00%, such that the coupon will not exceed 7.50%, if there is a downgrade of the credit rating assigned to the notes to a rating below investment grade. A downgrade with a resulting increase to the coupon does not preclude the coupon from returning to its original rate if the Company's credit rating is subsequently upgraded.
(4)Current Portion of Long-Term Debt at September 30, 2022 consists of $500.0 million of 3.75% notes and $49.0 million of 7.395% notes that each mature in March 2023. The Company has committed to redeeming $150.0 million of the 3.75% notes on November 25, 2022. None of the Company's long-term debt as of September 30, 2021 had a maturity date within the following twelve-month period.
On February 24, 2021, the Company issued $500.0 million of 2.95% notes due September 15, 2027.March 1, 2031. After deducting underwriting discounts, commissions and other debt issuance costs, the net proceeds to the Company amounted to $295.2$495.3 million. The proceeds of this debt issuance were used to redeem $300.0for general corporate purposes, including the redemption of $500.0 million of 6.50%4.90% notes on March 11, 2021 that were scheduled to mature in October 2017.December 2021. The Company redeemed those notes for $515.7 million, plus accrued interest. The early redemption premium of $15.7 million was recorded to Interest Expense on Long-Term Debt on the Consolidated Income Statement during the quarter ended March 31, 2021.
On June 3, 2020, the Company issued $500.0 million of 5.50% notes due January 15, 2026. After deducting underwriting discounts, commissions and other debt issuance costs, the net proceeds to the Company amounted to $493.0 million. The proceeds of this debt issuance were used for general corporate purposes, which included the payment of a portion of the purchase price of the acquisition of Shell's upstream assets and midstream gathering assets in Pennsylvania that closed on July 31, 2020 and the repayment and refinancing of short-term debt.
As of September 30, 2017,2022, the aggregate principal amounts of long-term debt maturing during the next five years and thereafter are as follows: $549.0 million in 2023, zero in 2024, $500.0 million in 2025, $500.0 million in 2026, $300.0 million in 2018, $250.0 million in 2019, zero in 20202027, and 2021, $500.0 million in 2022, and $1,349.0$800.0 million thereafter.
Short-Term BorrowingsLong-Term Debt
The Company historically has obtained short-term funds either through bank loans or the issuance of commercial paper. On September 9, 2016, the Company entered into a Third Amended and Restated Credit Agreement (Credit Agreement) with a syndicate of what now numbers 13 banks. This Credit Agreement provides a $750.0 million multi-year unsecured committed revolving credit facility through December 5, 2019. The Credit Agreement also provided a $500.0 million 364-day unsecured committed revolving credit facility with 11 of the 13 banks, which expired on September 8, 2017 and was not subsequently renewed. The Company also has a number of individual uncommitted or discretionary lines of credit with certain financial institutions for general corporate purposes. Borrowings under the uncommitted lines of credit are made at competitive market rates. The uncommitted credit lines are revocable at the option of the financial institutions 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. The total amount available to be issued under the Company’s commercial paper program is $500.0 million. At September 30, 2017, the commercial paper program was backed by the Credit Agreement.
The Company did not have any outstanding commercial paper or short term notes payable to banks at September 30, 2017 and 2016.
Debt Restrictions
The Credit Agreement provides that the Company's debt to capitalization ratio will not exceed .675 at the last day of any fiscal quarter through September 30, 2017, or .65 at the last day of any fiscal quarter from October 1, 2017 through December 5, 2019. At September 30, 2017, the Company’s debt to capitalization ratio (as calculated under the facility) was .58. The constraints specified in the Credit Agreement would have permitted an additional $1.15 billion in short-term and/or long-term debt to be outstanding (further limited by the indenture covenants discussed below) before the Company’s debt to capitalization ratio exceeded .675.is as follows:
A downgrade in the Company’s credit ratings could increase borrowing costs, negatively impact the availability of capital from banks, commercial paper purchasers | | | | | | | | | | | |
| | At September 30 |
| | 2022 | | 2021 |
| | (Thousands) |
| Medium-Term Notes(1): | | | |
| 7.4% due March 2023 to June 2025 | $ | 99,000 | | | $ | 99,000 | |
| Notes(1)(2)(3): | | | |
| 2.95% to 5.50% due March 2023 to March 2031 | 2,550,000 | | | 2,550,000 | |
| Total Long-Term Debt | 2,649,000 | | | 2,649,000 | |
| Less Unamortized Discount and Debt Issuance Costs | 16,591 | | | 20,313 | |
| Less Current Portion(4) | 549,000 | | | — | |
| $ | 2,083,409 | | | $ | 2,628,687 | |
(1)The Medium-Term Notes 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, including cash provided by operations.
The Credit Agreement contains a cross-default provision whereby the failure by the Company or its significant subsidiaries to make payments under other borrowing arrangements, or the occurrence of certain events affecting those other borrowing arrangements, could trigger an obligation to repay any amounts outstanding under the Credit Agreement. In particular, a repayment obligation could be triggered if (i) the Company or any of its significant subsidiaries fails to make a payment when due of any principal or interest on any other indebtedness aggregating $40.0 million or more, or (ii) an event occurs that causes, or would permit the holders of any other indebtednessNotes are unsecured.
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(2)The holders of these notes may require the Company to repurchase their notes at a price equal to 101% of the principal amount in the event of both a change in control and a ratings downgrade to a rating below investment grade.
aggregating $40.0(3)The interest rate payable on $300.0 million or moreof 4.75% notes, $300.0 million of 3.95% notes and $500.0 million of 2.95% notes will be subject to cause,adjustment from time to time, with a maximum of 2.00%, if certain change of control events involving a material subsidiary result in a downgrade of the credit rating assigned to the notes to below investment grade (or if the credit rating assigned to the notes is subsequently upgraded). The interest rate payable on $500.0 million of 5.50% notes will be subject to adjustment from time to time, with a maximum adjustment of 2.00%, such indebtednessthat the coupon will not exceed 7.50%, if there is a downgrade of the credit rating assigned to become due priorthe notes to a rating below investment grade. A downgrade with a resulting increase to the coupon does not preclude the coupon from returning to its stated maturity. original rate if the Company's credit rating is subsequently upgraded.
(4)Current Portion of Long-Term Debt at September 30, 2022 consists of $500.0 million of 3.75% notes and $49.0 million of 7.395% notes that each mature in March 2023. The Company has committed to redeeming $150.0 million of the 3.75% notes on November 25, 2022. None of the Company's long-term debt as of September 30, 2021 had a maturity date within the following twelve-month period.
On February 24, 2021, the Company issued $500.0 million of 2.95% notes due March 1, 2031. After deducting underwriting discounts, commissions and other debt issuance costs, the net proceeds to the Company amounted to $495.3 million. The proceeds of this debt issuance were used for general corporate purposes, including the redemption of $500.0 million of 4.90% notes on March 11, 2021 that were scheduled to mature in December 2021. The Company redeemed those notes for $515.7 million, plus accrued interest. The early redemption premium of $15.7 million was recorded to Interest Expense on Long-Term Debt on the Consolidated Income Statement during the quarter ended March 31, 2021.
On June 3, 2020, the Company issued $500.0 million of 5.50% notes due January 15, 2026. After deducting underwriting discounts, commissions and other debt issuance costs, the net proceeds to the Company amounted to $493.0 million. The proceeds of this debt issuance were used for general corporate purposes, which included the payment of a portion of the purchase price of the acquisition of Shell's upstream assets and midstream gathering assets in Pennsylvania that closed on July 31, 2020 and the repayment and refinancing of short-term debt.
As of September 30, 2017,2022, the Company had noaggregate principal amounts of long-term debt outstanding undermaturing during the Credit Agreement.
Under the Company’s existing indenture covenants, at September 30, 2017, the Company would have been permitted to issue up to a maximum of $126.0next five years and thereafter are as follows: $549.0 million in additional long-term indebtedness at then current market interest rates2023, zero in addition to being able to issue new indebtedness to replace maturing debt. However, if the Company were to experience a significant loss2024, $500.0 million in the future (for example, as a result of an impairment of oil2025, $500.0 million in 2026, $300.0 million in 2027, and gas properties), it is possible, depending on factors including the magnitude of the loss, that these indenture covenants would restrict the Company's ability to issue additional long-term unsecured indebtedness for a period of up to nine calendar months, beginning with the fourth calendar month following the loss. This would not preclude the Company from issuing new indebtedness to replace maturing debt. The Company's present liquidity position is believed to be adequate to satisfy known demands.
The Company’s 1974 indenture pursuant to which $98.7$800.0 million (or 4.1%) of the Company’s long-term debt (as of September 30, 2017) 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.thereafter.
Note F — Fair Value Measurements
The FASB authoritative guidance regarding fair value measurements establishes a fair-value hierarchy and prioritizes the inputs used in valuation techniques that measure fair value. Those inputs are prioritized into three levels. Level 1 inputs are unadjusted quoted prices in active markets for assets or liabilities that the Company can access at the measurement date. Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly at the measurement date. Level 3 inputs are unobservable inputs for the asset or liability at the measurement date. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.
The following table sets forth, by level within the fair value hierarchy, the Company’s financial assets and liabilities (as applicable) that were accounted for at fair value on a recurring basis as of September 30, 2017 and 2016. Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The fair value presentation for over-the-counter swaps combines gas and oil swaps because a significant number of the counterparties enter into both gas and oil swap agreements with the Company.
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
|
| | | | | | | | | | | | | | | | | | | |
| | At Fair Value as of September 30, 2017 |
| Recurring Fair Value Measures | Level 1 | | Level 2 | | Level 3 | | Netting Adjustments(1) | | Total(1) |
| | (Dollars in thousands) |
| Assets: | | | | | | | | | |
| Cash Equivalents — Money Market Mutual Funds | $ | 527,978 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 527,978 |
|
| Derivative Financial Instruments: | | | | | | | | | |
| Commodity Futures Contracts — Gas | 1,483 |
| | — |
| | — |
| | (963 | ) | | 520 |
|
| Over the Counter Swaps — Gas and Oil | — |
| | 38,977 |
| | — |
| | (4,206 | ) | | 34,771 |
|
| Foreign Currency Contracts | — |
| | 1,227 |
| | — |
| | (407 | ) | | 820 |
|
| Other Investments: | | | | | | | | |
|
| Balanced Equity Mutual Fund | 37,033 |
| | — |
| | — |
| | — |
| | 37,033 |
|
| Fixed Income Mutual Fund | 45,727 |
| | — |
| | — |
| | — |
| | 45,727 |
|
| Common Stock — Financial Services Industry | 3,150 |
| | — |
| | — |
| | — |
| | 3,150 |
|
| Hedging Collateral Deposits | 1,741 |
| | — |
| | — |
| | — |
| | 1,741 |
|
| Total | $ | 617,112 |
| | $ | 40,204 |
| | $ | — |
| | $ | (5,576 | ) | | $ | 651,740 |
|
| Liabilities: | | | | | | | | | |
| Derivative Financial Instruments: | | | | | | | | | |
| Commodity Futures Contracts — Gas | $ | 963 |
| | $ | — |
| | $ | — |
| | $ | (963 | ) | | $ | — |
|
| Over the Counter Swaps — Gas and Oil | — |
| | 5,309 |
| | — |
| | (4,206 | ) | | 1,103 |
|
| Foreign Currency Contracts | — |
| | 407 |
| | — |
| | (407 | ) | | — |
|
| Total | $ | 963 |
| | $ | 5,716 |
| | $ | — |
| | $ | (5,576 | ) | | $ | 1,103 |
|
| Total Net Assets/(Liabilities) | $ | 616,149 |
| | $ | 34,488 |
| | $ | — |
| | $ | — |
| | $ | 650,637 |
|
|
| | | | | | | | | | | | | | | | | | | |
| | At Fair Value as of September 30, 2016 |
| Recurring Fair Value Measures | Level 1 | | Level 2 | | Level 3 | | Netting Adjustments(1) | | Total(1) |
| | (Dollars in thousands) |
| Assets: | | | | | | | | | |
| Cash Equivalents — Money Market Mutual Funds | $ | 113,407 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 113,407 |
|
| Derivative Financial Instruments: | | | | | | | | | |
| Commodity Futures Contracts — Gas | 2,623 |
| | — |
| | — |
| | (2,276 | ) | | 347 |
|
| Over the Counter Swaps — Gas and Oil | — |
| | 119,654 |
| | — |
| | (3,860 | ) | | 115,794 |
|
| Foreign Currency Contracts | — |
| | — |
| | — |
| | (2,337 | ) | | (2,337 | ) |
| Other Investments: | | | | | | | | | |
| Balanced Equity Mutual Fund | 36,658 |
| | — |
| | — |
| | — |
| | 36,658 |
|
| Fixed Income Mutual Fund | 31,395 |
| | — |
| | — |
| | — |
| | 31,395 |
|
| Common Stock — Financial Services Industry | 2,902 |
| | — |
| | — |
| | — |
| | 2,902 |
|
| Hedging Collateral Deposits | 1,484 |
| | — |
| | — |
| | — |
| | 1,484 |
|
| Total | $ | 188,469 |
|
| $ | 119,654 |
|
| $ | — |
|
| $ | (8,473 | ) |
| $ | 299,650 |
|
| Liabilities: | | | | | | | | | |
| Derivative Financial Instruments: | | | | | | | | | |
| Commodity Futures Contracts — Gas | $ | 2,276 |
| | $ | — |
| | $ | — |
| | $ | (2,276 | ) | | $ | — |
|
| Over the Counter Swaps — Gas and Oil | — |
| | 5,322 |
| | — |
| | (3,860 | ) | | 1,462 |
|
| Foreign Currency Contracts | — |
| | 2,337 |
| | — |
| | (2,337 | ) | | — |
|
| Total | $ | 2,276 |
| | $ | 7,659 |
| | $ | — |
| | $ | (8,473 | ) | | $ | 1,462 |
|
| Total Net Assets/(Liabilities) | $ | 186,193 |
| | $ | 111,995 |
| | $ | — |
| | $ | — |
| | $ | 298,188 |
|
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
| |
(1) | Netting Adjustments represent the impact of legally-enforceable master netting arrangements that allow the Company to net gain and loss positions held with the same counterparties. The net asset or net liability for each counterparty is recorded as an asset or liability on the Company’s balance sheet. |
Derivative Financial Instruments
At September 30, 2017 and 2016, the derivative financial instruments reported in Level 1 consist of natural gas NYMEX and ICE futures contracts used in the Company’s Energy Marketing segment. Hedging collateral deposits of $1.7 million (at September 30, 2017) and $1.5 million (at September 30, 2016), which are associated with these futures contracts, have been reported in Level 1 as well. The derivative financial instruments reported in Level 2 at September 30, 2017 and 2016 consist of natural gas price swap agreements used in the Company’s Exploration and Production and Energy Marketing segments, the majority of the crude oil price swap agreements used in the Company’s Exploration and Production segment and foreign currency contracts used in the Company's Exploration and Production segment. The fair value of the Level 2 price swap agreements is based on an internal, discounted cash flow model that uses observable inputs (i.e. LIBOR based discount rates and basis differential information, if applicable, at active natural gas and crude oil trading markets). The fair value of the Level 2 foreign currency contracts is determined using the market approach based on observable market transactions of forward Canadian currency rates.
The accounting rules for fair value measurements and disclosures require consideration of the impact of nonperformance risk (including credit risk) from a market participant perspective in the measurement of the fair value of assets and liabilities. At September 30, 2017, the Company determined that nonperformance risk would have no material impact on its financial position or results of operation. To assess nonperformance risk, the Company considered information such as any applicable collateral posted, master netting arrangements, and applied a market-based method by using the counterparty's (assuming the derivative is in a gain position) or the Company’s (assuming the derivative is in a loss position) credit default swaps rates.
For the years ended September 30, 2017 and 2016, there were no assets or liabilities measured at fair value and classified as Level 3. The Company's Exploration and Production segment had a small portion of their crude oil price swap agreements reported as Level 3 at October 1, 2015 that settled during the first quarter of fiscal 2016. For the years ended September 30, 2017 and September 30, 2016, no transfers in or out of Level 1 or Level 2 occurred.
Note G — Financial Instruments
Long-Term Debt
The outstanding long-term debt is as follows:
| | | | | | | | | | | |
| | At September 30 |
| | 2022 | | 2021 |
| | (Thousands) |
| Medium-Term Notes(1): | | | |
| 7.4% due March 2023 to June 2025 | $ | 99,000 | | | $ | 99,000 | |
| Notes(1)(2)(3): | | | |
| 2.95% to 5.50% due March 2023 to March 2031 | 2,550,000 | | | 2,550,000 | |
| Total Long-Term Debt | 2,649,000 | | | 2,649,000 | |
| Less Unamortized Discount and Debt Issuance Costs | 16,591 | | | 20,313 | |
| Less Current Portion(4) | 549,000 | | | — | |
| $ | 2,083,409 | | | $ | 2,628,687 | |
(1)The Medium-Term Notes and Notes are unsecured.
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(2)The holders of these notes may require the Company to repurchase their notes at a price equal to 101% of the principal amount in the event of both a change in control and a ratings downgrade to a rating below investment grade.
(3)The interest rate payable on $300.0 million of 4.75% notes, $300.0 million of 3.95% notes and $500.0 million of 2.95% notes will be subject to adjustment from time to time, with a maximum of 2.00%, if certain change of control events involving a material subsidiary result in a downgrade of the credit rating assigned to the notes to below investment grade (or if the credit rating assigned to the notes is subsequently upgraded). The interest rate payable on $500.0 million of 5.50% notes will be subject to adjustment from time to time, with a maximum adjustment of 2.00%, such that the coupon will not exceed 7.50%, if there is a downgrade of the credit rating assigned to the notes to a rating below investment grade. A downgrade with a resulting increase to the coupon does not preclude the coupon from returning to its original rate if the Company's credit rating is subsequently upgraded.
(4)Current Portion of Long-Term Debt at September 30, 2022 consists of $500.0 million of 3.75% notes and $49.0 million of 7.395% notes that each mature in March 2023. The Company has committed to redeeming $150.0 million of the 3.75% notes on November 25, 2022. None of the Company's long-term debt as of September 30, 2021 had a maturity date within the following twelve-month period.
On February 24, 2021, the Company issued $500.0 million of 2.95% notes due March 1, 2031. After deducting underwriting discounts, commissions and other debt issuance costs, the net proceeds to the Company amounted to $495.3 million. The proceeds of this debt issuance were used for general corporate purposes, including the redemption of $500.0 million of 4.90% notes on March 11, 2021 that were scheduled to mature in December 2021. The Company redeemed those notes for $515.7 million, plus accrued interest. The early redemption premium of $15.7 million was recorded to Interest Expense on Long-Term Debt on the Consolidated Income Statement during the quarter ended March 31, 2021.
On June 3, 2020, the Company issued $500.0 million of 5.50% notes due January 15, 2026. After deducting underwriting discounts, commissions and other debt issuance costs, the net proceeds to the Company amounted to $493.0 million. The proceeds of this debt issuance were used for general corporate purposes, which included the payment of a portion of the purchase price of the acquisition of Shell's upstream assets and midstream gathering assets in Pennsylvania that closed on July 31, 2020 and the repayment and refinancing of short-term debt.
As of September 30, 2022, the aggregate principal amounts of long-term debt maturing during the next five years and thereafter are as follows: $549.0 million in 2023, zero in 2024, $500.0 million in 2025, $500.0 million in 2026, $300.0 million in 2027, and $800.0 million thereafter.
Short-Term Borrowings
The Company historically has obtained short-term funds either through bank loans or the issuance of commercial paper. On February 28, 2022, the Company entered into a Credit Agreement (as amended from time to time, the "Credit Agreement") with a syndicate of twelve banks. The Credit Agreement replaced the previous Fourth Amended and Restated Credit Agreement and a previous 364-Day Credit Agreement. The Credit Agreement provides a $1.0 billion unsecured committed revolving credit facility with a maturity date of February 26, 2027.
On June 30, 2022, the Company entered into a new 364-Day Credit Agreement (the "364-Day Credit Agreement") with a syndicate of five banks, all of which are also lenders under the Credit Agreement. The 364-Day Credit Agreement provides an additional $250.0 million unsecured committed delayed draw term loan credit facility with a maturity date of June 29, 2023. The Company elected to draw $250.0 million under the facility on October 27, 2022. The Company is using the proceeds for general corporate purposes, which will include the redemption in November of a portion of the Company's outstanding long-term debt maturing in March 2023.
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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.
At September 30, 2022, the Company had outstanding short-term notes payable to banks of $60.0 million, all of which was issued under the Credit Agreement, with an interest rate of 4.02%. The Company did not have any outstanding commercial paper at September 30, 2022. The Company had outstanding commercial paper of $158.5 million at September 30, 2021, with a weighted average interest rate on the commercial paper of 0.40%. The Company did not have any outstanding short-term notes payable to banks at September 30, 2021.
Debt Restrictions
The Credit Agreement provides that the Company's debt to capitalization ratio will not exceed .65 at the last day of any fiscal quarter. For purposes of calculating the debt to capitalization ratio, the Company's total capitalization will be increased by adding back 50% of the aggregate after-tax amount of non-cash charges directly arising from any ceiling test impairment occurring on or after July 1, 2018, not to exceed $400 million. Since July 1, 2018, the Company recorded non-cash, after-tax ceiling test impairments totaling $381.4 million. As a result, at September 30, 2022, $190.7 million was added back to the Company's total capitalization for purposes of the calculation under the Credit Agreement and 364-Day Credit Agreement. On May 3, 2022, the Company entered into Amendment No. 1 to the Credit Agreement with the same twelve banks under the initial Credit Agreement. The amendment further modified the definition of consolidated capitalization, for purposes of calculating the debt to capitalization ratio under the Credit Agreement, to exclude, beginning with the quarter ended June 30, 2022, all unrealized gains or losses on commodity-related derivative financial instruments and up to $10 million in unrealized gains or losses on other derivative financial instruments included in Accumulated Other Comprehensive Income (Loss) within Total Comprehensive Shareholders' Equity on the Company's consolidated balance sheet. Under the Credit Agreement, such unrealized losses will not negatively affect the calculation of the debt to capitalization ratio, and such unrealized gains will not positively affect the calculation. The 364-Day Credit Agreement includes the same debt to capitalization covenant and the same exclusions of unrealized gains or losses on derivative financial instruments as the Credit Agreement. At September 30, 2022, the Company’s debt to capitalization ratio, as calculated under the Credit Agreement and 364-Day Credit Agreement, was .49. The constraints specified in the Credit Agreement and 364-Day Credit Agreement would have permitted an additional $2.56 billion in short-term and/or long-term debt to be outstanding at September 30, 2022 (further limited by the indenture covenants discussed below) before the Company’s debt to capitalization ratio exceeded .65.
A downgrade in the Company’s credit ratings could increase borrowing costs, negatively impact the availability of capital from banks, commercial paper purchasers and other sources, and require the Company's subsidiaries to post letters of credit, cash or other assets as collateral with certain counterparties. If the Company is not able to maintain investment-grade credit ratings, it may not be able to access commercial paper markets. However, the Company expects that it could borrow under its credit facilities or rely upon other liquidity sources.
The Credit Agreement and 364-Day Credit Agreement contain a cross-default provision whereby the failure by the Company or its significant subsidiaries to make payments under other borrowing arrangements, or the occurrence of certain events affecting those other borrowing arrangements, could trigger an obligation to repay any amounts outstanding under the Credit Agreement and 364-Day Credit Agreement. In particular, a repayment obligation could be triggered if (i) the Company or any of its significant subsidiaries fails to make a
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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.
In order to issue incremental long-term debt, the Company must meet an interest coverage test under its existing indenture covenants. In general, the Company’s operating income, subject to certain adjustments, over a consecutive 12-month period within the 15 months preceding the debt issuance, must be not less than two times the total annual interest charges on the Company’s long-term debt, taking into account the incremental issuance. In addition, taking into account the incremental issuance, and using a pro forma balance sheet as of the last day of the 12-month period used in the interest coverage test, the Company must maintain a ratio of long-term debt to consolidated assets (as defined under the indenture) of not more than 60%. Under the Company's existing indenture covenants at September 30, 2022, the Company would have been permitted to issue up to a maximum of approximately $2.0 billion in additional unsubordinated long-term indebtedness at then current market interest rates, in addition to being able to issue new indebtedness to replace existing debt. The Company's present liquidity position is believed to be adequate to satisfy known demands. It is possible, depending on amounts reported in various income statement and balance sheet line items, that the indenture covenants could, for a period of time, prevent the Company from issuing incremental unsubordinated long-term debt, or significantly limit the amount of such debt that could be issued. Losses incurred as a result of significant impairments of oil and gas properties have in the past resulted in such temporary restrictions. The indenture covenants would not preclude the Company from issuing new long-term debt to replace existing long-term debt, or from issuing additional short-term debt. Please refer to Part II, Item 7, Critical Accounting Estimates section above for a sensitivity analysis concerning commodity price changes and their impact on the ceiling test.
The Company’s 1974 indenture pursuant to which $99.0 million (or 3.7%) of the Company’s long-term debt (as of September 30, 2022) was issued, contains a cross-default provision whereby the failure by the Company to perform certain obligations under other borrowing arrangements could trigger an obligation to repay the debt outstanding under the indenture. In particular, a repayment obligation could be triggered if the Company fails (i) to pay any scheduled principal or interest on any debt under any other indenture or agreement, or (ii) to perform any other term in any other such indenture or agreement, and the effect of the failure causes, or would permit the holders of the debt to cause, the debt under such indenture or agreement to become due prior to its stated maturity, unless cured or waived.
Note I — Fair Value Measurements
The FASB authoritative guidance regarding fair value measurements establishes a fair-value hierarchy and prioritizes the inputs used in valuation techniques that measure fair value. Those inputs are prioritized into three levels. Level 1 inputs are unadjusted quoted prices in active markets for assets or liabilities that the Company can access at the measurement date. Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly at the measurement date. Level 3 inputs are unobservable inputs for the asset or liability at the measurement date. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.
The following table sets forth, by level within the fair value hierarchy, the Company’s financial assets and liabilities (as applicable) that were accounted for at fair value on a recurring basis as of September 30, 2022 and 2021. Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The fair value presentation for over-the-counter swaps combines gas and oil swaps because a significant number of the counterparties have historically entered into both gas and oil swap agreements with the Company.
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | At Fair Value as of September 30, 2022 |
| Recurring Fair Value Measures | Level 1 | | Level 2 | | Level 3 | | Netting
Adjustments(1) | | Total(1) |
| | (Dollars in thousands) |
| Assets: | | | | | | | | | |
| Cash Equivalents — Money Market Mutual Funds | $ | 35,015 | | | $ | — | | | $ | — | | | $ | — | | | $ | 35,015 | |
| Hedging Collateral Deposits | 91,670 | | | — | | | — | | | — | | | 91,670 | |
| Derivative Financial Instruments: | | | | | | | | | |
| | | | | | | | | |
| Over the Counter Swaps — Gas | — | | | 5,177 | | | — | | | (4,178) | | | 999 | |
| | | | | | | | | |
| Contingent Consideration for Asset Sale | — | | | 8,176 | | | — | | | — | | | 8,176 | |
| Foreign Currency Contracts | — | | | 128 | | | — | | | (128) | | | — | |
| Other Investments: | | | | | | | | | |
| Balanced Equity Mutual Fund | 19,506 | | | — | | | — | | | — | | | 19,506 | |
| Fixed Income Mutual Fund | 33,348 | | | — | | | — | | | — | | | 33,348 | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| Total | $ | 179,539 | | | $ | 13,481 | | | $ | — | | | $ | (4,306) | | | $ | 188,714 | |
| Liabilities: | | | | | | | | | |
| Derivative Financial Instruments: | | | | | | | | | |
| | | | | | | | | |
| Over the Counter Swaps — Gas | $ | — | | | $ | 517,464 | | | $ | — | | | $ | (4,178) | | | $ | 513,286 | |
| Over the Counter No Cost Collars — Gas | — | | | 270,453 | | | — | | | — | | | 270,453 | |
| Foreign Currency Contracts | — | | | 2,048 | | | — | | | (128) | | | 1,920 | |
| Total | $ | — | | | $ | 789,965 | | | $ | — | | | $ | (4,306) | | | $ | 785,659 | |
| Total Net Assets/(Liabilities) | $ | 179,539 | | | $ | (776,484) | | | $ | — | | | $ | — | | | $ | (596,945) | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | At Fair Value as of September 30, 2021 |
| Recurring Fair Value Measures | Level 1 | | Level 2 | | Level 3 | | Netting
Adjustments(1) | | Total(1) |
| | (Dollars in thousands) |
| Assets: | | | | | | | | | |
| Cash Equivalents — Money Market Mutual Funds | $ | 22,269 | | | $ | — | | | $ | — | | | $ | — | | | $ | 22,269 | |
| Hedging Collateral Deposits | 88,610 | | | — | | | — | | | — | | | 88,610 | |
| Derivative Financial Instruments: | | | | | | | | | |
| Over the Counter Swaps — Gas and Oil | — | | | 1,802 | | | — | | | (1,802) | | | — | |
| | | | | | | | | |
| Foreign Currency Contracts | — | | | 938 | | | — | | | (938) | | | — | |
| Other Investments: | | | | | | | | | |
| Balanced Equity Mutual Fund | 34,433 | | | — | | | — | | | — | | | 34,433 | |
| Fixed Income Mutual Fund | 70,639 | | | — | | | — | | | — | | | 70,639 | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| Total | $ | 215,951 | | | $ | 2,740 | | | $ | — | | | $ | (2,740) | | | $ | 215,951 | |
| Liabilities: | | | | | | | | | |
| Derivative Financial Instruments: | | | | | | | | | |
| Over the Counter Swaps — Gas and Oil | $ | — | | | $ | 601,551 | | | $ | — | | | $ | (1,802) | | | $ | 599,749 | |
| Over the Counter No Cost Collars — Gas | — | | | 17,385 | | | — | | | — | | | 17,385 | |
| Foreign Currency Contracts | — | | | 214 | | | — | | | (938) | | | (724) | |
| Total | $ | — | | | $ | 619,150 | | | $ | — | | | $ | (2,740) | | | $ | 616,410 | |
| Total Net Assets/(Liabilities) | $ | 215,951 | | | $ | (616,410) | | | $ | — | | | $ | — | | | $ | (400,459) | |
(1)Netting Adjustments represent the impact of legally-enforceable master netting arrangements that allow the Company to net gain and loss positions held with the same counterparties. The net asset or net liability for each counterparty is recorded as an asset or liability on the Company’s balance sheet.
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Derivative Financial Instruments
At September 30, 2022, the derivative financial instruments reported in Level 2 consist of natural gas price swap agreements, natural gas no cost collars, and foreign currency contracts, all of which are used in the Company's Exploration and Production segment. The derivative financial instruments reported in Level 2 at September 30, 2021 consist of the same type of instruments in addition to crude oil price swap agreements. The use of crude oil price swap agreements was discontinued during the year ended September 30, 2022 in conjunction with the sale of the Exploration and Production segment's California assets. Hedging collateral deposits of $91.7 million (at September 30, 2022) and $88.6 million (at September 30, 2021), which were associated with the price swap agreements, no cost collars and foreign currency contracts, have been reported in Level 1.
The fair value of the Level 2 price swap agreements and no cost collars is based on an internal cash flow model that uses observable inputs (i.e. LIBOR based discount rates for the price swap agreements and basis differential information, if applicable, at active natural gas and crude oil trading markets). The fair value of the Level 2 foreign currency contracts at September 30, 2022 and September 30, 2021 are determined using the market approach based on observable market transactions of forward Canadian currency rates.
The authoritative guidance for fair value measurements and disclosures require consideration of the impact of nonperformance risk (including credit risk) from a market participant perspective in the measurement of the fair value of assets and liabilities. At September 30, 2022, the Company determined that nonperformance risk associated with the price swap agreements, no cost collars and foreign currency contracts would have no material impact on its financial position or results of operation. To assess nonperformance risk, the Company considered information such as any applicable collateral posted, master netting arrangements, and applied a market-based method by using the counterparty's (assuming the derivative is in a gain position) or the Company’s (assuming the derivative is in a loss position) credit default swaps rates.
Derivative financial instruments reported in Level 2 at September 30, 2022 also includes the contingent consideration associated with the sale of the Exploration and Production segment's California assets on June 30, 2022, which is discussed at Note B — Asset Acquisitions and Divestituresand at Note J — Financial Instruments. The fair value of the contingent consideration was calculated using a Monte Carlo simulation model that uses observable inputs, including the ICE Brent closing price as of the valuation date, initial and max trigger price, volatility, risk free rate, time of maturity and counterparty risk.
For the years ended September 30, 2022 and 2021, there were no assets or liabilities measured at fair value and classified as Level 3.
Note J — Financial Instruments
Long-Term Debt
The fair market value of the Company’s debt, as presented in the table below, was determined using a discounted cash flow model, which incorporates the Company’s credit ratings and current market conditions in determining the yield, and subsequently, the fair market value of the debt. Based on these criteria, the fair market value of long-term debt, including current portion, was as follows:
|
| | | | | | | | | | | | | | | |
| | At September 30 |
| | 2017 Carrying Amount | | 2017 Fair Value | | 2016 Carrying Amount | | 2016 Fair Value |
| | (Thousands) |
| Long-Term Debt | $ | 2,383,681 |
| | $ | 2,523,639 |
| | $ | 2,086,252 |
| | $ | 2,255,562 |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | At September 30 |
| | 2022
Carrying
Amount | | 2022
Fair Value | | 2021
Carrying
Amount | | 2021
Fair Value |
| | (Thousands) |
| Long-Term Debt | $ | 2,632,409 | | | $ | 2,453,209 | | | $ | 2,628,687 | | | $ | 2,898,552 | |
The fair value amounts are not intended to reflect principal amounts that the Company will ultimately be required to pay. Carrying amounts for other financial instruments recorded on the Company’s Consolidated Balance
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Balance Sheets approximate fair value. The fair value of long-term debt was calculated using observable inputs (U.S. Treasuries/LIBORTreasuries for the risk-free component and company specific credit spread information — generally obtained from recent trade activity in the debt). As such, the Company considers the debt to be Level 2.
Any temporary cash investments, notes payable to banks and commercial paper are stated at cost. Temporary cash investments are considered Level 1, while notes payable to banks and commercial paper are considered to be Level 2. Given the short-term nature of the notes payable to banks and commercial paper, the Company believes cost is a reasonable approximation of fair value.
Other Investments
The components of the Company's Other Investments are as follows (in thousands):
| | | | | | | | | | | |
| At September 30 |
| 2022 | | 2021 |
| (Thousands) |
| Life Insurance Contracts | $ | 42,171 | | | $ | 44,560 | |
| Equity Mutual Fund | 19,506 | | | 34,433 | |
| Fixed Income Mutual Fund | 33,348 | | | 70,639 | |
| | | |
| $ | 95,025 | | | $ | 149,632 | |
Investments in life insurance contracts are stated at their cash surrender values or net present value as discussed below.value. Investments in an equity mutual fund and a fixed income mutual fund and the stock of an insurance company (marketable equity securities), as discussed below, are stated at fair value based on quoted market prices.
Other investments include cash surrender values of insurance contracts (net present valueprices with changes in the case of split-dollar collateral assignment arrangements) and marketable equity and fixed income securities. The values of the insurance contracts amounted to $39.4 million and $39.7 million at September 30, 2017 and 2016, respectively. The fair value of the equity mutual fund was $37.0 million and $36.7 million at September 30, 2017 and 2016, respectively. The gross unrealized gain on this equity mutual fund was $9.9 million at September 30, 2017 and $7.9 million at September 30, 2016. The fair value of the fixed income mutual fund was $45.7 million and $31.4 million at September 30, 2017 and 2016, respectively. The gross unrealized loss on this fixed income mutual fund was less than $0.1 million at September 30, 2017 and the gross unrealized gain on this fixed income mutual fund was less than $0.1 million at September 30, 2016. The fair value of the stock of an insurance company was $3.2 million and $2.9 million at September 30, 2017 and 2016, respectively. The gross unrealized gain on this stock was $2.2 million and $1.6 million at September 30, 2017 and 2016, respectively.recognized in net income. The insurance contracts and marketable equity and fixed income securitiesmutual fund are primarily informal funding mechanisms for various benefit obligations the Company has to certain employees. The fixed income mutual fund is primarily an informal funding mechanism for certain regulatory obligations that the Company has to Utility segment customers in its Pennsylvania jurisdiction, as discussed in Note F — Regulatory Matters, and for various benefit obligations the Company has to certain employees.
Derivative Financial Instruments
The Company uses derivative financial instruments to manage commodity price risk in the Exploration and Production segment as well as the Energy Marketing segment. The Company enters into futures contractsover-the-counter no cost collars and over-the-counter swap agreements for natural gas and crude oil to manage the price risk associated with forecasted sales of gas and oil.natural gas. In addition, the Company also enters into foreign exchange forward contracts to manage the risk of currency fluctuations associated with transportation costs denominated in Canadian currency in the Exploration and Production segment. These instruments are accounted for as cash flow hedges. The Company also enters into futures contracts and swaps, which are accounted for as cash flow hedges, to manage the price risk associated with forecasted gas purchases. The Company enters into futures contracts and swaps to mitigate risk associated with fixed price sales commitments, fixed price purchase commitments, and the decline in value of natural gas held in storage. These instruments are accounted for as fair value hedges. The lengthduration of the Company’s combined cash flow and fair value hedges does not typically exceed 65 years while the foreign currency forward contracts do not exceed 98 years. The Exploration and Production segment holds
On June 30, 2022, the majorityCompany completed the sale of Seneca’s California assets. Under the terms of the Company’spurchase 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 Company has determined that this contingent consideration meets the definition of a derivative financial instruments.under the authoritative accounting guidance. Changes in the fair value of this contingent consideration are marked-to-market each reporting period, with changes in fair value recognized in Other Income (Deductions) on the Consolidated Statement of Income. The fair value of this contingent consideration was estimated to be $12.6 million and $8.2 million at June 30, 2022 and September 30, 2022, respectively. A $4.4 million mark-to-market adjustment was recorded during the quarter ended September 30, 2022.
The Company has presented its net derivative assets and liabilities as “Fair Value of Derivative Financial Instruments” on its Consolidated Balance Sheets at September 30, 20172022 and September 30, 2016. Substantially all of the derivative financial instruments reported on those line items relate to commodity contracts and a small portion relates to foreign currency forward contracts.2021.
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Cash Flow Hedges
For derivative financial instruments that are designated and qualify as a cash flow hedge, the effective portion of the gain or loss on the derivative is reported as a component of other comprehensive income (loss) and reclassified into earnings in the period or periods during which the hedged transaction affects earnings. Gains and losses on the derivative representing either hedge ineffectiveness or hedge components excluded from the assessment of effectiveness are recognized in current earnings.
As of September 30, 2017,2022, the Company had the following420.8 Bcf of natural gas commodity derivative contracts (swaps and futures contracts) outstanding:
|
| | | |
Commodity | Units |
| |
Natural Gas | 114.3 |
| Bcf (short positions) |
Natural Gas | 1.0 |
| Bcf (long positions) |
Crude Oil | 3,459,000 |
| Bbls (short positions) |
no cost collars) outstanding.As of September 30, 2017,2022, the Company was hedging a total of $89.2$49.4 million of forecasted transportation costs denominated in Canadian dollars with foreign currency forward contracts (long positions).contracts.
As of September 30, 2017,2022, the Company had $35.5$784.7 million ($20.8572.2 million after tax)after-tax) of net hedging gainslosses included in the accumulated other comprehensive income (loss) balance. It is expected that $18.0$476.7 million ($10.6347.6 million after tax)after-tax) of such unrealized gainslosses will be reclassified into the Consolidated Statement of Income within the next 12 months as the underlying hedged transactions are recorded in earnings.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
The Effect of Derivative Financial Instruments on the Statement of Financial Performance for the Year Ended September 30, 2022 and 2021 (Dollar Amounts in Thousands) |
Derivatives in Cash
Flow Hedging
Relationships | | Amount of
Derivative Gain or (Loss) Recognized in Other
Comprehensive
Income (Loss) on the Consolidated Statement
of Comprehensive
Income (Loss)
for the Year Ended
September 30, | | Location of
Derivative Gain or (Loss) Reclassified
from Accumulated
Other Comprehensive
Income (Loss) on
the Consolidated
Balance Sheet into the Consolidated
Statement of Income | | Amount of
Derivative Gain or (Loss) Reclassified from Accumulated
Other Comprehensive
Income (Loss) on the Consolidated Balance
Sheet into the Consolidated
Statement of Income
for the Year Ended
September 30, |
| | | 2022 | | 2021 | | | | 2022 | | | 2021 |
| Commodity Contracts | | $ | (1,048,200) | | | $ | (668,074) | | | Operating Revenue | | $ | (882,594) | | (1) | | $ | (83,973) | |
| | | | | | | | | | | |
| Foreign Currency Contracts | | (2,631) | | | 2,703 | | | Operating Revenue | | 13 | | | | 262 | |
| Total | | $ | (1,050,831) | | | $ | (665,371) | | | | | $ | (882,581) | | | | $ | (83,711) | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
The Effect of Derivative Financial Instruments on the Statement of Financial Performance for the Year Ended September 30, 2017 and 2016 (Dollar Amounts in Thousands) |
Derivatives in Cash Flow Hedging Relationships | | Amount of Derivative Gain or (Loss) Recognized in Other Comprehensive Income (Loss) on the Consolidated Statement of Comprehensive Income (Loss) (Effective Portion) for the Year Ended September 30, | | Location of Derivative Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet into the Consolidated Statement of Income (Effective Portion) | | Amount of Derivative Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet into the Consolidated Statement of Income (Effective Portion) for the Year Ended September 30, | | Location of Derivative Gain or (Loss) Recognized in the Consolidated Statement of Income (Ineffective Portion and Amount Excluded from Effectiveness Testing) | | Derivative Gain or (Loss) Recognized in the Consolidated Statement of Income (Ineffective Portion and Amount Excluded from Effectiveness Testing) for the Year Ended September 30, |
| | | 2017 | | 2016 | | | | 2017 | | 2016 | | | | 2017 | | 2016 |
| Commodity Contracts | | $ | 2,811 |
| | $ | 58,714 |
| | Operating Revenue | | $ | 83,983 |
| | $ | 216,823 |
| | Operating Revenue | | $ | (100 | ) | | $ | 392 |
|
| Commodity Contracts | | (164 | ) | | 1,585 |
| | Purchased Gas | | (1,921 | ) | | 4,520 |
| | Not Applicable | | — |
| | — |
|
| Foreign Currency Contracts | | 2,700 |
| | 194 |
| | Operation and Maintenance Expense | | (457 | ) | | (424 | ) | | Not Applicable | | — |
| | — |
|
| Total | | $ | 5,347 |
| | $ | 60,493 |
| | | | $ | 81,605 |
| | $ | 220,919 |
| | | | $ | (100 | ) | | $ | 392 |
|
Fair Value Hedges
The(1)On June 30, 2022, the Company utilizes fair value hedgescompleted the sale of Seneca's California assets. Because of this sale, the Company terminated its remaining crude oil derivative contracts and discontinued hedge accounting for such contracts. A loss of $44.6 million was reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet to mitigate risk associated with fixed price sales commitments, fixed price purchase commitments, andOperating Revenues on the declineConsolidated Statement of Income for the year ended September 30, 2022. This loss is included in the value of certain natural gas held in storage. With respect to fixed price sales commitments, the Company enters into long positions to mitigate the risk of price increases for natural gas supplies that could occur after the Company enters into fixed price sales agreements with its customers.
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
With respect to fixed price purchase commitments, the Company enters into short positions to mitigate the risk of price decreases that could occur after the Company locks into fixed price purchase deals with its suppliers. With respect to storage hedges, the Company enters into short positions to mitigate the risk of price decreases that could result in a lower of cost or net realizable value writedown of the value of natural gas in storage that is recorded in the Company’s financial statements. As of September 30, 2017, the Company’s Energy Marketing segment had fair value hedges covering approximately 17.5 Bcf (16.4 Bcf of fixed price sales commitments and 1.1 Bcf of commitments related to the withdrawal of storage gas). For derivative instruments that are designated and qualify as a fair value hedge, the gain or loss on the derivative as well as the offsetting gain or loss on the hedged item attributable to the hedged risk completely offset each other in current earnings, as shown below.
|
| | | | | | | | | | |
| Derivatives in Fair Value Hedging Relationships | | Location of Gain or (Loss) on Derivative and Hedged Item Recognized in the Consolidated Statement of Income | | Amount of Gain or (Loss) on Derivative Recognized in the Consolidated Statement of Income for the Year Ended September 30, 2017 | | Amount of Gain or (Loss) on Hedged Item Recognized in the Consolidated Statement of Income for the Year Ended September 30, 2017 |
| | | | | (In thousands) |
| Commodity Contracts | | Operating Revenues | | $ | 1,655 |
| | $ | (1,655 | ) |
| Commodity Contracts | | Purchased Gas | | 464 |
| | (464 | ) |
| | | | | $ | 2,119 |
| | $ | (2,119 | ) |
Credit Risk
The Company may be exposed to credit risk on any of the derivative financial instruments that are in a gain position. Credit risk relates to the risk of loss that the Company would incur as a result of nonperformance by counterparties pursuant to the terms of their contractual obligations. To mitigate such credit risk, management performs a credit check, and then on a quarterly basis monitors counterparty credit exposure. The majority of the Company’s counterparties are financial institutions and energy traders. The Company has over-the-counterover the-counter swap positions, no cost collars and applicable foreign currency forward contracts with seventeennineteen counterparties of which sixteen areone is in a net gain position. On average, theThe Company had $2.2$1.0 million of credit exposure perwith the counterparty in a gain position at September 30, 2017. The maximum credit exposure per counterparty in a gain position at September 30, 2017 was $6.0 million.2022. As of September 30, 2017,2022, no collateral was received from the counterparties by the Company. The Company's gain position on such derivative financial instruments had not exceeded the established thresholds at which the counterparties would be required to post collateral, nor had the counterparties' credit ratings declined to levels at which the counterparties were required to post collateral.
As of September 30, 2017, fourteen2022, seventeen of the seventeennineteen counterparties to the Company’s outstanding derivative instrumentfinancial contracts (specifically the over-the-counter swaps, over-the-counter no cost collars and
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
applicable foreign currency forward contracts) had a common credit-risk related contingency feature. In the event the Company’s credit rating increases or falls below a certain threshold (applicable debt ratings), the available credit extended to the Company would either increase or decrease. A decline in the Company’s credit rating, in and of itself, would not cause the Company to be required to post or increase the level of its hedging collateral deposits (in the form of cash deposits, letters of credit or treasury debt instruments). If the Company’s outstanding derivative financial instrument contracts with a credit-risk contingency feature were in a liability position (or if the liability were larger) and/or the Company’s credit rating declined, then additional hedging collateral deposits mayor an increase to such deposits could be required. At September 30, 2017,2022, the fair market value of the derivative financial instrument assetsliabilities with a credit-risk related contingency feature was $26.0$564.3 million according to the Company’sCompany's internal model (discussed in Note FI — Fair Value Measurements). For its over-the-counter swap agreements and foreign currency forward contracts, no hedging collateral deposits were required to be posted by the Company at September 30, 2017.
For its exchange traded futures contracts, the Company was required to post $1.7posted $91.7 million in hedging collateral deposits asdeposits. Depending on the movement of September 30, 2017. Ascommodity prices in the future, it is possible that these are exchange traded futures contracts, there are no specific credit-
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
liability positions could swing into asset positions, at which point the Company would be exposed to credit risk related contingency features. The Company posts or receiveson its derivative financial instruments. In that case, the Company's counterparties could be required to post hedging collateral based on open positions and margin requirements it has with its counterparties.deposits.
The Company’s requirement to post hedging collateral deposits and the Company's right to receive hedging collateral deposits is based on the fair value determined by the Company’s counterparties, which may differ from the Company’s assessment of fair value. Hedging collateral deposits may also include closed derivative positions in which the broker has not cleared the cash from the account to offset the derivative liability. The Company records liabilities related to closed derivative positions in Other Accruals and Current Liabilities on the Consolidated Balance Sheet. These liabilities are relieved when the broker clears the cash from the hedging collateral deposit account. This is discussed in Note A under Hedging Collateral Deposits.
Note HK — Retirement Plan and Other Post-Retirement Benefits
The Company has a tax-qualified, noncontributory, defined-benefit retirement plan (Retirement Plan). The Retirement Plan covers certain non-collectively bargained employees hired before July 1, 2003 and certain collectively bargained employees hired before November 1, 2003. Certain non-collectively bargained employees hired after June 30, 2003 and certain collectively bargained employees hired after October 31, 2003 are eligible for a Retirement Savings Account benefit provided under the Company’s defined contribution Tax-Deferred Savings Plans. Costs associated with the Retirement Savings Account were $2.9$5.3 million, $2.6$4.8 million and $2.3$4.2 million for the years ended September 30, 2017, 20162022, 2021 and 2015,2020, respectively. Costs associated with the Company’s contributions to the Tax-Deferred Savings Plans, exclusive of the costs associated with the Retirement Savings Account, were $5.9$7.8 million, $5.9$7.2 million, and $5.8$6.7 million for the years ended September 30, 2017, 20162022, 2021 and 2015,2020, respectively.
The Company provides health care and life insurance benefits (other post-retirement benefits) for a majority of its retired employees. The other post-retirement benefits cover certain non-collectively bargained employees hired before January 1, 2003 and certain collectively bargained employees hired before October 31, 2003.
The Company’s policy is to fund the Retirement Plan with at least an amount necessary to satisfy the minimum funding requirements of applicable laws and regulations and not more than the maximum amount deductible for federal income tax purposes. The Company has established VEBA trusts for its other post-retirement benefits. Contributions to the VEBA trusts are tax deductible, subject to limitations contained in the Internal Revenue Code and regulations and are made to fund employees’ other post-retirement benefits, as well as benefits as they are paid to current retirees. In addition, the Company has established 401(h) accounts for its other post-retirement benefits. They are separate accounts within the Retirement Plan trust used to pay retiree medical benefits for the associated participants in the Retirement Plan. Although these accounts are in the Retirement Plan trust, for funding status purposes as shown below, the 401(h) accounts are included in Fair Value of Assets under Other Post-Retirement Benefits. Contributions are tax-deductible when made, subject to limitations contained in the Internal Revenue Code and regulations.
The expected return on Retirement Plan assets, a component of net periodic benefit cost shown in the tables below, is applied to the market-related value of plan assets. The market-related value of plan assets is the market value as of the measurement date adjusted for variances between actual returns and expected returns (from previous years) that have not been reflected in net periodic benefit costs. The expected return on other
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
post-retirement benefit assets (i.e. the VEBA trusts and 401(h) accounts), which is a component of net periodic benefit cost shown in the tables below, is applied to the fair value of assets as of the measurement date.
Reconciliations of the Benefit Obligations, Plan Assets and Funded Status, as well as the components of Net Periodic Benefit Cost and the Weighted Average Assumptions of the Retirement Plan and other post-retirement benefits are shown in the tables below. The components of net periodic benefit cost other than service cost are presented in Other Income (Deductions) on the Consolidated Statements of Income. The date used to measure the Benefit Obligations, Plan Assets and Funded Status is September 30 for fiscal years 2017, 20162022, 2021 and 2015.2020.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Retirement Plan | | Other Post-Retirement Benefits |
| | Year Ended September 30 | | Year Ended September 30 |
| | 2022 | | 2021 | | 2020 | | 2022 | | 2021 | | 2020 |
| | (Thousands) |
| Change in Benefit Obligation | | | | | | | | | | | |
| Benefit Obligation at Beginning of Period | $ | 1,098,456 | | $ | 1,139,105 | | $ | 1,097,625 | | $ | 431,213 | | $ | 476,722 | | $ | 468,163 |
| Service Cost | 8,758 | | 9,865 | | 9,318 | | 1,328 | | 1,602 | | 1,609 |
| Interest Cost | 22,827 | | 21,686 | | 29,930 | | 9,066 | | 9,303 | | 12,913 |
| Plan Participants’ Contributions | — | | — | | — | | 3,271 | | 3,216 | | 3,058 |
| Retiree Drug Subsidy Receipts | — | | — | | — | | 312 | | 1,244 | | 1,411 |
| | | | | | | | | | | |
| Actuarial (Gain) Loss | (251,173) | | (8,141) | | 65,908 | | (120,276) | | (34,729) | | 16,396 |
| Benefits Paid | (65,040) | | (64,059) | | (63,676) | | (25,631) | | (26,145) | | (26,828) |
| Benefit Obligation at End of Period | $ | 813,828 | | $ | 1,098,456 | | $ | 1,139,105 | | $ | 299,283 | | $ | 431,213 | | $ | 476,722 |
| Change in Plan Assets | | | | | | | | | | | |
| Fair Value of Assets at Beginning of Period | $ | 1,095,729 | | $ | 1,016,796 | | $ | 968,449 | | $ | 575,565 | | $ | 547,885 | | $ | 524,127 |
| Actual Return on Plan Assets | (205,884) | | 122,992 | | 87,402 | | (94,849) | | 47,541 | | 44,448 |
| Employer Contributions | 20,400 | | 20,000 | | 24,621 | | 3,082 | | 3,068 | | 3,080 |
| Plan Participants’ Contributions | — | | — | | — | | 3,271 | | 3,216 | | 3,058 |
| Benefits Paid | (65,040) | | (64,059) | | (63,676) | | (25,631) | | (26,145) | | (26,828) |
| Fair Value of Assets at End of Period | $ | 845,205 | | $ | 1,095,729 | | $ | 1,016,796 | | $ | 461,438 | | $ | 575,565 | | $ | 547,885 |
| Net Amount Recognized at End of Period (Funded Status) | $ | 31,377 | | $ | (2,727) | | $ | (122,309) | | $ | 162,155 | | $ | 144,352 | | $ | 71,163 |
| Amounts Recognized in the Balance Sheets Consist of: | | | | | | | | | | | |
| Non-Current Liabilities | $ | — | | $ | (2,727) | | $ | (122,309) | | $ | (3,065) | | $ | (4,799) | | $ | (4,872) |
| Non-Current Assets | 31,377 | | — | | — | | 165,220 | | 149,151 | | 76,035 |
| Net Amount Recognized at End of Period | $ | 31,377 | | $ | (2,727) | | $ | (122,309) | | $ | 162,155 | | $ | 144,352 | | $ | 71,163 |
| Accumulated Benefit Obligation | $ | 793,555 | | $ | 1,060,659 | | $ | 1,096,427 | | N/A | | N/A | | N/A |
| Weighted Average Assumptions Used to Determine Benefit Obligation at September 30 | | | | | | | | | | | |
| Discount Rate | 5.57 | % | | 2.75 | % | | 2.66 | % | | 5.56 | % | | 2.76 | % | | 2.71 | % |
| Rate of Compensation Increase | 4.60 | % | | 4.70 | % | | 4.70 | % | | 4.60 | % | | 4.70 | % | | 4.70 | % |
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Retirement Plan | | Other Post-Retirement Benefits |
| | Year Ended September 30 | | Year Ended September 30 |
| | 2017 | | 2016 | | 2015 | | 2017 | | 2016 | | 2015 |
| | (Thousands) |
| Change in Benefit Obligation | | | | | | | | | | | |
| Benefit Obligation at Beginning of Period | $ | 1,097,421 |
| | $ | 1,026,190 |
| | $ | 999,499 |
| | $ | 526,138 |
| | $ | 464,987 |
| | $ | 465,583 |
|
| Service Cost | 11,969 |
| | 11,710 |
| | 12,047 |
| | 2,449 |
| | 2,331 |
| | 2,693 |
|
| Interest Cost | 38,383 |
| | 42,315 |
| | 41,217 |
| | 19,007 |
| | 20,386 |
| | 19,285 |
|
| Plan Participants’ Contributions | — |
| | — |
| | — |
| | 2,717 |
| | 2,558 |
| | 2,242 |
|
| Retiree Drug Subsidy Receipts | — |
| | — |
| | — |
| | 1,553 |
| | 1,925 |
| | 1,338 |
|
| Amendments(1) | — |
| | — |
| | 7,752 |
| | — |
| | — |
| | — |
|
| Actuarial (Gain) Loss | (32,466 | ) | | 76,309 |
| | 23,426 |
| | (62,215 | ) | | 60,402 |
| | (1,575 | ) |
| Benefits Paid | (60,481 | ) | | (59,103 | ) | | (57,751 | ) | | (27,030 | ) | | (26,451 | ) | | (24,579 | ) |
| Benefit Obligation at End of Period | $ | 1,054,826 |
| | $ | 1,097,421 |
| | $ | 1,026,190 |
| | $ | 462,619 |
| | $ | 526,138 |
| | $ | 464,987 |
|
| Change in Plan Assets | | | | | | | | | | | |
| Fair Value of Assets at Beginning of Period | $ | 869,775 |
| | $ | 834,870 |
| | $ | 869,791 |
| | $ | 494,320 |
| | $ | 477,959 |
| | $ | 497,601 |
|
| Actual Return on Plan Assets | 84,279 |
| | 87,008 |
| | (13,370 | ) | | 40,157 |
| | 37,415 |
| | 534 |
|
| Employer Contributions | 17,146 |
| | 7,000 |
| | 36,200 |
| | 3,853 |
| | 2,839 |
| | 2,161 |
|
| Plan Participants’ Contributions | — |
| | — |
| | — |
| | 2,717 |
| | 2,558 |
| | 2,242 |
|
| Benefits Paid | (60,481 | ) | | (59,103 | ) | | (57,751 | ) | | (27,030 | ) | | (26,451 | ) | | (24,579 | ) |
| Fair Value of Assets at End of Period | $ | 910,719 |
| | $ | 869,775 |
| | $ | 834,870 |
| | $ | 514,017 |
| | $ | 494,320 |
| | $ | 477,959 |
|
| Net Amount Recognized at End of Period (Funded Status) | $ | (144,107 | ) | | $ | (227,646 | ) | | $ | (191,320 | ) | | $ | 51,398 |
| | $ | (31,818 | ) | | $ | 12,972 |
|
| Amounts Recognized in the Balance Sheets Consist of: | | | | | | | | | | | |
| Non-Current Liabilities | $ | (144,107 | ) | | $ | (227,646 | ) | | $ | (191,320 | ) | | $ | (4,972 | ) | | $ | (49,467 | ) | | $ | (11,487 | ) |
| Non-Current Assets | — |
| | — |
| | — |
| | 56,370 |
| | 17,649 |
| | 24,459 |
|
| Net Amount Recognized at End of Period | $ | (144,107 | ) | | $ | (227,646 | ) | | $ | (191,320 | ) | | $ | 51,398 |
| | $ | (31,818 | ) | | $ | 12,972 |
|
| Accumulated Benefit Obligation | $ | 1,010,179 |
| | $ | 1,039,408 |
| | $ | 968,984 |
| | N/A |
| | N/A |
| | N/A |
|
| Weighted Average Assumptions Used to Determine Benefit Obligation at September 30 | | | | | | | | | | | |
| Discount Rate | 3.77 | % | | 3.60 | % | | 4.25 | % | | 3.81 | % | | 3.70 | % | | 4.50 | % |
| Rate of Compensation Increase | 4.70 | % | | 4.70 | % | | 4.75 | % | | 4.70 | % | | 4.70 | % | | 4.75 | % |
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Retirement Plan | | Other Post-Retirement Benefits |
| | Year Ended September 30 | | Year Ended September 30 |
| | 2017 | | 2016 | | 2015 | | 2017 | | 2016 | | 2015 |
| | (Thousands) |
| Components of Net Periodic Benefit Cost | | | | | | | | | | | |
| Service Cost | $ | 11,969 |
| | $ | 11,710 |
| | $ | 12,047 |
| | $ | 2,449 |
| | $ | 2,331 |
| | $ | 2,693 |
|
| Interest Cost | 38,383 |
| | 42,315 |
| | 41,217 |
| | 19,007 |
| | 20,386 |
| | 19,285 |
|
| Expected Return on Plan Assets | (59,718 | ) | | (59,369 | ) | | (59,615 | ) | | (31,458 | ) | | (31,535 | ) | | (34,089 | ) |
| Amortization of Prior Service Cost (Credit) | 1,058 |
| | 1,234 |
| | 183 |
| | (429 | ) | | (912 | ) | | (1,913 | ) |
| Recognition of Actuarial Loss(2) | 42,687 |
| | 32,248 |
| | 36,129 |
| | 18,415 |
| | 5,530 |
| | 4,148 |
|
| Net Amortization and Deferral for Regulatory Purposes | 469 |
| | 3,957 |
| | 7,739 |
| | 6,108 |
| | 17,123 |
| | 20,322 |
|
| Net Periodic Benefit Cost | $ | 34,848 |
| | $ | 32,095 |
| | $ | 37,700 |
| | $ | 14,092 |
| | $ | 12,923 |
| | $ | 10,446 |
|
| Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost at September 30 | | | | | | | | | | | |
| Discount Rate | 3.60 | % | | 4.25 | % | | 4.25 | % | | 3.70 | % | | 4.50 | % | | 4.25 | % |
| Expected Return on Plan Assets | 7.00 | % | | 7.25 | % | | 7.50 | % | | 6.50 | % | | 6.75 | % | | 7.00 | % |
| Rate of Compensation Increase | 4.75 | % | | 4.75 | % | | 4.75 | % | | 4.75 | % | | 4.75 | % | | 4.75 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Retirement Plan | | Other Post-Retirement Benefits |
| | Year Ended September 30 | | Year Ended September 30 |
| | 2022 | | 2021 | | 2020 | | 2022 | | 2021 | | 2020 |
| | (Thousands) |
| Components of Net Periodic Benefit Cost | | | | | | | | | | | |
| Service Cost | $ | 8,758 | | $ | 9,865 | | $ | 9,318 | | $ | 1,328 | | $ | 1,602 | | $ | 1,609 |
| Interest Cost | 22,827 | | 21,686 | | 29,930 | | 9,066 | | 9,303 | | 12,913 |
| Expected Return on Plan Assets | (52,294) | | (58,148) | | (60,063) | | (29,359) | | (28,964) | | (29,232) |
| Amortization of Prior Service Cost (Credit) | 537 | | 631 | | 729 | | (429) | | (429) | | (429) |
| | | | | | | | | | | |
| Recognition of Actuarial (Gain) Loss(1) | 26,405 | | 36,814 | | 39,384 | | (7,610) | | 849 | | 535 |
| Net Amortization and Deferral for Regulatory Purposes | 16,854 | | 14,063 | | 5,359 | | 21,340 | | 28,010 | | 25,596 |
| Net Periodic Benefit Cost (Income) | $ | 23,087 | | $ | 24,911 | | $ | 24,657 | | $ | (5,664) | | $ | 10,371 | | $ | 10,992 |
| Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost at September 30 | | | | | | | | | | | |
| Effective Discount Rate for Benefit Obligations | 2.75 | % | | 2.66 | % | | 3.15 | % | | 2.76 | % | | 2.71 | % | | 3.17 | % |
| Effective Rate for Interest on Benefit Obligations | 2.14 | % | | 1.96 | % | | 2.81 | % | | 2.17 | % | | 2.01 | % | | 2.84 | % |
| Effective Discount Rate for Service Cost | 2.95 | % | | 3.01 | % | | 3.31 | % | | 3.00 | % | | 3.20 | % | | 3.39 | % |
| Effective Rate for Interest on Service Cost | 2.70 | % | | 2.60 | % | | 3.12 | % | | 2.93 | % | | 2.98 | % | | 3.30 | % |
| Expected Return on Plan Assets | 5.20 | % | | 6.00 | % | | 6.40 | % | | 5.20 | % | | 5.40 | % | | 5.70 | % |
| Rate of Compensation Increase | 4.70 | % | | 4.70 | % | | 4.70 | % | | 4.70 | % | | 4.70 | % | | 4.70 | % |
| |
(1) | In fiscal 2015, the Company passed an amendment which updated the mortality table used in the Retirement Plan's definition of "actuarially equivalent" effective July 1, 2015. This increased the benefit obligation of the Retirement Plan. |
| |
(2) | Distribution Corporation’s New York jurisdiction calculates the amortization of the actuarial loss on a vintage year basis over 10 years, as mandated by the NYPSC. All the other subsidiaries of the Company utilize the corridor approach. |
(1)Distribution Corporation’s New York jurisdiction calculates the amortization of the actuarial loss on a vintage year basis over 10 years, as mandated by the NYPSC. All the other subsidiaries of the Company utilize the corridor approach.
The Net Periodic Benefit Cost (Income) in the table above includes the effects of regulation. The Company recovers pension and other post-retirement benefit costs in its Utility and Pipeline and Storage segments in accordance with the applicable regulatory commission authorizations. Certain of those commission authorizations established tracking mechanisms which allow the Company to record the difference between the amount of pension and other post-retirement benefit costs recoverable in rates and the amounts of such costs as determined under the existing authoritative guidance as either a regulatory asset or liability, as appropriate. Any activity under the tracking mechanisms (including the amortization of pension and other post-retirement regulatory assets and liabilities) is reflected in the Net Amortization and Deferral for Regulatory Purposes line item above.
In addition to the Retirement Plan discussed above, the Company also has Non-Qualified benefit plans that cover a group of management employees whose income level has exceeded certain IRS thresholds or who have been designated as participants by the Chief Executive Officer of the Company. These plans provide for defined benefit payments upon retirement of the management employee, or to the spouse upon death of the management employee. The net periodic benefit costs associated with these plans were $7.6$8.9 million, $7.5 $8.3
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
million and $7.0$8.9 million in 2017, 20162022, 2021 and 2015,2020, respectively. The components of net periodic benefit cost other than service costs associated with these plans are presented in Other Income (Deductions) on the Consolidated Statements of Income. The accumulated benefit obligations for the plans were $72.5$64.9 million, $72.4$76.9 million and $66.0$78.7 million at September 30, 2017, 20162022, 2021 and 2015,2020, respectively. The projected benefit obligations for the plans were $88.9$77.2 million, $91.7$95.8 million and $85.8$98.1 million at September 30, 2017, 20162022, 2021 and 2015,2020, respectively. At September 30, 2017, $14.12022, $17.5 million of the projected benefit obligation is recorded in Other Accruals and Current Liabilities and the remaining $74.8$59.7 million is recorded in Other Deferred CreditsLiabilities on the Consolidated Balance Sheets. At September 30, 2016, $9.8 million of the projected benefit obligation
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
was recorded in Other Accruals and Current Liabilities and the remaining $81.9 million was recorded in Other Deferred Credits on the Consolidated Balance Sheets. At September 30, 2015, $4.52021, $15.4 million of the projected benefit obligation was recorded in Other Accruals and Current Liabilities and the remaining $81.3$80.4 million was recorded in Other Deferred CreditsLiabilities on the Consolidated Balance Sheets. At September 30, 2020, $14.5 million of the projected benefit obligation was recorded in Other Accruals and Current Liabilities and the remaining $83.6 million was recorded in Other Liabilities on the Consolidated Balance Sheets. The weighted average discount rates for these plans were 3.22%5.49%, 2.80%2.15% and 3.50%1.92% as of September 30, 2017, 20162022, 2021 and 2015,2020, respectively and the weighted average ratesrate of compensation increase for these plans were 7.75%, 7.75% and 7.75%was 8.00% as of September 30, 2017, 20162022, 2021 and 2015, respectively.2020.
The cumulative amounts recognized in accumulated other comprehensive income (loss), regulatory assets, and regulatory liabilities through fiscal 2017,2022, as well as the changes in such amounts during 2017, as well as the amounts expected to be recognized in net periodic benefit cost in fiscal 20182022, are presented in the table below: |
| | | | | | | | | | | |
| | Retirement Plan | | Other Post-Retirement Benefits | | Non-Qualified Benefit Plans |
| | (Thousands) |
| Amounts Recognized in Accumulated Other Comprehensive Income (Loss), Regulatory Assets and Regulatory Liabilities(1) | | | | | |
| Net Actuarial Loss | $ | (203,887 | ) | | $ | (19,578 | ) | | $ | (24,332 | ) |
| Prior Service (Cost) Credit | (6,133 | ) | | 3,687 |
| | — |
|
| Net Amount Recognized | $ | (210,020 | ) | | $ | (15,891 | ) | | $ | (24,332 | ) |
| Changes to Accumulated Other Comprehensive Income (Loss), Regulatory Assets and Regulatory Liabilities Recognized During Fiscal 2017(1) | | | | | |
| Decrease (Increase) in Actuarial Loss, excluding amortization(2) | $ | 57,028 |
| | $ | 70,915 |
| | $ | (1,351 | ) |
| Change due to Amortization of Actuarial Loss | 42,687 |
| | 18,415 |
| | 4,059 |
|
| Prior Service (Cost) Credit | 1,058 |
| | (429 | ) | | — |
|
| Net Change | $ | 100,773 |
| | $ | 88,901 |
| | $ | 2,708 |
|
| Amounts Expected to be Recognized in Net Periodic Benefit Cost in the Next Fiscal Year(1) | | | | | |
| Net Actuarial Loss | $ | (37,205 | ) | | $ | (10,558 | ) | | $ | (3,549 | ) |
| Prior Service (Cost) Credit | (938 | ) | | 429 |
| | — |
|
| Net Amount Expected to be Recognized | $ | (38,143 | ) | | $ | (10,129 | ) | | $ | (3,549 | ) |
| | | | | | | | | | | | | | | | | |
| Retirement
Plan | | Other
Post-Retirement
Benefits | | Non-Qualified
Benefit Plans |
| | (Thousands) |
| Amounts Recognized in Accumulated Other Comprehensive Income (Loss), Regulatory Assets and Regulatory Liabilities(1) | | | | | |
| Net Actuarial Gain (Loss) | $ | (86,133) | | | $ | 14,569 | | | $ | (18,718) | |
| Prior Service (Cost) Credit | (2,472) | | | 1,543 | | | — | |
| Net Amount Recognized | $ | (88,605) | | | $ | 16,112 | | | $ | (18,718) | |
| Changes to Accumulated Other Comprehensive Income (Loss), Regulatory Assets and Regulatory Liabilities Recognized During Fiscal 2022(1) | | | | | |
| Decrease (Increase) in Actuarial Loss, excluding amortization(2) | $ | (7,006) | | | $ | (3,932) | | | $ | 8,222 | |
| Change due to Amortization of Actuarial Loss | 26,405 | | | (7,610) | | | 6,301 | |
| | | | | |
| Prior Service (Cost) Credit | 537 | | | (429) | | | — | |
| Net Change | $ | 19,936 | | | $ | (11,971) | | | $ | 14,523 | |
| |
(1) | Amounts presented are shown before recognizing deferred taxes. |
| |
(2) | Amounts presented include the impact of actuarial gains/losses related to return on assets, as well as the Actuarial (Gain) Loss amounts presented in the Change in Benefit Obligation. |
(1)Amounts presented are shown before recognizing deferred taxes.
(2)Amounts presented include the impact of actuarial gains/losses related to return on assets, as well as the Actuarial (Gain) Loss amounts presented in the Change in Benefit Obligation.
In order to adjust the funded status of its pension (tax-qualified and non-qualified) and other post-retirement benefit plans at September 30, 2017,2022, the Company recorded a $163.3$1.9 million decrease to Other Regulatory Assets in the Company’s Utility and Pipeline and Storage segments and a $29.1$20.6 million (pre-tax) increase to Accumulated Other Comprehensive Income.
The effect of the discount rate change for the Retirement Plan in 20172022 was to decrease the projected benefit obligation of the Retirement Plan by $20.5$262.2 million. The mortality improvement projection scale was updated, which decreasedincreased the projected benefit obligation of the Retirement Plan in 20172022 by $8.3$1.8 million. In addition, otherOther actuarial experience decreasedincreased the projected benefit obligation for the Retirement Plan in 20172022 by $3.6$9.2 million. The effect of the discount rate change for the Retirement Plan in 20162021 was to increasedecrease the projected benefit obligation
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
obligation of the Retirement Plan by $78.5$11.2 million. The effect of the mortality assumptiondiscount rate change for the Retirement Plan in 20152020 was to increase the projected benefit obligation of the Retirement Plan by $24.2$61.3 million.
The Company made cash contributions totaling $17.1$20.4 million to the Retirement Plan during the year ended September 30, 2017.2022. The Company expects that the annual contribution to the Retirement Plan in 20182023 will be in the range of $15.0 millionzero to $40.0$8.0 million.
The following Retirement Plan benefit payments, which reflect expected future service, are expected to be paid by the Retirement Plan during the next five years and the five years thereafter: $64.4$67.6 million in 2018; $65.02023; $67.7 million in 2019; $65.42024; $67.3 million in 2020; $65.82025; $66.9 million in 2021;2026; $66.2 million in 2022;2027; and $331.1$316.1 million in the five years thereafter.
The effect of the discount rate change in 20172022 was to decrease the other post-retirement benefit obligation by $6.2$98.9 million. The mortality improvement projection scale was updated, which decreasedincreased the other post-retirement benefit obligation in 20172022 by $5.7$1.1 million. Other actuarial experience decreased the other post-retirement benefit obligation in 20172022 by $50.3$22.5 million, primarilythe majority of which was attributable to a revision in assumed per-capita claims cost, premiums, retiree contributions and retiree drug subsidy assumptions based on actual experience.
The effect of the discount rate change in 20162021 was to increasedecrease the other post-retirement benefit obligation by $49.4$2.5 million. Other actuarial experience increasedThe mortality improvement projection scale was updated, which decreased the other post-retirement benefit obligation in 20162021 by $11.0$2.0 million. The health care cost trend rates were updated, which decreased the other post-retirement benefit obligation in 2021 by $3.7 million. Other actuarial experience decreased the other post-retirement benefit obligation in 2021 by $26.6 million, primarilythe majority of which was attributable to a revision in assumed per-capita claims cost, premiums, participantretiree contributions and retiree drug subsidy assumptions based on actual experience.
The effect of the discount rate change in 20152020 was to decreaseincrease the other post-retirement benefit obligation by $14.3$25.4 million. Other actuarial experience increasedThe mortality improvement projection scale was updated, which decreased the other post-retirement benefit obligation in 20152020 by $12.8$2.5 million. Other actuarial experience decreased the other post-retirement benefit obligation in 2020 by $6.5 million, primarilythe majority of which was attributable to the changea revision in mortality assumption.assumed per-capita claims cost, premiums, retiree contributions and retiree drug subsidy assumptions based on actual experience.
The Medicare Prescription Drug, Improvement, and Modernization Act of 2003 provides for a prescription drug benefit under Medicare (Medicare Part D), as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to Medicare Part D.
The estimated gross other post-retirement benefit payments and gross amount of Medicare Part D prescription drug subsidy receipts are as follows (dollars in thousands):
|
| | | | | | | |
| | Benefit Payments | | Subsidy Receipts |
| 2018 | $ | 26,483 |
| | $ | (1,910 | ) |
| 2019 | $ | 27,456 |
| | $ | (2,074 | ) |
| 2020 | $ | 28,359 |
| | $ | (2,225 | ) |
| 2021 | $ | 29,173 |
| | $ | (2,369 | ) |
| 2022 | $ | 29,757 |
| | $ | (2,515 | ) |
| 2023 through 2027 | $ | 152,957 |
| | $ | (14,271 | ) |
| | | | | | | | | | | |
| Benefit Payments | | Subsidy Receipts |
| 2023 | $ | 26,221 | | | $ | (1,829) | |
| 2024 | $ | 26,337 | | | $ | (1,929) | |
| 2025 | $ | 26,376 | | | $ | (2,014) | |
| 2026 | $ | 26,291 | | | $ | (2,096) | |
| 2027 | $ | 26,140 | | | $ | (2,162) | |
| 2028 through 2032 | $ | 125,765 | | | $ | (11,391) | |
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Assumed health care cost trend rates as of September 30 were: |
| | | | | | | | | | | |
| | 2017 | | | 2016 | | | 2015 | |
| Rate of Medical Cost Increase for Pre Age 65 Participants | 5.67 | % | (1) | | 5.75 | % | (1) | | 6.93 | % | (2) |
| Rate of Medical Cost Increase for Post Age 65 Participants | 4.75 | % | (1) | | 4.75 | % | (1) | | 6.68 | % | (2) |
| Annual Rate of Increase in the Per Capita Cost of Covered Prescription Drug Benefits | 8.45 | % | (1) | | 9.00 | % | (1) | | 7.17 | % | (2) |
| Annual Rate of Increase in the Per Capita Medicare Part B Reimbursement | 4.75 | % | (1) | | 4.75 | % | (1) | | 6.68 | % | (2) |
| Annual Rate of Increase in the Per Capita Medicare Part D Subsidy | 7.33 | % | (1) | | 7.20 | % | (1) | | 6.65 | % | (2) |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2022 | | | 2021 | | | 2020 | |
| Rate of Medical Cost Increase for Pre Age 65 Participants | 5.30 | % | (1) | | 5.38 | % | (1) | | 5.42 | % | (2) |
| Rate of Medical Cost Increase for Post Age 65 Participants | 4.84 | % | (1) | | 4.84 | % | (1) | | 4.75 | % | (2) |
| Annual Rate of Increase in the Per Capita Cost of Covered Prescription Drug Benefits | 6.29 | % | (1) | | 6.53 | % | (1) | | 6.80 | % | (2) |
| Annual Rate of Increase in the Per Capita Medicare Part B Reimbursement | 4.84 | % | (1) | | 4.84 | % | (1) | | 4.75 | % | (2) |
| Annual Rate of Increase in the Per Capita Medicare Part D Subsidy | 5.96 | % | (1) | | 6.15 | % | (1) | | 6.20 | % | (2) |
| |
(1) | (1)It was assumed that this rate would gradually decline to 4.5% by 2039. |
| |
(2) | It was assumed that this rate would gradually decline to 4.5% by 2028. |
The health care cost trend rate assumptions usedwould gradually decline to calculate the per capita cost of covered medical care benefits have a significant effect on the amounts reported. If the health care cost trend rates were increased4% by 1% in each year, the other post-retirement benefit obligation as of October 1, 20172046.
(2)It was assumed that this rate would increasegradually decline to 4.5% by $57.9 million. This 1% change would also have increased the aggregate of the service and interest cost components of net periodic post-retirement benefit cost for 2017 by $3.3 million. If the health care cost trend rates were decreased by 1% in each year, the other post-retirement benefit obligation as of October 1, 2017 would decrease by $48.5 million. This 1% change would also have decreased the aggregate of the service and interest cost components of net periodic post-retirement benefit cost for 2017 by $2.7 million.2039.
The Company made cash contributions totaling $3.8$2.8 million to its VEBA trusts during the year ended September 30, 2017.2022. In addition, the Company made direct payments of $0.1$0.3 million to retirees not covered by the VEBA trusts and 401(h) accounts during the year ended September 30, 2017.2022. The Company expects that the annual contributiondoes not expect to make any contributions to its VEBA trusts in 2018 will be in the range of $2.5 million to $4.0 million.2023.
Investment Valuation
The Retirement Plan assets and other post-retirement benefit assets are valued under the current fair value framework. See Note FI — Fair Value Measurements for further discussion regarding the definition and levels of fair value hierarchy established by the authoritative guidance.
The inputs or methodologies used for valuing securities are not necessarily an indication of the risk associated with investing in those securities. Below is a listing of the major categories of plan assets held as of September 30, 20172022 and 2016,2021, as well as the associated level within the fair value hierarchy in which the fair value measurements in their entirety fall, based on the lowest level input that is significant to the fair value measurement in its entirety (dollars in thousands):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| At September 30, 2022 |
| Total
Fair Value | | Level 1 | | Level 2 | | Level 3 | | Measured
at NAV(7) |
| Retirement Plan Investments | | | | | | | | | |
| Domestic Equities(1) | $ | 41,633 | | | $ | 41,633 | | | $ | — | | | $ | — | | | $ | — | |
| International Equities(2) | 1,363 | | | — | | | — | | | — | | | 1,363 | |
| Global Equities(3) | 44,434 | | | — | | | — | | | — | | | 44,434 | |
| Domestic Fixed Income(4) | 658,833 | | | — | | | 579,606 | | | — | | | 79,227 | |
| International Fixed Income(5) | 7,782 | | | — | | | 7,782 | | | — | | | — | |
| | | | | | | | | |
| | | | | | | | | |
| Real Estate | 140,739 | | | — | | | — | | | — | | | 140,739 | |
| Cash Held in Collective Trust Funds | 17,388 | | | — | | | — | | | — | | | 17,388 | |
| Total Retirement Plan Investments | 912,172 | | | 41,633 | | | 587,388 | | | — | | | 283,151 | |
| 401(h) Investments | (73,044) | | | (3,310) | | | (46,694) | | | — | | | (23,040) | |
| Total Retirement Plan Investments (excluding 401(h) Investments) | $ | 839,128 | | | $ | 38,323 | | | $ | 540,694 | | | $ | — | | | $ | 260,111 | |
| Miscellaneous Accruals, Interest Receivables, and Non-Interest Cash | 6,077 | | | | | | | | | |
| Total Retirement Plan Assets | $ | 845,205 | | | | | | | | | |
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
|
| | | | | | | | | | | | | | | | | | | |
| | Total Fair Value Amounts at September 30, 2017 | | Level 1 | | Level 2 | | Level 3 | | Measured at NAV(7) |
| Retirement Plan Investments | | | | | | | | | |
| Domestic Equities(1) | $ | 290,716 |
| | $ | 209,421 |
| | $ | — |
| | $ | — |
| | $ | 81,295 |
|
| International Equities(2) | 123,069 |
| | — |
| | — |
| | — |
| | 123,069 |
|
| Global Equities(3) | 121,008 |
| | — |
| | — |
| | — |
| | 121,008 |
|
| Domestic Fixed Income(4) | 348,501 |
| | 1,664 |
| | 346,837 |
| | — |
| | — |
|
| International Fixed Income(5) | 422 |
| | 422 |
| | — |
| | — |
| | — |
|
| Global Fixed Income(6) | 75,428 |
| | — |
| | — |
| | — |
| | 75,428 |
|
| Real Estate | 3,391 |
| | — |
| | — |
| | 3,391 |
| | — |
|
| Cash Held in Collective Trust Funds | 26,058 |
| | — |
| | — |
| | — |
| | 26,058 |
|
| Total Retirement Plan Investments | 988,593 |
| | 211,507 |
| | 346,837 |
| | 3,391 |
| | 426,858 |
|
| 401(h) Investments | (64,728 | ) | | (14,026 | ) | | (23,001 | ) | | (225 | ) | | (27,476 | ) |
| Total Retirement Plan Investments (excluding 401(h) Investments) | $ | 923,865 |
| | $ | 197,481 |
| | $ | 323,836 |
| | $ | 3,166 |
| | $ | 399,382 |
|
| Miscellaneous Accruals, Interest Receivables, and Non-Interest Cash | (13,146 | ) | | | | | | | | |
| Total Retirement Plan Assets | $ | 910,719 |
| | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | |
| | Total Fair Value
Amounts at
September 30, 2016 | | Level 1 | | Level 2 | | Level 3 | | Measured at NAV(7) |
| Retirement Plan Investments | | | | | | | | | |
| Domestic Equities(1) | $ | 256,796 |
| | $ | 188,253 |
| | $ | — |
| | $ | — |
| | $ | 68,543 |
|
| International Equities(2) | 104,592 |
| | — |
| | — |
| | — |
| | 104,592 |
|
| Global Equities(3) | 120,025 |
| | — |
| | — |
| | — |
| | 120,025 |
|
| Domestic Fixed Income(4) | 342,442 |
| | 1,647 |
| | 340,795 |
| | — |
| | — |
|
| International Fixed Income(5) | 744 |
| | 407 |
| | 337 |
| | — |
| | — |
|
| Global Fixed Income(6) | 81,146 |
| | — |
| | — |
| | — |
| | 81,146 |
|
| Real Estate | 2,970 |
| | — |
| | — |
| | 2,970 |
| | — |
|
| Cash Held in Collective Trust Funds | 24,812 |
| | — |
| | — |
| | — |
| | 24,812 |
|
| Total Retirement Plan Investments | 933,527 |
| | 190,307 |
| | 341,132 |
| | 2,970 |
| | 399,118 |
|
| 401(h) Investments | (58,707 | ) | | (12,025 | ) | | (21,555 | ) | | (188 | ) | | (24,939 | ) |
| Total Retirement Plan Investments (excluding 401(h) Investments) | $ | 874,820 |
| | $ | 178,282 |
| | $ | 319,577 |
| | $ | 2,782 |
| | $ | 374,179 |
|
| Miscellaneous Accruals, Interest Receivables, and Non-Interest Cash | (5,045 | ) | | | | | | | | |
| Total Retirement Plan Assets | $ | 869,775 |
| | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| At September 30, 2021 |
| Total
Fair Value | | Level 1 | | Level 2 | | Level 3 | | Measured
at NAV(7) |
| Retirement Plan Investments | | | | | | | | | |
| Domestic Equities(1) | $ | 56,511 | | | $ | 146 | | | $ | — | | | $ | — | | | $ | 56,365 | |
| International Equities(2) | 28,917 | | | — | | | — | | | — | | | 28,917 | |
| Global Equities(3) | 95,865 | | | — | | | — | | | — | | | 95,865 | |
| Domestic Fixed Income(4) | 818,361 | | | 1,447 | | | 758,417 | | | — | | | 58,497 | |
| International Fixed Income(5) | 13,773 | | | — | | | 13,773 | | | — | | | — | |
| Global Fixed Income(6) | 42,454 | | | — | | | — | | | — | | | 42,454 | |
| | | | | | | | | |
| Real Estate | 119,451 | | | — | | | — | | | 319 | | | 119,132 | |
| Cash Held in Collective Trust Funds | 27,471 | | | — | | | — | | | — | | | 27,471 | |
| Total Retirement Plan Investments | 1,202,803 | | | 1,593 | | | 772,190 | | | 319 | | | 428,701 | |
| 401(h) Investments | (90,429) | | | (121) | | | (58,840) | | | (24) | | | (31,444) | |
| Total Retirement Plan Investments (excluding 401(h) Investments) | $ | 1,112,374 | | | $ | 1,472 | | | $ | 713,350 | | | $ | 295 | | | $ | 397,257 | |
| Miscellaneous Accruals, Interest Receivables, and Non-Interest Cash | (16,645) | | | | | | | | | |
| Total Retirement Plan Assets | $ | 1,095,729 | | | | | | | | | |
| |
(1) | Domestic Equities include mostly collective trust funds, common stock, and exchange traded funds. |
| |
(2) | International Equities are comprised of collective trust funds. |
| |
(3) | Global Equities are comprised of collective trust funds. |
| |
(4) | Domestic Fixed Income securities include mostly collective trust funds, corporate/government bonds and mortgages, and exchange traded funds. |
(1)Domestic Equities include mostly collective trust funds, common stock, and exchange traded funds.
(2)International Equities are comprised of collective trust funds.
(3)Global Equities are comprised of collective trust funds.
(4)Domestic Fixed Income securities include mostly collective trust funds, corporate/government bonds and mortgages, and exchange traded funds.
(5)International Fixed Income securities are comprised mostly of corporate/government bonds.
(6)Global Fixed Income securities are comprised of a collective trust fund.
(7)Reflects the authoritative guidance related to investments measured at net asset value (NAV).
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| At September 30, 2022 |
| Total
Fair Value | | Level 1 | | Level 2 | | Level 3 | | Measured
at NAV(1) |
| Other Post-Retirement Benefit Assets held in VEBA Trusts | | | | | | | | | |
| Collective Trust Funds — Global Equities | $ | 104,554 | | | $ | — | | | $ | — | | | $ | — | | | $ | 104,554 | |
| | | | | | | | | |
| | | | | | | | | |
| Exchange Traded Funds — Fixed Income | 270,581 | | | 270,581 | | | — | | | — | | | — | |
| | | | | | | | | |
| Cash Held in Collective Trust Funds | 10,635 | | | — | | | — | | | — | | | 10,635 | |
| Total VEBA Trust Investments | 385,770 | | | 270,581 | | | — | | | — | | | 115,189 | |
| 401(h) Investments | 73,044 | | | 3,310 | | | 46,694 | | | — | | | 23,040 | |
| Total Investments (including 401(h) Investments) | $ | 458,814 | | | $ | 273,891 | | | $ | 46,694 | | | $ | — | | | $ | 138,229 | |
| Miscellaneous Accruals (including Current and Deferred Taxes, Claims Incurred But Not Reported, Administrative) | 2,624 | | | | | | | | | |
| Total Other Post-Retirement Benefit Assets | $ | 461,438 | | | | | | | | | |
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| At September 30, 2021 |
| Total
Fair Value | | Level 1 | | Level 2 | | Level 3 | | Measured
at NAV(1) |
| Other Post-Retirement Benefit Assets held in VEBA Trusts | | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| Collective Trust Funds — Global Equities | $ | 165,226 | | | $ | — | | | $ | — | | | $ | — | | | $ | 165,226 | |
| Exchange Traded Funds — Fixed Income | 313,392 | | | 313,392 | | | — | | | — | | | — | |
| | | | | | | | | |
| Cash Held in Collective Trust Funds | 9,700 | | | — | | | — | | | — | | | 9,700 | |
| Total VEBA Trust Investments | 488,318 | | | 313,392 | | | — | | | — | | | 174,926 | |
| 401(h) Investments | 90,429 | | | 121 | | | 58,840 | | | 24 | | | 31,444 | |
| Total Investments (including 401(h) Investments) | $ | 578,747 | | | $ | 313,513 | | | $ | 58,840 | | | $ | 24 | | | $ | 206,370 | |
| Miscellaneous Accruals (Including Current and Deferred Taxes, Claims Incurred But Not Reported, Administrative) | (3,182) | | | | | | | | | |
| Total Other Post-Retirement Benefit Assets | $ | 575,565 | | | | | | | | | |
| | |
(5) | International Fixed Income securities are comprised mostly of an exchange traded fund. |
| |
(6) | Global Fixed Income securities are comprised of a collective trust fund. |
| |
(7) | Reflects the adoption of the new authoritative guidance related to investments measured at the net asset value (NAV) practical expedient. |
|
| | | | | | | | | | | | | | | | | | | |
| | Total Fair Value
Amounts at
September 30, 2017 | | Level 1 | | Level 2 | | Level 3 | | Measured at NAV(1) |
| Other Post-Retirement Benefit Assets held in VEBA Trusts | | | | | | | | | |
| Collective Trust Funds — Domestic Equities | $ | 130,864 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 130,864 |
|
| Collective Trust Funds — International Equities | 52,063 |
| | — |
| | — |
| | — |
| | 52,063 |
|
| Exchange Traded Funds — Fixed Income | 256,099 |
| | 256,099 |
| | — |
| | — |
| | — |
|
| Cash Held in Collective Trust Funds | 9,569 |
| | — |
| | — |
| | — |
| | 9,569 |
|
| Total VEBA Trust Investments | 448,595 |
| | 256,099 |
| | — |
| | — |
| | 192,496 |
|
| 401(h) Investments | 64,728 |
| | 14,026 |
| | 23,001 |
| | 225 |
| | 27,476 |
|
| Total Investments (including 401(h) Investments) | $ | 513,323 |
| | $ | 270,125 |
| | $ | 23,001 |
| | $ | 225 |
| | $ | 219,972 |
|
| Miscellaneous Accruals (Including Current and Deferred Taxes, Claims Incurred But Not Reported, Administrative) | 694 |
| | | | | | | | |
| Total Other Post-Retirement Benefit Assets | $ | 514,017 |
| | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | |
| | Total Fair Value
Amounts at
September 30, 2016 | | Level 1 | | Level 2 | | Level 3 | | Measured at NAV(1) |
| Other Post-Retirement Benefit Assets held in VEBA Trusts | | | | | | | | | |
| Collective Trust Funds — Domestic Equities | $ | 139,617 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 139,617 |
|
| Collective Trust Funds — International Equities | 51,488 |
| | — |
| | — |
| | — |
| | 51,488 |
|
| Exchange Traded Funds — Fixed Income | 230,761 |
| | 230,761 |
| | — |
| | — |
| | — |
|
| Cash Held in Collective Trust Funds | 13,176 |
| | — |
| | — |
| | — |
| | 13,176 |
|
| Total VEBA Trust Investments | 435,042 |
| | 230,761 |
| | — |
| | — |
| | 204,281 |
|
| 401(h) Investments | 58,707 |
| | 12,025 |
| | 21,555 |
| | 188 |
| | 24,939 |
|
| Total Investments (including 401(h) Investments) | $ | 493,749 |
| | $ | 242,786 |
| | $ | 21,555 |
| | $ | 188 |
| | $ | 229,220 |
|
| Miscellaneous Accruals (Including Current and Deferred Taxes, Claims Incurred But Not Reported, Administrative) | 571 |
| | | | | | | | |
| Total Other Post-Retirement Benefit Assets | $ | 494,320 |
| | | | | | | | |
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
| |
(1) | Reflects the adoption of the new authoritative guidance related to investments measured at the net asset value (NAV) practical expedient. |
(1)Reflects the authoritative guidance related to investments measured at net asset value (NAV).
The fair values disclosed in the above tables may not be indicative of net realizable value or reflective of future fair values. Furthermore, although the Company believes its valuation methods are appropriate and consistent with other market participants, the use of different methodologies or assumptions to determine the fair value of certain financial instruments could result in a different fair value measurement at the reporting date.
The following tables provide a reconciliation of the beginning and ending balances of the Retirement Plan and other post-retirement benefit assets measured at fair value on a recurring basis where the determination of fair value includes significant unobservable inputs (Level 3). For the years ended September 30, 20172022 and September 30, 2016,2021, there were no transfers from Level 1 to Level 2. In addition, as shown in the following tables, there were no transfers in or out of Level 3.
| | | | | | | | | | | | | | | | | | | |
| | | | Retirement Plan Level 3 Assets
(Thousands) |
| | | | Real
Estate | | Excluding
401(h)
Investments | | Total |
|
|
| Balance at September 30, 2020 | | | $ | 471 | | | $ | (35) | | | $ | 436 | |
| | | | | | | |
| Unrealized Gains/(Losses) | | | (152) | | | 11 | | | (141) | |
| | | | | | | |
| Sales | | | — | | | — | | | — | |
| Balance at September 30, 2021 | | | 319 | | | (24) | | | 295 | |
| | | | | | | |
| Unrealized Gains/(Losses) | | | 234 | | | (18) | | | 216 | |
| | | | | | | |
| Sales | | | (553) | | | 42 | | | (511) | |
| Balance at September 30, 2022 | | | $ | — | | | $ | — | | | $ | — | |
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
|
| | | | | | | | | | | | | | | | |
| | | Retirement Plan Level 3 Assets (Thousands) |
| | | Hedge Funds | | Real Estate | | Excluding 401(h) Investments | | Total |
| |
| |
| | Balance at September 30, 2015 | $ | 26,490 |
| | $ | 4,724 |
| | $ | (1,885 | ) | | $ | 29,329 |
|
| | Realized Gains/(Losses) | 5,878 |
| | — |
| | (354 | ) | | 5,524 |
|
| | Unrealized Gains/(Losses) | (5,445 | ) | | (404 | ) | | 344 |
| | (5,505 | ) |
| | Sales | (26,923 | ) | | (1,350 | ) | | 1,707 |
| | (26,566 | ) |
| | Balance at September 30, 2016 | — |
| | 2,970 |
|
| (188 | ) |
| 2,782 |
|
| | Unrealized Gains/(Losses) | — |
| | 421 |
| | (37 | ) | | 384 |
|
| | Balance at September 30, 2017 | $ | — |
| | $ | 3,391 |
| | $ | (225 | ) | | $ | 3,166 |
|
|
| | | | |
| | | Other Post-Retirement Benefit Level 3 Assets (Thousands) |
| | | 401(h) Investments |
| | |
| Balance at September 30, 2015 | | $ | 1,885 |
|
| Realized Gains/(Losses) | | 354 |
|
| Unrealized Gains/(Losses) | | (344 | ) |
| Sales | | (1,707 | ) |
| Balance at September 30, 2016 | | 188 |
|
| Unrealized Gains/(Losses) | | 37 |
|
| Balance at September 30, 2017 | | $ | 225 |
|
| | | | | | | | | |
| | | Other Post-Retirement Benefit Level 3 Assets
(Thousands) | | |
| | | 401(h)
Investments | | |
| | |
| Balance at September 30, 2020 | | | $ | 35 | | | |
| | | | | |
| Unrealized Gains/(Losses) | | | (11) | | | |
| | | | | |
| Sales | | | — | | | |
| Balance at September 30, 2021 | | | 24 | | | |
| | | | | |
| Unrealized Gains/(Losses) | | | 18 | | | |
| Sales | | | (42) | | | |
| Balance at September 30, 2022 | | | $ | — | | | |
The Company’s assumption regarding the expected long-term rate of return on plan assets is 7.00%6.90% (Retirement Plan) and 6.25%5.70% (other post-retirement benefits), effective for fiscal 2018.2023. The return assumption reflects the anticipated long-term rate of return on the plan’s current and future assets. The Company utilizes projected capital market conditions and the plan’s target asset class and investment manager allocations to set the assumption regarding the expected return on plan assets.
The long-term investment objective of the Retirement Plan trust, the VEBA trusts and the 401(h) accounts is to achieve the target total return in accordance with the Company’s risk tolerance. Assets are diversified utilizing
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
a mix of equities, fixed income and other securities (including real estate). The target allocation for the Retirement Plan and the VEBA trusts (including 401(h) accounts) is 40-60% equity securities, 40-60% fixed income securities and 0-15% other. Risk tolerance is established through consideration of plan liabilities, plan funded status and corporate financial condition. The assets of the Retirement Plan trusts,trust, VEBA trusts and the 401(h) accounts have no significant concentrations of risk in any one country (other than the United States), industry or entity. In fiscal 2021 and fiscal 2022, capital market conditions led to significant improvements in the funded status of the Retirement Plan. As a result, the Company reduced the return seeking portion of its assets during both years, particularly equity securities and return seeking fixed income securities, held in the Retirement Plan, and increased its allocation to hedging fixed income securities in conjunction with the Company’s liability driven investment strategy. The actual asset allocations as of September 30, 2022 are noted in the table above, and such allocations are subject to change, but the majority of the assets will remain hedging fixed income assets. Given the level of the VEBA trust and 401(h) assets in relation to the Other Post-Retirement Benefits, the majority of those assets are and will remain in fixed income securities.
Investment managers are retained to manage separate pools of assets. Comparative market and peer group performance of individual managers and the total fund are monitored on a regular basis, and reviewed by the Company’s Retirement Committee on at least a quarterly basis.
Beginning in fiscal 2018, theThe Company refined the method used to determinedetermines the service and interest cost components of net periodic benefit cost. Using the refined method, known ascost using the spot rate approach, the Company will usewhich uses individual spot rates along the yield curve that correspond to the timing of each benefit payment in order to determine the discount rate. The individual spot rates along the yield curve will continue to beare determined by an above mean methodology in that the coupon interest rates that are in the lower 50th percentile will beare excluded based on the assumption that the Company would not utilize more expensive (i.e. lower yield) instruments to settle its liabilities. The impact on the benefit obligation, as of September 30, 2017, is immaterial. This change will provide a more precise measurement of service and interest costs by improving the correlation between projected cash outflows and corresponding spot rates on the yield curve. Compared to the previous method, the spot rate approach will decrease the service and interest components of net periodic benefit costs in fiscal 2018. The Company will account for this change prospectively as a change in accounting estimate.
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note IL — Commitments and Contingencies
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 to comply with regulatory requirements.
It is the Company’s policy to accrue estimated environmental clean-up costs (investigation and remediation) when such amounts can reasonably be estimated and it is probable that the Company will be required to incur such costs. At September 30, 2017,2022, the Company has estimated its remaining clean-up costs related to former manufactured gas plant sites will be approximately $3.1$3.6 million. This estimatedThe Company's liability for such clean-up costs has been recorded in Other Deferred CreditsLiabilities on the Consolidated Balance Sheet at September 30, 2017.2022. The Company expects to recover its environmental clean-up costs through rate recovery over a period of approximately 4 years. The Companyone year and is currently not aware of any material additional exposure to environmental liabilities. However, changes in environmental laws and regulations, new information or other factors could could have an adverse financial impact on the Company.
Northern Access 2016 Project
On February 3, 2017, Supply Corporation and Empire received FERC approval of the Northern Access 2016 project described herein. On April 7, 2017,Shortly thereafter, the NYDEC issued a Notice of Denial of the federal Clean Water Act Section 401 Water Quality Certification and other state stream and wetland permits for the New York portion of the project (the Water Quality Certification for the Pennsylvania portion of the project was received onin January 27,of 2017). On April 21, 2017, Supply Corporation and Empire filed a Petition for Review in the United States Court of Appeals for the Second Circuit of the NYDEC's Notice of Denial with respect to National Fuel's application for the Water Quality Certification, and on May 11, 2017, the Company commenced legal action in New York State Supreme Court challenging the NYDEC's actions with regard to various state permits. The Company also has pending withSubsequently, FERC a proceeding asserting, among other things,issued an Order finding that the NYDEC exceeded the reasonablestatutory time frame to take action under the Clean Water Act and, therefore, waived its opportunity to approve or deny the Water Quality Certification. FERC denied rehearing requests associated with its Order and FERC's decisions were appealed. The Second Circuit Court of Appeals issued an order upholding the FERC waiver orders. In lightaddition, in the Company's state court litigation challenging the NYDEC's actions with regard to various state permits, the New York State Supreme Court issued a decision finding these permits to be preempted. The Company remains committed to the project and, on June 29, 2022, received an extension of these pending legal actions,time from FERC, until December 31, 2024, to construct the project. As of September 30, 2022, the Company has not yet determined a target
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
in-service date. As a result of the decision of the NYDEC, Supply Corporation and Empire evaluated the capitalized project costs for impairment as of September 30, 2017 and determined that an impairment charge was not required. The evaluation considered probability weighted scenarios of undiscounted future net cash flows, including a scenario assuming successful resolution with the NYDEC and construction of the pipeline, as well as a scenario wherespent approximately $55.8 million on the project, does not proceed. Further developments or indicatorsall of an unfavorable resolution could result in the impairment of a significant portion of the project costs, which totaled $75.8 million at September 30, 2017. The project costs are included within Property, Plant and Equipment and Deferred Chargesis recorded on the Consolidated Balance Sheet.balance sheet.
Other
The Company, in its Utility segment, Energy Marketing segment and Exploration and Production segment, has entered into contractual commitments in the ordinary course of business, including commitments to purchase gas, transportation, and storage service to meet customer gas supply needs. The future gas purchase, transportation and storage contract commitments during the next five years and thereafter are as follows: $262.4$458.2 million in 2018, $84.62023, $98.6 million in 2019, $77.92024, $135.6 million in 2020, $70.92025, $150.7 million in 2021, $61.72026, $142.1 million in 20222027 and $504.9$1,001.0 million thereafter. Gas prices within the gas purchase contracts are variable based on NYMEX prices adjusted for basis. In the Utility segment, these costs are subject to state commission review, and are being recovered in customer rates. Management believes that, to the extent any stranded pipeline costs are generated by the unbundling of services in the Utility segment’s service territory, such costs will be recoverable from customers.
The Company, has entered into leases for the use of compressors, drilling rigs, buildings and other items. These leases are accounted for as operating leases. The future lease commitments during the next five years and thereafter are as follows: $10.8 million in 2018, $4.6 million in 2019, $3.7 million in 2020, $2.2 million in 2021, $1.5 million in 2022 and $1.9 million thereafter.
The Company, in its Pipeline and Storage segment, Gathering segment and Utility segment, has entered into several contractual commitments associated with various pipeline, compressor and gathering system modernization and expansion projects. As of September 30, 2017,2022, the future contractual commitments related to the system modernization and expansion projects are $61.7$68.9 million in 2018, $0.72023, $8.5 million in 2019, $0.22024, $8.1 million in 2020, $0.32025, $6.9 million in 2021, $0.32026, $5.8 million in 20222027 and $1.1$5.8 million thereafter.
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The Company, in its Exploration and Production segment, has entered into contractual obligations associated withto support its development activities and operations in Pennsylvania, including hydraulic fracturing and fuel.other well completion services, well tending services, well workover activities, tubing and casing purchases, production equipment purchases, water hauling services and contracts for drilling rig services. The future contractual commitments are $79.5$282.5 million in 2018, $98.02023, $180.4 million in 20192024 and $17.1$153.8 million in 2020.2025, and $43.8 million in 2026. There are no contractual commitments extending beyond 2020.2026.
The Company is involved in other litigation arising in the normal course of business. In addition to the regulatory matters discussed in Note CF — Regulatory Matters, the Company is involved in other regulatory matters arising in the normal course of business. These other litigation and regulatory matters may include, for example, negligence claims and tax, regulatory or other governmental audits, inspections, investigations and 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 other matters arising in the normal course of business could have a material effect on earnings and cash flows in the period in which they are resolved, an estimate of the possible loss or range of loss, if any, cannot be made at this time.
Note JM — Business Segment Information
The Company reports financial results for fivefour segments: Exploration and Production, Pipeline and Storage, Gathering, Utility and Energy Marketing.Utility. The division of the Company’s operations into reportable segments is based upon a combination of factors including differences in products and services, regulatory environment and geographic factors.
The Exploration and Production segment, through Seneca, is engaged in exploration for and development of natural gas and oil reserves in California and the Appalachian region of the United States.
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The Pipeline and Storage segment operations are regulated by the FERC for both Supply Corporation and Empire. Supply Corporation transports and stores natural gas for utilities (including Distribution Corporation), natural gas marketers, (including NFR), exploration and production companies (including Seneca) and pipeline companies in the northeastern United States markets. Empire transports and stores natural gas for major industrial companies, utilities (including Distribution Corporation) and power producers in New York State. Empire also transports natural gas for natural gas marketers along withand exploration and production companies (including Seneca) from natural gas producing areas in Pennsylvania to markets in New York and to interstate pipeline delivery points forwith access to additional markets in the northeastern United States and Canada.
The Gathering segment is comprised of Midstream Corporation’sCompany’s operations. Midstream CorporationCompany builds, owns and operates natural gas processing and pipeline gathering facilities in the Appalachian region and currently provides gathering services primarily to Seneca.
The Utility segment operations are regulated by the NYPSC and the PaPUC and are carried out by Distribution Corporation. Distribution Corporation sells natural gas to retail customers and provides natural gas transportation services in western New York and northwestern Pennsylvania.
The Energy Marketing segment is comprised of NFR’s operations. NFR markets natural gas to industrial, wholesale, commercial, public authority and residential customers primarily in western and central New York and northwestern Pennsylvania, offering competitively priced natural gas for its customers.
The data presented in the tables below reflects financial information for the segments and reconciliations to consolidated amounts. The accounting policies of the segments are the same as those described in Note A — Summary of Significant Accounting Policies. Sales of products or services between segments are billed at regulated rates or at market rates, as applicable. The Company evaluates segment performance based on income before discontinued operations extraordinary items and cumulative effects of changes in accounting (when applicable). When these items arethis is not applicable, the Company evaluates performance based on net income.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended September 30, 2017 |
| | Exploration and Production | | Pipeline and Storage | | Gathering | | Utility | | Energy Marketing | | Total Reportable Segments | | All Other | | Corporate and Intersegment Eliminations | | Total Consolidated |
| | (Thousands) |
| Revenue from External Customers(1) | $ | 614,599 |
| | $ | 206,615 |
| | $ | 115 |
| | $ | 626,899 |
| | $ | 128,586 |
| | $ | 1,576,814 |
| | $ | 2,173 |
| | $ | 894 |
| | $ | 1,579,881 |
|
| Intersegment Revenues | $ | — |
| | $ | 87,810 |
| | $ | 107,566 |
| | $ | 13,072 |
| | $ | 794 |
| | $ | 209,242 |
| | $ | — |
| | $ | (209,242 | ) | | $ | — |
|
| Interest Income | $ | 707 |
| | $ | 1,467 |
| | $ | 994 |
| | $ | 1,051 |
| | $ | 571 |
| | $ | 4,790 |
| | $ | 213 |
| | $ | (890 | ) | | $ | 4,113 |
|
| Interest Expense | $ | 53,702 |
| | $ | 33,717 |
| | $ | 9,142 |
| | $ | 28,492 |
| | $ | 47 |
| | $ | 125,100 |
| | $ | — |
| | $ | (5,263 | ) | | $ | 119,837 |
|
| Depreciation, Depletion and Amortization | $ | 112,565 |
| | $ | 41,196 |
| | $ | 16,162 |
| | $ | 52,582 |
| | $ | 279 |
| | $ | 222,784 |
| | $ | 661 |
| | $ | 750 |
| | $ | 224,195 |
|
| Income Tax Expense (Benefit) | $ | 66,093 |
| | $ | 40,947 |
| | $ | 29,694 |
| | $ | 24,894 |
| | $ | 891 |
| | $ | 162,519 |
| | $ | (247 | ) | | $ | (1,590 | ) | | $ | 160,682 |
|
| Segment Profit: Net Income (Loss) | $ | 129,326 |
| | $ | 68,446 |
| | $ | 40,377 |
| | $ | 46,935 |
| | $ | 1,509 |
| | $ | 286,593 |
| | $ | (342 | ) | | $ | (2,769 | ) | | $ | 283,482 |
|
| Expenditures for Additions to Long-Lived Assets | $ | 253,057 |
| | $ | 95,336 |
| | $ | 32,645 |
| | $ | 80,867 |
| | $ | 36 |
| | $ | 461,941 |
| | $ | 39 |
| | $ | 137 |
| | $ | 462,117 |
|
| | At September 30, 2017 |
| | (Thousands) |
| Segment Assets | $ | 1,407,152 |
| | $ | 1,929,788 |
| | $ | 580,051 |
| | $ | 2,013,123 |
| | $ | 60,937 |
| | $ | 5,991,051 |
| | $ | 76,861 |
| | $ | 35,408 |
| | $ | 6,103,320 |
|
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended September 30, 2022 |
| | Exploration
and
Production | | Pipeline
and
Storage | | Gathering | | Utility | | Total
Reportable
Segments | | All
Other | | Corporate
and
Intersegment
Eliminations | | Total
Consolidated |
| | (Thousands) |
| Revenue from External Customers(1)(2) | $ | 1,010,464 | | | $ | 265,415 | | | $ | 12,086 | | | $ | 897,916 | | | $ | 2,185,881 | | | $ | — | | | $ | 165 | | | $ | 2,186,046 | |
| Intersegment Revenues | $ | — | | | $ | 111,629 | | | $ | 202,757 | | | $ | 305 | | | $ | 314,691 | | | $ | 6 | | | $ | (314,697) | | | $ | — | |
| Interest Income | $ | 1,929 | | | $ | 2,275 | | | $ | 198 | | | $ | 2,730 | | | $ | 7,132 | | | $ | 3 | | | $ | (1,024) | | | $ | 6,111 | |
| Interest Expense | $ | 53,401 | | | $ | 42,492 | | | $ | 16,488 | | | $ | 24,115 | | | $ | 136,496 | | | $ | 4 | | | $ | (6,143) | | | $ | 130,357 | |
| Depreciation, Depletion and Amortization | $ | 208,148 | | | $ | 67,701 | | | $ | 33,998 | | | $ | 59,760 | | | $ | 369,607 | | | $ | — | | | $ | 183 | | | $ | 369,790 | |
| Income Tax Expense (Benefit) | $ | 43,898 | | | $ | 35,043 | | | $ | 24,949 | | | $ | 17,165 | | | $ | 121,055 | | | $ | 3 | | | $ | (4,429) | | | $ | 116,629 | |
| | | | | | | | | | | | | | | |
| Significant Item: Gain on Sale of Assets | $ | 12,736 | | | $ | — | | | $ | — | | | $ | — | | | $ | 12,736 | | | $ | — | | | $ | — | | | $ | 12,736 | |
| Segment Profit: Net Income (Loss) | $ | 306,064 | | | $ | 102,557 | | | $ | 101,111 | | | $ | 68,948 | | | $ | 578,680 | | | $ | (9) | | | $ | (12,650) | | | $ | 566,021 | |
| Expenditures for Additions to Long-Lived Assets | $ | 565,791 | | | $ | 95,806 | | | $ | 55,546 | | | $ | 111,033 | | | $ | 828,176 | | | $ | — | | | $ | 1,212 | | | $ | 829,388 | |
| | At September 30, 2022 |
| | (Thousands) |
| Segment Assets | $ | 2,507,541 | | | $ | 2,394,697 | | | $ | 878,796 | | | $ | 2,299,473 | | | $ | 8,080,507 | | | $ | 2,036 | | | $ | (186,281) | | | $ | 7,896,262 | |
| | | | Year Ended September 30, 2016 | | Year Ended September 30, 2021 |
| | Exploration and Production | | Pipeline and Storage | | Gathering | | Utility | | Energy Marketing | | Total Reportable Segments | | All Other | | Corporate and Intersegment Elimination | | Total Consolidated | | Exploration
and
Production | | Pipeline
and
Storage | | Gathering | | Utility | | Total
Reportable
Segments | | All
Other | | Corporate
and
Intersegment
Elimination | | Total
Consolidated |
| | (Thousands) | | (Thousands) |
| Revenue from External Customers(1) | $ | 607,113 |
| | $ | 215,674 |
| | $ | 374 |
| | $ | 531,024 |
| | $ | 93,578 |
| | $ | 1,447,763 |
| | $ | 3,753 |
| | $ | 900 |
| | $ | 1,452,416 |
| Revenue from External Customers(1) | $ | 836,697 | | | $ | 234,397 | | | $ | 3,116 | | | $ | 666,920 | | | $ | 1,741,130 | | | $ | 1,173 | | | $ | 356 | | | $ | 1,742,659 | |
| Intersegment Revenues | $ | — |
| | $ | 90,755 |
| | $ | 89,073 |
| | $ | 13,123 |
| | $ | 884 |
| | $ | 193,835 |
| | $ | — |
| | $ | (193,835 | ) | | $ | — |
| Intersegment Revenues | $ | — | | | $ | 109,160 | | | $ | 190,148 | | | $ | 331 | | | $ | 299,639 | | | $ | 49 | | | $ | (299,688) | | | $ | — | |
| Interest Income | $ | 858 |
| | $ | 770 |
| | $ | 297 |
| | $ | 1,737 |
| | $ | 422 |
| | $ | 4,084 |
| | $ | 117 |
| | $ | 34 |
| | $ | 4,235 |
| Interest Income | $ | 211 | | | $ | 1,085 | | | $ | 259 | | | $ | 2,117 | | | $ | 3,672 | | | $ | 230 | | | $ | 486 | | | $ | 4,388 | |
| Interest Expense | $ | 55,434 |
| | $ | 33,327 |
| | $ | 8,872 |
| | $ | 27,582 |
| | $ | 49 |
| | $ | 125,264 |
| | $ | — |
| | $ | (4,220 | ) | | $ | 121,044 |
| Interest Expense | $ | 69,662 | | | $ | 40,976 | | | $ | 17,493 | | | $ | 21,795 | | | $ | 149,926 | | | $ | — | | | $ | (3,569) | | | $ | 146,357 | |
| Depreciation, Depletion and Amortization | $ | 139,963 |
| | $ | 43,273 |
| | $ | 15,282 |
| | $ | 48,618 |
| | $ | 278 |
| | $ | 247,414 |
| | $ | 1,260 |
| | $ | 743 |
| | $ | 249,417 |
| Depreciation, Depletion and Amortization | $ | 182,492 | | | $ | 62,431 | | | $ | 32,350 | | | $ | 57,457 | | | $ | 334,730 | | | $ | 394 | | | $ | 179 | | | $ | 335,303 | |
| Income Tax Expense (Benefit) | $ | (334,029 | ) | | $ | 50,241 |
| | $ | 24,334 |
| | $ | 25,602 |
| | $ | 2,460 |
| | $ | (231,392 | ) | | $ | 561 |
| | $ | (1,718 | ) | | $ | (232,549 | ) | Income Tax Expense (Benefit) | $ | 33,370 | | | $ | 28,812 | | | $ | 28,876 | | | $ | 14,007 | | | $ | 105,065 | | | $ | 11,438 | | | $ | (1,821) | | | $ | 114,682 | |
| Significant Non-Cash Item: Impairment of Oil and Gas Producing Properties | $ | 948,307 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 948,307 |
| | $ | — |
| | $ | — |
| | $ | 948,307 |
| Significant Non-Cash Item: Impairment of Oil and Gas Producing Properties | $ | 76,152 | | | $ | — | | | $ | — | | | $ | — | | | $ | 76,152 | | | $ | — | | | $ | — | | | $ | 76,152 | |
| Significant Item: Gain on Sale of Assets | | Significant Item: Gain on Sale of Assets | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | 51,066 | | | $ | — | | | $ | 51,066 | |
| Segment Profit: Net Income (Loss) | $ | (452,842 | ) | | $ | 76,610 |
| | $ | 30,499 |
| | $ | 50,960 |
| | $ | 4,348 |
| | $ | (290,425 | ) | | $ | 778 |
| | $ | (1,311 | ) | | $ | (290,958 | ) | Segment Profit: Net Income (Loss) | $ | 101,916 | | | $ | 92,542 | | | $ | 80,274 | | | $ | 54,335 | | | $ | 329,067 | | | $ | 37,645 | | | $ | (3,065) | | | $ | 363,647 | |
| Expenditures for Additions to Long-Lived Assets | $ | 256,104 |
| | $ | 114,250 |
| | $ | 54,293 |
| | $ | 98,007 |
| | $ | 34 |
| | $ | 522,688 |
| | $ | 37 |
| | $ | 326 |
| | $ | 523,051 |
| Expenditures for Additions to Long-Lived Assets | $ | 381,408 | | | $ | 252,316 | | | $ | 34,669 | | | $ | 100,845 | | | $ | 769,238 | | | $ | — | | | $ | 673 | | | $ | 769,911 | |
| | At September 30, 2016 | | At September 30, 2021 |
| | (Thousands) | | (Thousands) |
| Segment Assets | $ | 1,323,081 |
| | $ | 1,680,734 |
| | $ | 534,259 |
| | $ | 2,021,514 |
| | $ | 63,392 |
| | $ | 5,622,980 |
| | $ | 77,138 |
| | $ | (63,731 | ) | | $ | 5,636,387 |
| Segment Assets | $ | 2,286,058 | | | $ | 2,296,030 | | | $ | 837,729 | | | $ | 2,148,267 | | | $ | 7,568,084 | | | $ | 4,146 | | | $ | (107,405) | | | $ | 7,464,825 | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended September 30, 2015 |
| | Exploration
and
Production | | Pipeline and Storage | | Gathering | | Utility | | Energy Marketing | | Total Reportable Segments | | All Other | | Corporate and Intersegment Eliminations | | Total Consolidated |
| | (Thousands) |
| Revenue from External Customers(1) | $ | 693,441 |
| | $ | 203,089 |
| | $ | 497 |
| | $ | 700,761 |
| | $ | 159,857 |
| | $ | 1,757,645 |
| | $ | 2,352 |
| | $ | 916 |
| | $ | 1,760,913 |
|
| Intersegment Revenues | $ | — |
| | $ | 88,251 |
| | $ | 76,709 |
| | $ | 15,506 |
| | $ | 849 |
| | $ | 181,315 |
| | $ | — |
| | $ | (181,315 | ) | | $ | — |
|
| Interest Income | $ | 2,554 |
| | $ | 474 |
| | $ | 140 |
| | $ | 2,220 |
| | $ | 195 |
| | $ | 5,583 |
| | $ | 66 |
| | $ | (1,727 | ) | | $ | 3,922 |
|
| Interest Expense | $ | 46,726 |
| | $ | 27,658 |
| | $ | 1,627 |
| | $ | 28,176 |
| | $ | 27 |
| | $ | 104,214 |
| | $ | — |
| | $ | (4,743 | ) | | $ | 99,471 |
|
| Depreciation, Depletion and Amortization | $ | 239,818 |
| | $ | 38,178 |
| | $ | 10,829 |
| | $ | 45,616 |
| | $ | 209 |
| | $ | 334,650 |
| | $ | 832 |
| | $ | 676 |
| | $ | 336,158 |
|
| Income Tax Expense (Benefit) | $ | (428,217 | ) | | $ | 48,113 |
| | $ | 24,721 |
| | $ | 33,143 |
| | $ | 4,547 |
| | $ | (317,693 | ) | | $ | 13 |
| | $ | (1,456 | ) | | $ | (319,136 | ) |
| Significant Non-Cash Item: Impairment of Oil and Gas Producing Properties | $ | 1,126,257 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 1,126,257 |
| | $ | — |
| | $ | — |
| | $ | 1,126,257 |
|
| Segment Profit: Net Income (Loss) | $ | (556,974 | ) | | $ | 80,354 |
| | $ | 31,849 |
| | $ | 63,271 |
| | $ | 7,766 |
| | $ | (373,734 | ) | | $ | (2 | ) | | $ | (5,691 | ) | | $ | (379,427 | ) |
| Expenditures for Additions to Long-Lived Assets | $ | 557,313 |
| | $ | 230,192 |
| | $ | 118,166 |
| | $ | 94,371 |
| | $ | 128 |
| | $ | 1,000,170 |
| | $ | — |
| | $ | 339 |
| | $ | 1,000,509 |
|
| | At September 30, 2015 |
| | (Thousands) |
| Segment Assets | $ | 2,439,801 |
| | $ | 1,590,524 |
| | $ | 444,358 |
| | $ | 1,934,731 |
| | $ | 90,676 |
| | $ | 6,500,090 |
| | $ | 77,350 |
| | $ | (12,501 | ) | | $ | 6,564,939 |
|
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended September 30, 2020 |
| | Exploration
and
Production | | Pipeline
and
Storage | | Gathering | | Utility | | Total
Reportable
Segments | | All
Other | | Corporate
and
Intersegment
Eliminations | | Total
Consolidated |
| | (Thousands) |
| Revenue from External Customers(1) | $ | 607,453 | | | $ | 205,998 | | | $ | 72 | | | $ | 642,855 | | | $ | 1,456,378 | | | $ | 89,435 | | | $ | 478 | | | $ | 1,546,291 | |
| Intersegment Revenues | $ | — | | | $ | 103,606 | | | $ | 142,821 | | | $ | 9,443 | | | $ | 255,870 | | | $ | 836 | | | $ | (256,706) | | | $ | — | |
| Interest Income | $ | 698 | | | $ | 1,475 | | | $ | 545 | | | $ | 2,262 | | | $ | 4,980 | | | $ | 860 | | | $ | (833) | | | $ | 5,007 | |
| Interest Expense | $ | 58,098 | | | $ | 32,731 | | | $ | 10,877 | | | $ | 22,150 | | | $ | 123,856 | | | $ | 66 | | | $ | (6,845) | | | $ | 117,077 | |
| Depreciation, Depletion and Amortization | $ | 172,124 | | | $ | 53,951 | | | $ | 22,440 | | | $ | 55,248 | | | $ | 303,763 | | | $ | 1,716 | | | $ | 679 | | | $ | 306,158 | |
| Income Tax Expense (Benefit) | $ | (41,472) | | | $ | 28,613 | | | $ | 18,191 | | | $ | 13,274 | | | $ | 18,606 | | | $ | 210 | | | $ | (77) | | | $ | 18,739 | |
| Significant Non-Cash Item: Impairment of Oil and Gas Producing Properties | $ | 449,438 | | | $ | — | | | $ | — | | | $ | — | | | $ | 449,438 | | | $ | — | | | $ | — | | | $ | 449,438 | |
| Segment Profit: Net Income (Loss) | $ | (326,904) | | | $ | 78,860 | | | $ | 68,631 | | | $ | 57,366 | | | $ | (122,047) | | | $ | (269) | | | $ | (1,456) | | | $ | (123,772) | |
| Expenditures for Additions to Long-Lived Assets | $ | 670,455 | | | $ | 166,652 | | | $ | 297,806 | | | $ | 94,273 | | | $ | 1,229,186 | | | $ | 39 | | | $ | (608) | | | $ | 1,228,617 | |
| | At September 30, 2020 |
| | (Thousands) |
| Segment Assets | $ | 1,979,028 | | | $ | 2,204,971 | | | $ | 945,199 | | | $ | 2,067,852 | | | $ | 7,197,050 | | | $ | 113,571 | | | $ | (345,686) | | | $ | 6,964,935 | |
| |
(1) | All Revenue from External Customers originated in the United States. |
(1)All Revenue from External Customers originated in the United States. |
| | | | | | | | | | | |
| Geographic Information | At September 30 |
| | 2017 | | 2016 | | 2015 |
| | (Thousands) |
| Long-Lived Assets: | | | | | |
| United States | $ | 5,285,040 |
| | $ | 5,223,356 |
| | $ | 6,189,138 |
|
Note K — Quarterly Financial Data (unaudited)
In the opinion of management, the following quarterly information includes all adjustments necessary for a fair statement(2)Revenues from three customers of the resultsCompany's Exploration and Production segment, exclusive of operations for such periods. Per common share amounts are calculated usinghedging losses transacted with separate parties, represented approximately $850 million of the weighted average number of shares outstanding during each quarter. The total of all quarters may differ from the per common share amounts shown on the Consolidated Statements of Income. Those per common share amounts are based on the weighted average number of shares outstandingCompany's consolidated revenue for the entire fiscal year. Because of the seasonal nature of the Company’s heating business, there are substantial variations in operations reported on a quarterly basis.
|
| | | | | | | | | | | | | | | | | | | | |
| | Quarter Ended | Operating Revenues | | Operating Income (Loss) | | Net Income (Loss) Available for Common Stock | | Earnings (Loss) per Common Share |
| |
| | Basic | | Diluted |
| | | (Thousands, except per common share amounts) |
| | 2017 | | | | | | | | | |
| | 9/30/2017 | $ | 286,937 |
| | $ | 87,395 |
| | $ | 45,577 |
| | $ | 0.53 |
| | $ | 0.53 |
|
| | 6/30/2017 | $ | 348,369 |
| | $ | 123,354 |
| | $ | 59,714 |
| | $ | 0.70 |
| | $ | 0.69 |
|
| | 3/31/2017 | $ | 522,075 |
| | $ | 169,957 |
| | $ | 89,283 |
| | $ | 1.05 |
| | $ | 1.04 |
|
| | 12/31/2016 | $ | 422,500 |
| | $ | 172,139 |
| | $ | 88,908 |
| | $ | 1.04 |
| | $ | 1.04 |
|
| | 2016 | | | | | | | | | |
| | 9/30/2016 | $ | 292,472 |
| | $ | 81,244 |
| | $ | 37,553 |
| (1) | $ | 0.44 |
| | $ | 0.44 |
|
| | 6/30/2016 | $ | 335,617 |
| | $ | 45,162 |
| | $ | 8,286 |
| (2) | $ | 0.10 |
| | $ | 0.10 |
|
| | 3/31/2016 | $ | 449,132 |
| | $ | (237,000 | ) | | $ | (147,688 | ) | (3) | $ | (1.74 | ) | | $ | (1.74 | ) |
| | 12/31/2015 | $ | 375,195 |
| | $ | (305,924 | ) | | $ | (189,109 | ) | (4) | $ | (2.23 | ) | | $ | (2.23 | ) |
| |
(1) | Includes a non-cash $32.7 million impairment charge ($19.0 million after tax) associated with the Exploration and Production segment's oil and gas producing properties. |
| |
(2) | Includes a non-cash $82.7 million impairment charge ($47.9 million after tax) associated with the Exploration and Production segment's oil and gas producing properties. |
| |
(3) | Includes a non-cash $397.4 million impairment charge ($230.5 million after tax) associated with the Exploration and Production segment's oil and gas producing properties. |
| |
(4) | Includes a non-cash $435.5 million impairment charge ($252.6 million after tax) associated with the Exploration and Production segment's oil and gas producing properties. |
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note L — Market for Common Stock and Related Shareholder Matters (unaudited)
At September 30, 2017, there were 11,211 registered shareholders of Company common stock. The common stock is listed and traded on the New York Stock Exchange. Information related to restrictions on the payment of dividends can be found in Note E — Capitalization and Short-Term Borrowings. The quarterly price ranges (based on intra-day prices) and quarterly dividends declared for the fiscal yearsyear ended September 30, 20172022. These three customers were also customers of the Company's Pipeline and 2016, are shown below:Storage segment, accounting for an additional $15 million of the Company's consolidated revenue for the year ended September 30, 2022.
| | | | | | | | | | | | | | | | | |
| Geographic Information | At September 30 |
| | 2022 | | 2021 | | 2020 |
| | (Thousands) |
| Long-Lived Assets: | | | | | |
| United States | $ | 7,135,131 | | | $ | 6,942,376 | | | $ | 6,597,313 | |
|
| | | | | | | | | | | |
| | Price Range | | Dividends Declared |
| Quarter Ended | High | | Low | |
| 2017 | | | | | |
| 9/30/2017 | $ | 59.92 |
| | $ | 54.89 |
| | $ | 0.415 |
|
| 6/30/2017 | $ | 61.20 |
| | $ | 53.03 |
| | $ | 0.415 |
|
| 3/31/2017 | $ | 61.25 |
| | $ | 54.67 |
| | $ | 0.405 |
|
| 12/31/2016 | $ | 58.78 |
| | $ | 50.61 |
| | $ | 0.405 |
|
| 2016 | | | | | |
| 9/30/2016 | $ | 59.62 |
| | $ | 53.81 |
| | $ | 0.405 |
|
| 6/30/2016 | $ | 57.06 |
| | $ | 47.49 |
| | $ | 0.405 |
|
| 3/31/2016 | $ | 51.53 |
| | $ | 39.79 |
| | $ | 0.395 |
|
| 12/31/2015 | $ | 56.64 |
| | $ | 37.03 |
| | $ | 0.395 |
|
Note MN — Supplementary Information for Oil and Gas Producing Activities (unaudited, except for Capitalized Costs Relating to Oil and Gas Producing Activities)
The Company follows authoritative guidance related to oil and gas exploration and production activities that aligns the reserve estimation and disclosure requirements with the requirements of the SEC Modernization of Oil and Gas Reporting rule, which the Company also follows. The SEC rules require companies to value their year-end reserves using 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 following supplementary information is presented in accordance with the authoritative guidance regarding disclosures about oil and gas producing activities and related SEC accounting rules.authoritative guidance. All monetary amounts are expressed in U.S. dollars.
Capitalized Costs Relating to Oil As discussed in Note B — Asset Acquisitions and Gas Producing ActivitiesDivestitures, the Company completed the sale of its California assets on June 30, 2022. With the completion of this sale, the Company no longer has any oil or gas reserves in the West Coast region of the U.S.
|
| | | | | | | |
| | At September 30 |
| | 2017 | | 2016 |
| | (Thousands) |
| Proved Properties(1) | $ | 4,832,301 |
| | $ | 4,554,929 |
|
| Unproved Properties | 80,932 |
| | 135,285 |
|
| | 4,913,233 |
| | 4,690,214 |
|
| Less — Accumulated Depreciation, Depletion and Amortization | 3,765,710 |
| | 3,657,239 |
|
| | $ | 1,147,523 |
| | $ | 1,032,975 |
|
| |
(1) | Includes asset retirement costs of $54.4 million and $63.6 million at September 30, 2017 and 2016, respectively. |
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Capitalized Costs Relating to Oil and Gas Producing Activities
| | | | | | | | | | | |
| | At September 30 |
| | 2022 | | 2021 |
| | (Thousands) |
| Proved Properties(1) | $ | 5,915,807 | | | $ | 6,652,341 | |
| Unproved Properties | 65,994 | | | 103,759 | |
| 5,981,801 | | | 6,756,100 | |
| Less — Accumulated Depreciation, Depletion and Amortization | 4,034,266 | | | 4,881,972 | |
| $ | 1,947,535 | | | $ | 1,874,128 | |
(1)Includes asset retirement costs of $120.8 million and $152.8 million at September 30, 2022 and 2021, respectively.
Costs related to unproved properties are excluded from amortization until proved reserves are found or it is determined that the unproved properties are impaired. All costs related to unproved properties are reviewed quarterly to determine if impairment has occurred. The amount of any impairment is transferred to the pool of capitalized costs being amortized. Although the timing of the ultimate evaluation or disposition of the unproved properties cannot be determined, the Company expects the majority of its acquisition costs associated with unproved properties to be transferred into the amortization base by 2023.2027. It expects the majority of its development and exploration costs associated with unproved properties to be transferred into the amortization base by 2018.2025. Following is a summary of costs excluded from amortization at September 30, 2017:2022:
| | | | Total as of September 30, 2017 | | Year Costs Incurred | | Total as of September 30, 2022 | | Year Costs Incurred |
| | | 2017 | | 2016 | | 2015 | | Prior | | 2022 | | 2021 | | 2020 | | Prior |
| | (Thousands) | | (Thousands) |
| Acquisition Costs | $ | 55,193 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 55,193 |
| Acquisition Costs | $ | 41,831 | | | $ | — | | | $ | — | | | $ | 29,698 | | | $ | 12,133 | |
| Development Costs | 11,879 |
| | 4,388 |
| | 6,707 |
| | 416 |
| | 368 |
| Development Costs | 24,163 | | | 17,590 | | | 4,085 | | | 2,488 | | | — | |
| Exploration Costs | 13,388 |
| | 2,376 |
| | 7,593 |
| | 3,419 |
| | — |
| Exploration Costs | — | | | — | | | — | | | — | | | — | |
| Capitalized Interest | 472 |
| | 235 |
| | 149 |
| | 88 |
| | — |
| Capitalized Interest | — | | | — | | | — | | | — | | | — | |
| | $ | 80,932 |
| | $ | 6,999 |
| | $ | 14,449 |
| | $ | 3,923 |
| | $ | 55,561 |
| | $ | 65,994 | | | $ | 17,590 | | | $ | 4,085 | | | $ | 32,186 | | | $ | 12,133 | |
Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities
| | | | Year Ended September 30 | | Year Ended September 30 |
| | 2017 | | 2016 | | 2015 | | 2022 | | 2021 | | 2020 |
| | (Thousands) | | (Thousands) |
| United States | | United States | |
| Property Acquisition Costs: | | | | | | Property Acquisition Costs: | |
| Proved | $ | 8,908 |
| | $ | 1,342 |
| | $ | 1,767 |
| Proved | $ | 2,491 | | | $ | 1,801 | | | $ | 245,976 | |
| Unproved | 262 |
| | 2,165 |
| | 19,998 |
| Unproved | 10,665 | | | 5,102 | | | 42,922 | |
| Exploration Costs(1) | 40,975 |
| | 27,561 |
| | 53,222 |
| Exploration Costs(1) | 9,631 | | | 15,413 | | | 3,891 | |
| Development Costs(2) | 200,639 |
| | 219,386 |
| | 454,605 |
| Development Costs(2) | 528,684 | | | 329,368 | | | 355,742 | |
| Asset Retirement Costs | (9,175 | ) | | (49,653 | ) | | 37,595 |
| Asset Retirement Costs | 9,768 | | | 20,194 | | | 62,080 | |
| | $ | 241,609 |
| | $ | 200,801 |
| | $ | 567,187 |
| | $ | 561,239 | | | $ | 371,878 | | | $ | 710,611 | |
| |
(1) | Amounts for 2017, 2016 and 2015 include capitalized interest of $0.3 million, $0.3 million and $0.4 million, respectively. |
| |
(2) | Amounts for 2017, 2016 and 2015 include capitalized interest of $0.2 million, $0.2 million and $0.5 million, respectively. |
For the years ended September 30, 2017, 2016 and 2015, the Company spent $101.1 million, $92.8 million and $161.8 million, respectively, developing proved undeveloped reserves.
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(1)Amounts for 2022, 2021 and 2020 include capitalized interest of zero, $0.1 million and zero respectively.
(2)Amounts for 2022, 2021 and 2020 include capitalized interest of $0.6 million, $0.4 million and $1.0 million, respectively.
For the years ended September 30, 2022, 2021 and 2020, the Company spent $154.3 million, $81.2 million and $219.9 million, respectively, developing proved undeveloped reserves.
Results of Operations for Producing Activities
|
| | | | | | | | | | | |
| | Year Ended September 30 |
| | 2017 | | 2016 | | 2015 |
| United States | (Thousands, except per Mcfe amounts) |
| Operating Revenues: | | | | | |
| Natural Gas (includes transfers to operations of $2,357, $1,765 and $1,946, respectively)(1) | $ | 399,975 |
| | $ | 282,619 |
| | $ | 350,673 |
|
| Oil, Condensate and Other Liquids | 126,517 |
| | 103,533 |
| | 156,048 |
|
| Total Operating Revenues(2) | 526,492 |
| | 386,152 |
| | 506,721 |
|
| Production/Lifting Costs | 165,991 |
| | 153,914 |
| | 167,800 |
|
| Franchise/Ad Valorem Taxes | 15,372 |
| | 13,794 |
| | 20,167 |
|
| Purchased Emission Allowance Expense | 1,391 |
| | 700 |
| | 3,089 |
|
| Accretion Expense | 4,896 |
| | 6,663 |
| | 6,186 |
|
| Depreciation, Depletion and Amortization ($0.63, $0.85 and $1.49 per Mcfe of production, respectively) | 108,471 |
| | 136,579 |
| | 234,480 |
|
| Impairment of Oil and Gas Producing Properties | — |
| | 948,307 |
| | 1,126,257 |
|
| Income Tax Expense (Benefit) | 86,657 |
| | (368,940 | ) | | (444,393 | ) |
| Results of Operations for Producing Activities (excluding corporate overheads and interest charges) | $ | 143,714 |
| | $ | (504,865 | ) | | $ | (606,865 | ) |
| | | | | | | | | | | | | | | | | |
| | Year Ended September 30 |
| | 2022 | | 2021 | | 2020 |
| United States | (Thousands, except per Mcfe amounts) |
| Operating Revenues: | | | | | |
| Gas (includes transfers to operations of $5,696, $3,061 and $1,921, respectively)(1) | $ | 1,730,723 | | | $ | 780,477 | | | $ | 402,447 | |
| Oil, Condensate and Other Liquids | 150,957 | | | 135,191 | | | 107,844 | |
| Total Operating Revenues(2) | 1,881,680 | | | 915,668 | | | 510,291 | |
| Production/Lifting Costs | 283,914 | | | 267,316 | | | 203,670 | |
| Franchise/Ad Valorem Taxes | 25,112 | | | 22,128 | | | 15,582 | |
| Purchased Emission Allowance Expense | 1,305 | | | 2,940 | | | 2,930 | |
| Accretion Expense | 7,530 | | | 7,743 | | | 5,237 | |
| Depreciation, Depletion and Amortization ($0.57, $0.54 and $0.69 per Mcfe of production, respectively) | 202,418 | | | 177,055 | | | 166,759 | |
| Impairment of Oil and Gas Producing Properties | — | | | 76,152 | | | 449,438 | |
| Income Tax Expense | 368,925 | | | 98,593 | | | (92,820) | |
| Results of Operations for Producing Activities (excluding corporate overheads and interest charges) | $ | 992,476 | | | $ | 263,741 | | | $ | (240,505) | |
| |
(1) | There were no revenues from sales to affiliates for all years presented. |
| |
(2) | Exclusive of hedging gains and losses. See further discussion in Note G — Financial Instruments. |
(1)There were no revenues from sales to affiliates for all years presented.
(2)Exclusive of hedging gains and losses. See further discussion in Note J — Financial Instruments.
Reserve Quantity Information
The Company's proved oil and gas reserve estimates are prepared by the Company's reservoirpetroleum engineers who meet the qualifications of Reserve Estimator per the "Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserve Information" promulgated by the Society of Petroleum Engineers as of February 19, 2007. The Company maintains comprehensive internal reserve guidelines and a continuing education program designed to keep its staff up to date with current SEC regulations and guidance.
The Company's Vice PresidentSenior Manager of Reservoir Engineering is the primary technical person responsible for overseeing the Company's reserve estimation process and engaging and overseeing the third party reserve audit. His qualifications include a Bachelor of Science Degree in Petroleum Engineering and over 3013 years of Petroleum Engineering experience with both major and independent oil and gas companies. He has maintained oversight of the Company's reserve estimation process since 2003. Hecompanies, licensure as a Professional Engineer and is a member of the Society of Petroleum Evaluation Engineers and a Registered Professional Engineer in the State of Texas.Engineers.
The Company maintains a system of internal controls over the reserve estimation process. Management reviews the price, heat content, lease operating cost and future investment assumptions used in the economic model to determine the reserves. The Vice PresidentSenior Manager of Reservoir Engineering reviews and approves all new reserve assignments and significant reserve revisions. Access to the Reservereserve database is restricted. Significant changes to the reserve report are reviewed by senior management on a quarterly basis. Periodically, the
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Company's internal audit department assesses the design of these controls and performs testing to determine the effectiveness of such controls.
All of the Company's reserve estimates are audited annually by Netherland, Sewell and& Associates, Inc. (NSAI). Since 1961, NSAI has evaluated gas and oil properties and independently certified petroleum reserve quantities in the United States and internationally under the Texas Board of Professional Engineers Registration No. F-002699. The primary technical persons (employed by NSAI) that are responsible for leading the audit include
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
a professional engineer registered with the State of Texas (consulting at NSAI since 20042011 and with over 54 years of prior industry experience in petroleum engineering) and a professional geoscientist registered in the State of Texas (consulting at NSAI since 2008 and with over 11 years of prior industry experience in petroleum geosciences). NSAI was satisfied with the methods and procedures used by the Company to prepare its reserve estimates at September 30, 20172022 and did not identify any problems which would cause it to take exception to those estimates.
The reliable technologies that were utilized in estimating the reserves include wire line open-hole log data, performance data, log cross sections, core data, 2D and 3D seismic data and statistical analysis. The statistical method utilized production performance from both the Company's and competitors’ wells. Geophysical data includes data from the Company's wells, third-party wells, published documents and state data-sites, and 2D and 3D seismic data. These were used to confirm continuity of the formation.
|
| | | | | | | | |
| | Gas MMcf |
| | U. S. | | |
| | Appalachian Region | | West Coast Region | | Total Company |
| Proved Developed and Undeveloped Reserves: | | | | | |
| September 30, 2014 | 1,624,062 |
| | 58,822 |
| | 1,682,884 |
|
| Extensions and Discoveries | 633,360 |
| (1) | — |
| | 633,360 |
|
| Revisions of Previous Estimates | (28,124 | ) | | (6,317 | ) | | (34,441 | ) |
| Production | (136,404 | ) | (2) | (3,159 | ) | | (139,563 | ) |
| Sale of Minerals in Place | (112 | ) | | — |
| | (112 | ) |
| September 30, 2015 | 2,092,782 |
| | 49,346 |
| | 2,142,128 |
|
| Extensions and Discoveries | 185,347 |
| (1) | — |
| | 185,347 |
|
| Revisions of Previous Estimates | (245,029 | ) | | (3,132 | ) | | (248,161 | ) |
| Production | (140,457 | ) | (2) | (3,090 | ) | | (143,547 | ) |
| Sale of Minerals in Place | (261,192 | ) | | — |
| | (261,192 | ) |
| September 30, 2016 | 1,631,451 |
| | 43,124 |
| | 1,674,575 |
|
| Extensions and Discoveries | 386,649 |
| (1) | 8 |
| | 386,657 |
|
| Revisions of Previous Estimates | 84,480 |
| | 6,369 |
| | 90,849 |
|
| Production | (154,093 | ) | (2) | (2,995 | ) | | (157,088 | ) |
| Sale of Minerals in Place | (21,873 | ) | | — |
| | (21,873 | ) |
| September 30, 2017 | 1,926,614 |
| | 46,506 |
| | 1,973,120 |
|
| Proved Developed Reserves: | | | | |
|
|
| September 30, 2014 | 1,119,901 |
| | 57,907 |
| | 1,177,808 |
|
| September 30, 2015 | 1,267,498 |
| | 49,346 |
| | 1,316,844 |
|
| September 30, 2016 | 1,089,492 |
| | 43,124 |
| | 1,132,616 |
|
| September 30, 2017 | 1,316,596 |
| | 46,506 |
| | 1,363,102 |
|
| Proved Undeveloped Reserves: | | | | |
|
|
| September 30, 2014 | 504,161 |
| | 915 |
| | 505,076 |
|
| September 30, 2015 | 825,284 |
| | — |
| | 825,284 |
|
| September 30, 2016 | 541,959 |
| | — |
| | 541,959 |
|
| September 30, 2017 | 610,018 |
| | — |
| | 610,018 |
|
| |
(1) | Extensions and discoveries include 598 Bcf (during 2015), 179 Bcf (during 2016) and 181 Bcf (during 2017), of Marcellus Shale gas in the Appalachian region. |
| |
(2) | Production includes 130,291 MMcf (during 2015), 135,598 MMcf (during 2016) and 145,452 MMcf (during 2017), from Marcellus Shale fields (which exceed 15% of total reserves). |
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
| | | | | | | | | | | | | | | | | |
| | Gas MMcf |
| | U.S. | | |
| | Appalachian
Region | | West Coast
Region | | Total
Company |
| Proved Developed and Undeveloped Reserves: | | | | | |
| September 30, 2019 | 2,915,886 | | | 33,633 | | | 2,949,519 | |
| Extensions and Discoveries | 7,246 | | (1) | — | | | 7,246 | |
| Revisions of Previous Estimates | (85,647) | | | (2,772) | | | (88,419) | |
| Production | (225,513) | | (2) | (1,889) | | | (227,402) | |
| Purchases of Minerals in Place | 684,141 | | | — | | | 684,141 | |
| | | | | |
| September 30, 2020 | 3,296,113 | | | 28,972 | | | 3,325,085 | |
| Extensions and Discoveries | 689,395 | | (1) | — | | | 689,395 | |
| Revisions of Previous Estimates | 19,940 | | | 3,033 | | | 22,973 | |
| Production | (312,300) | | (2) | (1,720) | | | (314,020) | |
| | | | | |
| | | | | |
| September 30, 2021 | 3,693,148 | | | 30,285 | | | 3,723,433 | |
| Extensions and Discoveries | 837,510 | | (1) | — | | | 837,510 | |
| Revisions of Previous Estimates | 2,882 | | | 71 | | | 2,953 | |
| Production | (341,700) | | (2) | (1,211) | | | (342,911) | |
| | | | | |
| Sale of Minerals in Place | (21,178) | | | (29,145) | | | (50,323) | |
| September 30, 2022 | 4,170,662 | | | — | | | 4,170,662 | |
| Proved Developed Reserves: | | | | | |
| September 30, 2019 | 1,901,162 | | | 33,633 | | | 1,934,795 | |
| September 30, 2020 | 2,744,851 | | | 28,972 | | | 2,773,823 | |
| September 30, 2021 | 3,061,178 | | | 30,285 | | | 3,091,463 | |
| September 30, 2022 | 3,312,568 | | | — | | | 3,312,568 | |
| Proved Undeveloped Reserves: | | | | | |
| September 30, 2019 | 1,014,724 | | | — | | | 1,014,724 | |
| September 30, 2020 | 551,262 | | | — | | | 551,262 | |
| September 30, 2021 | 631,970 | | | — | | | 631,970 | |
| September 30, 2022 | 858,094 | | | — | | | 858,094 | |
|
| | | | | | | | |
| | Oil Mbbl |
| | U. S. | | |
| | Appalachian Region | | West Coast Region | | Total Company |
| Proved Developed and Undeveloped Reserves: | | | | | |
| September 30, 2014 | 253 |
| | 38,224 |
| | 38,477 |
|
| Extensions and Discoveries | — |
| | 533 |
| | 533 |
|
| Revisions of Previous Estimates | (3 | ) | | (2,251 | ) | | (2,254 | ) |
| Production | (30 | ) | | (3,004 | ) | | (3,034 | ) |
| September 30, 2015 | 220 |
| | 33,502 |
| | 33,722 |
|
| Extensions and Discoveries | — |
| | 530 |
| | 530 |
|
| Revisions of Previous Estimates | (46 | ) | | (2,201 | ) | | (2,247 | ) |
| Production | (28 | ) | | (2,895 | ) | | (2,923 | ) |
| Sales of Minerals in Place | (73 | ) | | — |
| | (73 | ) |
| September 30, 2016 | 73 |
| | 28,936 |
| | 29,009 |
|
| Extensions and Discoveries | — |
| | 674 |
| | 674 |
|
| Revisions of Previous Estimates | (12 | ) | | 3,305 |
| | 3,293 |
|
| Production | (4 | ) | | (2,736 | ) | | (2,740 | ) |
| Sales of Minerals in Place | (29 | ) | | — |
| | (29 | ) |
| September 30, 2017 | 28 |
| | 30,179 |
| | 30,207 |
|
| Proved Developed Reserves: | | | | |
|
| September 30, 2014 | 253 |
| | 37,002 |
| | 37,255 |
|
| September 30, 2015 | 220 |
| | 33,150 |
| | 33,370 |
|
| September 30, 2016 | 73 |
| | 28,698 |
| | 28,771 |
|
| September 30, 2017 | 28 |
| | 29,771 |
| | 29,799 |
|
| Proved Undeveloped Reserves: | | | | |
|
|
| September 30, 2014 | — |
| | 1,222 |
| | 1,222 |
|
| September 30, 2015 | — |
| | 352 |
| | 352 |
|
| September 30, 2016 | — |
| | 238 |
| | 238 |
|
| September 30, 2017 | — |
| | 408 |
| | 408 |
|
The Company’s proved undeveloped (PUD) reserves increased from 543 Bcfe at September 30, 2016 to 612 Bcfe at September 30, 2017. PUD reserves(1)Extensions and discoveries include 7 Bcf (during 2020), 180 Bcf (during 2021) and 301 Bcf (during 2022), of Marcellus Shale gas (which exceed 15% of total reserves) in the Appalachian region. Extensions and discoveries include 0 Bcf (during 2020), 497 Bcf (during 2021) and 537 Bcf (during 2022), of Utica Shale gas (which exceed 15% of total reserves) in the Appalachian region.
(2)Production includes 169,453 MMcf (during 2020), 218,016 MMcf (during 2021) and 209,463 MMcf (during 2022), from Marcellus Shale decreasedfields. Production includes 55,392 MMcf (during 2020), 93,253 MMcf (during 2021) and 130,240 MMcf (during 2022), from 542 Bcfe at September 30, 2016 to 456 Bcfe at September 30, 2017. The Company’s total PUD reserves were 28% of total proved reserves at September 30, 2017, down from 29% of total proved reserves at September 30, 2016.
The Company’s PUD reserves decreased from 827 Bcfe at September 30, 2015 to 543 Bcfe at September 30, 2016. PUD reserves in the Marcellus Shale decreased from 825 Bcfe at September 30, 2015 to 542 Bcfe at September 30, 2016. The Company’s total PUD reserves were 29% of total proved reserves at September 30, 2016, down from 35% of total proved reserves at September 30, 2015.
The increase in PUD reserves in 2017 of 69 Bcfe is a result of 269 Bcfe in new PUD reserve additions (113 Bcfe from the Marcellus Shale, 154 Bcfe from the Utica Shale and 2 Bcfe from the West Coast region) and 13 Bcfe in upward revisions to remaining PUD reserves, partially offset by 159 Bcfe in PUD conversions to developed reserves (158 Bcfe from the Marcellus Shale and 1 Bcfe from the West Coast region) and 54 Bcfe in PUD reserves removed. The PUD reserves removed were all in the Marcellus Shale and were due to a couple of factors. PUD reserves of 36 Bcfe associated with a few wells were removed due to development timing no longer scheduled to meet the five year requirement for proved reserves. Seneca successfully leased an adjacent tract to these wells infields.
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
| | | | | | | | | | | | | | | | | |
| | Oil Mbbl |
| | U.S. | | |
| | Appalachian
Region | | West Coast
Region | | Total
Company |
| Proved Developed and Undeveloped Reserves: | | | | | |
| September 30, 2019 | 13 | | | 24,860 | | | 24,873 | |
| Extensions and Discoveries | — | | | 288 | | | 288 | |
| Revisions of Previous Estimates | 2 | | | (715) | | | (713) | |
| Production | (3) | | | (2,345) | | | (2,348) | |
| | | | | |
| | | | | |
| | | | | |
| September 30, 2020 | 12 | | | 22,088 | | | 22,100 | |
| Extensions and Discoveries | — | | | 1,041 | | | 1,041 | |
| Revisions of Previous Estimates | 1 | | | 630 | | | 631 | |
| Production | (2) | | | (2,233) | | | (2,235) | |
| | | | | |
| | | | | |
| September 30, 2021 | 11 | | | 21,526 | | | 21,537 | |
| Extensions and Discoveries | — | | | 296 | | | 296 | |
| Revisions of Previous Estimates | 255 | | | 532 | | | 787 | |
| Production | (16) | | | (1,588) | | | (1,604) | |
| | | | | |
| Sales of Minerals in Place | — | | | (20,766) | | | (20,766) | |
| September 30, 2022 | 250 | | | — | | | 250 | |
| Proved Developed Reserves: | | | | | |
| September 30, 2019 | 13 | | | 24,246 | | | 24,259 | |
| September 30, 2020 | 12 | | | 22,088 | | | 22,100 | |
| September 30, 2021 | 11 | | | 20,930 | | | 20,941 | |
| September 30, 2022 | 250 | | | — | | | 250 | |
| Proved Undeveloped Reserves: | | | | | |
| September 30, 2019 | — | | | 614 | | | 614 | |
| September 30, 2020 | — | | | — | | | — | |
| September 30, 2021 | — | | | 596 | | | 596 | |
| September 30, 2022 | — | | | — | | | — | |
2017 and intendsThe Company’s proved undeveloped (PUD) reserves increased from 636 Bcfe at September 30, 2021 to develop the wells now with longer laterals drilled into this adjacent tract. This will now take longer than the five year time horizon from original booking.858 Bcfe at September 30, 2022. PUD reserves of 18 Bcfe were removed due to a change in plans this year and its impact on a few wells. As part of Seneca’s transition toward a Utica focused development program in the Western Development Area, certainUtica Shale increased from 411 Bcfe at September 30, 2021 to 503 Bcfe at September 30, 2022. PUD reserves in the Marcellus wells have been replaced with Utica wellsShale increased from 220 Bcfe at September 30, 2021 to 355 Bcfe at September 30, 2022. PUD reserves in our development plan.the West Coast region decreased from 5 Bcfe at September 30, 2021 to zero at September 30, 2022. The Company’s total PUD reserves were 20.6% of total proved reserves at September 30, 2022, up from 16.5% of total proved reserves at September 30, 2021.
The decreaseCompany’s PUD reserves increased from 551 Bcfe at September 30, 2020 to 636 Bcfe at September 30, 2021. PUD reserves in the Utica Shale increased from 265 Bcfe at September 30, 2020 to 411 Bcfe at September 30, 2021. PUD reserves in the Marcellus Shale decreased from 287 Bcfe at September 30, 2020 to 220 Bcfe at September 30, 2021. The Company’s total PUD reserves were 16.5% of total proved reserves at September 30, 2021, roughly flat from 16% of total proved reserves at September 30, 2020.
The increase in PUD reserves in 20162022 of 284222 Bcfe wasis a result of 102502 Bcfe in new PUD reserve additions (102 Bcfe from the Marcellus Shale), offset by sales of 166 Bcfe associated with a joint development agreement (JDA) that Seneca entered into in December 2015, 14and 23 Bcfe in downwardupward revisions to remaining PUD reserves, partially offset by 110287 Bcfe in PUD conversions to developed reserves (55 Bcfe from the Marcellus Shale, 231 Bcfe from the Utica Shale and 961 Bcfe from the West Coast region), and 13 Bcfe in PUD reserves removed.removed for one Utica PUD location due to pad layout changes. The remaining change of 3 Bcf was due to removing West Coast region PUDs included in the beginning of year balances through development and divesture of Seneca's California assets.
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The increase in PUD reserves in 2021 of 85 Bcfe is a result of 344 Bcfe in new PUD reserve additions and 9 Bcfe in upward revisions to remaining PUD reserves, partially offset by 188 Bcfe in PUD conversions to developed reserves (82 Bcfe from the Marcellus Shale and 106 Bcfe from the Utica Shale), and 80 Bcfe in PUD reserves removed for eight PUD locations, half of these due to pad layout changes, and the other half due to schedule changes. Six of these wells removed were primarily in the Marcellus Shale (74(54 Bcfe) and two were due to several factors including schedule changes, lower performance expectations and lower natural gas pricing. Geneseoin the Utica Shale PUD reserves of 23 Bcfe were removed solely due to lower gas pricing as they were uneconomic at trailing twelve month pricing.(26 Bcfe).
The Company invested $101$154 million during the year ended September 30, 20172022 to convert 147287 Bcfe (159(333 Bcfe beforeafter revisions) of predominantly Marcellus and Utica Shale PUD reserves to developed reserves. This represents 27% of the net PUD reserves booked at September 30, 2016. In fiscal 2017, the Company developed 37 (or 41%) of its wells that were recorded at September 30, 2016. The vast majority of these wells were in the Appalachian region.
The Company invested $93 million (includes $36 million of drilling carry costs for a JDA partner that were later reimbursed) during the year ended September 30, 2016 to convert 92 Bcfe (110 Bcfe before revisions) of PUD reserves to developed reserves. This represents 11%45% of the net PUD reserves recorded at September 30, 2015.2021. In 2016, the majorityAppalachian region, 31 of Seneca's planned65 PUD locations were developed while the West Coast region developed 6 of 17 PUD locations prior to the divesture. PUD expenditures in 2022 were lower than the 2021 estimate primarily due to changes in the development schedule.
The Company invested $81 million during the year ended September 30, 2021 to convert 188 Bcfe (198 Bcfe after revisions) of predominantly Marcellus and Utica Shale PUD reserves development was funded by a JDA partner, which reduced Seneca's working interest, as discussed in Note A — Summaryto developed reserves. This represents 34% of Significant Accounting Policies under the heading “Property, Plant and Equipment.” In fiscal 2016, the Company developed 31 (or 28%) of its gross Marcellus Shale wells that were recorded at September 30, 2015. The majority of these wells were included in the JDA. Including the impact of JDA sales, the Company developed 207 Bcfe (or 25%) of its net PUD reserves recorded at September 30, 2015.2020. In addition, as stated above, the sales associated withAppalachian region, 18 of 53 PUD locations were developed. PUD expenditures in 2021 were lower than the JDA further decreased PUD reserves.
As part of Seneca’s JDA2020 estimate primarily due to changes in the Marcellus Shale, Seneca anticipates it will sell approximately 60 Bcfe of its working interest PUD reserves in 2018 to its JDA partner as it develops the last group of wells included in the JDA.development schedule.
In 2018,2023, the Company estimates that it will invest approximately $186$308 million to develop its PUD reserves. The Company is committed to developing its PUD reserves within five years as required by the SEC’s final rule on Modernization of Oil and Gas Reporting. Since that rule was adopted, and over the last five years, the Company developed 51% of its beginning year PUD reserves in fiscal 2018, 39% of its beginning year PUD reserves in fiscal 2013, 51%2019, 36% of its beginning year PUD reserves in fiscal 2014, 33%2020, 34% of its beginning year PUD reserves in fiscal 2015, 25%2021 and 45% of its beginning year PUD reserves in fiscal 2016 and 27% of its beginning year PUD reserves in fiscal 2017.2022.
At September 30, 2017,2022, the Company does not have a material concentration ofany proved undeveloped reserves that have been on the books for more than five years at the corporate level, country level or field level. All of the Company’s proved reserves are in the United States.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
The Company cautions that the following presentation of the standardized measure of discounted future net cash flows is intended to be neither a measure of the fair market value of the Company’s oil and gas properties, nor an estimate of the present value of actual future cash flows to be obtained as a result of their development and production. It is based upon subjective estimates of proved reserves only and attributes no value to categories of reserves other than proved reserves, such as probable or possible reserves, or to unproved acreage. Furthermore, in accordance with the SEC’s final rule on Modernization of Oil and Gas Reporting, it is based on the unweighted
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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 and costs adjusted only for existing contractual changes. It assumes an arbitrary discount rate of 10%. Thus, it gives no effect to future price and cost changes certain to occur under widely fluctuating political and economic conditions.
The standardized measure is intended instead to provide a means for comparing the value of the Company’s proved reserves at a given time with those of other oil- and gas-producing companies than is provided by a simple comparison of raw proved reserve quantities.
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
| | | | Year Ended September 30 | | Year Ended September 30 |
| | 2017 | | 2016 | | 2015 | | 2022 | | 2021 | | 2020 |
| | (Thousands) | | (Thousands) |
| United States | | | | | | United States | |
| Future Cash Inflows | $ | 6,144,317 |
| | $ | 3,768,463 |
| | $ | 6,916,775 |
| Future Cash Inflows | $ | 19,209,099 | | | $ | 10,175,182 | | | $ | 6,493,362 | |
| Less: | | | | | | Less: | |
| Future Production Costs | 2,378,262 |
| | 1,994,916 |
| | 2,854,142 |
| Future Production Costs | 3,138,226 | | | 3,423,629 | | | 3,149,857 | |
| Future Development Costs | 411,578 |
| | 375,152 |
| | 761,922 |
| Future Development Costs | 781,847 | | | 597,662 | | | 501,678 | |
| Future Income Tax Expense at Applicable Statutory Rate | 1,160,469 |
| | 303,397 |
| | 1,117,433 |
| Future Income Tax Expense at Applicable Statutory Rate | 3,876,272 | | | 1,397,175 | | | 454,553 | |
| Future Net Cash Flows | 2,194,008 |
| | 1,094,998 |
| | 2,183,278 |
| Future Net Cash Flows | 11,412,754 | | | 4,756,716 | | | 2,387,274 | |
| Less: | | | | | | Less: | |
| 10% Annual Discount for Estimated Timing of Cash Flows | 1,080,962 |
| | 452,470 |
| | 860,244 |
| 10% Annual Discount for Estimated Timing of Cash Flows | 5,964,424 | | | 2,403,144 | | | 1,164,804 | |
| Standardized Measure of Discounted Future Net Cash Flows | $ | 1,113,046 |
| | $ | 642,528 |
| | $ | 1,323,034 |
| Standardized Measure of Discounted Future Net Cash Flows | $ | 5,448,330 | | | $ | 2,353,572 | | | $ | 1,222,470 | |
The principal sources of change in the standardized measure of discounted future net cash flows were as follows:
| | | | | | | | | | | | | | | | | |
| | Year Ended September 30 |
| | 2022 | | 2021 | | 2020 |
| | (Thousands) |
| United States | | | | | |
| Standardized Measure of Discounted Future | | | | | |
| Net Cash Flows at Beginning of Year | $ | 2,353,572 | | | $ | 1,222,470 | | | $ | 1,736,319 | |
| Sales, Net of Production Costs | (1,572,402) | | | (626,132) | | | (290,975) | |
| Net Changes in Prices, Net of Production Costs | 4,132,889 | | | 1,478,995 | | | (1,109,101) | |
| Extensions and Discoveries | 1,355,257 | | | 462,040 | | | 4,236 | |
| Changes in Estimated Future Development Costs | (32,160) | | | 48,247 | | | 99,884 | |
| Purchases of Minerals in Place | — | | | — | | | 170,363 | |
| Sales of Minerals in Place | (311,308) | | | — | | | — | |
| Previously Estimated Development Costs Incurred | 154,253 | | | 81,239 | | | 219,938 | |
| Net Change in Income Taxes at Applicable Statutory Rate | (1,180,349) | | | (415,993) | | | 248,182 | |
| Revisions of Previous Quantity Estimates | 3,316 | | | (52,383) | | | (28,337) | |
| Accretion of Discount and Other | 545,262 | | | 155,089 | | | 171,961 | |
| Standardized Measure of Discounted Future Net Cash Flows at End of Year | $ | 5,448,330 | | | $ | 2,353,572 | | | $ | 1,222,470 | |
|
| | | | | | | | | | | |
| | Year Ended September 30 |
| | 2017 | | 2016 | | 2015 |
| | (Thousands) |
| United States | | | | | |
| Standardized Measure of Discounted Future | | | | | |
| Net Cash Flows at Beginning of Year | $ | 642,528 |
| | $ | 1,323,034 |
| | $ | 2,066,878 |
|
| Sales, Net of Production Costs | (345,075 | ) | | (218,444 | ) | | (318,753 | ) |
| Net Changes in Prices, Net of Production Costs | 828,187 |
| | (1,066,593 | ) | | (1,752,843 | ) |
| Extensions and Discoveries | 170,500 |
| | 47,742 |
| | 266,159 |
|
| Changes in Estimated Future Development Costs | 8,816 |
| | 143,752 |
| | 164,510 |
|
| Sales of Minerals in Place | (9,849 | ) | | (95,849 | ) | | (1 | ) |
| Previously Estimated Development Costs Incurred | 101,134 |
| | 92,840 |
| | 161,833 |
|
| Net Change in Income Taxes at Applicable Statutory Rate | (393,353 | ) | | 387,739 |
| | 545,442 |
|
| Revisions of Previous Quantity Estimates | 39,078 |
| | 6,202 |
| | (16,573 | ) |
| Accretion of Discount and Other | 71,080 |
| | 22,105 |
| | 206,382 |
|
| Standardized Measure of Discounted Future Net Cash Flows at End of Year | $ | 1,113,046 |
| | $ | 642,528 |
| | $ | 1,323,034 |
|
Schedule II — Valuation and Qualifying Accounts
|
| | | | | | | | | | | | | | | | | | | |
| Description | Balance at Beginning of Period | | Additions Charged to Costs and Expenses | | Additions Charged to Other Accounts(1) | | Deductions (2) | | Balance at End of Period |
| Year Ended September 30, 2017 | | | | | | | | | |
| Allowance for Uncollectible Accounts | $ | 21,109 |
| | $ | 6,301 |
| | $ | 1,774 |
| | $ | 6,658 |
| | $ | 22,526 |
|
| Year Ended September 30, 2016 | | | | | | | | | |
| Allowance for Uncollectible Accounts | $ | 29,029 |
| | $ | 6,819 |
| | $ | 1,521 |
| | $ | 16,260 |
| | $ | 21,109 |
|
| Year Ended September 30, 2015 | | | | | | | | | |
| Allowance for Uncollectible Accounts | $ | 31,811 |
| | $ | 9,316 |
| | $ | 2,585 |
| | $ | 14,683 |
| | $ | 29,029 |
|
| | |
(1) | Represents the discount on accounts receivable purchased in accordance with the Utility segment’s 2005 New York rate agreement. |
| |
(2) | Amounts represent net accounts receivable written-off. |
|
| |
| Item 9 | Changes in and Disagreements with Accountants on Accounting and Financial Disclosure |
None.
|
| | | | |
| Item 9A | Controls and Procedures |
Evaluation of Disclosure Controls and Procedures
The term “disclosure controls and procedures” is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act. These rules refer to the controls and other procedures of a company that are designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed is accumulated and communicated to the company’s management, including its principal executive and principal financial officers, as appropriate to allow timely decisions regarding required disclosure. The Company’s management, including the Chief Executive Officer and Principal Financial Officer, evaluated the effectiveness of the Company’s disclosure controls and procedures as of the end of the period covered by this report. Based upon that evaluation, the Company’s Chief Executive Officer and Principal Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of September 30, 2017.2022.
Management’s Annual Report on Internal Control over Financial Reporting
The management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act. The Company’s internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and preparation of financial statements for external purposes in accordance with GAAP. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.
The Company’s management assessed the effectiveness of the Company’s internal control over financial reporting as of September 30, 2017.2022. In making this assessment, management used the framework and criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control — Integrated Framework, published in 2013. Based on this assessment, management concluded that the Company maintained effective internal control over financial reporting as of September 30, 2017.2022.
PricewaterhouseCoopers LLP, the independent registered public accounting firm that audited the Company’s consolidated financial statements included in this Annual Report on Form 10-K, has issued an attestation report on the effectiveness of the Company’s internal control over financial reporting as of September 30, 2017.2022. The report appears in Part II, Item 8 of this Annual Report on Form 10-K.
Changes in Internal Control over Financial Reporting
There were no changes in the Company’s internal control over financial reporting that occurred during the quarter ended September 30, 20172022 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
None.
| | | | | |
| Item 9C | Disclosure Regarding Foreign Jurisdictions that Prevent Inspections |
None.
PART III
|
| | | | |
| Item 10 | Directors, Executive Officers and Corporate Governance |
The Company will file the definitive Proxy Statement with the SEC no later than 120 days after September 30, 2022. The information concerning directors will be set forth in the definitive Proxy Statement under the headings entitled “Nominees for Election as Directors for Three-YearOne-Year Terms to Expire in 2021,2024,” “Directorsand
“Continuing Directors Whose Terms Expire in 2020,2024,” “Directors Whose Terms Expire in 2019,” and “Section 16(a) Beneficial Ownership Reporting Compliance” and is incorporated herein by reference. The information concerning corporate governance will be set forth in the definitive Proxy Statement under the heading entitled “Meetings of the Board of Directors and Standing Committees” and is incorporated herein by reference. Information concerning the Company’s executive officers can be found in Part I, Item 1, of this report.
The Company has adopted a Code of Business Conduct and Ethics that applies to the Company’s directors, officers and employees and has posted such Code of Business Conduct and Ethics on the Company’s website, www.nationalfuelgas.com, together with certain other corporate governance documents. Copies of the Company’s Code of Business Conduct and Ethics, charters of important committees, and Corporate Governance Guidelines will be made available free of charge upon written request to Investor Relations, National Fuel Gas Company, 6363 Main Street, Williamsville, New York 14221.
The Company intends to satisfy the disclosure requirement under Item 5.05 of Form 8-K regarding an amendment to, or a waiver from, a provision of its code of ethics that applies to the Company’s principal executive officer, principal financial officer, principal accounting officer or controller, or persons performing similar functions, and that relates to any element of the code of ethics definition enumerated in paragraph (b) of Item 406 of the SEC’s Regulation S-K, by posting such information on its website, www.nationalfuelgas.com.
|
| | | | |
| Item 11 | Executive Compensation |
The information concerning executive compensation will be set forth in the definitive Proxy Statement under the headings “Executive Compensation” and “Compensation Committee Interlocks and Insider Participation” and, excepting the “Report of the Compensation Committee,” is incorporated herein by reference.
|
| | | | |
| Item 12 | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters |
Equity Compensation Plan Information
The equity compensation plan information will be set forth in the definitive Proxy Statement under the heading “Equity Compensation Plan Information” and is incorporated herein by reference.
Security Ownership and Changes in Control
(a) Security Ownership of Certain Beneficial Owners
The information concerning security ownership of certain beneficial owners will be set forth in the definitive Proxy Statement under the heading “Security Ownership of Certain Beneficial Owners and Management” and is incorporated herein by reference.
(b) Security Ownership of Management
The information concerning security ownership of management will be set forth in the definitive Proxy Statement under the heading “Security Ownership of Certain Beneficial Owners and Management” and is incorporated herein by reference.
(c) Changes in Control
None.
|
| | | | |
| Item 13 | Certain Relationships and Related Transactions, and Director Independence |
The information regarding certain relationships and related transactions will be set forth in the definitive Proxy Statement under the headings “Compensation Committee Interlocks and Insider Participation” and “Related Person Transactions” and is incorporated herein by reference. The information regarding director independence iswill be set forth in the definitive Proxy Statement under the heading “Director Independence” and is incorporated herein by reference.
|
| | | | |
| Item 14 | Principal Accountant Fees and Services |
The information concerning principal accountant fees and services will be set forth in the definitive Proxy Statement under the heading “Audit Fees” and is incorporated herein by reference.
PART IV
|
| | | | |
| Item 15 | Exhibits and Financial Statement Schedules |
|
| | | | |
| (a)1. | Financial Statements |
Financial statements filed as part of this report are listed in the index included in Item 8 of this Form 10-K, and reference is made thereto.
|
| | | | |
| (a)2. | Financial Statement Schedules |
Financial statementAll schedules filed as part of this report are listedomitted because they are not applicable or the required information is shown in the index included in Item 8 of this Form 10-K, and reference is madeConsolidated Financial Statements or Notes thereto.
All documents referenced below were filed pursuant to the Securities Exchange Act of 1934 by National Fuel Gas Company (File No. 1-3880), unless otherwise noted.
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| | | | |
Exhibit Number | Description of Exhibits |
| |
| 3(i) | Articles of Incorporation: |
| |
| • | |
| |
3(ii) | By-Laws: |
| |
| • | |
| |
| |
| |
|
| |
Exhibit
Number
3(ii) | By-Laws: |
| |
| • | Exhibits National Fuel Gas Company, as amended June 15, 2022 (Exhibit 3.1, Form 8-K dated June 17, 2022)
|
4 | |
| 4 | Instruments Defining the Rights of Security Holders, Including Indentures: |
| |
| • | |
| |
| • | Indenture, dated as of October 15, 1974, between the Company and The Bank of New York Mellon (formerly Irving Trust Company) (Exhibit 2(b) in File No. 2-51796) |
| |
| • | Third Supplemental Indenture, dated as of December 1, 1982, to Indenture dated as of October 15, 1974, between the Company and The Bank of New York Mellon (formerly Irving Trust Company) (Exhibit 4(a)(4) in File No. 33-49401) |
| |
| • | Eleventh Supplemental Indenture, dated as of May 1, 1992, to Indenture dated as of October 15, 1974, between the Company and The Bank of New York Mellon (formerly Irving Trust Company) (Exhibit 4(b), Form 8-K dated February 14, 1992) |
| |
| • | Twelfth Supplemental Indenture, dated as of June 1, 1992, to Indenture dated as of October 15, 1974, between the Company and The Bank of New York Mellon (formerly Irving Trust Company) (Exhibit 4(c), Form 8-K dated June 18, 1992) |
| |
| • | Thirteenth Supplemental Indenture, dated as of March 1, 1993, to Indenture dated as of October 15, 1974, between the Company and The Bank of New York Mellon (formerly Irving Trust Company) (Exhibit 4(a)(14) in File No. 33-49401) |
| |
| • | Fourteenth Supplemental Indenture, dated as of July 1, 1993, to Indenture dated as of October 15, 1974, between the Company and The Bank of New York Mellon (formerly Irving Trust Company) (Exhibit 4.1, Form 10-K for fiscal year ended September 30, 1993) |
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| • | |
| |
| | | | | |
•Exhibit Number | Exhibits |
| |
| • | |
| |
• | |
| |
| • | |
| |
| • | |
| |
| • | Amended and Restated Rights Agreement,Officers Certificate establishing 4.75% Notes due 2028, dated as of December 4, 2008, between the Company and The Bank of New York Mellon (formerly The Bank of New York), as rights agentAugust 17, 2018 (Exhibit 4.1,4.1.1, Form 8-K dated December 4, 2008)August 17, 2018) |
| |
| • | Letter of Appointment of Wells Fargo Bank, National Association, as Successor Rights Agent,Officers Certificate establishing 5.50% Notes due 2026, dated July 18, 2012June 3, 2020 (Exhibit 4.1,4.1.1, Form 10-K for fiscal year ended September 30, 2012)8-K dated June 3, 2020) |
| |
10 | Material Contracts: |
| |
| • | Third Amended and Restated Credit Agreement,Officer’s Certificate establishing 2.95% Notes due 2031, dated as of September 9, 2016, among the Company, the Lenders Party Thereto, and JP Morgan Chase Bank, National Association, as Administrative AgentFebruary 24, 2021 (Exhibit 10.1,4.1.1, Form 10-K for the fiscal year ended September 30, 2016)8-K dated February 24, 2021) |
| |
| 10 | Material Contracts: |
| |
| • | |
| |
| |
| |
|
| |
Exhibit
Number
• | Exhibits May 4, 2020, by and among SWEPI LP, Seneca Resources Company, LLC, NFG Midstream Covington, LLC, National Fuel Gas Midstream Company, LLC and National Fuel Gas Company (Exhibit 10.1, Form 8-K dated May 4, 2020)
|
| |
| • | |
| |
| • | |
| |
| • | |
| |
| 10.1 | |
| |
| Management Contracts and Compensatory Plans and Arrangements: |
| |
| • | |
| |
10.1• |
|
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• | |
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| • | |
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• | |
| |
• | |
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| • | |
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| • | |
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• | |
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| • | |
| | | | | |
Exhibit Number | Description of Exhibits |
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| • | |
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| • | |
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| • | |
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| • | |
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| • | |
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| • | |
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| • | |
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| • | |
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|
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Exhibit
Number
• | Description of
|
| |
| • | |
| |
| • | |
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| • | |
| |
| • | |
| |
| • | |
| |
| • | |
| |
| • | |
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| • | |
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| • | |
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| • | |
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| | | | | |
•Exhibit Number | Description of Exhibits |
| • | |
| |
| • | |
| |
| • | |
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| • | |
| |
| • | |
| |
| • | |
| |
| • | |
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| • | |
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| • | |
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|
| |
Exhibit
Number
21 | Description of
Exhibits
|
• | |
| |
12 | |
| |
21 | |
| |
| 23 | Consents of Experts: |
| |
| 23.1 | |
| |
| 23.2 | |
| |
| 31 | Rule 13a-14(a)/15d-14(a) Certifications: |
| |
| 31.1 | |
| |
| 31.2 | |
| |
| 32•• | |
| |
| 99 | Additional Exhibits: |
| |
| 99.1 | |
| |
| 99.2 | |
| |
| | | | | |
Exhibit Number | Description of Exhibits |
| 101 | Interactive data files submitted pursuant to Regulation S-T:S-T, formatted in Inline XBRL (eXtensible Business Reporting Language): (i) the Consolidated Statements of Income and Earnings Reinvested in the Business for the years ended September 30, 2017, 20162022, 2021 and 2015,2020, (ii) the Consolidated Statements of Comprehensive Income for the years ended September 30, 2017, 20162022, 2021 and 20152020 (iii) the Consolidated Balance Sheets at September 30, 20172022 and September 30, 2016,2021, (iv) the Consolidated Statements of Cash Flows for the years ended September 30, 2017, 20162022, 2021 and 20152020 and (v) the Notes to Consolidated Financial Statements. |
| |
•104 | Cover Page Interactive Data File (embedded within the Inline XBRL document) |
| |
| • | Incorporated herein by reference as indicated. |
| |
| All other exhibits are omitted because they are not applicable or the required information is shown elsewhere in this Annual Report on Form 10-K. |
| |
| •• | In accordance with Item 601(b)(32)(ii) of Regulation S-K and SEC Release Nos. 33-8238 and 34-47986, Final Rule: Management’s Reports on Internal Control Over Financial Reporting and Certification of Disclosure in Exchange Act Periodic Reports, the material contained in Exhibit 32 is “furnished” and not deemed “filed” with the SEC and is not to be incorporated by reference into any filing of the Registrant under the Securities Act of 1933 or the Exchange Act, whether made before or after the date hereof and irrespective of any general incorporation language contained in such filing, except to the extent that the Registrant specifically incorporates it by reference. |
None.
Signatures
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
| | | | | | | | |
| | |
| | |
| National Fuel Gas Company |
| (Registrant) |
| |
| By | | /s/ R. J. TanskiD. P. Bauer |
| | R. J. Tanski D. P. Bauer |
| | President and Chief Executive Officer |
Date: November 17, 201718, 2022
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. | | | | | | | | | | | | | | |
| Signature | | Title | |
|
| | | | |
| /s/ D. F. Smith | | Chairman of the Board and Director | | Date: November 18, 2022 |
| D. F. Smith | | | | |
| | | | |
Signature | | Title | | |
| | | | |
/s/ D. F. SmithH. Anderson | | Chairman of the Board and Director | | Date: November 17, 201718, 2022 |
D. F. SmithH. Anderson | | | | |
| | | | |
/s/ P. C. AckermanB. M. Baumann | | Director | | Date: November 17, 201718, 2022 |
P. C. AckermanB. M. Baumann | | | | |
| | | | |
| /s/ D. C. Carroll | | Director | | Date: November 17, 201718, 2022 |
| D. C. Carroll | | | | |
| | | | |
/s/ S. E. EwingC. Finch | | Director | | Date: November 17, 201718, 2022 |
S. E. EwingS.C. Finch | | | | |
| | | | |
| /s/ J. N. Jaggers | | Director | | Date: November 17, 201718, 2022 |
| J. N. Jaggers | | | | |
| | | | |
/s/ C. G. Matthews | | Director | | Date: November 17, 2017 |
C. G. Matthews | | | | |
| | | | |
| /s/ R. Ranich | | Director | | Date: November 17, 201718, 2022 |
| R. Ranich | | | | |
| | | | |
| /s/ J. W. Shaw | | Director | | Date: November 17, 201718, 2022 |
| J. W. Shaw | | | | |
| | | | |
| /s/ T. E. Skains | | Director | | Date: November 17, 201718, 2022 |
| T. E. Skains | | | | |
| | | | |
| /s/ R. J. Tanski | | Director | | Date: November 18, 2022 |
| R. J. Tanski | | | | |
| | | | |
| /s/ D. P. Bauer | | President and Chief Executive Officer and Director | | Date: November 17, 201718, 2022 |
R. J. Tanski | | | | |
| | | | |
/s/ D. P. Bauer | | Treasurer and Principal
Financial Officer
| | Date: November 17, 2017 |
D. P. Bauer | | | | |
| | | | |
| /s/ K. M. Camiolo | | Treasurer and Principal
Financial Officer | | Date: November 18, 2022 |
| K. M. Camiolo | | | | |
| | | | |
| /s/ E. G. Mendel | | Controller and Principal Accounting Officer | | Date: November 17, 201718, 2022 |
K. M. CamioloE. G. Mendel | | | | |