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2023
Annual
Report
Dear Fellow Shareholders,
Fiscal 2023 was another strong year for National Fuel Gas Company. Driving solid execution
across our organization, the efforts of our 2,200 dedicated employees position us for growth in
the years ahead while maintaining the Company’s long-standing focus on responsibly, safely and
reliably producing and delivering critical energy supplies to consumers.
Strong Operational Results from Appalachian
Development Program
In 2023, Seneca Resources Company, LLC (Seneca) achieved
solid operational results, growing its production by approximately
6% to 372 billion cubic feet equivalent, a company record. This
production growth drove record throughput and revenue at
our Gathering business, which transports Seneca’s natural
gas volumes.
During the year, given our deep inventory of high-returning locations
in Tioga County, PA, Seneca began a multi-year transition of
its development program to focus more heavily on the Eastern
Development Area (EDA). Seneca also closed on three separate,
largely contiguous acquisitions, adding between 50 and 70 well
locations to its inventory in this prolific region. With more than
10 years of core, high-quality inventory in this area, we expect to
see sustained improvement in long-term capital efficiency and free
cash flow generation from our Appalachian development program
in the years to come.
Positioned for Steady Growth in Regulated Operations
In line with our increased focus on EDA development, in September,
Seneca executed a precedent agreement with our Pipeline &
Storage subsidiary, National Fuel Gas Supply Corporation (Supply),
for 190,000 dekatherms per day of firm transportation capacity
on the Tioga Pathway Project. This approximately $90 million
project, which has a target in-service date of late 2026, will provide
a new outlet for Seneca’s Tioga County production and access to
higher-value markets. Additionally, the project, which is expected
to provide $15 million in incremental annual revenues, offers a
layer of growth for our Pipeline & Storage segment. Combined
with an expected increase in revenues from Supply’s pending rate
proceeding, which was filed in July, and our continued investments
in system modernization and emissions reductions, we expect to
see consistent and steady growth in this business.
Our Utility business remains focused on safely and reliably providing
natural gas service to more than 2 million residents in Western
New York and Northwestern Pennsylvania. In 2023, we continued
to advance our system modernization efforts, replacing more than
160 miles of pipeline mains and bringing our investment on these
efforts to more than $415 million since 2019. To ensure timely
recovery of these critical investments, along with increased
operating costs, our Utility commenced rate proceedings in both
service territories recently. In June, we reached a settlement in
our Pennsylvania jurisdiction, with annual base rates increasing by
$23 million. In our New York jurisdiction, we filed a rate proceeding
shortly after the close of fiscal 2023. We expect this proceeding to
advance through fiscal 2024, as we work with key stakeholders to
achieve a positive result.
Making Progress Toward Emissions Reductions Targets
National Fuel continues to take significant decarbonization steps
through system modernization, best management practices and
embracing new and emerging technologies. These efforts have
resulted in our subsidiaries making further progress toward their
methane intensity targets, with reductions to date ranging from
8.3% to 27.4%, as compared to 2020 baselines.
Important Role in the Energy Future
With an operating history that spans well over a century, the value of
National Fuel’s weather-hardened assets was never more evident
than in late December 2022, when Winter Storm Elliott dropped
more than 50 inches of snow and brought sustained temperatures
below 5 degrees Fahrenheit to our operating footprint. Although
electric infrastructure faltered, leaving tens of thousands of
residences without power, National Fuel’s natural gas facilities were
up to the challenge, reliably providing essential energy supplies
to homes and businesses, with minimal outages. As policymakers
continue to push for a “rapid transformation” to a predominantly
electric future, powered primarily by intermittent wind and solar, this
recent event serves as an important reminder that this transition
needs to be pragmatic and measured, and should not overlook our
most affordable and reliable energy option — natural gas.
Across our operations, National Fuel is well positioned for continued
success. Our recent and ongoing ratemaking activity at our
regulated businesses, continued investment in the modernization
of our pipeline systems, and ongoing focus on the integrated
development of our high-quality well inventory in Appalachia
all position the Company for further growth in the years ahead.
This outlook differentiates us from our peers, as we expect to
simultaneously grow our businesses, strengthen our investment
grade balance sheet and continue our long history of returning
significant and increasing amounts of capital to shareholders
through our dividend, all of which we expect will deliver
considerable long-term value to our shareholders.
David P. Bauer
President and Chief Executive Officer
January 4, 2024
Our Guiding Principles
Safety
We embrace a culture of safety
that extends to our customers,
employees and communities.
Community
We are committed to the
health and vitality of our
local communities.
Satisfaction
We work to deliver reliable,
high-quality service and to
address the distinct needs
of our stakeholders.
Environmental Stewardship
We operate our assets in a
manner that respects and
protects the environment.
Innovation
We strive to exceed the
standards for safe, clean and
reliable energy development.
Transparency
We believe that open
communication is key
to maintaining strong
relationships.
Growth, Balance and Diversity
Fifty-Three Years of Dividend Growth
(Annual Rate at Fiscal Year-End)
Diversity of Earnings and Cash Flows
(Percent of Fiscal 2023 Net Income by Segment)
$1.98
$0.19
1970
1980
1990
2000
2010
2023
Utility and
All Other
9%
Pipeline &
Storage
21%
Gathering
21%
49% Exploration &
Production
Cover Photo Captions (from top to bottom):
A drilling rig operates at a well pad in
Cameron County, PA. Seneca has certified
100% of its production under Equitable
Origin’s EO100™ Standard for Responsible
Energy Development and the MiQ Standard
for Methane Emissions Performance.
The Appalachian basin boasts some of
the lowest greenhouse gas and methane
intensities in the world.
Utility employees in Erie, PA, discuss
safety practices before heading out
to the field. National Fuel continuously
works to establish a culture that focuses
on all aspects of safety. The Company
has implemented numerous safety
programs and management practices
to foster a safety culture embraced
throughout the entire organization.
A pipeline right-of-way in Zoar Valley,
NY, is maintained to support the area’s
natural environment. Our Pipeline
& Storage segment is focused on
organic growth opportunities and
modernization of our transmission and
storage system to enhance safety and
reliability while reducing emissions.
2023 ANNUAL REPORT
1
Lawtons Storage Field in North Collins,
NY, was discovered in 1917 and used
for production for more than 30 years
until it was converted to storage in
1949. Today, its 33 wells, including a
new horizontal well to improve overall
efficiency, are used to facilitate storage
operations and help meet the natural
gas needs of residents and commercial
and industrial businesses throughout
Western New York.
Our natural gas gathering system,
which transports more than
1.2 Bcfe of natural gas daily,
achieved certification under
Equitable Origin’s EO100™
Standard for Responsible
Energy Development for 100%
of its assets. National Fuel Gas
Midstream Company is the
first gathering or midstream
company to receive this
ESG-focused certification.
Seneca Resources Production
(Bcfe)
2024E
2023
2022
2021
2020
Gathering Revenues
($ millions)
2024E
2023
2022
2021
2020
Utility Investment in Safety
(Fiscal Year — $ millions)
2023
2022
2021
2020
2019
400.0
372.5
352.5
327.4
241.5
$240–$260
$230
$215
$193
$143
$109
$83
$80
$71
$74
Utility Delivery System GHG Emissions
(Calendar Year — Thousand Metric Tons, CO2e)
800
700
600
500
400
300
200
100
0
1990
~67%
Reduction
Since 1990
(484,000
Metric Tons
CO2e)
1995
2000
2005
2010
2015
2020
2
NATIONAL FUEL GAS COMPANY
Seneca’s Surface Footprint Neutral Program
aims to restore, enhance and protect
biodiversity by returning one acre of land
to the natural environment for every acre
disturbed by operations. As part of this effort,
Seneca planted 260 trees on a reclaimed
well pad and abandoned pipeline corridor in
Elk County, PA.
Left:
Natural gas service was installed on the newly
reopened Buffalo AKG Art Museum. The AKG
is one of many new and planned construction
projects within our service territory that relies on
the critical energy that natural gas provides.
Right:
New facilities were installed to provide
natural gas service to the Great Lakes
Cheese facility constructed in Franklinville,
NY. Natural gas, and the economic benefit
it offers, is critical to the manufacturing
industry and the communities we serve.
2023 ANNUAL REPORT
3
Above:
Seneca’s volunteer program, Seneca Serves, empowers employees
to be catalysts of positive change by using their skills, passion and
resources to improve the health and well-being of our communities.
As a participant in a voluntary nationwide program that supports
monarch butterflies and their habitats, National Fuel implements annual
conservation measures on more than 3,000 acres of its rights-of-way.
Directors
David H. Anderson
President and Chief Executive Officer of
Northwest Natural Holding Company and
Northwest Natural Gas Company
Steven C. Finch
Former President, Manufacturing and
Director of Community Engagement
at Viridi Parente, Inc.
Thomas E. Skains
Former President, Chairman and
Chief Executive Officer of Piedmont
Natural Gas Company, Inc.
David P. Bauer
President and Chief Executive Officer
of National Fuel Gas Company
Barbara M. Baumann
President and Owner of Cross Creek
Energy Corporation
Joseph N. Jaggers
Former President, Chairman and
Chief Executive Officer of Jagged Peak
Energy Inc.
David F. Smith
Chairman of the Board and former
Chief Executive Officer of
National Fuel Gas Company
Rebecca Ranich
Former Director at Deloitte Consulting, LLP
Ronald J. Tanski
Former President and
Chief Executive Officer of
National Fuel Gas Company
David C. Carroll
Former President and Chief Executive
Officer of GTI Energy
Jeffrey W. Shaw
Former Director and Chief Executive Officer
of Southwest Gas Corporation
Officers
David P. Bauer
President and Chief Executive Officer
Ronald C. Kraemer
Chief Operating Officer
President, National Fuel Gas Supply
Corporation and Empire Pipeline, Inc.
Donna L. DeCarolis
President, National Fuel Gas
Distribution Corporation
4
NATIONAL FUEL GAS COMPANY
Justin I. Loweth
President, Seneca Resources
Company, LLC
President, National Fuel Gas Midstream
Company, LLC
Martin A. Krebs
Chief Information Officer
Michael W. Reville
General Counsel and Secretary
Timothy J. Silverstein
Treasurer and Principal Financial Officer
Meghan A. Corcoran
Corporate Responsibility Officer
Elena G. Mendel
Controller and Principal Accounting Officer
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
☑ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year Ended September 30, 2023
☐ 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)
New Jersey
13-1086010
(State or other jurisdiction of incorporation or organization)
(I.R.S. Employer Identification No.)
6363 Main Street
Williamsville, New York
(Address of principal executive offices)
14221
(Zip Code)
(716) 857-7000
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class
Common Stock, par value $1.00 per share
Trading Symbol
NFG
Name of Each Exchange
on Which Registered
New York Stock Exchange
Indicate by check mark if
Act. Yes ☑
No ☐
Securities registered pursuant to Section 12(g) of the Act: None
the registrant
is a well-known seasoned issuer, as defined in Rule 405 of
the Securities
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 ☑
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 ☑
No ☐
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted 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 such files). Yes ☑
No ☐
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.
Large accelerated filer
Non-accelerated filer
☑
☐
Accelerated filer
Smaller reporting company
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. ☑
If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the
registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐
Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based
compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ☐
The aggregate market value of the voting stock held by nonaffiliates of the registrant amounted to $5,187,493,000 as of March 31,
No ☑
2023.
Common Stock, par value $1.00 per share, outstanding as of October 31, 2023: 91,829,588 shares.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrant’s definitive Proxy Statement for its 2024 Annual Meeting of Stockholders, to be filed with the Securities and
this report.
Exchange Commission within 120 days of September 30, 2023, are incorporated by reference into Part
III of
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 Company National Fuel Gas Midstream Company,
LLC
National Fuel National Fuel Gas Company
Registrant National Fuel Gas Company
Seneca Seneca Resources Company, 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
2017 Tax Reform Act Tax legislation referred to as the "Tax
Cuts and Jobs Act," enacted December 22, 2017.
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 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.
the coldness of
-2-
assets
and/or
Includes
for
stock
investments
capital
in
long-lived
acquisitions
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.
EAP Energy Affordability Program; a program that provides
bill discounts to gas customers who receive benefits under
qualifying public assistance programs.
ESG Environmental, social and governance
Exchange Act Securities Exchange Act of 1934, as amended
Expenditures
expenditures,
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
ascertaining the presence
the purpose of
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.
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
representing the difference
Goodwill An intangible asset
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
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.
Impact Fee An annual fee imposed on unconventional wells
spud in Pennsylvania. The fee is administered by the PaPUC
and fees are distributed to counties and municipalities where the
well is located.
Interruptible
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
LIFO Last-in, first-out
Marcellus Shale A Middle Devonian-age geological shale
is present nearly a mile or more below the
formation that
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)
transportation
storage
and/or
things,
MD&A Management’s Discussion and Analysis of Financial
Condition and Results of Operations
MDth Thousand decatherms (of natural gas)
Methane The primary component of natural gas. It is a
compound made up of one carbon atom and four hydrogen
atoms (CH4).
MMBtu Million British thermal units (heating value of one
decatherm of natural gas)
MMcf Million cubic feet (of natural gas)
MMcfe Million cubic feet equivalent
Natural Gas A naturally occurring mixture of gaseous
hydrocarbons consisting primarily of methane and found in
underground rock formations.
NGA The Natural Gas Act of 1938, as amended; the federal law
regulating interstate natural gas pipeline and storage companies,
among other
codified beginning at 15 U.S.C.
Section 717.
NOAA National Oceanic and Atmospheric Administration
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
they had been submitted
if
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.
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.
evaluated as
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
WNC Weather normalization clause; a clause/adjustment
in
utility rates which adjusts customer rates to allow a utility to
its normal operating costs calculated at normal
recover
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.
-3-
For the Fiscal Year Ended September 30, 2023
CONTENTS
Part I
ITEM 1
BUSINESS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
THE COMPANY AND ITS SUBSIDIARIES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
RATES AND REGULATION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
THE EXPLORATION AND PRODUCTION SEGMENT . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
THE PIPELINE AND STORAGE SEGMENT . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
THE GATHERING SEGMENT . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
THE UTILITY SEGMENT . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
ALL OTHER CATEGORY AND CORPORATE OPERATIONS . . . . . . . . . . . . . . . . . . . . . . . . . .
SOURCES AND AVAILABILITY OF RAW MATERIALS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
COMPETITION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
SEASONALITY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CAPITAL EXPENDITURES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
ENVIRONMENTAL MATTERS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
MISCELLANEOUS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
HUMAN CAPITAL . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
EXECUTIVE OFFICERS OF THE COMPANY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
ITEM 1A RISK FACTORS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
ITEM 1B UNRESOLVED STAFF COMMENTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
ITEM 1C CYBERSECURITY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
PROPERTIES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
ITEM 2
GENERAL INFORMATION ON FACILITIES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
EXPLORATION AND PRODUCTION ACTIVITIES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
LEGAL PROCEEDINGS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
ITEM 3
ITEM 4 MINE SAFETY DISCLOSURES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Part II
ITEM 5 MARKET FOR THE REGISTRANT’S COMMON EQUITY, RELATED
STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES .
[RESERVED] . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
ITEM 6
ITEM 7 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
ITEM 7A QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK . . . .
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA . . . . . . . . . . . . . . . . . . . .
ITEM 8
ITEM 9
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
ITEM 9A CONTROLS AND PROCEDURES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
ITEM 9B OTHER INFORMATION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
ITEM 9C DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT
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Part III
ITEM 10 DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE . . . . . . . .
ITEM 11 EXECUTIVE COMPENSATION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
ITEM 12
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT AND RELATED STOCKHOLDER MATTERS . . . . . . . . . . . . . . . . . . .
ITEM 13 CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR
ITEM 14
INDEPENDENCE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
PRINCIPAL ACCOUNTANT FEES AND SERVICES . . . . . . . . . . . . . . . . . . . . . . . . . . . .
ITEM 15 EXHIBITS AND FINANCIAL STATEMENT SCHEDULES . . . . . . . . . . . . . . . . . . . . . . .
ITEM 16
FORM 10-K SUMMARY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
SIGNATURES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Part IV
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Item 1
Business
The Company and its Subsidiaries
PART I
National Fuel Gas Company (the Registrant), incorporated in 1902, is a holding company organized under
the laws of the State of New Jersey. The 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, storage and distribution 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 and Utica shales, geological formations that are present nearly a mile or more
below the surface in the Appalachian region of the United States. Pipeline development activities are designed
to transport natural gas production to both existing and 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 the eastern United States and Canada. The Company reports financial results for four
business segments: Exploration and Production, Pipeline and Storage, Gathering, and Utility.
1. The Exploration and Production segment operations are carried out by Seneca Resources Company,
LLC (Seneca), a Pennsylvania limited liability company. Seneca is engaged in the exploration for, and the
development and production of, primarily natural gas in the Appalachian region of the United States. At
September 30, 2023, Seneca had proved developed and undeveloped reserves of 4,535,084 MMcf of natural gas
and 216 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 and Empire provide interstate natural gas transportation services for affiliated and
nonaffiliated companies through integrated natural gas pipeline systems in Pennsylvania and New York. Supply
Corporation also provides storage services through its underground natural gas storage fields, and Empire
provides storage service (via lease with Supply Corporation) to a nonaffiliated company.
3. The Gathering segment operations are carried out by wholly-owned subsidiaries of National Fuel Gas
Midstream Company, LLC (Midstream Company), a Pennsylvania limited liability company. Through these
subsidiaries, Midstream Company 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 provides natural gas utility
services to approximately 754,000 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.
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 M — Business Segment Information.
Revenue from one customer of the Company's Exploration and Production segment, exclusive of hedging
losses transacted with separate parties, represented approximately $208 million, or 9.6%, of the Company's
consolidated revenue for the year ended September 30, 2023. This one customer was also a customer of the
Company's Pipeline and Storage segment, accounting for an additional $14 million, or 0.6%, of the Company's
consolidated revenue for the year ended September 30, 2023.
-6-
Rates and Regulation
The Company’s businesses are subject to regulation under a wide variety of federal, state and local laws,
regulations and policies. This includes federal and state agency regulations with respect to rate proceedings,
project permitting and environmental requirements.
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. 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 segments’ rates,
see Item 7, MD&A under the heading “Rate Matters” and Item 8 at Note A — Summary of Significant
Accounting Policies (Regulatory Mechanisms) and Note F — Regulatory Matters.
The discussion under Item 8 at Note F — 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.
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 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. PHMSA may delegate this
authority to a state, as it has in New York and Pennsylvania, 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 the 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
regulation, see Item 7, MD&A under the heading “Environmental Matters.”
The Exploration and Production Segment
The Exploration and Production segment contributed net income of $232.3 million in 2023.
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 net income of $100.5 million in 2023.
The Pipeline and Storage segment generated approximately 32% of its revenues in 2023 from services
provided to the Utility segment or Exploration and Production segment.
-7-
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 net income of $99.7 million in 2023.
The Gathering segment generated approximately 94% of its revenues in 2023 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 net income of $48.4 million in 2023.
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.
All Other Category and Corporate Operations
The All Other category and Corporate operations incurred a net loss of $4.0 million in 2023.
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 (primarily natural
gas) as further described in this report in Item 7, MD&A and Item 8 at Note M — Business Segment
Information and Note N — 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 Appalachian region 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.
Natural gas is the principal raw material for the Utility segment. In 2023, the Utility segment purchased
73.1 Bcf of gas (including 71.3 Bcf for delivery to retail customers and 1.8 Bcf used in operations) pursuant to
its purchase contracts with firm delivery requirements. Gas purchased from producers and suppliers in the
United States under multi-month contracts accounted for 50% of these purchases. Purchases of gas in the spot
market (contracts of one month or less) accounted for 50% of the Utility segment’s 2023 purchases. Purchases
from DTE Energy Trading, Inc. (24%), Vitol, Inc. (14%), Shell Energy North America US (9%), EQT Energy,
LLC (9%), Emera Energy Services, Inc. (8%), J. Aron & Company (7%), Tenaska Marketing Ventures (5%),
Chevron Natural Gas (5%), and NRG Business Marketing Inc. (5%), accounted for nearly 86% of the Utility
segment's 2023 gas purchases. No other producer or supplier provided the Utility segment with more than 5%
of its gas requirements in 2023. The Utility segment does not directly purchase gas from affiliates.
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, geothermal, solar and wind. Management believes that the
reliability and affordability of natural gas support its competitive position relative to other fuels.
-8-
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 natural gas producers and marketers with
respect to sales of natural gas. The Exploration and Production segment also competes, by competitive bidding
and otherwise, with other 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 its prospects,
maintains a portfolio of firm transportation and sales contracts in order to compete in higher priced markets,
seeks to minimize the risk of exploratory efforts through partnership-type arrangements, utilizes technology for
both exploratory studies and drilling operations, and seeks prospect and partnership opportunities based on size,
operating expertise and financial criteria.
Competition: The Pipeline and Storage Segment
Supply Corporation competes for 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. Most of Supply
Corporation’s facilities are in or near areas overlying the Marcellus and Utica shale production areas in
Pennsylvania, and it has established interconnections with producers and other pipelines that provide access to
these supplies and to premium off-system markets. Its facilities are also located adjacent to the Canadian border
at the Niagara River providing access to markets in Canada and the northeastern and midwestern United States
via the TC Energy pipeline system. Supply Corporation has developed and placed into service a number of
pipeline expansion projects designed to transport natural gas to key markets in New York, Pennsylvania, the
northeastern United States, Canada, and to long-haul pipelines with access to the U.S. Midwest, Mid-Atlantic
and the Gulf Coast. For further discussion of Pipeline and Storage projects, refer to Item 7, MD&A under the
heading “Investing Cash Flow.”
Empire competes for 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 shale gas as well as gas supplies available at Empire’s interconnect with TC Energy at Chippawa.
Empire’s geographic location provides it the opportunity to compete for service to its on-system LDC markets,
as well as for a share of the gas transportation markets into Canada (via Chippawa) and into the northeastern
United States. Various expansion projects on Empire have expanded it's footprint and capability, 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 natural 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 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 and Pennsylvania,
approximately 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
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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.
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 with fuel oil
suppliers continues to exist and competition with electrification alternatives is growing, particularly in New
York State, natural gas retains its competitive position from a reliability and affordability standpoint.
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 advance
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 federal 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 discussed in Item 7, MD&A under the heading “Environmental Matters” and subheading
“Environmental Regulation,” any meaningful competition and/or business impacts resulting from the CLCPA
cannot be determined.
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 is largely mitigated by a weather normalization clause (WNC).
Prior to October 2023, the weather impact on cash flow in the Utility segment was mitigated by a WNC solely
in its New York rate jurisdiction. However, effective October 2023, the weather impact on cash flow in the
Utility segment will also be mitigated by a WNC in its Pennsylvania rate jurisdiction. Refer to Item 8, Note A –
Summary of Significant Accounting Policies under the heading “Regulatory Mechanisms” for additional
discussion. Under the WNC, 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 delivery revenues calculated at normal temperatures will be largely recovered.
Volumes transported and stored by Supply Corporation and Empire may vary significantly 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.
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 L — Commitments and Contingencies.
Miscellaneous
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.
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 website,
www.nationalfuel.com, as soon as reasonably practicable after they are electronically filed with or furnished to
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the SEC. The information available at the Company’s 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
total rewards, 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 total rewards, 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.nationalfuel.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 2,240 full-time employees at September
30, 2023.
As of September 30, 2023, 47% 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, contractors and communities 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 and applicable contractors.
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 was 8.7% (not including retirements), which is
comparable to last year’s voluntary attrition rate of 8%. The Company continues to actively monitor employee
metrics, including attrition rate, to ensure proper management of and responsiveness to human capital matters.
No Work Stoppages
During fiscal 2023, the Company did not incur any work stoppages (strikes or lockouts) and therefore
experienced zero idle days for the fiscal year.
Total Rewards
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, and periodically conducts employee surveys to provide
additional insight into employee perspectives and interest in desired benefits.
The Company's compensation program for salaried employees is intended to align employee
compensation with the market while providing greater incentive to the Company’s employees to work toward
the achievement of Company goals. These goals include the coordinated business goals and ESG objectives of
the Company's business segments as a whole. This meaningful investment illustrates the Company’s view that
attracting, retaining and motivating our employees is integral to the Company’s success.
-11-
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. The Company’s focus on building a diverse and
inclusive culture is reflected in the Company's approach to Board diversity, its adoption of specific diversity and
inclusion performance goals as part of the Company’s executive compensation program, and policies and
training that reinforce the Company’s commitment to diversity and inclusion in the workplace. The Company’s
policies prohibit discrimination or harassment against any employee or applicant on the basis of sex, race/
ethnicity, and other protected categories. The Company communicates to employees its commitment to a
harassment free workplace through the onboarding process, annual distribution and acknowledgement of the
Company’s Non-Discrimination and Anti-Harassment Policy, and training for all employees including
management. Additionally, to ensure transparency over time, the Company publicly discloses gender, racial
and ethnic minority representation, and multi-generational workforce metrics in the Company’s Corporate
Responsibility Report.
The Company's Diversity and Inclusion team continues to spearhead diversity and inclusion initiatives to
help attract candidates within diverse communities, encourage partnerships with diverse vendors and suppliers
and provide tools and trainings designed to promote equity and inclusion within employment teams. The
Company also supports multiple active Employee Resource Groups for women, ethnically diverse employees,
veterans and employees who identify as LGBTQ+, where employees can network, build community and seek
support. Each group is voluntary, employee-led, open to allies, and has an executive sponsor to help facilitate
communication directly to senior management.
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Executive Officers of the Company as of November 15, 2023(1)
Name and Age (as of
November 15, 2023)
David P. Bauer
(54)
Donna L. DeCarolis
(64)
Ronald C. Kraemer
(67)
Timothy J. Silverstein
(40)
Elena G. Mendel
(57)
Martin A. Krebs
(53)
Michael W. Reville
(64)
Current Company Positions and
Other Material Business Experience
During Past Five Years
Chief Executive Officer of the Company since July 2019. Mr. Bauer previously
served as President of Supply Corporation from February 2016 through June 2019.
Treasurer and Principal Financial Officer of the Company from July 2010 through
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 and Empire from June 2007 through June 2019.
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.
Chief Operating Officer of the Company since March 2021, President of Supply
Corporation since July 2019 and President of Empire since August 2008. Mr.
Kraemer previously served as Senior Vice President of Supply Corporation from
June 2016 through June 2019.
Treasurer and Principal Financial Officer of the Company since May 2023. Treasurer
of Seneca Resources Company since May 2023. Treasurer of Distribution
Corporation, Supply Corporation, Empire and Midstream Company since July 2021.
Mr. Silverstein previously served as Assistant Treasurer of Distribution Corporation,
Supply Corporation and Empire from April 2020 through June 2021. General
Manager of Finance from April 2019 through March 2020. Manager of Finance
from April 2017 through March 2019.
Controller and Principal Accounting Officer of the Company since July 2019.
Controller of Distribution Corporation, Supply Corporation, Empire, and Midstream
Company since July 2019. Ms. Mendel previously served as Assistant Controller of
Distribution Corporation, Supply Corporation and Empire from February 2017
through June 2019.
Chief Information Officer of the Company since December 2018 and Senior Vice
President of Distribution Corporation since May 2023. 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.
General Counsel and Secretary of the Company since April 2023 and Senior Vice
President of Distribution Corporation since May 2020. Mr. Reville previously
served as General Counsel of Distribution Corporation from April 2015 through
March 2023. Secretary of Distribution Corporation from May 2020 through March
2023. Vice President of Distribution Corporation from April 2015 through April
2020.
Justin I. Loweth
(45)
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 Seneca Resources Company from October 2017 through 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.
-13-
Item 1A
Risk Factors
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 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
In general, the Company’s operating income,
must meet an interest coverage test under its 1974 indenture.
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 credit ratings published by S&P, Moody's Investors Service, Inc. and Fitch
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 uncommitted sources,
and require the Company’s subsidiaries to post letters of credit, cash or other assets as collateral with certain
counterparties. Additionally, $1.4 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 a credit rating assigned to the notes below investment grade.
In addition to the $1.4 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. Executive orders from the federal administration, in
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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 natural 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, cap-and-invest 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.
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. Furthermore, in 2019, the New York State legislature passed the
CLCPA, which created emission reduction and electrification mandates, and could ultimately impact the Utility
segment’s customer base and business. Pursuant to the CLCPA, New York's Climate Action Council (“CAC”)
approved a final scoping plan that includes recommendations to strategically downsize and decarbonize the
natural gas system and curtail use of natural gas and natural gas appliances. The final scoping plan was
approved on December 19, 2022 and includes detailed recommendations to meet the CLCPA’s emissions
reduction targets in the transportation, buildings, electricity, industry, agriculture & forestry and waste sectors.
The final scoping plan also recommends statewide and cross-sector policies relevant to gas system transition,
economywide strategies, land use, local government and adaptation and resilience. Additionally, the scoping
plan recommends the implementation of a cap-and-invest program in New York. In January 2023, New York’s
Governor directed the NYDEC and the New York State Energy Research and Development Authority to
advance an economywide cap-and-invest program that establishes a declining cap on greenhouse gas emissions,
and invests in programs to drive emissions reductions. If this proposed program or a similar program becomes
effective and the Company becomes subject
to new or revised cap-and-trade programs, cap-and-invest
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, and may also experience decreased revenue in the event that implementation of these policies leads
to reduced demand for natural gas.
In addition to the scoping plan, 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. For example, in May 2023, New York State
passed legislation that prohibits the installation of fossil fuel burning equipment and building systems in new
buildings commencing on or after December 31, 2025, subject to various exemptions. While the Company
does not currently expect that this legislation will have a substantial impact on its financial results or operations,
future legislation or regulation that aims to reduce natural gas demand or to impose additional operations
requirements or restrictions on natural gas facilities, if effectuated, could impact our future earnings and cash
flows.
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, which could impact our future earnings and cash flows. For further discussion of the risks
associated with environmental regulation to address climate change, refer to Item 2, 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
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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 policymakers, 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
In turn, these
could cause operational delays or restrictions, and increase the Company’s operating costs.
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, as well as the renewal or modification of key permits for ongoing operations, 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 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. 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 as well as
the renewal or modification of key permits for ongoing operations. 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
increased project costs due to extended construction timeframes, 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 generate sufficient net income to 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
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territories, along with legislative and regulatory prohibitions and/or limitations on terminations of service, also
impact its collections of accounts receivable. Customers of the Company’s Utility segment 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, 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
capacity. Certain customers of the Company's Exploration and Production segment can represent a
concentrated risk during times of high commodity prices and high hedging 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.
Changes in interest rates may affect the Company’s financing and its regulated businesses’ rates of
return.
Rising interest rates may impair the Company’s ability to cost-effectively finance capital expenditures and
may increase the rates at which the Company can refinance maturing debt.
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 natural gas prices could adversely affect revenues, cash flows and profitability.
Financial results in the Company’s Exploration and Production segment are materially 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, consumer demand, national and
worldwide economic conditions, economic disruptions caused by terrorist activities, acts of war or major
accidents, domestic and foreign political conditions and events, 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. Any
prolonged reduction in natural gas prices could result in the Company reducing the level of exploration and
production activity the Company otherwise would pursue, which could have a material adverse effect on its
future 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 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 impact 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
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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, customer demand could be reduced, thereby decreasing revenue. Customers may also have
trouble paying the resulting higher bills when gas prices are higher or in periods of economic uncertainty, which
could increase bad debt expenses and could 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 natural gas 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 volumes, the Company may incur substantial losses to cover its hedges to the extent the hedges are in a
loss position.
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.”
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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
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 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 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 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 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.
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) 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
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incremental long-term unsecured indebtedness for a period of time, beginning with the fourth calendar month
following the impairment. In addition, because an impairment results in a charge to retained earnings, it lowers
the Company's total capitalization, all other things being equal, and increases the Company'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 committed credit facility. The Company last recognized non-
cash, pre-tax impairment charges on its oil and natural gas properties in fiscal years 2020 and 2021, in the
amounts of $449.4 million and $76.2 million, respectively.
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; 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, equipment, and technology/software systems may be subject to sabotage. These events, in turn,
could lead 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. The
Company also seeks, but may be unable, to secure written indemnification agreements with contractors that
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
its indemnification
mandated programs by governmental authorities,
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.
the failure of a contractor to meet
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 through
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 segment.
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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 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 costs of our natural gas
production operations are difficult to predict and may vary significantly from 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 negatively impact the Company’s financial outlook for these businesses. 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
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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 Company's ability to access water and opportunities for disposal or recycling produced water can
impact drilling and completion operations.
The drilling and hydraulic fracturing process requires significant volumes of water and an ability to
recycle or dispose of water produced as a by-product of gas production. Limitations or restrictions on the
Company's ability to secure sufficient amounts of water, including disruptions from natural causes (such as
If the Company is
drought) or issues with transportation availability and costs, could impact its operations.
unable to secure adequate water volumes, drilling and completions can be delayed, or it would have to obtain
new sources of water at increased costs. Similarly, if the Company experiences limitations or restrictions on its
ability to recycle or dispose of its produced water, whether due to environmental regulations, permit
requirements, transportation issues or other factors, producing wells may need to be shut-in and new wells may
be delayed until such time as adequate recycling or disposal capacity is obtained, which can require significant
lead times for permitting and could result in increased costs, delays in the Company's operations and adverse
impacts on its cash flow and results of operations.
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 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 impact natural gas demand, 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.
-22-
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 and state prevailing wage
rate schedules, may be revised or reinterpreted and new laws and regulations may be adopted or become
applicable to the Company or its contractors, 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 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 agency
policies relating to environmental protection including obtaining and complying with permits, leases, approvals,
consents and certifications from various governmental and permit authorities. These laws, regulations and
policies 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
-23-
materials that can be released into the environment in connection with regulated activities, limit or prohibit
remediate
activities in certain protected areas, and may require the Company to investigate and/or
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.
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, regulations or permit conditions
could require unexpected capital expenditures at
temporarily shut down the
Company’s facilities or delay or cause the cancellation of expansion projects or natural gas drilling activities.
the
Because the costs of such compliance are significant, additional regulation could negatively affect
Company’s business.
the Company’s facilities,
Increased regulation of exploration and production activities, including hydraulic fracturing, could
adversely impact the Company.
Various state legislative and regulatory initiatives regarding the exploration and production business have
been proposed or 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, monitoring and abandonment of wells, the protection of water supplies and restrictions on
water use and water rights, hydraulic fracturing operations, increased setback requirements, 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
legislative initiatives in the U.S. Congress and
natural gas production are also possible. Additionally,
environmental and health 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, which could lead to increased operating costs 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. 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
-24-
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, and the regulatory treatment of certain
benefit plan activity, 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.
The Company’s earnings and cash flows may also be impacted by the rate treatment of certain income and
expense activity and regulatory asset and liability balances that would be determined in a future rate proceeding.
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.
Item 1B Unresolved Staff Comments
None.
Item 1C Cybersecurity
Not applicable.
Item 2
Properties
General Information on Facilities
The net investment of the Company in property, plant and equipment was $7.3 billion at September 30,
2023. The Exploration and Production segment constitutes 35.0% of this investment, and is primarily located in
the Appalachian region of the United States. Approximately 52.8% 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 western Pennsylvania. The Gathering segment
constitutes 12.2% of the Company’s investment in net property, plant and equipment, and is located in
northwestern and central Pennsylvania. 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 modernize transmission, storage, and distribution
facilities for customers in New York and Pennsylvania. Net property, plant and equipment has increased $2.3
billion, or 46.7%, since September 30, 2018. 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
$2.6 billion at September 30, 2023 consisting primarily of capitalized costs relating to oil and gas producing
-25-
activities, the components of which are disclosed in Item 8, Note N — Supplementary Information for Oil and
Gas Producing Activities.
The Pipeline and Storage segment had a net investment of $2.1 billion in property, plant and equipment at
September 30, 2023. Transmission pipeline represents 35% of this segment’s total net investment and includes
2,246 miles of pipeline utilized to move large volumes of gas throughout its service area. Storage facilities
represent 13% of this segment’s total net investment and consist of 385 miles of pipeline, as well as 29 storage
fields operating at a combined working gas level of 77.2 Bcf, three of which are jointly owned and operated
with other interstate gas pipeline companies. Net investment in storage facilities includes $82.2 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 31 compressor stations with 260,008
installed horsepower that represent 31% 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 2023
peak day sendout for transportation service of 2,360 MMcf, which occurred on February 3, 2023. Withdrawals
from storage of 505 MMcf provided approximately 21% of the requirements on that day.
The Gathering segment had a net investment of $0.9 billion in property, plant and equipment at
September 30, 2023. Gathering lines and related compressor stations represent substantially all of this
segment’s total net investment, including 376 miles of pipelines utilized to move Appalachian production
(including Marcellus and Utica shales) to various transmission pipeline receipt points. The Gathering segment
has 24 compressor stations with 124,256 installed horsepower.
The Utility segment had a net
in property, plant and equipment of $1.7 billion at
September 30, 2023. The net investment in its gas distribution network (including 15,052 miles of distribution
pipeline) and its service connections to customers represent approximately 49% and 32%, respectively, of the
Utility segment’s net investment in property, plant and equipment at September 30, 2023.
investment
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 reserves in the
Appalachian region of the United States. The Company's development activities in the Appalachian region are
focused primarily in the Marcellus and Utica shales. Further discussion of oil and gas producing activities is
included in Item 8, Note N — Supplementary Information for Oil and Gas Producing Activities. Note N sets
forth proved developed and undeveloped reserve information for Seneca. The September 30, 2023, 2022 and
2021 reserves shown in Note N 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 petroleum engineers and were audited by independent petroleum engineers
from Netherland, Sewell & Associates, Inc. Note N discusses the qualifications of the Company's petroleum
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 4,171 Bcf at September
30, 2022 to 4,535 Bcf at September 30, 2023. This increase is attributed to extensions and discoveries of 670
Bcf, purchases of minerals in place of 34 Bcf, and revisions of previous estimates of 32 Bcf, partially offset by
production of 372 Bcf. Upward revisions of 94 Bcf are mainly attributed to positive performance improvements
and adding back one PUD location. The additions and upward revisions were partially offset by downward
revisions of 62 Bcf from the removal of seven PUD locations related to pad layout changes and price-related
revisions. The Company has no near term plans to develop the reserves at these PUD locations.
Seneca’s proved developed and undeveloped oil reserves decreased from 250 Mbbl at September 30,
2022 to 216 Mbbl at September 30, 2023. The decrease was attributed to current year production of 30 Mbbl
and downward revisions of previous estimates of 4 Mbbl.
-26-
On a Bcfe basis, Seneca’s proved developed and undeveloped reserves increased from 4,172 Bcfe at
September 30, 2022 to 4,536 Bcfe at September 30, 2023. This increase is attributed to extensions and
discoveries of 670 Bcfe, purchases of minerals in place of 34 Bcfe and net upward revisions of previous
estimates of 32 Bcfe, partially offset by production of 372 Bcfe.
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 was 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 one 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 was 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 was 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.
At September 30, 2023, the Company’s Exploration and Production segment had delivery commitments
for natural gas production of 2,147 Bcf. The Company expects to meet those commitments through the future
production of reserves that are currently classified as proved reserves and future extensions and discoveries.
-27-
The following is a summary of certain oil and gas information taken from Seneca’s records.
Production
United States
Appalachian Region
For The Year Ended September 30
2023
2022
2021
Average Sales Price per Mcf of Gas . . . . . . . . . . . . . . . . . . . . . . $
Average Sales Price per Barrel of Oil . . . . . . . . . . . . . . . . . . . . . $ 75.64
Average Sales Price per Mcf of Gas (after hedging)
2.55
Average Sales Price per Barrel of Oil (after hedging) . . . . . . . . $ 75.64
Average Production (Lifting) Cost per Mcf Equivalent of Gas
. . . . . . . . . $
2.78 (1)
5.03 (1)
$
$ 97.82
$
2.69
$ 97.82
2.46 (1)
$
$ 48.02
$
2.22
$ 48.02
and Oil Produced . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
0.68 (1)
$
0.68 (1)
$
0.67 (1)
Average Production per Day (in MMcf Equivalent of Gas and
Oil Produced) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1,020 (1)
936 (1)
856 (1)
West Coast Region
Average Sales Price per Mcf of Gas . . . . . . . . . . . . . . . . . . . . . .
Average Sales Price per Barrel of Oil . . . . . . . . . . . . . . . . . . . . .
Average Sales Price per Mcf of Gas (after hedging)
. . . . . . . . .
Average Sales Price per Barrel of Oil (after hedging) . . . . . . . .
Average Production (Lifting) Cost per Mcf Equivalent of Gas
and Oil Produced . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Average Production per Day (in MMcf Equivalent of Gas and
Oil Produced) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
N/A (2)
N/A (2)
N/A (2)
N/A (2)
$ 10.03
$ 94.06
$ 10.03
$ 70.53
$
6.34
$ 60.50
$
6.34
$ 56.55
N/A (2)
$
4.83
$
3.74
N/A (2)
39 (2)
41
Total Company
Average Sales Price per Mcf of Gas . . . . . . . . . . . . . . . . . . . . . . $
2.78
Average Sales Price per Barrel of Oil . . . . . . . . . . . . . . . . . . . . . $ 75.64
2.55
Average Sales Price per Mcf of Gas (after hedging)
Average Sales Price per Barrel of Oil (after hedging) . . . . . . . . $ 75.64
Average Production (Lifting) Cost per Mcf Equivalent of Gas
. . . . . . . . . $
and Oil Produced . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
0.68
Average Production per Day (in MMcf Equivalent of Gas and
$
5.05
$ 94.10
2.71
$
$ 70.80
$
2.49
$ 60.49
2.25
$
$ 56.54
$
0.81
$
0.82
Oil Produced) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1,020
966
897
(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, 2023, 2022 and 2021)
contributed 521 MMcfe, 574 MMcfe and 597 MMcfe of daily production in 2023, 2022 and 2021,
respectively. The average lifting costs (per Mcfe) were $0.73 in 2023, $0.71 in 2022 and $0.70 in 2021.
The Utica Shale fields (which exceed 15% of total reserves at September 30, 2023, 2022 and 2021)
contributed 495 MMcfe, 357 MMcfe and 255 MMcfe of daily production in 2023, 2022 and 2021,
respectively. The average lifting costs (per Mcfe) were $0.62 in 2023, $0.63 in 2022 and $0.62 in 2021.
(2) West Coast region properties were sold at June 30, 2022. Information for the year ended September 30,
2023 is not applicable (N/A) as a result of the sale.
-28-
Productive Wells
Appalachian
Region
At September 30, 2023
Productive Wells — Gross . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Productive Wells — Net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gas
1,006
891
Oil
—
—
Developed and Undeveloped Acreage
At September 30, 2023
Developed Acreage
— Gross . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
— Net
Undeveloped Acreage
— Gross . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
— Net
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total Developed and Undeveloped Acreage
— Gross . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
— Net
Appalachian
Region
661,478
650,278
728,389
671,676
1,389,867
1,321,954 (1)
(1) Of the 1,321,954 Total Developed and Undeveloped Net Acreage in the Appalachian region as of
September 30, 2023, there are a total of 1,250,077 net acres in Pennsylvania. Of the 1,250,077 total net
acres in Pennsylvania, shale development in the Marcellus, Utica or Geneseo shales has occurred on
approximately 134,414 net acres, or 11% 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, 2023, the aggregate amounts of gross undeveloped acreage expiring under lease in
the next three years and thereafter are as follows: 20,858 acres in 2024 (19,108 net acres), 11,176 acres in 2025
(10,180 net acres), 15,389 acres in 2026 (14,219 net acres) and 211,719 acres thereafter (193,090 net acres).
The remaining 469,247 gross acres (435,079 net acres) represent non-expiring oil and gas rights owned by the
Company. Of the acreage that is currently scheduled to expire in 2024, 2025 and 2026, Seneca has 352.2 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.
-29-
Drilling Activity
For the Year Ended September 30
United States
Appalachian Region
Net Wells Completed
— Exploratory . . . . . . . . . . . . . . . . . . . . . . .
— Development(1) . . . . . . . . . . . . . . . . . . . .
West Coast Region
Net Wells Completed
— Exploratory . . . . . . . . . . . . . . . . . . . . . . .
— Development . . . . . . . . . . . . . . . . . . . . . .
Total Company
Net Wells Completed
— Exploratory . . . . . . . . . . . . . . . . . . . . . . .
— Development . . . . . . . . . . . . . . . . . . . . . .
Productive
2023
2022
2021
2023
Dry
2022
2021
—
34.25
—
43.00
—
47.83
—
0.50
—
2.50
—
2.00
—
—
—
23.00
—
10.00
—
—
—
—
—
—
—
34.25
—
66.00
—
57.83
—
0.50
—
2.50
—
2.00
(1) Fiscal 2023, 2022 and 2021 Appalachian region dry wells include 0.5, 2.5 and 2 net wells, respectively,
drilled prior to 2013 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 2023, 2022 and 2021 after the Company determined it would not continue development
activities.
Present Activities
At September 30, 2023
Wells in Process of Drilling(1)
— Gross . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
— Net
Appalachian
Region
54.00
52.00
(1) Includes wells awaiting completion.
Item 3
Legal Proceedings
For a discussion of various environmental and other matters, refer to Part II, Item 7, MD&A and Item 8 at
Note L — 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 Matters."
Item 4 Mine Safety Disclosures
Not Applicable.
-30-
PART II
Item 5 Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases
of Equity Securities
At September 30, 2023, there were 8,751 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 H — Capitalization and Short-Term Borrowings.
On July 3, 2023, the Company issued a total of 8,490 unregistered shares of Company common stock to
non-employee directors of the Company then serving on the Board of Directors of the Company (or, in the case
of non-employee directors who elected to defer receipt of such shares pursuant to the Company's Deferred
Compensation Plan for Directors and Officers (the “DCP”), to the DCP trustee), consisting of 849 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, 2023. The Company issued an additional 540 unregistered shares in the aggregate on July 14,
2023 pursuant to the dividend reinvestment feature of the DCP, to the six non-employee directors who
participate in the DCP. 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
July 1-31, 2023 . . . . . . . . . . . . . . . . . .
Aug. 1-31, 2023 . . . . . . . . . . . . . . . . . .
Sept. 1-30, 2023 . . . . . . . . . . . . . . . . . .
Total . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total Number
of Shares
Purchased(a)
14,954
12,495
13,493
40,942
Average Price
Paid per
Share
$
$
$
$
51.00
53.88
51.42
52.10
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)
6,971,019
6,971,019
6,971,019
6,971,019
(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, if any, tendered to the Company by holders of stock-based compensation awards
for the payment of applicable withholding taxes. During the quarter ended September 30, 2023, the
Company did not purchase any shares of its common stock pursuant to its publicly announced share
repurchase program. Of the 40,942 shares purchased other than through a publicly announced share
repurchase program, 40,679 were purchased for the Company’s 401(k) plans and 263 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.
-31-
Performance Graph
The following graph compares the Company’s common stock performance with the performance of the
S&P 500 Index, the S&P Mid Cap 400 Gas Utility Index and the S&P 1500 Oil & Gas Exploration &
Production Index for the period September 30, 2018 through September 30, 2023. The graph assumes that the
value of the investment in the Company’s common stock and in each index was $100 on September 30, 2018
and that all dividends were reinvested.
Comparison of Five-Year Cumulative Total Returns
Fiscal Years 2019 - 2023
175
150
125
100
75
50
25
2018
2019
2020
2021
2022
2023
National Fuel
S&P 500 Index
S&P Mid Cap 400 Gas Utility Index (S4GASU)
S&P 1500 Oil & Gas Exp & Prod Index (S15OILP)
National Fuel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
S&P 500 Index . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
S&P Mid Cap 400 Gas Utility Index (S4GASU)
. .
S&P 1500 Oil & Gas Exp & Prod Index (S15OILP)
2018
$100
$100
$100
$100
2019
$86
$104
$105
$64
2020
$78
$120
$74
$35
2021
$105
$155
$91
$82
2022
$126
$131
$93
$122
2023
$110
$160
$84
$144
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
(Reserved)
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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, storage and distribution of natural gas. The Company operates an integrated business, with
assets centered in western New York and Pennsylvania, being utilized for, and benefiting from, the production
and transportation of natural gas from the Appalachian Basin. Current development activities are focused
primarily in the Marcellus and Utica shales. The common geographic footprint of the Company’s subsidiaries
enables them to share management, labor, facilities and support services across various businesses and pursue
coordinated projects designed to produce and transport natural gas from the Appalachian Basin to markets in the
eastern United States and Canada. The Company's efforts in this regard are not limited to affiliated projects.
The Company has also been designing and building pipeline projects for the transportation of natural gas for
non-affiliated natural gas customers in the Appalachian Basin. The Company reports financial results for four
business segments: Exploration and Production, Pipeline and Storage, Gathering, and Utility.
Corporate Responsibility
The Board of Directors and management recognize that the long-term interests of stockholders are served
by considering the interests of customers, employees and the communities in which the Company operates. The
Board retains risk oversight and general oversight of corporate responsibility, including environmental, social
and governance (“ESG”) concerns, and any related health and safety issues that might arise from the
Company’s operations. The Board’s Nominating/Corporate Governance Committee oversees and provides
guidance concerning the Company’s practices and reporting with respect to corporate responsibility and ESG
factors that are of significance to the Company and its stakeholders, and may also make recommendations to the
Board regarding ESG initiatives and strategies, including the Company’s progress on integrating ESG factors
into business strategy and decision-making.
Part of the Board and management’s strategic and capital spending decision process includes identifying
and assessing climate-related risks and opportunities. Management reports quarterly to the Board on critical and
potentially emerging risks, including climate-related risks, as part of the Enterprise Risk Management process.
Since the Company operates an integrated business with assets being utilized for, and benefiting from, the
production, transportation and consumption of natural gas, the Board and management consider physical and
transitional climate risks,
technological developments, shifts in market
conditions, including future natural gas usage, and reputational risks, and the impact of those risks on the
Company’s business. The Company reviews and considers adjustments to its approach to capital investment in
response to these risks and developments, with its long-term, returns-focused approach.
including policy and legal risks,
The Company recognizes the important role of ongoing system modernization and efficiency in reducing
greenhouse gas emissions and remains focused on reducing the Company’s carbon footprint, with these efforts
positioning natural gas, and the Company’s related infrastructure, to remain an important part of the energy
In 2021, the Company set methane intensity reduction targets at each of its businesses, an absolute
complex.
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
The Company also incorporated short-term and long-term executive
compensation goals designed to incentivize and reward performance if reduction targets are met or exceeded.
The Company's ability to estimate accurately the time, costs and resources necessary to meet these emissions
reduction targets may change as environmental exposures and opportunities change, technology advances, and
legislative and regulatory updates are issued.
these reduction targets.
Fiscal 2023 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;”
-33-
3. Operating, investing and financing cash flows under the heading “Capital Resources and Liquidity”
and;
4. Other Matters, including: (a) 2023 and projected 2024 funding for the Company’s pension and other
post-retirement benefits; (b) disclosures and tables concerning market risk sensitive instruments;
(c) rate matters in the Company’s New York, Pennsylvania and FERC-regulated jurisdictions;
(d) environmental matters; and (e) effects of inflation.
The information in MD&A should be read in conjunction with the Company’s financial statements in
Item 8 of this report, which includes a comparison of our Results of Operations and Capital Resources and
Liquidity for fiscal 2023 and fiscal 2022. 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 2021 to
fiscal 2022 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, 2022, filed with the SEC on November 18, 2022.
The Company's Exploration and Production segment continues to grow, as evidenced by a 9% growth in
proved reserves from the prior year to a total of 4,536 Bcfe at September 30, 2023. Production increased 19.9
Bcfe during the fiscal year ended September 30, 2023 to a total of 372.5 Bcfe, and is expected to increase again
in fiscal 2024.
On June 1, 2023, the Company completed its acquisition of certain upstream assets located primarily in
Tioga County, Pennsylvania from SWN Production Company, LLC ("SWN") for total consideration of
$124.8 million. As part of the transaction, the Company acquired approximately 34,000 net acres in an area that
is contiguous with existing Company-owned upstream assets. This transaction was accounted for as an asset
acquisition and, as such, the purchase price was allocated to property, plant and equipment.
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 Tioga Pathway Project, would allow for the
transportation of 190,000 Dth per day of shale gas supplies from a new interconnection in northwest Tioga
County, Pennsylvania to an existing Supply Corporation interconnection with Tennessee Gas Pipeline
Company, LLC at Ellisburg and a new virtual delivery point into an existing Transcontinental Gas Pipe Line
Company, LLC’s (“Transco”) capacity lease, providing access to Mid-Atlantic markets. The Tioga Pathway
Project has a target in-service date in late calendar 2026 and a preliminary cost estimate of approximately $90
million. The Tioga Pathway Project is discussed in more detail in the Capital Resources and Liquidity section
that follows.
From a rate perspective, Distribution Corporation, in its Pennsylvania jurisdiction, reached a settlement
with the parties to its rate case proceeding. On June 15, 2023, the PaPUC issued an order adopting the
settlement in full. The settlement authorized an increase in Distribution Corporation's annual base rate
operating revenues of $23 million that became effective August 1, 2023. Distribution Corporation also filed a
rate case proceeding with the NYPSC in its New York jurisdiction on October 31, 2023 seeking an increase of
$88.8 million in its total annual operating revenues for the projected rate year ending September 30, 2025, with
a proposed effective date of October 1, 2024. In addition, Supply Corporation filed a NGA Section 4 rate case
at FERC on July 31, 2023. For further discussion of Distribution Corporation and Supply Corporation rate
matters, refer to the Rate Matters section below.
From a financing perspective, on June 30, 2022, the Company entered into a 364-Day Credit Agreement
(the "364-Day Credit Agreement") with a syndicate of five banks, all of which are also lenders under a Credit
Agreement (as amended from time to time, the "Credit Agreement"). The 364-Day Credit Agreement provided
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 used the proceeds for general corporate purposes, which included using $150.0 million for the
November 2022 redemption of a portion of the Company's outstanding long-term debt with a maturity date in
March 2023.
In March 2023, the Company utilized short-term borrowings and cash on hand to redeem the
remaining long-term debt that had maturity dates in March 2023, which included $350.0 million of 3.75% notes
and $49.0 million of 7.395% notes.
-34-
On May 18, 2023, the Company issued $300.0 million of 5.50% notes due October 1, 2026. The proceeds
of this debt issuance were used for general corporate purposes, including to repay all indebtedness under the
$250.0 million unsecured committed delayed draw term loan under the 364-Day Credit Agreement mentioned
above.
The Company expects to use cash on hand, cash from operations, and short-term and long-term
borrowings, as needed, to meet its financing needs for fiscal 2024. The Company continues to evaluate these
financing needs and options to meet them. Given the current economic conditions, which include continued
inflationary pressures and rising interest rates, the cost and/or availability of capital may be impacted, but the
Company continues to expect to meet its financing needs as discussed above.
In early 2023, turmoil with certain financial institutions created uncertainty in the economy. While the
Company was not directly impacted, it continues to closely monitor any potential future impacts on the
business. The Company has a diverse group of twelve banks that participate in its multi-year credit facility. All
of these banks have solid investment grade credit ratings. Additionally, the Company regularly reviews the
credit quality of its hedging counterparties, those that provide credit support for customers, and any other
material counterparties, and has not identified any material risks as a result of the current economic uncertainty.
CRITICAL ACCOUNTING ESTIMATES
The Company has prepared its consolidated financial statements in conformity with GAAP. The
preparation of these financial statements requires management to make estimates and assumptions that affect the
reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the
financial statements and the reported amounts of revenues and expenses during the reporting period. Actual
results could differ from those estimates. In the event estimates or assumptions prove to be different from actual
results, adjustments are made in subsequent periods to reflect more current information. The following is a
summary of the Company’s most critical accounting estimates, which are defined as those estimates whereby
judgments or uncertainties could affect the application of accounting policies and materially different amounts
could be reported under different conditions or using different assumptions. For a complete discussion of the
Company’s significant accounting policies, refer to Item 8 at Note A — Summary of Significant Accounting
Policies.
Oil and Gas Exploration and Development Costs.
In the Company's Exploration and Production
segment, gas and oil property acquisition, exploration and development costs are capitalized under the full cost
method of accounting, with natural gas properties in the Appalachian region being the primary component of
these capitalized costs after the June 30, 2022 sale of the Company's California oil and natural gas properties.
That sale is discussed in more detail in Item 8 at Note B — Asset Acquisitions and Divestitures. Under this
accounting methodology, all costs associated with property acquisition, exploration and development activities
are capitalized, including internal costs directly identified with acquisition, exploration and development
activities. The internal costs that are capitalized do not include any costs related to production, general corporate
overhead, or similar activities. The Company does not recognize any gain or loss on the sale or other disposition
of oil and gas properties unless the gain or loss would significantly alter the relationship between capitalized
costs and proved reserves of oil and gas attributable to a cost center.
Proved reserves are estimated quantities of reserves that, based on geologic and engineering data, appear
with reasonable certainty to be producible under existing economic and operating conditions. Such estimates of
proved reserves are inherently imprecise and may be subject to substantial revisions as a result of numerous
factors including, but not limited to, additional development activity, evolving production history and continual
reassessment of the viability of production under varying economic conditions. The estimates involved in
determining proved reserves are critical accounting estimates because they serve as the basis over which
capitalized costs are depleted under the full cost method of accounting (on a units-of-production basis).
Unproved properties are excluded from the depletion calculation until proved reserves are found or it is
determined that the unproved properties are impaired. All costs related to unproved properties are reviewed
quarterly to determine if impairment has occurred. The amount of any impairment is transferred to the pool of
capitalized costs being amortized.
-35-
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 unproved properties not being depleted, less (c) income
tax effects related to the differences between the book and tax basis of the properties. The estimates of future
production and future expenditures are based on internal budgets that reflect planned production from current
wells and expenditures necessary to sustain such future production. The amount of the ceiling can fluctuate
significantly from period to period because of additions to or subtractions from proved reserves and significant
fluctuations in natural gas prices. The ceiling is then compared to the capitalized cost of oil and gas properties
less accumulated depletion and related deferred income taxes. If the capitalized costs of oil and gas properties
less accumulated depletion and related deferred taxes exceeds the ceiling at the end of any fiscal quarter, a non-
cash impairment charge must be recorded to write down the book value of the reserves to their present value.
This non-cash impairment cannot be reversed at a later date if the ceiling increases. It should also be noted that
a non-cash impairment to write down the book value of the reserves to their present value in any given period
causes a reduction in future depletion expense. At September 30, 2023, the ceiling exceeded the book value of
the oil and gas properties by approximately $794.7 million. The 12-month average of the first day of the month
price for natural gas for each month during 2023, based on the quoted Henry Hub spot price for natural gas, was
$3.42 per MMBtu. (Note — because actual pricing of the Company’s producing properties vary depending on
their location and hedging, the prices used to calculate the ceiling may differ from the Henry Hub price, which
is only indicative of 12-month average prices for 2023. Actual realized pricing includes adjustments for regional
market differentials, transportation fees and contractual arrangements.) In regard to the sensitivity of the ceiling
test calculation to commodity price changes, if natural gas prices were $0.25 per MMBtu lower than the average
prices used at September 30, 2023 in the ceiling test calculation, the ceiling would have exceeded the book
value of the Company's oil and gas properties by approximately $442.9 million (after-tax), which would not
have resulted in an impairment charge. This calculated amount is based solely on price changes and does not
take into account any other changes to the ceiling test calculation, including, among others, changes in reserve
quantities and future cost estimates.
It is difficult to predict what factors could lead to future non-cash impairments under the SEC’s full cost
ceiling test. As discussed above, fluctuations in or subtractions from proved reserves, increases in development
costs for undeveloped reserves and significant fluctuations in natural gas prices have an impact on the amount
of the ceiling at any point in time.
As discussed above, the full cost method of accounting provides a ceiling to the amount of costs that can
be capitalized in the full cost pool. In accordance with current authoritative guidance, the future cash outflows
associated with plugging and abandoning wells are excluded from the computation of the present value of
estimated future net revenues for purposes of the full cost ceiling calculation.
Regulation. The Company is subject to regulation by certain state and federal authorities. The Company,
in its Utility and Pipeline and Storage segments, has accounting policies which conform to the FASB
authoritative guidance regarding accounting for certain types of regulations, and which are in accordance with
the accounting requirements and ratemaking practices of the regulatory authorities. The application of these
accounting principles for certain types of rate-regulated activities provides 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
-36-
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 Consolidated Statement of Income 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 F — Regulatory Matters.
RESULTS OF OPERATIONS
EARNINGS
2023 Compared with 2022
The Company's earnings were $476.9 million in 2023 compared with earnings of $566.0 million in 2022.
The decrease in earnings of $89.1 million was a result of lower earnings in all reportable segments, as well as
losses in the Corporate and All Other categories. In the discussion that follows, all amounts used in the earnings
discussions are after-tax amounts, unless otherwise noted. Earnings were impacted by the following events in
2022:
2022 Events
•
•
•
•
•
•
The reversal of a deferred tax valuation allowance of $24.9 million recorded in the Exploration and
Production and Gathering segments, which increased earnings in 2022.
A $28.4 million remeasurement of accumulated deferred income taxes, primarily in the Exploration and
Production and Gathering segments, related to a reduction in the Pennsylvania state corporate income
tax rate that was signed into law in July 2022, which increased earnings in 2022.
A gain recognized on the sale of Seneca's California assets of $12.7 million ($9.5 million after-tax)
recorded during 2022 in the Exploration and Production segment related to a portion of the sale price
that was applied to assets that were not subject to the full cost method of accounting.
A loss of $44.6 million ($33.3 million after-tax) recorded during 2022 in the Exploration and Production
segment related to the termination of this segment's remaining crude oil derivative contracts as a result
of the sale of Seneca's California assets.
Transaction and 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 in accordance with a regulatory proceeding in
Distribution Corporation's Pennsylvania service territory.
Earnings (Loss) by Segment
Year Ended September 30
2023
2022
2021
Exploration and Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Pipeline and Storage . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gathering . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Utility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total Reported Segments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
All Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Corporate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total Consolidated . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
232,275
100,501
99,724
48,395
480,895
(531)
(3,498)
476,866
(Thousands)
306,064
$
102,557
101,111
68,948
578,680
(9)
(12,650)
566,021
$
$
$
101,916
92,542
80,274
54,335
329,067
37,645
(3,065)
363,647
-37-
EXPLORATION AND PRODUCTION
Revenues
Exploration and Production Operating Revenues
Gas (after Hedging) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Oil (after Hedging)(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gas Processing Plant . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Operating Revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
948,484
2,261
1,203
6,507
958,455
$
930,130
113,588
3,511
(36,765)
$ 1,010,464
Year Ended September 30
2023
2022
(Thousands)
Production
Gas Production (MMcf)
Year Ended September 30
2023
2022
Appalachia . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
West Coast . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
372,271
—
372,271
Oil Production (Mbbl)
Appalachia . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
West Coast . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
30
—
30
341,700
1,211
342,911
16
1,588
1,604
Average Prices
Average Gas Price/Mcf
Year Ended September 30
2023
2022
Appalachia . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
West Coast(2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Weighted Average Before Hedging . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Weighted Average After Hedging(3) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
2.78
$
N/A $
$
2.78
$
2.55
Average Oil Price/Barrel (Bbl)
Appalachia . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
West Coast(2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Weighted Average Before Hedging . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Weighted Average After Hedging(1)(3) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
75.64
$
N/A $
$
$
75.64
75.64
5.03
10.03
5.05
2.71
97.82
94.06
94.10
70.80
(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) Prices for the year ended September 30, 2023 are not applicable (N/A) as a result of the sale of Seneca's
West Coast assets in June 2022.
(3) 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.
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2023 Compared with 2022
Operating revenues for the Exploration and Production segment decreased $52.0 million in 2023 as
compared with 2022. Gas production revenue after hedging increased $18.4 million primarily due to a 29.4 Bcf
increase in gas production offset by a $0.16 per Mcf decrease in the weighted average realized price of gas after
hedging. The increase in gas production was largely due to new Marcellus and Utica wells in the Appalachian
region. Oil production revenue after hedging decreased $111.3 million mainly attributable to the sale of
California assets at June 30, 2022. In addition, other revenue increased $43.3 million and plant revenue
decreased $2.3 million. The increase in other revenue was primarily attributable to the non-recurrence of a loss
on the discontinuance of crude oil cash flow hedges as a result of the sale of California assets combined with the
non-recurrence of royalty shut-in payments made in 2022 in accordance with lease agreements. These increases
to other revenue were partially offset by decreases to temporary capacity release revenue and a decrease in
operating revenue from this segment's water treatment plants. Finally, the decrease in gas processing plant
revenues was mainly attributable to the sale of California assets combined with declining gas pricing.
Refer to further discussion of derivative financial instruments in the “Market Risk Sensitive Instruments”
section that follows. Refer to the tables above for production and price information.
Earnings
2023 Compared with 2022
The Exploration and Production segment’s earnings for 2023 were $232.3 million, a decrease of $73.8
million when compared with earnings of $306.1 million for 2022. The sale of California assets on June 30,
2022 was a large factor in the earnings variance year over year. As a result of the sale, 2023 earnings decreased
due to lower oil production ($88.1 million) and the non-recurrence of a gain that was recognized on the sale of
Seneca’s California non-full cost pool assets ($9.5 million). However, these factors were partially offset by the
non-recurrence of a 2022 loss related to the discontinuance of its crude oil cash flow hedges ($33.3 million) and
2022 transaction and severance costs associated with the sale ($7.2 million). There was also a lower unrealized
loss recognized in 2023 ($0.7 million) on contingent consideration received as part of the California asset sale
as compared to the unrealized loss that was recognized in 2022 ($3.2 million) on that contingent consideration.
Other factors impacted by the sale included lower lease operating and transportation expenses ($24.0 million),
lower other operating expenses ($11.1 million), and lower other taxes ($6.0 million). Excluding the impact of
the California sale, lease operating and transportation costs in the Appalachian region increased year over year.
Other operating costs were also impacted by the non-recurrence of abandonment costs recognized in 2022 for
certain offshore Gulf of Mexico wells that were formerly owned by Seneca, and other taxes was also impacted
by lower Impact Fees in the Appalachain region. Aside from the earnings impact of these items, the earnings
decrease reflected lower natural gas prices after hedging ($48.4 million), lower other revenue ($1.1 million) and
lower gas processing plant revenue ($1.8 million), all of which are discussed above. Other factors that
decreased earnings included higher depletion expense ($26.1 million), higher interest expense ($0.7 million)
and higher income tax expense ($3.4 million). In 2022, 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) in 2022 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.
Partially offsetting these items, the Exploration and Production segment had higher natural gas production
($62.9 million), and higher other income ($2.7 million).
The increase in depletion expense was primarily due to the increase in production, combined with a $0.06
per Mcfe increase in the depletion rate. The year over year increase in the depletion rate was mainly driven by
higher capitalized costs and an increase in future development costs related to proved undeveloped wells. The
increase in interest expense can largely be attributed to higher average interest rates on short-term and long-term
borrowings offset partially by lower intercompany long-term debt balances. The increase in income tax
expense was primarily driven by a prior-year benefit realized from the Enhanced Oil Recovery tax credit, which
-39-
did not recur in the current year as a result of the sale of the California assets. The increase in other income was
attributable to higher interest income, as well as non-service pension and post-retirement income in 2023
compared to non-service pension and post-retirement benefit costs in 2022.
PIPELINE AND STORAGE
Revenues
Pipeline and Storage Operating Revenues
Firm Transportation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Interruptible Transportation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Firm Storage Service . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interruptible Storage Service . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
Pipeline and Storage Throughput — (MMcf)
Firm Transportation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interruptible Transportation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Year Ended September 30
2023
2022
(Thousands)
289,935
1,290
291,225
84,960
2
84,962
3,004
379,191
$
$
287,486
2,481
289,967
84,565
—
84,565
2,512
377,044
Year Ended September 30
2023
816,484
2,192
818,676
2022
790,417
5,612
796,029
2023 Compared with 2022
Operating revenues for the Pipeline and Storage segment increased $2.1 million in 2023 as compared with
2022. The increase in operating revenues was primarily due to an increase in transportation revenues of $1.3
million, an increase in storage revenues of $0.4 million and an increase in other revenues of $0.5 million. The
increase in transportation revenues was primarily attributable to new demand charges for transportation service
from Supply Corporation's FM100 Project, which was placed into service in December 2021. The increase
from the FM100 Project includes the impact of a negotiated revenue step-up to Period 2 Rates that went into
effect April 1, 2022, as specified in Supply Corporation's 2020 rate case settlement. An increase in short-term
contracts also contributed to the increase in transportation revenues. These increases were partially offset by a
decline in revenues associated with miscellaneous contract expirations and revisions. The increase in other
revenues primarily reflects proceeds received during the quarter ended September 30, 2023 as a result of a
contract buyout.
Transportation volume increased by 22.6 Bcf in 2023 as compared with 2022, primarily due to an
increase in short-term contracts, as well as an increase in volume from the FM100 Project. These increases
were partially offset by certain contract expirations during fiscal 2023. Volume fluctuations, other than those
caused by the addition or termination of contracts, generally do not have a significant impact on revenues as a
result of the straight fixed-variable rate design utilized by Supply Corporation and Empire.
The 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 Pipeline and Storage segment's contracted
transportation and storage capacity with both affiliated and unaffiliated shippers is expected to remain relatively
constant in fiscal 2024.
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Earnings
2023 Compared with 2022
The Pipeline and Storage segment’s earnings in 2023 were $100.5 million, a decrease of $2.1 million
when compared with earnings of $102.6 million in 2022. The decrease in earnings was primarily due to an
increase in operating expenses ($5.2 million) and an increase in depreciation expense ($2.5 million). The
increase in operating expenses was primarily due to higher personnel costs, higher pipeline integrity costs and
an increase in compressor maintenance costs. The increase in depreciation expense was primarily due to
incremental depreciation from the FM100 Project. These earnings decreases were partially offset by the impact
of higher operating revenues ($1.7 million), as discussed above, combined with higher other income ($3.6
million). The increase in other income is primarily due to a higher weighted average interest rate on
intercompany short-term notes receivables along with higher non-service pension and post-retirement benefit
income. This was partially offset by a decrease in allowance for funds used during construction (equity
component) related to the construction of the FM100 Project along with an annual adjustment that was recorded
during the current fiscal year.
GATHERING
Revenues
Gathering Operating Revenues
Year Ended September 30
2023
2022
(Thousands)
Gathering . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
230,317
$
214,843
Gathering Volume — (MMcf)
Gathered Volume . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2023 Compared with 2022
Year Ended September 30
2023
453,338
2022
419,332
Operating revenues for the Gathering segment increased $15.5 million in 2023 as compared with 2022,
which was driven primarily by a 34.0 Bcf increase in gathered volume. Gathered volume on the Tioga and
Clermont gathering systems increased 36.3 Bcf and 7.1 Bcf, respectively, partially offset by a decrease of 9.4
Bcf on the Trout Run gathering system. The net increase in gathered volume can be attributed to the increase in
gross natural gas production in the Appalachian region by producers connected to the aforementioned gathering
systems. All references to the Tioga gathering system in this operating revenues discussion and the earnings
discussion that follows include the revenues, volume and earnings of the gathering system owned by NFG
Midstream Covington, LLC (Covington), which includes the gathering system previously owned by NFG
Midstream Wellsboro, LLC (Wellsboro). Wellsboro was merged into Covington effective August 31, 2023.
The merger of Wellsboro into Covington reflects the completion of a pipeline that connects the two systems.
Earnings
2023 Compared with 2022
The Gathering segment’s earnings in 2023 were $99.7 million, a decrease of $1.4 million when compared
with earnings of $101.1 million in 2022. Income taxes were a significant factor in the year over year variation.
First, earnings were negatively impacted by the non-recurrence of an income tax benefit ($11.9 million) during
the quarter ended September 30, 2022 from the remeasurement of deferred income taxes related to a state
corporate income tax rate reduction in Pennsylvania that was signed into law in July 2022 (as discussed above,
in the Exploration and Production segment). This segment also experienced an increase in income tax expense
($1.0 million) due to higher state income tax expense. Partially offsetting these factors, earnings benefited from
the non-recurrence of deferred income tax expense ($3.7 million) recognized during the quarter ended
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September 30, 2022 as an offset to the Exploration and Production segment's reversal of the deferred tax asset
valuation allowance. This offset is a result of the Gathering and Exploration and Production segments'
subsidiaries filing a combined state tax return. In addition to these income tax variations, earnings decreased due
to higher operating expenses ($4.9 million) and higher depreciation expense ($1.4 million). The increase in
operating expenses was largely attributable to higher outside service costs associated with preventative
maintenance overhauls on the Clermont, Tioga and Trout Run gathering systems, higher leased compression
expense on the Trout Run and Tioga gathering systems and higher labor-related costs across all of the gathering
systems. The increase in depreciation expense was largely due to higher plant balances associated with the
Tioga and Clermont gathering systems. These earnings decreases were partially offset by the impact of higher
gathering revenues ($12.2 million) driven by the increase in gathered volume (discussed above). Additionally,
earnings increased due to lower interest expense ($1.2 million) and higher other income ($0.6 million). The
decrease in interest expense was primarily due to higher capitalized interest and lower interest on intercompany
long-term borrowings associated with the Company's redemption of $500.0 million of 3.75% notes during 2023.
The increase in other income is primarily due to lower non-service pension and post-retirement benefit
expenses.
UTILITY
Revenues
Utility Operating Revenues
Retail Revenues:
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Residential
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Commercial
Industrial . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Transportation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
Utility Throughput — million cubic feet (MMcf)
Retail Sales:
Residential
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Commercial
Industrial . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Transportation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Year Ended September 30
2023
2022
(Thousands)
729,715
103,150
5,682
838,547
103,305
508
942,360
$
$
691,034
95,120
4,913
791,067
111,072
(3,918)
898,221
Year Ended September 30
2023
2022
61,401
9,342
548
71,291
62,986
134,277
64,011
9,621
541
74,173
65,993
140,166
-42-
Degree Days
Percent (Warmer)
Colder Than
Year Ended September 30
2023 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2022 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Buffalo, NY
Erie, PA(2)
Buffalo, NY
Erie, PA
Normal
6,617
6,104
6,617
6,147
Actual
5,717
5,493
5,769
5,368
Normal(1)
(13.6)%
(10.0)%
(12.8)%
(12.7)%
Prior Year(1)
(0.9)%
2.3 %
0.7 %
2.8 %
(1) Percents compare actual degree days to normal degree days and actual degree days to actual prior year
degree days.
(2) Normal degree days changed from the NOAA 30-year degree days to NOAA 15-year degree days with
the implementation of new base rates in Pennsylvania in August 2023.
2023 Compared with 2022
Operating revenues for the Utility segment increased $44.1 million in 2023 compared with 2022. The
increase resulted from a $47.5 million increase in retail gas sales revenue and a $4.4 million increase in other
revenues, which were partially offset by a $7.8 million decrease in transportation revenue. The increase in retail
gas sales revenue was primarily due to an increase in the cost of gas sold (per Mcf), partially offset by a 2.9 Bcf
decrease in throughput due to warmer weather during the winter months and a decrease in base rates. The
decrease in base rates is related to a tariff filing approved by the NYPSC, which created a surcredit that
temporarily eliminates pension and OPEB cost recovery from base rates effective October 1, 2022. Additional
details related to the regulatory proceeding are discussed in Item 8 at Note F — Regulatory Matters. The
increase in other revenues was due to an increase in capacity release revenues and a smaller estimated refund
provision from the income tax benefits resulting from the 2017 Tax Reform Act. The decrease in transportation
revenue resulted from a 3.0 Bcf decrease in throughput due to warmer weather and the decrease in base rates, as
previously mentioned. The decreases in gas retail sales revenue and transportation revenue were partially offset
by an increase in revenues earned under the system modernization and system improvement
tracker
mechanisms in Distribution Corporation's New York jurisdiction, which allow for the recovery of investments
in leak prone pipe replacement.
Purchased Gas
The cost of purchased gas is one of the Company’s largest operating expenses. Annual variations in
purchased gas costs are attributed directly to changes in gas sales volume, the price of gas purchased and the
operation of purchased gas adjustment clauses. Distribution Corporation recorded $548.2 million and
$498.0 million of Purchased Gas expense during 2023 and 2022, respectively. Under its purchased gas
adjustment clauses in New York and Pennsylvania, Distribution Corporation does not profit from fluctuations in
gas costs. Purchased Gas expense recorded on the consolidated income statement matches the revenues
collected from customers, a component of Operating Revenues on the consolidated income statement. Under
mechanisms approved by the NYPSC in New York and the PaPUC in Pennsylvania, any difference between
actual purchased gas costs and what has been collected from the customer is deferred on the consolidated
balance sheet as either an asset, Unrecovered Purchased Gas Costs, or a liability, Amounts Payable to
Customers. These deferrals are subsequently collected from the customer or passed back to the customer,
subject to review by the NYPSC and the PaPUC. Absent disallowance of full recovery of Distribution
Corporation’s purchased gas costs, such costs do not impact the profitability of the Company. Purchased gas
costs impact cash flow from operations due to the timing of recovery of such costs versus the actual purchased
gas costs incurred during a particular period. Distribution Corporation’s purchased gas adjustment clauses seek
to mitigate this impact by adjusting revenues on either a quarterly or monthly basis.
Distribution Corporation contracts for firm long-term transportation and storage capacity services with
rights-of-first-refusal from ten upstream pipeline companies including Supply Corporation for transportation
and storage services and Empire, for transportation services. Distribution Corporation contracts for firm spot
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and term gas supplies with various producers, marketers and two local distribution companies to meet its gas
purchase requirements. Additional discussion of the Utility segment’s gas purchases appears under the heading
“Sources and Availability of Raw Materials” in Item 1.
Earnings
2023 Compared with 2022
The Utility segment’s earnings in 2023 were $48.4 million, a decrease of $20.5 million when compared
with earnings of $68.9 million in 2022. The decrease in earnings was due in part to the impact of a proceeding
in the Utility's Pennsylvania service territory during the quarter ended March 31, 2022 that allowed for a
favorable one-time adjustment of $14.6 million to recognize the cumulative amount of OPEB income,
previously deferred as a regulatory liability in that jurisdiction, which did not recur in 2023. In addition to the
non-recurrence of this transaction, there was a decrease in OPEB income ($2.4 million) in the Utility's
Pennsylvania service territory.
The earnings impact of the reduction in the New York jurisdiction's base rates in 2023 resulting from the
NYPSC tariff filing related to pension and OPEB costs discussed above ($12.0 million), combined with an
increase in operating costs ($2.0 million) associated with the elimination of fringe benefit credits being applied
to service and non-service pension and OPEB costs, was offset by a decrease in other deductions associated
with non-service pension and OPEB costs ($14.0 million). With the elimination of pension and OPEB expenses
in customer rates, Distribution Corporation’s New York service territory did not recognize any pension and
OPEB expenses during 2023 compared to the prior year when it recognized pension and OPEB expenses to
match against the pension and OPEB amounts collected in base rates.
Other factors that contributed to the earnings decrease in the Utility segment included higher operating
expenses ($6.8 million) and higher interest expense ($8.6 million). The increase in operating expenses was
mainly due to higher personnel costs and outside services. The increase in interest expense was largely the
result of a higher weighted average interest rate on intercompany short-term borrowings combined with higher
average short-term debt balances. There were also several factors that helped to reduce the earnings decrease
year over year. The Utility segment's earnings benefited from the impact of the system modernization and
system improvement trackers in New York ($3.8 million), lower income tax expense ($3.5 million) in New
York and Pennsylvania, of which $1.7 million relates to a methodology change for the repair and maintenance
tax deduction in Pennsylvania, higher capacity release revenues ($1.6 million), and a regulatory adjustment
($1.5 million). The Utility's Pennsylvania service territory also benefited from new rates that went into effect
August 1, 2023 ($0.8 million).
The impact of weather variations on earnings in the Utility segment's New York rate jurisdiction is largely
mitigated by that jurisdiction's weather normalization clause (WNC). The WNC in New York, which covers the
eight-month period from October through May, has had a stabilizing effect on earnings for the New York rate
jurisdiction. In addition, in periods of colder than normal weather, the WNC benefits the Utility segment's New
York customers. For both 2023 and 2022, the WNC contributed approximately $4.8 million to earnings, as the
weather was warmer than normal. Effective October 2023, the weather impact on cash flow in the Utility
segment will also be mitigated by a WNC in its Pennsylvania rate jurisdiction.
ALL OTHER AND CORPORATE OPERATIONS
Earnings
2023 Compared with 2022
All Other and Corporate operations had a net loss of $4.0 million in 2023, an improvement of $8.7
million when compared with a net loss of $12.7 million in 2022. The improvement was primarily attributable to
changes in unrealized gains and losses on investments in equity securities. In 2023, the Company recorded
unrealized gains of $0.7 million, while in 2022, the Company recorded unrealized losses of $9.2 million. Other
contributing factors include an increase in the cash surrender value of life insurance policies ($1.3 million), an
increase in interest income on temporary cash investments ($1.3 million) and lower non-service pension and
post-retirement benefit costs ($2.1 million). These changes were partially offset by a decrease in realized gains
-44-
from sales of investments in equity securities ($2.9 million), as well as an increase in operating expenses as a
result of an increase in professional services ($2.7 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 income on the Consolidated Statements of Income was $18.1 million in 2023 compared to net
other deductions of $1.5 million in 2022, for a net increase of $19.6 million. This was mostly due to changes in
unrealized and realized gains and losses on investments in equity securities of $10.4 million, along with an
increase in the cash surrender value of life insurance policies of $1.3 million. Higher interest income of $5.0
million also contributed to the increase, which resulted from an increase in interest on temporary cash
investments, an increase in interest on a larger undercollection of gas costs over the prior year in Distribution
income earned on investments. The mark-to-market valuation
Corporation and an increase in interest
adjustment for the contingent consideration received from the sale of Seneca's California assets in June 2022
was a loss of $0.9 million during 2023 as compared to a loss of $4.4 million during 2022. There was also a $1.9
million increase in non-service pension and post-retirement benefit income year over year. Offsetting these
increases was a $2.3 million reduction in allowance for funds used during construction.
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 $8.6 million in 2023 as compared to 2022. The Company redeemed
$150.0 million of the $500.0 million 3.75% notes in November 2022.
In addition, $350.0 million of $500.0
million 3.75% notes and $49.0 million of 7.395% notes were redeemed in March 2023. These redemptions
were partially offset by the issuance of $300.0 million of 5.50% notes in May 2023.
Other interest expense increased $10.1 million in 2023 as compared to 2022. The increase was primarily
due to higher weighted average interest rates for 2023 partially offset by lower average short-term debt balances
in 2023 compared to 2022.
CAPITAL RESOURCES AND LIQUIDITY
The primary sources and uses of cash during the last two years are summarized in the following
condensed statement of cash flows:
Year Ended September 30
2023
2022
(Millions)
$
Provided by Operating Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 1,237.1
(1,009.9)
Capital Expenditures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
—
Net Proceeds from Sale of Oil and Gas Producing Properties . . . . . . . . . . . . . . . . . . . .
(124.8)
Acquisition of Upstream Assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
10.0
. . . . . . . . . . . . . . . . . . . . .
Sale of Fixed Income Mutual Fund Shares in Grantor Trust
12.3
Other Investing Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(549.0)
Reduction of Long-Term Debt
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
297.3
Net Proceeds from Issuance of Long-Term Debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
250.0
Proceeds from Issuance of Short-Term Note Payable to Bank . . . . . . . . . . . . . . . . . . . .
(250.0)
Repayments of Short-Term Note Payable to Bank . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
227.5
Net Change in Other Short-Term Notes Payable to Banks and Commercial Paper . . . .
(6.7)
Net Repurchases of Common Stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(176.1)
Dividends Paid on Common Stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(82.3) $
Net Increase (Decrease) in Cash, Cash Equivalents, and Restricted Cash . . . . . . . . . . . $
812.5
(811.8)
254.4
—
30.0
8.7
—
—
—
—
(98.5)
(9.6)
(168.1)
17.6
-45-
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
2024, cash provided by operating activities is forecasted to be lower than 2023 largely due to a decrease in
working capital sources, but is expected to be more than enough to fund the Company's capital expenditures.
Looking forward to 2025, based on current commodity prices, cash provided by operating activities is again
expected to exceed capital expenditures. The Company also has two long-term debt maturities in 2025, totaling
$500.0 million, which the Company anticipates funding with cash on hand and short-term and long-term
borrowings. 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 Pipeline and Storage segment by the straight fixed-variable rate
design used by Supply Corporation and Empire. Prior to October 2023, the weather impact on cash flow in the
Utility segment was mitigated by a WNC solely in its New York rate jurisdiction. However, effective October
2023, the weather impact on cash flow in the Utility segment will also be mitigated by a WNC in its
Pennsylvania rate jurisdiction. Refer to Item 8 at Note A — Summary of Significant Accounting Policies
(Regulatory Mechanisms) for additional discussion.
Cash provided by operating activities in the Exploration and Production segment may vary from year to
year as a result of changes in the commodity prices of natural gas as well as changes in production. The
Company uses various derivative financial instruments, including price swap agreements and no cost collars, in
an attempt to manage this energy commodity price risk.
The Company,
in its Utility segment and Exploration and Production segment, has entered into
contractual commitments in the ordinary course of business,
including commitments to purchase gas,
transportation, and storage service to meet customer gas supply needs. Refer to Item 8 at Note L —
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 $1,237.1 million in 2023, an increase of $424.6 million
compared with the $812.5 million provided by operating activities in 2022. The increase in cash provided by
operating activities primarily reflects higher cash provided by operating activities in the Exploration and
Production segment and Utility segment. The increase in the Exploration and Production segment is primarily
due to higher cash receipts from natural gas production, net of royalty and working interests. The increase in the
Utility segment is primarily due to the timing of gas cost recovery and the timing of customer receivable
balance collections.
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INVESTING CASH FLOW
Expenditures for Long-Lived Assets
The Company’s expenditures for long-lived assets, including non-cash capital expenditures, totaled $1.12
billion and $829.4 million in 2023 and 2022, respectively. The table below presents these expenditures:
Year Ended September 30
2023
2022
(Millions)
Exploration and Production:
Capital Expenditures (1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 737.7 (2)
$ 565.8 (3)
Pipeline and Storage:
Capital Expenditures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
141.9 (2)
95.8 (3)
Gathering:
Capital Expenditures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
103.3 (2)
55.5 (3)
Utility:
Capital Expenditures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
139.9 (2)
111.0 (3)
All Other and Corporate:
Capital Expenditures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
0.8
Total Expenditures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $1,123.6
1.3
$ 829.4
(1) The year ended September 30, 2023 includes $124.8 million related to the acquisition of upstream assets
acquired from SWN. The acquisition cost is reported as a component of Acquisition of Upstream Assets
on the Consolidated Statement of Cash Flows.
(2) 2023 capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment,
the Gathering segment and the Utility segment include $43.2 million, $31.8 million, $20.6 million and
$13.6 million, respectively, of non-cash capital expenditures.
(3) 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.
Exploration and Production
In 2023, the Exploration and Production segment capital expenditures were primarily well drilling and
completion expenditures in the Appalachian region and included $292.6 million in the Marcellus Shale area and
$430.7 million in the Utica Shale area. These amounts included approximately $342.0 million spent to develop
proved undeveloped reserves.
On June 1, 2023, the Company completed its acquisition of certain upstream assets located primarily in
Tioga County, Pennsylvania from SWN for total consideration of $124.8 million. As part of the transaction, the
Company acquired approximately 34,000 net acres in an area that is contiguous with existing Company-owned
upstream assets. This transaction was accounted for as an asset acquisition and, as such, the purchase price was
allocated to property, plant and equipment.
Other 2023 acquisitions included the acquisition of certain upstream assets located in Lycoming County
in Northeast Pennsylvania for total consideration of $11.5 million as well as the acquisition of undeveloped
acreage in Tioga County, Pennsylvania for $13.6 million. The acquisition in Lycoming County included 1,145
net acres and the acquisition in Tioga County included 4,222 net acres. Both transactions were accounted for as
asset acquisitions and, as such, the purchase price for each transaction was allocated to property, plant and
equipment. The cost of these acquisitions is reported as a component of Capital Expenditures on the
Consolidated Statement of Cash Flows.
In 2022, the Exploration and Production segment capital expenditures were primarily well drilling and
completion expenditures and included approximately $547.1 million for the Appalachian region (including
$161.4 million in the Marcellus Shale area and $370.6 million in the Utica Shale area) and $18.7 million for the
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West Coast region. These amounts included approximately $154.3 million spent to develop proved undeveloped
reserves.
Pipeline and Storage
The Pipeline and Storage segment’s capital expenditures for 2023 were primarily for additions,
improvements and replacements to this segment's transmission and gas storage systems, which included system
modernization expenditures that enhance the reliability and safety of the systems and reduce emissions.
The Pipeline and Storage segment’s capital expenditures for 2022 were primarily for additions,
improvements and replacements to this segment's transmission and gas storage systems, which included system
modernization expenditures that enhance the reliability and safety of the systems and reduce emissions. In
addition, the Pipeline and Storage segment capital expenditures for 2022 include expenditures related to Supply
Corporation's FM100 Project ($25.2 million).
Gathering
The majority of the Gathering segment's capital expenditures for 2023 included expenditures related to
the continued expansion of Midstream Company's Clermont, Tioga and Trout Run gathering systems, as
discussed below. The Tioga gathering system refers to the gathering system owned by NFG Midstream
Covington, LLC (Covington), which includes the gathering system previously owned by NFG Midstream
Wellsboro, LLC (Wellsboro). Wellsboro was merged into Covington effective August 31, 2023. The merger of
Wellsboro into Covington reflects the completion of a pipeline that connects the two systems. Midstream
Company spent $20.7 million, $71.2 million and $10.8 million, respectively, in 2023 on the development of the
Clermont, Tioga and Trout Run gathering systems. These expenditures were largely attributable to the
installation of new in-field gathering pipelines related to bringing new development online, as well as the
continued development of centralized station facilities,
including increased dehydration capacity and
compression horsepower.
The majority of the Gathering segment's capital expenditures for 2022 included expenditures related to
the continued expansion of Midstream Company's Clermont, Covington, Trout Run and Wellsboro gathering
systems. Midstream Company spent $20.9 million, $27.0 million, $4.9 million and $2.3 million in 2022 on the
development of the Clermont, Covington, Trout Run and Wellsboro gathering systems, respectively. These
expenditures were largely attributable to the installation of new in-field gathering pipelines in the Clermont
gathering system, as well as the continued expansion of centralized station facilities, including increased
compression horsepower at
the Clermont, Trout Run, and Wellsboro gathering systems. In Covington,
expenditures were largely attributable to the installation of in-field gathering pipelines and upgraded station
facilities related to new development.
Utility
The majority of the Utility segment’s capital expenditures for 2023 and 2022 were made for main and
service line improvements and replacements that enhance the reliability and safety of the system and reduce
emissions. Expenditures were also made for main extensions.
Other Investing Activities
In October 2021, the Company sold $30 million of fixed income mutual fund shares held in a grantor trust
that was established for the benefit of Pennsylvania ratepayers. The proceeds were used in the Utility segment’s
Pennsylvania service territory to fund a one-time customer bill credit of $25 million in October 2021 for
previously overcollected OPEB expenses and the first year installment of a 5-year pass back of an additional
$29 million in previously overcollected OPEB expenses in accordance with new rates that went into effect on
October 1, 2021. In October 2022, the Company sold an additional $10 million of fixed income mutual fund
shares held in the grantor trust. The proceeds from this sale were used to fund the second year installment of the
5-year pass back of overcollected OPEB expenses, as well as to diversify a portion of grantor trust investments
into lower risk money market mutual fund shares. Please refer to the Rate Matters section that follows for
additional discussion of this matter.
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In March 2022, the Company completed the sale of certain oil and gas assets located in Tioga County,
Pennsylvania effective as of October 1, 2021. The Company received net proceeds of $13.5 million from this
sale. Under the full cost method of accounting for oil and natural gas properties, the sale proceeds were
accounted for as a reduction of capitalized costs. Since the disposition did not significantly alter the relationship
between capitalized costs and proved reserves of oil and gas attributable to the cost center, the Company did not
record any gain or loss from this sale.
On June 30, 2022, the Company completed the sale of Seneca’s California assets, all of which were in the
Exploration and Production segment, to Sentinel Peak Resources California LLC for a total sale price of $253.5
million, consisting of $240.9 million in cash and contingent consideration valued at $12.6 million at closing.
The fair value of the contingent consideration was $7.3 million at September 30, 2023. The Company pursued
this sale given the strong commodity price environment and the Company’s strategic focus in the Appalachian
Basin. Under the terms of the purchase and sale agreement, the Company can receive up to three annual
contingent payments between calendar year 2023 and calendar year 2025, not to exceed $10 million per year,
with the amount of each annual payment calculated as $1.0 million for each $1 per barrel that the ICE Brent
Average for each calendar year exceeds $95 per barrel up to $105 per barrel. The sale price, which reflected an
effective date of April 1, 2022, was reduced for production revenues less expenses that were retained by Seneca
from the effective date to the closing date. Under the full cost method of accounting for oil and natural gas
properties, $220.7 million of the sale price at closing was accounted for as a reduction of capitalized costs since
the disposition did not alter the relationship between capitalized costs and proved reserves of oil and gas
attributable to the cost center. The remainder of the sale price ($32.8 million) was applied against assets that are
not subject to the full cost method of accounting, with the Company recognizing a gain of $12.7 million on the
sale of such assets. The majority of this gain related to the sale of emission allowances.
Estimated Capital Expenditures
The Company’s estimated capital expenditures for the next three years are:
Exploration and Production(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Pipeline and Storage . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gathering . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Utility(2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
All Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
Year Ended September 30
2024
2025
2026
(Millions)
520
135
110
150
—
915
$
$
$
$
550
130
100
140
—
920
510
180
95
150
—
935
(1) Includes estimated expenditures for the years ended September 30, 2024, 2025 and 2026 of approximately
$315 million, $225 million and $120 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, 2024, 2025, and 2026 of
approximately $115 million, $115 million and $120 million, respectively, for system modernization and
safety to enhance the reliability and safety of the system and reduce emissions.
Exploration and Production
Capital expenditures for the Exploration and Production segment in 2024 through 2026 are expected to be
primarily well drilling and completion expenditures in the Appalachian region.
Pipeline and Storage
Capital expenditures for the Pipeline and Storage segment in 2024 through 2026 are expected to include:
the replacement and modernization of transmission and storage facilities, the reconditioning of storage wells,
improvements of compressor stations and emissions reduction initiatives, as well as capital expenditures related
to system expansion.
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In addition, due to the continuing demand for pipeline capacity to move natural gas from new wells
being drilled in Appalachia, specifically in the Marcellus and Utica Shale producing areas, Supply Corporation
and Empire have completed and continue to pursue expansion projects designed to move anticipated Marcellus
and Utica production gas to other interstate pipelines and to on-system markets, and markets beyond the Supply
Corporation and Empire pipeline systems. An expansion and modernization project where the Company has
forecasted a significant amount of investment in preliminary survey and investigation costs and/or capital
expenditures in 2024 through 2026, and where a precedent agreement has been executed, is discussed below.
Supply Corporation concluded an Open Season on August 25, 2023, and based on post-open season
discussions, has designed a project that would allow for the transportation of 190,000 Dth per day of shale gas
supplies from a new interconnection in northwest Tioga County, Pennsylvania to an existing Supply
Corporation interconnection with Tennessee Gas Pipeline Company, LLC at Ellisburg and a new virtual
delivery point into an existing Transcontinental Gas Pipe Line Company, LLC’s (“Transco”) capacity lease,
providing access to Mid-Atlantic markets (“Tioga Pathway Project”). The Tioga Pathway Project involves the
construction of approximately 19 miles of new pipeline and the replacement of approximately four miles of
existing pipeline on the Supply Corporation system. Supply Corporation has executed a Precedent Agreement
with Seneca for 190,000 Dth per day of transportation capacity. Supply Corporation expects to file a Section
7(c) application with the FERC in the second half of calendar 2024. The Tioga Pathway project has a projected
in-service date of late calendar year 2026 and an estimated capital cost of approximately $90 million. The
majority of these expenditures are included as Pipeline and Storage segment estimated capital expenditures in
the table above. As of September 30, 2023, less than $0.1 million has been spent to study this project, all of
which has been included in Deferred Charges on the Consolidated Balance Sheet at September 30, 2023.
Gathering
The majority of the Gathering segment capital expenditures in 2024 through 2026, 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 shifted a larger share of its forward-looking 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.
Utility
Capital expenditures for the Utility segment in 2024 through 2026 are expected to be concentrated in the
areas of main and service line improvements and replacements that will enhance the reliability and safety of the
system, emission reduction initiatives and, to a lesser extent, the purchase of new equipment.
Project Funding
During fiscal 2023 and 2022, capital expenditures were funded with cash from operations and short-term
debt. Capital expenditures in fiscal 2022 were also funded with proceeds from the sale of the Company's
California assets. Going forward, the Company expects to use cash on hand, cash from operations and short-
term or long-term borrowings, as needed, to finance capital expenditures. The level of short-term and/or long-
term borrowings will depend upon the amount of cash provided by operations, which, in turn, will likely be
most impacted by natural gas production and the associated commodity price realizations in the Exploration and
Production segment. It will also likely depend on the timing of gas cost recovery in the Utility 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.
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The Company, in its Pipeline and Storage segment, Gathering segment and Utility segment, has entered
into several contractual commitments associated with various pipeline, compressor and gathering system
modernization and expansion projects. Refer to Item 8 at Note L — Commitments and Contingencies under the
heading “Other” for the amounts of contractual commitments expected to be incurred during the next five years
and thereafter associated with the Company’s pipeline, compressor and gathering system modernization and
expansion projects. These amounts are a subset of the estimated capital expenditures for the Pipeline and
Storage segment, Gathering segment and Utility segment that are shown above.
The Company continuously evaluates capital expenditures and potential investments in corporations,
partnerships, and other business entities. The amounts are subject to modification for opportunities such as the
acquisition of attractive natural gas properties, accelerated development of existing natural gas properties,
natural gas storage and transmission facilities, natural gas gathering and compression facilities and the
expansion of natural gas transmission line capacities, regulated utility assets and other opportunities as they may
arise. The amounts are also subject to modification for opportunities involving emission reductions and/or
energy transition including investments directly related to low- and no-carbon fuels. While the majority of
capital expenditures in the Utility segment are necessitated by the continued need for replacement and
upgrading of mains and service lines, the magnitude of future capital expenditures or other investments in the
Company’s business segments depends, to a large degree, upon market and regulatory conditions as well as
legislative actions.
FINANCING CASH FLOW
Consolidated short-term debt increased $227.5 million, to a total of $287.5 million, when comparing the
balance sheet at September 30, 2023 to the balance sheet at September 30, 2022. The maximum amount of
short-term debt outstanding during the year ended September 30, 2023 was $422.3 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, asset purchases, gas-in-storage inventory, unrecovered purchased gas costs, margin calls on
derivative financial instruments, other working capital needs and repayment of long-term debt. Fluctuations in
these items can have a significant impact on the amount and timing of short-term debt. During fiscal 2023, the
Company repaid $549.0 million of long-term debt with maturity dates in March 2023 and issued $300.0 million
of additional long-term debt in May 2023. The net reduction in long-term debt resulted in an increase in the
short-term debt balance. As of September 30, 2023, the Company had outstanding commercial paper of $287.5
million. The Company did not have any short-term notes payable to banks as of September 30, 2023.
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 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 provided 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 used the proceeds for general corporate purposes, which included
using $150.0 million for the November 25, 2022 redemption of a portion of the Company's outstanding long-
term debt with a maturity date of March 1, 2023. All indebtedness under the 364-Day Credit Agreement was
repaid on May 18, 2023.
The Company also has uncommitted lines of credit with financial institutions for general corporate
purposes. Borrowings under these uncommitted lines of credit would be made at competitive market rates. The
uncommitted credit lines are revocable at the option of the financial institution and are reviewed on an annual
basis. The Company anticipates that its uncommitted lines of credit generally will be renewed or substantially
replaced by similar lines. Other financial institutions may also provide the Company with uncommitted or
discretionary lines of credit in the future.
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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 0.65 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, 2023, $190.7
million was added back to the Company's total capitalization for purposes of the calculation under the 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. At September 30, 2023, the Company’s debt
to capitalization ratio, as calculated under the Credit Agreement was 0.46. The constraints specified in the
Credit Agreement would have permitted an additional $3.17 billion in short-term and/or long-term debt to be
outstanding at September 30, 2023 before the Company’s debt to capitalization ratio exceeded 0.65.
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 contains a cross-default provision whereby the failure by the Company or its
significant subsidiaries to make payments under other borrowing arrangements, or the occurrence of certain
events affecting those other borrowing arrangements, could trigger an obligation to repay any amounts
outstanding under the Credit Agreement. In particular, a repayment obligation could be triggered if (i) the
Company or any of its significant subsidiaries fails to make a payment when due of any principal or interest on
any other indebtedness aggregating $40.0 million or more or (ii) an event occurs that causes, or would permit
the holders of any other indebtedness aggregating $40.0 million or more to cause, such indebtedness to become
due prior to its stated maturity.
On May 18, 2023, the Company issued $300.0 million of 5.50% notes due October 1, 2026. After
deducting underwriting discounts, commissions and other debt issuance costs, the net proceeds to the Company
amounted to $297.3 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
7.50%, if certain change of control events involving a material subsidiary result in a downgrade of the credit
rating assigned to the notes to a rating below investment grade. A downgrade with a resulting increase to the
coupon does not preclude the coupon from returning to its original rate if the Company's credit rating is
subsequently upgraded. The proceeds of this debt issuance were used for general corporate purposes, including
to repay all indebtedness under the $250.0 million unsecured committed delayed draw term loan under the 364-
Day Credit Agreement.
None of the Company's long-term debt as of September 30, 2023 had a maturity date within the following
twelve-month period. The Current Portion of Long-Term Debt at September 30, 2022 consisted of $500.0
million of 3.75% notes and $49.0 million of 7.395% notes, that each had maturity dates in March 2023. The
Company utilized short-term borrowings and cash on hand to repay $150.0 million of these maturities in
November 2022 and the remaining $399.0 million in March 2023. As of September 30, 2023, the future
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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: $111.9 million in 2024, $605.9 million in
2025, $565.4 million in 2026, $640.4 million in 2027, $327.9 million in 2028, and $535.7 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 4.69% at September 30, 2023 and 4.48% at
September 30, 2022. Refer to “Interest Rate Risk” in this Item for a more detailed breakdown of the
Company’s embedded cost of long-term debt.
Under the Company's existing indenture covenants at September 30, 2023, the Company would have been
permitted to issue up to a maximum of approximately $3.43 billion in additional unsubordinated long-term
indebtedness at then current market interest rates, in addition to being able to issue new indebtedness to replace
existing debt (further limited by the debt
to capitalization ratio constraint under the Company's Credit
Agreement, as discussed above). The Company's present liquidity position is believed to be adequate to satisfy
known demands. It is possible, depending on amounts reported in various income statement and balance sheet
line items, that the indenture covenants could, for a period of time, prevent the Company from issuing
incremental unsubordinated long-term debt, or significantly limit the amount of such debt that could be issued.
Losses incurred as a result of significant impairments of oil and gas properties have in the past resulted in such
temporary restrictions. The indenture covenants would not preclude the Company from issuing new long-term
debt to replace existing long-term debt, or from issuing additional short-term debt. Please refer to the Critical
Accounting Estimates section above for a sensitivity analysis concerning commodity price changes and their
impact on the ceiling test.
The Company’s 1974 indenture pursuant to which $50.0 million (or 2.1%) of the Company’s long-term
debt (as of September 30, 2023) was issued, contains a cross-default provision whereby the failure by the
Company to perform certain obligations under other borrowing arrangements could trigger an obligation to
repay the debt outstanding under the indenture. In particular, a repayment obligation could be triggered if the
Company fails (i) to pay any scheduled principal or interest on any debt under any other indenture or agreement,
or (ii) to perform any other term in any other such indenture or agreement, and the effect of the failure causes,
or would permit the holders of the debt to cause, the debt under such indenture or agreement to become due
prior to its stated maturity, unless cured or waived.
OTHER MATTERS
In addition to the environmental and other matters discussed in this Item 7 and in Item 8 at Note L —
Commitments and Contingencies, the Company is involved in other litigation and regulatory matters arising in
the normal course of business. These other matters may include, for example, negligence claims and tax,
regulatory or other governmental audits, inspections, investigations or other proceedings. These matters may
involve state and federal taxes, safety, compliance with regulations, rate base, cost of service and purchased gas
cost issues, among other things. While these normal-course matters could have a material effect on earnings and
cash flows in the period in which they are resolved, they are not expected to change materially the Company’s
present liquidity position, nor are they expected to have a material adverse effect on the financial condition of
the Company.
Supply Corporation and Empire have developed a project which would move significant prospective
Marcellus and Utica production from Seneca's Western Development Area at Clermont
to an Empire
interconnection with the TC Energy pipeline at Chippawa and an interconnection with TGP's 200 Line in East
Aurora, New York (the “Northern Access project”). The Northern Access project would provide an outlet to
Dawn-indexed markets in Canada and to the TGP line serving the U.S. Northeast. The Northern Access project
involves the construction of approximately 99 miles of largely 24” pipeline and approximately 27,500
horsepower of compression on the two systems. Supply Corporation, Empire and Seneca executed anchor
shipper agreements for 350,000 Dth per day of firm transportation delivery capacity to Chippawa and 140,000
Dth per day of firm transportation capacity to a new interconnection with TGP's 200 Line on this project. The
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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, which is the subject of an ongoing appeal at the U.S. Court of
Appeals for the D.C. Circuit. 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, including the completion of ongoing litigation. As of September 30, 2023, approximately
$55.9 million has been spent on the Northern Access project, including $24.3 million that has been spent to
study the project that is included in Deferred Charges on the Consolidated Balance Sheet. The remaining $31.6
million spent on the project is included in Property, Plant and Equipment on the Consolidated Balance Sheet at
September 30, 2023.
The Company has a tax-qualified, noncontributory defined-benefit retirement plan (Retirement Plan).
During 2023, the Company did not make any contributions to the Retirement Plan. Estimated contributions to
the Retirement Plan in 2024 will be in the range of zero to $5.0 million. For further discussion of the
Company’s Retirement Plan, including actuarial assumptions, refer to Item 8 at Note K — Retirement Plan and
Other Post-Retirement Benefits. As noted in that footnote, the Retirement Plan has been closed to new
participants since 2003.
In that regard, the average remaining service life of active participants in the
Retirement Plan is approximately 6 years.
The Company provides health care and life insurance benefits (other post-retirement benefits) for a
majority of its retired employees. The Company has established VEBA trusts and 401(h) accounts for its other
post-retirement benefits. The Company has been making contributions to its VEBA trusts and/or 401(h)
accounts over the last several years and does not anticipate making contributions to the VEBA trusts and/or
401(h) accounts in the near term. However, this will be subject to future review. During 2023, the Company did
not make any contributions to its VEBA trusts. However, the Company made direct payments of $0.2 million to
retirees not covered by the VEBA trusts and 401(h) accounts during 2023. The Company does not expect to
make any contributions to its VEBA trusts in 2024. For further discussion of the Company’s other post-
retirement benefits, including actuarial assumptions, refer to Item 8 at Note K — Retirement Plan and Other
Post-Retirement Benefits. As noted in that footnote, the other post-retirement benefits provided by the
Company have been closed to new participants since 2003. In that regard, the average remaining service life of
active participants is approximately 4 years for those eligible for other post-retirement benefits.
The Company has made certain guarantees on behalf of its subsidiaries. The guarantees relate primarily
to: (i) obligations under derivative financial instruments, which are included on the Consolidated Balance
Sheets in accordance with the authoritative guidance (see Item 7, MD&A under the heading “Critical
Accounting Estimates - Accounting for Derivative Financial Instruments”); and (ii) other obligations which are
reflected on the Consolidated Balance Sheets. The Company believes that the likelihood it would be required to
make payments under the guarantees is remote.
MARKET RISK SENSITIVE INSTRUMENTS
Energy Commodity Price Risk
instruments (derivatives),
The Company uses various derivative financial
including price swap
agreements and no cost collars, as part of the Company’s overall energy commodity price risk management
strategy in its Exploration and Production segment. Under this strategy, the Company manages a portion of the
market risk associated with fluctuations in the price of natural gas, thereby attempting to provide more stability
to operating results. The Company has operating procedures in place that are administered by experienced
management to monitor compliance with the Company’s risk management policies. The derivatives are not
held for trading purposes. The fair value of these derivatives, as shown below, represents the amount that the
Company would receive from, or pay to, the respective counterparties at September 30, 2023 to terminate the
derivatives. However, the tables below and the fair value that is disclosed do not consider the physical side of
the natural gas transactions that are related to the financial instruments.
On July 21, 2010, the Dodd-Frank Act was signed into law. The Dodd-Frank Act required the CFTC,
SEC and other regulatory agencies to promulgate rules and regulations implementing the legislation, and
includes provisions related to the swaps and over-the-counter derivatives markets that are designed to promote
transparency, mitigate systemic risk and protect against market abuse. Although regulators have adopted
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several final regulations, other rules that may impact the Company have yet to be finalized. Rules adopted by
the CFTC and other regulators could adversely impact the Company. While many of those rules place specific
conditions on the operations of swap dealers rather than directly on the Company, concern remains that swap
dealers with whom the Company may transact will pass along their increased costs stemming from final rules
through higher transaction costs and prices or other direct or indirect costs. Some of those rules also may apply
directly to the Company and adversely impact its ability to trade swaps and over-the-counter derivatives,
whether due to increased costs, limitations on trading capacity or for other reasons. Additionally, given the
enforcement authority granted to the CFTC on anti-market manipulation, anti-fraud and anti-disruptive trading
practices, it is difficult to predict how the evolving enforcement priorities of the CFTC will impact our business.
Should the Company violate any laws or regulations applicable to our hedging activities, it could be subject to
CFTC enforcement action and material penalties and sanctions. The Company cannot predict the impact that
evolving application of the Dodd-Frank Act may have on its operations.
The authoritative guidance for fair value measurements and disclosures requires 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, 2023, the Company determined that nonperformance
risk associated with its natural gas price swap agreements, natural gas no cost collars and foreign currency
contracts would have no material
impact on its financial position or results of operation. To assess
nonperformance risk, the Company considered information such as any applicable collateral posted, master
netting arrangements, and applied a market-based method by using the counterparty's (assuming the derivative
is in a gain position) or the Company’s (assuming the derivative is in a loss position) credit default swaps rates.
The following tables disclose natural gas price swap information by expected maturity dates for
agreements in which the Company receives a fixed price in exchange for paying a variable price as quoted in
various national natural gas publications or on the NYMEX. Notional amounts (quantities) are used to calculate
the contractual payments to be exchanged under the contract. The weighted average variable prices represent
the weighted average settlement prices by expected maturity date as of September 30, 2023. At September 30,
2023, the Company had not entered into any natural gas price swap agreements extending beyond 2028.
Natural Gas Price Swap Agreements
Expected Maturity Dates
Notional Quantities (Equivalent Bcf) . . . . . .
Weighted Average Fixed Rate (per Mcf) . . . $
Weighted Average Variable Rate (per Mcf) $
2024
131.3
3.43
3.29
2025
2026
2027
2028
78.4
3.59
3.88
$
$
36.2
4.10
4.16
$
$
13.1
4.37
4.12
$
$
1.0
4.40
3.95
$
$
Total
260.0
3.62
3.63
$
$
At September 30, 2023, the Company would have paid its respective counterparties an aggregate of
approximately $2.5 million to terminate the natural gas price swap agreements outstanding at that date.
At September 30, 2022, the Company had natural gas price swap agreements covering 207.3 Bcf at a
weighted average fixed rate of $2.98 per Mcf.
No Cost Collars
The following table discloses the notional quantities, the weighted average ceiling price and the weighted
average floor price for the no cost collars used by the Company to manage natural gas price risk. The no cost
collars provide for the Company to receive monthly payments from (or make payments to) other parties when a
variable price falls below an established floor price (the Company receives payment from the counterparty) or
exceeds an established ceiling price (the Company pays the counterparty). At September 30, 2023, the
Company had not entered into any natural gas no cost collars extending beyond 2027.
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Natural Gas
Notional Quantities (Equivalent Bcf) . . . . . . . . . . . . . . . . . . . .
63.5
Weighted Average Ceiling Price (per Mcf) . . . . . . . . . . . . . . . $ 4.29
Weighted Average Floor Price (per Mcf) . . . . . . . . . . . . . . . . . $ 3.42
2024
Expected Maturity Dates
2027
2026
2025
42.8
41.5
$ 4.78 $ 4.89 $ 4.89 $
$ 3.59 $ 3.62 $ 3.62 $
3.5
Total
151.3
4.61
3.53
At September 30, 2023, the Company would have received an aggregate of approximately $16.0 million
to terminate the natural gas no cost collars outstanding at that date.
At September 30, 2022, the Company had no cost collars agreements covering 213.5 Bcf at a weighted
average ceiling price of $4.24 per Mcf and a weighted average floor price of $3.40 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, 2023. At September 30, 2023, the Company had not
entered into any foreign currency exchange contracts extending beyond 2030.
Notional Quantities (Canadian Dollar in millions) . $12.9 $10.9 $ 7.6 $ 6.8 $ 6.8 $
Weighted Average Fixed Rate ($Cdn/$US) . . . . . . . $1.29 $1.28 $1.32 $1.33 $1.32 $
Weighted Average Variable Rate ($Cdn/$US) . . . . $1.32 $1.32 $1.34 $1.34 $1.33 $
Total
11.9 $56.9
1.31 $1.30
1.33 $1.33
2024
2025
2026
2027
2028
Expected Maturity Dates
Thereafter
At September 30, 2023, absent other positions with the same counterparties, the Company would have
paid to its respective counterparties an aggregate of $1.3 million to terminate these foreign exchange contracts.
Refer to Item 8 at Note J — Financial Instruments for a discussion of the Company’s exposure to credit
risk related to its derivative financial instruments.
Interest Rate Risk
The fair value of long-term fixed rate debt is $2.2 billion at September 30, 2023. 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:
2024
2025
Principal Amounts by Expected Maturity Dates
2027
(Dollars in millions)
2028
2026
Thereafter
Total
Long-Term Fixed Rate Debt . . . $ — $ 500.0
Weighted Average Interest Rate
Paid . . . . . . . . . . . . . . . . . . . . .
5.4%
—
$ 500.0
$ 600.0
$ 300.0
$ 500.0
$2,400.0
5.5%
4.7%
4.8%
3.0%
4.7%
RATE MATTERS
Utility Operation
Delivery rates for both the New York and Pennsylvania divisions are regulated by the states’ respective
public utility commissions and typically are changed only when approved through a procedure known as a “rate
case.” As noted below, the New York division currently has a rate case on file. In both jurisdictions, delivery
rates do not reflect the recovery of purchased gas costs. Prudently-incurred gas costs are recovered through
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operation of automatic adjustment clauses, and are collected primarily through a separately-stated “supply
charge” on the customer bill.
New York Jurisdiction
Distribution Corporation's current delivery rates in its New York jurisdiction were approved by the
NYPSC in an order issued on April 20, 2017 with rates becoming effective May 1, 2017 ("2017 Rate Order").
The 2017 Rate Order provided for a return on equity of 8.7% and directed the implementation of an earnings
sharing mechanism to be in place beginning on April 1, 2018. On October 31, 2023, Distribution Corporation
made a filing with the NYPSC seeking an increase of $88.8 million in its total annual operating revenues for the
projected rate year ending September 30, 2025, with a proposed effective date of October 1, 2024 that includes
the maximum suspension period permitted under the New York Public Service Law ("2023 Rate Filing"). The
Company is also proposing, among other things, to continue its leak prone pipe replacement program and to
implement a number of initiatives that will facilitate achievement of the emissions reduction goals of the
Climate Leadership and Community Protection Act.
The 2017 Rate Order 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 2022, Distribution Corporation made a filing with the
NYPSC to effectuate a temporary 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 ceased funding the
Retirement Plan and its VEBA trusts in its New York jurisdiction. The 2023 Rate Filing proposes to keep the
rate recovery of pension and OPEB costs at zero in the rate year and reflect the $15 million of savings in new
base delivery rates.
On August 13, 2021, the NYPSC issued an order extending the date through which qualified pipeline
replacement costs incurred by the Company can be recovered using the existing system modernization tracker
for two years (until March 31, 2023). On December 9, 2022, the Company filed a petition with the NYPSC to
effectuate a system improvement tracker through which qualified pipeline replacement costs through September
30, 2024 would be tracked and recovered, and to recover certain deferred costs associated with the existing
system modernization tracker, effective April 1, 2023. The NYPSC approved the petition by order dated March
17, 2023 contingent on the Company not filing a base rate case that would result in new rates becoming
effective prior to October 1, 2024. The 2023 Rate Filing proposes to stop accruing and collecting revenues
under its current system modernization and system improvement trackers and shift those revenues into the
Company’s new base delivery rates.
In the absence of a multi-year rate plan settlement, the Company is
requesting that it be allowed to reinstate a tracking mechanism similar to the existing system modernization
tracker.
Pennsylvania Jurisdiction
Distribution Corporation’s delivery rates effective through July 31, 2023 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. A settlement involving all active parties to
the proceeding was reached and filed with the PaPUC on April 13, 2023. The settlement provided for, among
other things, an increase in Distribution Corporation’s annual base rate operating revenues of $23 million. The
PaPUC approved the settlement in full, without modification or correction, on June 15, 2023 and new rates went
into effect on August 1, 2023.
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. All matters with respect to
this tariff supplement were finalized on February 24, 2022 with the PaPUC's approval of an Administrative Law
the Company discontinued regulatory
Judge's Recommended Decision. Concurrent with that decision,
accounting for OPEB expenses and recorded an $18.5 million adjustment during the quarter ended March 31,
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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 filed a NGA Section 4 rate case at FERC on July 31, 2023 proposing rate increases to
be effective February 1, 2024. The proposed rates reflect an annual cost of service of $385.4 million, a rate
base of $1.32 billion and a proposed cost of equity of 15.12%. If the proposed rate increases finally approved at
the end of the proceeding exceed the rates that were in effect at July 31, 2023, but are less than rates put into
effect subject to refund on February 1, 2024, Supply Corporation would be required to refund the difference
between the rates collected subject to refund and the final approved rates, with interest at the FERC-approved
rate. If the rates approved at the end of the proceeding are lower than the rates in effect at July 31, 2023, such
lower rates will become effective prospectively from the effective date provided by the applicable FERC order,
and refunds with interest will be limited to the difference between the rates collected subject to refund and the
rates in effect at July 31, 2023.
Empire’s 2019 rate settlement provides that Empire must make a rate case filing no later than May 1,
2025.
ENVIRONMENTAL MATTERS
The Company is subject to various federal, state and local laws and regulations relating to the protection
of the environment. The Company has established procedures for the ongoing evaluation of its operations to
identify potential environmental exposures and comply with regulatory requirements. In 2021, the Company set
methane intensity reduction targets at each of its businesses, an absolute greenhouse gas emissions reduction
target for the consolidated Company, and greenhouse gas reduction targets associated with the Company’s
utility delivery system. In 2022, the Company began measuring progress against these reduction targets. The
Company's ability to estimate accurately the time, costs and resources necessary to meet emissions targets may
be impacted as environmental exposures, technology and opportunities change and regulatory and policy
updates are issued.
For further discussion of the Company's environmental exposures, refer to Item 8 at Note L —
Commitments and Contingencies under the heading “Environmental Matters.”
The effect (material or not) on the Company of any new legislative or regulatory measures will depend on
the particular provisions that are ultimately adopted.
Environmental 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 example, the
federal Inflation Reduction Act of 2022 (IRA) legislation was signed into law on August 16, 2022. The IRA
includes a methane charge that is expected to be applicable to the reported annual methane emissions of certain
oil and gas facilities, above specified methane intensity thresholds, starting in calendar year 2024. This portion
of the IRA is to be administered by the EPA and potential fees will begin with emissions reported for calendar
year 2024. The EPA is the lead federal agency that regulates greenhouse gas emissions pursuant to the Clean
Air Act. The regulations implemented by the EPA impose stringent leak detection and repair requirements and
address reporting and control of methane and volatile organic compound emissions. The Company must
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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. 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. In May 2023, New York
State passed legislation that prohibits the installation of fossil fuel burning equipment and building systems in
new buildings commencing on or after December 31, 2025, subject to certain exemptions. 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. The NYDEC has until
January 1, 2024 to issue further rules and regulations implementing the CLCPA. The NYDEC, in conjunction
with the New York State Energy Research and Development Authority, is also in the early phases of developing
a cap-and-invest program in the state, which is anticipated to be effective in 2025. The above-enumerated
initiatives could also increase the Company’s cost of environmental compliance by increasing reporting
requirements, requiring retrofitting of existing equipment, requiring installation of new equipment, and/or
requiring the purchase of emission allowances. They could also delay or otherwise negatively affect efforts to
obtain permits and other regulatory approvals. Changing market conditions and new regulatory requirements, as
well as unanticipated or inconsistent application of existing laws and regulations by administrative agencies,
make it difficult to predict a long-term business impact across twenty or more years.
EFFECTS OF INFLATION
The Company’s operations are sensitive to increases in the rate of inflation because of its operational and
capital spending requirements in both its regulated and non-regulated businesses. For the regulated businesses,
recovery of increasing costs from customers can be delayed by the regulatory process of a rate case filing. For
the non-regulated businesses, prices received for services performed or products produced are determined by
market factors that are not necessarily correlated to the underlying costs required to provide the service or
product.
SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS
The Company is including the following cautionary statement in this Annual Report on Form 10-K to
make applicable and take advantage of the safe harbor provisions of the Private Securities Litigation Reform
Act of 1995 for any forward-looking statements made by, or on behalf of, the Company. Forward-looking
statements include statements concerning plans, objectives, goals, projections, strategies, future events or
performance, and underlying assumptions and other statements which are other than statements of historical
facts. From time to time, the Company may publish or otherwise make available forward-looking statements of
this nature. All such subsequent forward-looking statements, whether written or oral and whether made by or on
behalf of the Company, are also expressly qualified by these cautionary statements. Certain statements
contained in this report, including, without limitation, statements regarding future prospects, plans, objectives,
goals, projections, estimates of oil and gas quantities, strategies, future events or performance and underlying
assumptions, capital structure, anticipated capital expenditures, completion of construction projects, projections
for pension and other post-retirement benefit obligations,
impacts of the adoption of new authoritative
accounting and reporting guidance, and possible outcomes of litigation or regulatory proceedings, as well as
statements that are identified by the use of the words “anticipates,” “estimates,” “expects,” “forecasts,”
“intends,” “plans,” “predicts,” “projects,” “believes,” “seeks,” “will,” “may,” and similar expressions, are
“forward-looking statements” as defined in the Private Securities Litigation Reform Act of 1995 and
accordingly involve risks and uncertainties which could cause actual results or outcomes to differ materially
from those expressed in the forward-looking statements. The Company’s expectations, beliefs and projections
are expressed in good faith and are believed by the Company to have a reasonable basis, but there can be no
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assurance that management’s expectations, beliefs or projections will result or be achieved or accomplished. In
addition to other factors and matters discussed elsewhere herein, the following are important factors that, in the
view of the Company, could cause actual results to differ materially from those discussed in the forward-
looking statements:
1. Changes in laws, regulations or judicial interpretations to which the Company is subject, including those
taxes, safety, employment, climate change, other environmental matters, real
involving derivatives,
property, and exploration and production activities such as hydraulic fracturing;
2. Governmental/regulatory actions, initiatives and proceedings, including those involving rate cases (which
target rates of return, rate design, retained natural gas and system
address, among other things,
modernization), environmental/safety requirements, affiliate relationships, industry structure, and franchise
renewal;
3. The Company’s ability to estimate accurately the time and resources necessary to meet emissions targets;
4. Governmental/regulatory actions and/or market pressures to reduce or eliminate reliance on natural gas;
5. Changes in economic conditions, including inflationary pressures, supply chain issues, liquidity challenges,
and global, national or regional recessions, and their effect on the demand for, and customers’ ability to pay
for, the Company’s products and services;
6. Changes in the price of natural gas;
7. The creditworthiness or performance of the Company’s key suppliers, customers and counterparties;
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. 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;
12. The impact of information technology disruptions, cybersecurity or data security breaches;
13. 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, water availability and disposal or recycling opportunities of used water, 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;
14. The Company's ability to complete strategic transactions;
15. Increasing health care costs and the resulting effect on health insurance premiums and on the obligation to
provide other post-retirement benefits;
16. Other changes in price differentials between similar quantities of natural gas having different quality,
heating value, hydrocarbon mix or delivery date;
17. The cost and effects of legal and administrative claims against the Company or activist shareholder
campaigns to effect changes at the Company;
18. Negotiations with the collective bargaining units representing the Company's workforce, including potential
work stoppages during negotiations;
19. Uncertainty of natural gas reserve estimates;
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20. Significant differences between the Company’s projected and actual production levels for natural gas;
21. Changes in demographic patterns and weather conditions (including those related to climate change);
22. Changes in the availability, price or accounting treatment of derivative financial instruments;
23. Changes in laws, actuarial assumptions, the interest rate environment and the return on plan/trust assets
related to the Company’s pension and other post-retirement benefits, which can affect future funding
obligations and costs and plan liabilities;
24. Economic disruptions or uninsured losses resulting from major accidents, fires, severe weather, natural
disasters, terrorist activities or acts of war, as well as economic and operational disruptions due to third-
party outages;
25. Significant differences between the Company’s projected and actual capital expenditures and operating
expenses; or
26. Increasing costs of insurance, changes in coverage and the ability to obtain insurance.
The Company disclaims any obligation to update any forward-looking statements to reflect events or
circumstances after the date hereof.
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.
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
Financial Statements:
Report of Independent Registered Public Accounting Firm (PCAOB ID 238) . . . . . . . . . . . . . . . . . . . . .
Consolidated Statement of Income and Earnings Reinvested in the Business for the years ended
September 30, 2023, 2022 and 2021 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Consolidated Statement of Comprehensive Income for the years ended September 30, 2023, 2022 and
2021 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Consolidated Balance Sheet at September 30, 2023 and 2022 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Consolidated Statement of Cash Flows for the years ended September 30, 2023, 2022 and 2021 . . . . . .
Notes to Consolidated Financial Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Page
63
66
67
68
69
70
All 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 N — Supplementary Information for Oil and Gas Producing
Activities (unaudited), appears under this Item, and reference is made thereto.
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Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholders of National Fuel Gas 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, 2023, 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 consolidated financial statements referred to above present fairly, in all material respects, the
financial position of the Company as of September 30, 2023 and 2022, and the results of its operations and its
cash flows for each of the three years in the period ended September 30, 2023 in conformity with accounting
principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in
all material respects, effective internal control over financial reporting as of September 30, 2023, based on
criteria established in Internal Control - Integrated Framework (2013) issued by the COSO.
Basis for Opinions
The Company's management is responsible for these consolidated financial statements, 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 Item 9A. Our responsibility is to express opinions on the Company’s consolidated financial
statements and on the Company's internal control over financial reporting based on our 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 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 regarding
the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the
accounting principles used and significant estimates made by management, as well as evaluating the overall
presentation of the consolidated financial 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.
-63-
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.
limitations,
internal control over financial reporting may not prevent or detect
Because of its inherent
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.
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 $2.4 billion as of September 30, 2023. 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, 2023. As of September 30, 2023, the ceiling exceeded
the book value of the natural gas properties by approximately $794.7 million. 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.
-64-
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 data, methods, and assumptions used by management and its
specialists in developing the estimates of proved natural gas reserves and the related assumption 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 and the related
assumption of quantities of proved natural gas that are ultimately recovered which is utilized in the DD&A
expense and ceiling test calculations. These procedures also included, among others, evaluating the
reasonableness of the significant assumption used by management related to the quantities of proved natural gas
that are ultimately recovered which included evaluating information on additional development activity,
production history, if the assumption used was reasonable considering the past performance of the Company,
and whether it was 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 and the related assumption of quantities of proved natural gas that are ultimately recovered.
As a basis for using this work, the specialists’ qualifications 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 completeness and accuracy of data used by the specialists and
an evaluation of the specialists’ findings.
/s/ PRICEWATERHOUSECOOPERS LLP
Buffalo, New York
November 17, 2023
We have served as the Company’s auditor since 1941.
-65-
NATIONAL FUEL GAS COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND EARNINGS
REINVESTED IN THE BUSINESS
INCOME
Operating Revenues:
Utility and Energy Marketing Revenues . . . . . . . . . . . . . . . . . . . . . . . . $
Exploration and Production and Other Revenues . . . . . . . . . . . . . . . . . .
Pipeline and Storage and Gathering Revenues . . . . . . . . . . . . . . . . . . . .
Operating Expenses:
Purchased Gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Operation and Maintenance:
Utility and Energy Marketing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Exploration and Production and Other . . . . . . . . . . . . . . . . . . . . . . . . .
Pipeline and Storage and Gathering . . . . . . . . . . . . . . . . . . . . . . . . . . .
Property, Franchise and Other Taxes . . . . . . . . . . . . . . . . . . . . . . . . . . .
Depreciation, Depletion and Amortization . . . . . . . . . . . . . . . . . . . . . . .
Impairment of Oil and Gas Producing Properties . . . . . . . . . . . . . . . . .
Gain on Sale of Assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Operating Income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other Income (Expense):
Other Income (Deductions) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest Expense on Long-Term Debt
. . . . . . . . . . . . . . . . . . . . . . . . . .
Other Interest Expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income Before Income Taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income Tax Expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net Income Available for Common Stock . . . . . . . . . . . . . . . . . . . . . . .
EARNINGS REINVESTED IN THE BUSINESS
Balance at Beginning of Year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Dividends on Common Stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Balance at End of Year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Earnings Per Common Share:
Basic:
Net Income Available for Common Stock . . . . . . . . . . . . . . . . . . . . . $
Diluted:
Net Income Available for Common Stock . . . . . . . . . . . . . . . . . . . . . $
Weighted Average Common Shares Outstanding:
Year Ended September 30
2023
2022
2021
(Thousands of dollars, except per common share
amounts)
$
$
941,779
958,455
273,537
2,173,771
897,916
1,010,629
277,501
2,186,046
667,549
837,597
237,513
1,742,659
437,595
392,093
171,827
205,239
124,270
149,247
92,700
409,573
—
1,418,624
—
755,147
18,138
(111,948)
(19,938)
641,399
164,533
476,866
1,587,085
2,063,951
(178,095)
1,885,856
5.20
5.17
$
$
$
193,058
191,572
136,571
101,182
369,790
—
1,384,266
12,736
814,516
(1,509)
(120,507)
(9,850)
682,650
116,629
566,021
1,191,175
1,757,196
(170,111)
1,587,085
6.19
6.15
$
$
$
179,547
173,041
123,218
94,713
335,303
76,152
1,153,801
51,066
639,924
(15,238)
(141,457)
(4,900)
478,329
114,682
363,647
991,630
1,355,277
(164,102)
1,191,175
3.99
3.97
Used in Basic Calculation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Used in Diluted Calculation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
91,748,890
92,285,918
91,410,625
92,107,066
91,130,941
91,684,583
See Notes to Consolidated Financial Statements
-66-
NATIONAL FUEL GAS COMPANY
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Year Ended September 30
2023
2022
2021
Net Income Available for Common Stock . . . . . . . . . . . . . . . . . . . . . . . $ 476,866
Other Comprehensive Income (Loss), Before Tax:
Increase (Decrease) in the Funded Status of the Pension and Other
(Thousands of dollars)
$ 566,021
$ 363,647
Post-Retirement Benefit Plans . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(9,660)
9,561
17,862
Reclassification Adjustment for Amortization of Prior Year Funded
Status of the Pension and Other Post-Retirement Benefit Plans . . . .
Unrealized Gain (Loss) on Derivative Financial Instruments Arising
1,674
11,054
16,229
During the Period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
708,206
(1,050,831)
(665,371)
Reclassification Adjustment for Realized (Gains) Losses on
Derivative Financial Instruments in Net Income . . . . . . . . . . . . . . . .
Other Post-Retirement Adjustment for Regulatory Proceeding . . . . . . .
Other Comprehensive Income (Loss), Before Tax . . . . . . . . . . . . . . . .
Income Tax Expense (Benefit) Related to the Increase (Decrease) in
the Funded Status of the Pension and Other Post-Retirement Benefit
Plans . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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 . . . . . . . . . . . . . . . . . . . . . . . . .
Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) on
Derivative Financial Instruments Arising During the Period . . . . . . .
Reclassification Adjustment for Income Tax Benefit (Expense) on
Realized Losses (Gains) from Derivative Financial Instruments in
Net Income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income Tax Expense (Benefit) Related to Other Post-Retirement
88,656
—
788,876
882,581
(7,351)
(154,986)
83,711
—
(547,569)
(2,284)
2,169
4,072
411
2,574
3,762
214,270
(287,608)
(179,028)
5,806
241,559
22,465
—
Adjustment for Regulatory Proceeding . . . . . . . . . . . . . . . . . . . . . . .
218,203
Income Taxes — Net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other Comprehensive Income (Loss) . . . . . . . . . . . . . . . . . . . . . . . . . . .
570,673
Comprehensive Income (Loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $1,047,539
(1,544)
(42,850)
(112,136)
$ 453,885
—
(148,729)
(398,840)
$ (35,193)
See Notes to Consolidated Financial Statements
-67-
NATIONAL FUEL GAS COMPANY
CONSOLIDATED BALANCE SHEETS
Property, Plant and Equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Less — Accumulated Depreciation, Depletion and Amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
ASSETS
Current Assets
Cash and Temporary Cash Investments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Hedging Collateral Deposits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Receivables — Net of Allowance for Uncollectible Accounts of $36,295 and $40,228, Respectively . . . . . .
Unbilled Revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gas Stored Underground . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Materials and Supplies - at average cost
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Unrecovered Purchased Gas Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other Current Assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other Assets
Recoverable Future Taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Unamortized Debt Expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other Regulatory Assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred Charges . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other Investments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Goodwill . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Prepaid Pension and Post-Retirement Benefit Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fair Value of Derivative Financial Instruments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total Assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
CAPITALIZATION AND LIABILITIES
Capitalization:
Comprehensive Shareholders’ Equity
Common Stock, $1 Par Value; Authorized - 200,000,000 Shares;
Issued and Outstanding - 91,819,405 Shares and 91,478,064 Shares, Respectively . . . . . . . . . . . . . . . . . . . . . $
Paid In Capital
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Earnings Reinvested in the Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accumulated Other Comprehensive Loss . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total Comprehensive Shareholders’ Equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Long-Term Debt, Net of Current Portion and Unamortized Discount and Debt Issuance Costs . . . . . . . .
Total Capitalization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Current and Accrued Liabilities
Notes Payable to Banks and Commercial Paper
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Current Portion of Long-Term Debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accounts Payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Amounts Payable to Customers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Dividends Payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest Payable on Long-Term Debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Customer Advances . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Customer Security Deposits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other Accruals and Current Liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fair Value of Derivative Financial Instruments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other Liabilities
Deferred Income Taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Taxes Refundable to Customers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cost of Removal Regulatory Liability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other Regulatory Liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other Post-Retirement Liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Asset Retirement Obligations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other Liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Commitments and Contingencies (Note L) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total Capitalization and Liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
See Notes to Consolidated Financial Statements
-68-
At September 30
2023
2022
(Thousands of dollars)
$
13,635,303
6,335,441
7,299,862
12,551,909
5,985,432
6,566,477
55,447
—
160,601
16,622
32,509
48,989
—
100,260
414,428
69,045
7,240
72,138
82,416
73,976
5,476
200,301
50,487
4,891
565,970
8,280,260
91,819
1,040,761
1,885,856
(55,060)
2,963,376
2,384,485
5,347,861
287,500
—
152,193
59,019
45,451
20,399
21,003
28,764
160,974
31,009
806,312
1,124,170
268,562
277,694
165,441
2,915
165,492
121,813
2,126,087
—
8,280,260
$
$
$
46,048
91,670
361,626
30,075
32,364
40,637
99,342
59,369
761,131
106,247
8,884
67,101
77,472
95,025
5,476
196,597
9,175
2,677
568,654
7,896,262
91,478
1,027,066
1,587,085
(625,733)
2,079,896
2,083,409
4,163,305
60,000
549,000
178,945
419
43,452
17,376
26,108
24,283
257,327
785,659
1,942,569
698,229
362,098
259,947
188,803
3,065
161,545
116,701
1,790,388
—
7,896,262
NATIONAL FUEL GAS COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
Operating Activities
Net Income Available for Common Stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities:
Gain on Sale of Assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Impairment of Oil and Gas Producing Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Depreciation, Depletion and Amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred Income Taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Premium Paid on Early Redemption of Debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Stock-Based Compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Reduction of Other Post-Retirement Regulatory Liability . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Change in:
Receivables and Unbilled Revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gas Stored Underground and Materials, Supplies and Emission Allowances . . . . .
Unrecovered Purchased Gas Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other Current Assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accounts Payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Amounts Payable to Customers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Customer Advances . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Customer Security Deposits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other Accruals and Current Liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other Assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other Liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net Cash Provided by Operating Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Investing Activities
Capital Expenditures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net Proceeds from Sale of Oil and Gas Producing Properties . . . . . . . . . . . . . . . . . . .
Net Proceeds from Sale of Timber Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Sale of Fixed Income Mutual Fund Shares in Grantor Trust . . . . . . . . . . . . . . . . . . . . .
Acquisition of Upstream Assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net Cash Used in Investing Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Financing Activities
Proceeds from Issuance of Short-Term Note Payable to Bank . . . . . . . . . . . . . . . . . . .
Repayment of Short-Term Note Payable to Bank . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net Change in Other Short-Term Notes Payable to Banks and Commercial Paper . . .
Net Proceeds from Issuance of Long-Term Debt
. . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Reduction of Long-Term Debt
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net Repurchases of Common Stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Dividends Paid on Common Stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net Cash Used in Financing Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net Increase (Decrease) in Cash, Cash Equivalents, and Restricted Cash . . . . . . . .
Cash, Cash Equivalents and Restricted Cash At Beginning of Year . . . . . . . . . . . . .
Cash, Cash Equivalents and Restricted Cash At End of Year . . . . . . . . . . . . . . . . . . $
Supplemental Disclosure of Cash Flow Information
Cash Paid For:
2023
Year Ended September 30
2022
(Thousands of dollars)
2021
476,866
$
566,021
$
363,647
—
—
409,573
151,403
—
20,630
—
19,647
213,579
(8,406)
99,342
(41,077)
(37,095)
58,600
(5,105)
4,481
(67,664)
(26,564)
(31,135)
1,237,075
(1,009,868)
—
—
10,000
(124,758)
12,279
(1,112,347)
250,000
(250,000)
227,500
297,306
(549,000)
(6,709)
(176,096)
(206,999)
(82,271)
137,718
55,447
(12,736)
—
369,790
104,415
—
19,506
(18,533)
31,983
(168,769)
3,109
(66,214)
291
11,907
398
8,885
4,991
34,260
(58,924)
(17,859)
812,521
(811,826)
254,439
—
30,000
—
8,683
(518,704)
—
—
(98,500)
—
—
(9,590)
(168,147)
(276,237)
17,580
120,138
137,718
124,312
16,680
$
$
$
(51,066)
76,152
335,303
105,993
15,715
17,065
—
10,896
(61,413)
(2,014)
(33,128)
(11,972)
31,352
(10,767)
1,904
2,093
34,314
1,250
(33,771)
791,553
(751,734)
—
104,582
—
—
13,935
(633,217)
—
—
128,500
495,267
(515,715)
(3,702)
(163,089)
(58,739)
99,597
20,541
120,138
135,136
6,374
102,700
—
$
$
$
$
$
Interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Income Taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
124,441
38,098
Non-Cash Investing Activities:
Non-Cash Capital Expenditures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Non-Cash Contingent Consideration for Asset Sale . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
109,208
$
— $
120,262
12,571
See Notes to Consolidated Financial Statements
-69-
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.
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 F —
Regulatory Matters for further discussion.
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 of customer accounts, other specific information about
customer accounts, and the economic and regulatory environment. Account balances have historically been
written 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. During 2022 and 2021, final billings were suppressed in
the Utility segment as a result of state shut-off moratoriums arising from the COVID-19 pandemic. Those
moratoriums were lifted in 2022 which allowed for the resumption of final billings during 2022, thereby
resulting in higher amounts being written off in 2023.
Activity in the allowance for uncollectible accounts are as follows:
Year Ended September 30
2023
2022
2021
Balance at Beginning of Year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Additions Charged to Costs and Expenses . . . . . . . . . . . . . . . . . . . .
Add: Discounts on Purchased Receivables . . . . . . . . . . . . . . . . . . . .
Deduct: Net Accounts Receivable Written-Off . . . . . . . . . . . . . . . . .
Balance at End of Year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
40,228
14,482
1,380
19,795
36,295
(Thousands)
31,639
$
13,209
1,314
5,934
40,228
$
$
$
22,810
14,940
1,168
7,279
31,639
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.
-70-
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Estimated refund liabilities to ratepayers represent management’s current estimate of such refunds.
Reference is made to Note F — 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
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.
On June 15, 2023, the PaPUC approved the Utility segment’s Pennsylvania rate jurisdiction’s use of a
WNC as a five-year pilot program. The program is effective October 2023 and covers the eight-month period
from October through May. Prior to October 2023, the Utility segment’s Pennsylvania rate jurisdiction did not
have a WNC, causing weather variations to 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 March 31st, and applied to customer bills annually,
beginning July 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
-71-
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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 $2.4 billion and $1.9 billion at September 30,
2023 and 2022, respectively. For further discussion of capitalized costs, refer to Note N — 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
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 unproved properties not being
depleted, less (c) income tax effects related to the differences between the book and tax basis of the properties.
The 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, 2023, the ceiling exceeded the book value
of the oil and gas properties by approximately $794.7 million. In adjusting estimated future net cash flows for
hedging under the ceiling test at September 30, 2023, 2022 and 2021, estimated future net cash flows were
increased by $38.8 million, decreased by $1.0 billion and decreased by $76.1 million, respectively.
The principal assets of the Utility, Pipeline and Storage and Gathering segments, consisting primarily of
gas 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 Utility, Pipeline and Storage and Gathering segments at September 30, 2023.
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. Depreciation, depletion and amortization expense for oil and gas
properties was $235.7 million, $202.4 million and $177.1 million for the years ended September 30, 2023, 2022
and 2021, 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 useful lives of property
in service. The following is a summary of depreciable plant by segment:
-72-
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
As of September 30
2023
2022
(Thousands)
Exploration and Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 6,741,095
2,803,690
Pipeline and Storage . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1,032,969
Gathering . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2,507,465
Utility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
15,787
All Other and Corporate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 13,101,006
$ 6,088,476
2,747,948
971,665
2,411,707
13,712
$ 12,233,508
Average depreciation, depletion and amortization rates are as follows:
2023
Exploration and Production, per Mcfe(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 0.65
Pipeline and Storage . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gathering . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Utility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
All Other and Corporate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2.6 %
3.6 %
2.7 %
2.9 %
2022
$ 0.59
2021
$ 0.56
2.7 %
3.6 %
2.7 %
1.4 %
2.6 %
3.6 %
2.7 %
3.4 %
Year Ended September 30
(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 $0.63, $0.57 and $0.54 per Mcfe of production in 2023, 2022
and 2021, respectively.
Goodwill
The Company has recognized goodwill of $5.5 million as of September 30, 2023 and 2022 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, 2023, 2022 and 2021, 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
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 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 no cost collars and foreign currency forward contracts. The Company
accounts for these instruments as cash flow hedges 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 is made to Note I — Fair Value Measurements for further discussion concerning the fair
value of derivative financial instruments.
For 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 on the Consolidated Statements of Income.
Reference is made to Note J — Financial Instruments for further discussion concerning cash flow hedges.
-73-
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Accumulated Other Comprehensive Loss
The components of Accumulated Other Comprehensive Loss and changes for the years ended September
30, 2023 and 2022, net of related tax effects, are as follows (amounts in parentheses indicate debits) (in
thousands):
Gains and Losses
on Derivative
Financial
Instruments
Funded Status of
the Pension and
Other Post-
Retirement
Benefit Plans
Total
Year Ended September 30, 2023
Balance at October 1, 2022 . . . . . . . . . . . . . . . . . . . . . $
Other Comprehensive Gains and Losses Before
Reclassifications . . . . . . . . . . . . . . . . . . . . . . . . . . .
Amounts Reclassified From Other Comprehensive
Loss . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Balance at September 30, 2023 . . . . . . . . . . . . . . . . . $
Year Ended September 30, 2022
Balance at October 1, 2021 . . . . . . . . . . . . . . . . . . . . . $
Other Comprehensive Gains and Losses Before
Reclassifications . . . . . . . . . . . . . . . . . . . . . . . . . . .
Amounts Reclassified From Other Comprehensive
Loss . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other Post-Retirement Adjustment for Regulatory
Proceeding . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Balance at September 30, 2022 . . . . . . . . . . . . . . . . . $
(572,163) $
(53,570) $
(625,733)
493,936
(7,376)
486,560
82,850
4,623
$
1,263
(59,683) $
84,113
(55,060)
(449,962) $
(63,635) $
(513,597)
(763,223)
641,022
7,392
8,480
—
(572,163) $
(5,807)
(53,570) $
(755,831)
649,502
(5,807)
(625,733)
The amounts included in accumulated other comprehensive 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 $0.4 million at both September 30, 2023 and 2022. The total
amount for accumulated losses was $59.3 million and $53.2 million at September 30, 2023 and 2022,
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.
-74-
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Reclassifications Out of Accumulated Other Comprehensive Loss
The details about the reclassification adjustments out of accumulated other comprehensive loss for the
years ended September 30, 2023 and 2022 are as follows (amounts in parentheses indicate debits to the income
statement) (in thousands):
Details About Accumulated Other
Comprehensive Loss Components
Amount of Gain or (Loss)
Reclassified from
Accumulated Other
Comprehensive Loss
for the
Year Ended
September 30,
2023
2022
Affected Line Item in the
Statement Where Net Income
is Presented
Gains (Losses) on Derivative Financial Instrument
Cash Flow Hedges:
Commodity Contracts . . . . . . . . . . . . . . . . . . . . . . $ (88,015) $ (882,594) Operating Revenues
13 Operating Revenues
Foreign Currency Contracts . . . . . . . . . . . . . . . . .
(641)
Amortization of Prior Year Funded Status of the
Pension and Other Post-Retirement Benefit Plans:
Prior Service Cost . . . . . . . . . . . . . . . . . . . . . . . . .
Net Actuarial Loss . . . . . . . . . . . . . . . . . . . . . . . .
(82)
(1,592)
(90,330)
6,217
(1)
(1)
(103)
(10,951)
(893,635) Total Before Income Tax
244,133
Income Tax Expense
$ (84,113) $ (649,502) Net of Tax
(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 $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 2023, including transportation costs, the current cost of replacing this inventory of gas stored
underground exceeded the amount stated on a LIFO basis by approximately $3.7 million at September 30, 2023.
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, 2023, the remaining weighted average amortization period for such costs was
approximately 4 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 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.
-75-
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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 (Deductions).
Consolidated Statement of Cash Flows
The components, as reported on the Company's Consolidated Balance Sheets, of the total cash, cash
equivalents, and restricted cash presented on the Statement of Cash Flows are as follows (in thousands):
Cash and Temporary Cash Investments . . . . . . . . . . . . . . . . . . . $ 55,447
Hedging Collateral Deposits . . . . . . . . . . . . . . . . . . . . . . . . . . .
—
Cash, Cash Equivalents, and Restricted Cash . . . . . . . . . . . . . . $ 55,447
2023
Year Ended September 30
2022
$ 46,048
91,670
$137,718
2021
$ 31,528
88,610
$120,138
2020
$ 20,541
—
$ 20,541
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 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 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 instruments
liability or asset balances.
Other Current Assets
The components of the Company’s Other Current Assets are as follows:
Prepayments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Prepaid Property and Other Taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Federal Income Taxes Receivable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
State Income Taxes Receivable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Regulatory Assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
Year Ended September 30
2023
2022
(Thousands)
18,966
14,186
14,602
16,133
36,373
100,260
$
$
17,757
14,321
—
5,933
21,358
59,369
Other Accruals and Current Liabilities
The components of the Company’s Other Accruals and Current Liabilities are as follows:
Accrued Capital Expenditures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Regulatory Liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Liability for Royalty and Working Interests . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Non-Qualified Benefit Plan Liability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
Year Ended September 30
2023
2022
(Thousands)
43,323
38,105
17,679
13,052
48,815
160,974
$
$
64,720
31,293
86,206
17,474
57,634
257,327
-76-
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Customer Advances
The Company, primarily in its Utility segment, 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, 2023 and 2022, customers in the balanced billing programs had advanced excess funds
of $21.0 million and $26.1 million, respectively.
Customer Security Deposits
The Company, primarily in its Utility and Pipeline and Storage segments, oftentimes requires security
deposits from marketers, producers, pipeline companies, and commercial and industrial customers before
providing services to such customers. At September 30, 2023 and 2022, the Company had received customer
security deposits amounting to $28.8 million and $24.3 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 had outstanding during fiscal 2023, 2022 and/or 2021 were SARs, restricted stock units and
performance shares. For the years ended September 30, 2023 and September 30, 2022, 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. SARs, restricted stock units and
performance shares that are antidilutive are excluded from the calculation of diluted earnings per common
share. There were 3,888 securities, 2,858 securities and 320,222 securities excluded as being antidilutive for the
years ended September 30, 2023, 2022 and 2021, respectively.
Stock-Based Compensation
The Company has various 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, 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. 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 SAR is exercisable less than one year or more than ten years after
the date of each grant. The Company chose the Black-Scholes-Merton closed form model to calculate the
compensation expense associated with SARs. For all Company stock awards, forfeitures are recognized as they
occur.
Restricted stock units are subject to restrictions on vesting and transferability. Restricted stock units
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 restricted stock units do not entitle the participants to dividend and voting rights.
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
-77-
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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 goal, 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 H — Capitalization and Short-Term Borrowings under the heading “Stock Award Plans”
for additional disclosures related to stock-based compensation awards for all plans.
Note B — Asset Acquisitions and Divestitures
On June 1, 2023, the Company completed its acquisition of certain upstream assets located primarily in
Tioga County, Pennsylvania from SWN Production Company, LLC (“SWN”) for total consideration of
$124.8 million. The purchase price, which reflects an effective date of January 1, 2023, was reduced for
production revenues less expenses that were retained by SWN from the effective date to the closing date. As
part of the transaction, the Company acquired approximately 34,000 net acres in an area that is contiguous with
existing Company-owned upstream assets. This transaction was accounted for as an asset acquisition, and, as
such, the purchase price was allocated to property, plant and equipment. The following is a summary of the
asset acquisition in thousands:
Purchase Price . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Transaction Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total Consideration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
124,178
580
124,758
On June 30, 2022, the Company completed the sale of Seneca’s California assets, all of which were 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 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
-78-
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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 completed the financing
of a July 31, 2020 acquisition of certain upstream assets and midstream gathering assets in Pennsylvania.
Note C — Revenue from Contracts with Customers
The following tables provide a disaggregation of the Company's revenues for the years ended September
30, 2023 and 2022, presented by type of service from each reportable segment.
Revenues by Type of Service
Exploration
and
Production
Pipeline
and
Storage
Gathering
Utility
Total
Reportable
Segments
All
Other
Corporate
and
Intersegment
Eliminations
Total
Consolidated
Year Ended September 30, 2023
(Thousands)
Production of Natural Gas . . . . . . . . $ 1,036,499
$
— $
— $
— $ 1,036,499
$
— $
— $
1,036,499
Production of Crude Oil . . . . . . . . . .
Natural Gas Processing . . . . . . . . . . .
Natural Gas Gathering Service . . . . .
2,261
1,203
—
—
—
—
—
—
230,317
—
—
—
Natural Gas Transportation Service .
— 291,225
Natural Gas Storage Service . . . . . . .
Natural Gas Residential Sales . . . . . .
Natural Gas Commercial Sales . . . . .
Natural Gas Industrial Sales . . . . . . .
—
—
—
—
84,962
—
—
—
Other . . . . . . . . . . . . . . . . . . . . . . . . .
6,507
3,004
—
—
98,304
—
— 727,728
— 103,270
—
—
5,658
508
2,261
1,203
230,317
389,529
84,962
727,728
103,270
5,658
10,019
Total Revenues from Contracts with
Customers . . . . . . . . . . . . . . . . . . . .
1,046,470
379,191
230,317
935,468
2,591,446
Alternative Revenue Programs . . . . .
—
Derivative Financial Instruments . . .
(88,015)
—
—
—
—
6,892
—
6,892
(88,015)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(216,426)
(82,889)
(36,283)
—
—
(7)
(947)
2,261
1,203
13,891
306,640
48,679
727,728
103,270
5,651
9,072
(336,552)
2,254,894
—
—
6,892
(88,015)
Total Revenues . . . . . . . . . . . . . . . . . $
958,455
$ 379,191
$ 230,317
$ 942,360
$ 2,510,323
$
— $
(336,552)
$
2,173,771
Revenues by Type of Service
Exploration
and
Production
Pipeline
and
Storage
Gathering
Utility
Total
Reportable
Segments
All
Other
Corporate
and
Intersegment
Eliminations
Total
Consolidated
Year Ended September 30, 2022
(Thousands)
Production of Natural Gas . . . . . . . . $ 1,730,723
$
— $
— $
— $ 1,730,723
$
— $
— $
1,730,723
Production of Crude Oil . . . . . . . . . .
150,957
Natural Gas Processing . . . . . . . . . . .
Natural Gas Gathering Service . . . . .
3,511
—
—
—
—
—
—
214,843
—
—
—
Natural Gas Transportation Service .
— 289,967
Natural Gas Storage Service . . . . . . .
Natural Gas Residential Sales . . . . . .
Natural Gas Commercial Sales . . . . .
Natural Gas Industrial Sales . . . . . . .
—
—
—
—
84,565
—
—
—
Other . . . . . . . . . . . . . . . . . . . . . . . . .
7,867
2,512
— 106,495
—
—
— 688,271
—
—
—
95,114
4,902
(3,918)
150,957
3,511
214,843
396,462
84,565
688,271
95,114
4,902
6,461
Total Revenues from Contracts with
Customers . . . . . . . . . . . . . . . . . . . .
1,893,058
377,044
214,843
890,864
3,375,809
Alternative Revenue Programs . . . . .
—
Derivative Financial Instruments . . .
(882,594)
—
—
—
—
7,357
7,357
—
(882,594)
Total Revenues . . . . . . . . . . . . . . . . . $ 1,010,464
$ 377,044
$ 214,843
$ 898,221
$ 2,500,572
$
—
—
—
—
—
—
—
—
6
6
—
—
6
—
—
(202,757)
(74,749)
(36,382)
—
—
—
(644)
150,957
3,511
12,086
321,713
48,183
688,271
95,114
4,902
5,823
(314,532)
3,061,283
—
—
7,357
(882,594)
$
(314,532)
$
2,186,046
-79-
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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
If a production imbalance occurs
natural gas production from the Appalachian region of the United States.
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
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
-80-
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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: $210.7 million for fiscal 2024; $184.0 million for fiscal 2025; $148.3 million for fiscal
2026; $123.3 million for fiscal 2027; $107.5 million for fiscal 2028; and $581.0 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
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 this situation, since the amount 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
NYPSC has authorized alternative revenue programs that are designed to mitigate the impact that weather and
-81-
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
conservation have on margin. The NYPSC and PaPUC have also authorized additional alternative revenue
programs that adjust billings for the 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
customers within 24 months of the annual reconciliation period.
Note D — Leases
The Company follows authoritative guidance regarding lease accounting, which requires entities that
lease the 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, including leases classified as operating leases. The Company has
elected to apply the following practical expedients provided in the authoritative guidance:
1. 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);
2. 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).
Nature of Leases
The Company primarily leases building space and drilling rigs, and on a limited basis, compressor
equipment and other miscellaneous assets. The Company 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 as an operating or a finance lease in accordance with the authoritative guidance. The Company did not
have any material finance leases as of September 30, 2023 or September 30, 2022. Aside from a sublease of
office space at the Company’s corporate headquarters, which terminated April 30, 2022, the Company does not
have any material arrangements where the Company is the lessor.
Buildings and Property
The Company enters into building and property rental agreements with third parties for office space,
certain field locations and other properties used in the Company’s operations. Building and property leases
include the Company’s corporate headquarters in Williamsville, New York, and Exploration and Production
segment offices in Houston, Texas, and Pittsburgh, Pennsylvania. The primary non-cancelable terms of the
Company’s building and property leases range from one month to sixteen years. Most building leases include
one or more options to renew, generally at the Company’s sole discretion, with 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 of one year or less. 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.
-82-
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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 9 months to 5 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
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 third party shippers 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 apply to leases to explore for or use natural gas resources, including
the right to explore for those resources and rights to use the land 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.
-83-
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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 the full cost method of accounting as well as certain equipment leases related to
construction projects, are presented in Operations and Maintenance expense on the Consolidated Statement of
Income. The following table summarizes the components of the Company’s total operating lease costs (in
thousands):
Year Ended September 30
2023
2022
Operating Lease Expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Variable Lease Expense(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Short-Term Lease Expense(2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Sublease Income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total Lease Expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
7,484
507
1,694
—
9,685
Lease Costs Recorded to Property, Plant and Equipment(3) . . . . . . . . . . . . . . . . . . . $
24,018
$
$
$
4,909
462
461
(166)
5,666
19,839
(1) Variable lease payments that are not dependent on an index or rate are not included in the lease 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 commencement date of a leasing
arrangement based on the present value of lease payments over the lease term. The weighted average remaining
lease term was 6.1 years and 6.0 years as of September 30, 2023 and 2022, respectively. The weighted average
discount rate was 5.48% and 3.92% as of September 30, 2023 and 2022, 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 lease term of one year or
less are not recorded on the Consolidated Balance Sheet.
The following amounts related to operating leases were recorded on the Company’s Consolidated Balance
Sheet (in thousands):
Assets:
Year Ended September 30
2023
2022
Deferred Charges . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
39,664
$
37,120
Liabilities:
Other Accruals and Current Liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Other Liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
9,969
29,510
$
$
14,239
22,881
Cash paid for lease liabilities, reported in cash provided by operating activities on the Company’s
Consolidated Statement of Cash Flows, was $9.7 million and $5.7 million for the years ended September 30,
2023 and 2022, respectively. The Company did not record any right-of-use assets in exchange for new lease
liabilities during the years ended September 30, 2023 or 2022.
-84-
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The following schedule of operating lease liability maturities summarizes the undiscounted lease
payments owed by the Company to lessors pursuant to contractual agreements in effect as of September 30,
2023 (in thousands):
At September 30, 2023
2024 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
2025 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2026 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2027 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2028 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Thereafter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total Lease Payments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less: Interest
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total Lease Liability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
10,187
8,791
6,557
5,809
5,195
9,971
46,510
(7,031)
39,479
Note E — 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 natural gas wells and has capitalized such costs in
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 other 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.
-85-
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
As discussed in Note B — Asset Acquisitions and Divestitures, on June 30, 2022, the Company
completed the sale of 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 Liabilities Settled in the table below.
The following is a reconciliation of the change in the Company’s asset retirement obligations:
Year Ended September 30
2023
2022
2021
Balance at Beginning of Year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Liabilities Incurred . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Revisions of Estimates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Liabilities Settled . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accretion Expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Balance at End of Year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
161,545
3,313
6,728
(14,448)
8,354
165,492
(Thousands)
209,639
$
2,401
10,700
(71,171)
9,976
161,545
$
$
$
192,228
7,035
14,509
(14,270)
10,137
209,639
Note F — Regulatory Matters
Regulatory Assets and Liabilities
The Company has recorded the following regulatory assets and liabilities:
Regulatory Assets(1):
Pension Costs(2) (Note K) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Post-Retirement Benefit Costs(2) (Note K) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Recoverable Future Taxes (Note G) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Environmental Site Remediation Costs(2) (Note L) . . . . . . . . . . . . . . . . . . . . . . . . .
Asset Retirement Obligations(2) (Note E) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Unamortized Debt Expense (Note A) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other(3) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total Regulatory Assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less: Amounts Included in Other Current Assets . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total Long-Term Regulatory Assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
At September 30
2023
2022
(Thousands)
20,459
2,536
69,045
—
19,384
7,240
66,132
184,796
(36,373)
148,423
$
$
11,677
6,814
106,247
3,646
18,517
8,884
47,805
203,590
(21,358)
182,232
-86-
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Regulatory Liabilities:
Cost of Removal Regulatory Liability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Taxes Refundable to Customers (Note G) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Post-Retirement Benefit Costs(5) (Note K) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Pension Costs(4) (Note K) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Amounts Payable to Customers (See Regulatory Mechanisms in Note A) . . . . . . .
Environmental Site Remediation Costs(4) (Note L) . . . . . . . . . . . . . . . . . . . . . . . . .
Other(6) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total Regulatory Liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less: Amounts included in Current and Accrued Liabilities . . . . . . . . . . . . . . . . . .
Total Long-Term Regulatory Liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
At September 30
2023
2022
(Thousands)
277,694
268,562
159,760
—
59,019
619
43,167
808,821
(97,124)
711,697
$
$
259,947
362,098
167,305
8,242
419
—
44,549
842,560
(31,712)
810,848
(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) $36,373 and $21,358 are included in Other Current Assets on the Consolidated Balance Sheets at
September 30, 2023 and 2022, respectively, since such amounts are expected to be recovered from
ratepayers in the next 12 months. $29,759 and $26,447 are included in Other Regulatory Assets on the
Consolidated Balance Sheets at September 30, 2023 and 2022, respectively.
(4) Included in Other Regulatory Liabilities on the Consolidated Balance Sheets.
(5) $5,800 is included in Other Accruals and Current Liabilities on the Consolidated Balance Sheets at both
September 30, 2023 and 2022, since such amounts are expected to be passed back to ratepayers in the
next 12 months. $153,960 and $161,505 are included in Other Regulatory Liabilities on the Consolidated
Balance Sheets at September 30, 2023 and 2022, respectively.
(6) $32,305 and $25,493 are included in Other Accruals and Current Liabilities on the Consolidated Balance
Sheets at September 30, 2023 and 2022, respectively, since such amounts are expected to be passed back
to ratepayers in the next 12 months. $10,862 and $19,056 are included in Other Regulatory Liabilities on
the Consolidated Balance Sheets at September 30, 2023 and 2022, 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 E — Asset Retirement Obligations. Rather, they are classified as a
regulatory liability in recognition of the fact that the Company has collected dollars from customers that will be
used in the future to fund asset retirement costs.
-87-
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
New York Jurisdiction
Distribution Corporation's current delivery rates in its New York jurisdiction were approved by the
NYPSC in an order issued on April 20, 2017 with rates becoming effective May 1, 2017 ("2017 Rate Order").
The 2017 Rate Order provided for a return on equity of 8.7% and directed the implementation of an earnings
sharing mechanism to be in place beginning on April 1, 2018. On October 31, 2023, Distribution Corporation
made a filing with the NYPSC seeking an increase of $88.8 million in its total annual operating revenues for the
projected rate year ending September 30, 2025, with a proposed effective date of October 1, 2024 that includes
the maximum suspension period permitted under the New York Public Service Law ("2023 Rate Filing"). The
Company is also proposing, among other things, to continue its leak prone pipe replacement program and to
implement a number of initiatives that will facilitate achievement of the emissions reduction goals of the
Climate Leadership and Community Protection Act.
The 2017 Rate Order 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 2022, Distribution Corporation made a filing
with the NYPSC to effectuate a temporary 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 ceased funding the
Retirement Plan and its VEBA trusts in its New York jurisdiction. The 2023 Rate Filing proposes to keep the
rate recovery of pension and OPEB costs at zero in the rate year and reflect the $15 million of savings in new
base delivery rates.
On August 13, 2021, the NYPSC issued an order extending the date through which qualified pipeline
replacement costs incurred by the Company can be recovered using the existing system modernization tracker
for two years (until March 31, 2023). On December 9, 2022, the Company filed a petition with the NYPSC to
effectuate a system improvement tracker through which qualified pipeline replacement costs through September
30, 2024 would be tracked and recovered, and to recover certain deferred costs associated with the existing
system modernization tracker, effective April 1, 2023. The NYPSC approved the petition by order dated March
17, 2023 contingent on the Company not filing a base rate case that would result in new rates becoming
effective prior to October 1, 2024. The 2023 Rate Filing proposes to stop accruing and collecting revenues
under its current system modernization and system improvement trackers and shift those revenues into the
In the absence of a multi-year rate plan settlement, the Company is
Company’s new base delivery rates.
requesting that it be allowed to reinstate a tracking mechanism similar to the existing system modernization
tracker.
Pennsylvania Jurisdiction
Distribution Corporation’s delivery rates effective through July 31, 2023 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. A settlement involving all active parties to
the proceeding was reached and filed with the PaPUC on April 13, 2023. The settlement provided for, among
other things, an increase in Distribution Corporation’s annual base rate operating revenues of $23 million. The
PaPUC approved the settlement in full, without modification or correction, on June 15, 2023 and new rates went
into effect on August 1, 2023.
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. All matters with respect to
this tariff supplement were finalized on February 24, 2022 with the PaPUC’s approval of an Administrative
Law Judge’s Recommended Decision. Concurrent with that decision, the Company discontinued regulatory
-88-
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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.
FERC Jurisdiction
Supply Corporation filed a NGA Section 4 rate case at FERC on July 31, 2023 proposing rate increases to
be effective February 1, 2024. The proposed rates reflect an annual cost of service of $385.4 million, a rate
base of $1.32 billion and a proposed cost of equity of 15.12%. If the proposed rate increases finally approved at
the end of the proceeding exceed the rates that were in effect at July 31, 2023, but are less than rates put into
effect subject to refund on February 1, 2024, Supply Corporation would be required to refund the difference
between the rates collected subject to refund and the final approved rates, with interest at the FERC-approved
rate. If the rates approved at the end of the proceeding are lower than the rates in effect at July 31, 2023, such
lower rates will become effective prospectively from the effective date provided by the applicable FERC order,
and refunds with interest will be limited to the difference between the rates collected subject to refund and the
rates in effect at July 31, 2023.
Empire’s 2019 rate settlement provides that Empire must make a rate case filing no later than May 1,
2025.
Note G — Income Taxes
The components of federal and state income taxes included in the Consolidated Statements of Income are
as follows:
Year Ended September 30
2023
2022
2021
(Thousands)
Current Income Taxes —
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Federal
State . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
11,744
1,386
Deferred Income Taxes —
Federal
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
State . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total Income Taxes
106,801
44,602
164,533
$
$
$
— $
12,214
(10)
8,699
137,025
(32,610)
116,629
$
90,970
15,023
114,682
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.
During fiscal 2022, the Company's deferred income taxes were initially 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
-89-
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
during the quarter ended September 30, 2022. As the rate reduction occurs through fiscal 2032, an annual re-
measurement will be made. This amount is reflected in State Income Taxes.
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 accompanying 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 before income taxes. The following is a reconciliation of this difference:
U.S. Income Before Income Taxes . . . . . . . . . . . . . . . . . . . . . . . . . . $
Income Tax Expense, Computed at
U.S. Federal Statutory Rate of 21% . . . . . . . . . . . . . . . . . . . . . . . . $
State Valuation Allowance (1)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . .
State Income Taxes (2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Amortization of Excess Deferred Federal Income Taxes . . . . . . . . .
Plant Flow Through Items . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Stock Compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Federal Tax Credits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Miscellaneous . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total Income Taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Year Ended September 30
2023
2022
2021
641,399
134,694
—
36,331
(6,053)
(2,856)
957
(6)
1,466
164,533
(Thousands)
682,650
$
$
$
143,357
(24,850)
8,736
(5,184)
(814)
820
(5,701)
265
116,629
$
$
$
478,329
100,449
(5,560)
24,300
(5,215)
(1,503)
2,239
(310)
282
114,682
(1) During fiscal 2022, the valuation allowance recorded against certain state deferred tax assets was
removed. See discussion below.
(2) The state income tax expense shown above includes adjustments to the estimated state effective tax rates
utilized in the calculation of deferred income 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
2023
2022
(Thousands)
Deferred Tax Liabilities:
Unrealized Hedging Gains . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Property, Plant and Equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Pension and Other Post-Retirement Benefit Costs . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total Deferred Tax Liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred Tax Assets:
3,385
1,178,893
44,358
21,470
1,248,106
Unrealized Hedging Losses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Tax Loss and Credit Carryforwards . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Pension and Other Post-Retirement Benefit Costs . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total Deferred Tax Assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total Net Deferred Income Taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
—
(33,744)
(41,843)
(48,349)
(123,936)
1,124,170
$
$
—
954,757
30,132
48,893
1,033,782
(215,187)
(50,686)
(37,250)
(32,430)
(335,553)
698,229
-90-
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The following is a summary of changes in valuation allowances for deferred tax assets:
Year Ended September 30
2023
2022
2021
Balance at Beginning of Year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Additions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deductions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Balance at End of Year
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
(Thousands)
57,645
—
57,645
$
— $
— $
—
—
— $
63,205
—
5,560
57,645
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 the benefit from the deferred tax assets 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 the likelihood of the realization of the deferred tax
assets. 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, 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 adjustment of $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 2022 due to
sustained strong operating results as well as the expectation for future forecasted earnings in Pennsylvania. The
sale of California assets also resulted in higher apportionment of income to Pennsylvania on a prospective basis,
which further supported realization of existing Pennsylvania net operating loss deferred tax assets.
Accordingly, as of September 30, 2022,
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 income taxes associated
with rate-regulated activities that are expected to be refundable to customers amounted to $268.6 million and
$362.1 million at September 30, 2023 and 2022, respectively. Also, regulatory assets representing future
amounts collectible from customers, corresponding to additional deferred income taxes not previously recorded
because of ratemaking practices, amounted to $69.0 million and $106.2 million at September 30, 2023 and
2022, respectively. The primary change in these was due to Distribution Corporation's rate settlement in
Pennsylvania. For further discussion of Distribution Corporation rate matters, refer to Note F — Regulatory
Matters.
The Company is in the Compliance Maintenance Phase of the IRS Compliance Assurance Process
(“CAP”) for fiscal 2023. The CAP program is intended for taxpayers with a low risk of non-compliance who are
cooperative and transparent with few, if any, material issues that require resolution. The federal statute of
limitations remains open for fiscal 2020 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 return. Net operating losses being
carried forward from prior years remain subject to examination on a future return until they are utilized, upon
which time the statute of limitation begins. The Company has no unrecognized tax benefits as of September 30,
2023, 2022, or 2021.
-91-
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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, subject to final guidance. The IRS released guidance on April 14, 2023, providing a natural gas
transmission and distribution property safe harbor method of accounting (“NGSH method”) that taxpayers may
use to determine whether expenses to repair, maintain, replace, or improve natural gas transmission and
distribution property must be capitalized or be allowable as deductions for repairs. The Company is planning to
elect this change in tax accounting method with its consolidated tax return filing in the upcoming year and has
reflected an estimate in the September 30, 2023 financial statements of what is intended to be treated as a repair
for tax purposes rather than being capitalized. That estimate, which amounted to $99.5 million, has been
recorded in Income Tax Expense.
Tax carryforwards available, prior to valuation allowance, at September 30, 2023, were as follows:
Jurisdiction
Tax Attribute
Amount
(Thousands)
Pennsylvania . . . . . . . . . . . . . Net Operating Loss . . . . . . . . . . . . . . . . . . . $
Federal . . . . . . . . . . . . . . . . . . General Business Credits . . . . . . . . . . . . . . $
404,403
1,819
Expires
2031-2043
2042
-92-
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note H — Capitalization and Short-Term Borrowings
Summary of Changes in Common Stock Equity
Common Stock
Shares
Amount
Paid In
Capital
Earnings
Reinvested
in the
Business
Accumulated
Other
Comprehensive
Income (Loss)
Balance at September 30, 2020 . . . . . . . . . . . 90,955
Net Income Available for Common Stock . .
Dividends Declared on Common Stock
($1.80 Per Share) . . . . . . . . . . . . . . . . . . . .
Other Comprehensive Loss, Net of Tax . . . .
Share-Based Payment Expense(1) . . . . . . . .
Common Stock Issued (Repurchased) Under
Stock and Benefit Plans . . . . . . . . . . . . . . .
227
Balance at September 30, 2021 . . . . . . . . . . . 91,182
Net Income Available for Common Stock . .
Dividends Declared on Common Stock
($1.86 Per Share) . . . . . . . . . . . . . . . . . . . .
Other Comprehensive Loss, Net of Tax . . . .
Share-Based Payment Expense(1) . . . . . . . .
Common Stock Issued (Repurchased) Under
Stock and Benefit Plans . . . . . . . . . . . . . . .
296
Balance at September 30, 2022 . . . . . . . . . . . 91,478
Net Income Available for Common Stock . .
Dividends Declared on Common Stock
($1.94 Per Share) . . . . . . . . . . . . . . . . . . . .
Other Comprehensive Income, Net of Tax . .
Share-Based Payment Expense(1) . . . . . . . .
Common Stock Issued (Repurchased) Under
Stock and Benefit Plans . . . . . . . . . . . . . . .
341
Balance at September 30, 2023 . . . . . . . . . . . 91,819
$90,955
(Thousands, except per share amounts)
$1,004,158 $ 991,630
363,647
$
(114,757)
15,297
227
91,182
(2,009)
1,017,446
17,699
296
91,478
(8,079)
1,027,066
(164,102)
1,191,175
566,021
(170,111)
1,587,085
476,866
(178,095)
(398,840)
(513,597)
(112,136)
(625,733)
570,673
18,746
(5,051)
$1,040,761 $1,885,856 (2) $
(55,060)
341
$91,819
(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.
(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, 2023, $1.7 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
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
-93-
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
issue shares purchased directly from the Company or shares purchased on the open market by an independent
agent. During 2023, the Company did not issue any original issue shares of common stock for the Direct Stock
Purchase and Dividend Reinvestment Plan or the Company's 401(k) plans.
During 2023, the Company issued 12,055 original issue shares of common stock as a result of SARs
exercises, 119,147 original issue shares of common stock for restricted stock units that vested and 278,687
issue shares of common stock for performance shares that vested. Holders of stock-based
original
compensation awards will often tender shares of common stock to the Company for payment of applicable
withholding taxes. During 2023, 103,059 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 (the "DCP"), as partial consideration for the
directors’ services during the fiscal year. Under this program, the Company issued 31,715 original issue shares
of common stock during 2023. In addition, the Company issued 2,796 original issue shares of common stock to
officers of the Company who elected to defer their shares pursuant to the dividend reinvestment features of the
Company's DCP during 2023.
Stock Award Plans
The Company has various 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, restricted stock,
restricted stock units, performance units or performance shares.
Stock-based compensation expense for the years ended September 30, 2023, 2022 and 2021 was
approximately $18.6 million, $17.6 million and $15.2 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, 2023, 2022 and
2021 was approximately $2.4 million, $2.5 million and $2.4 million, respectively. A portion of stock-based
to capitalization under IRS uniform capitalization rules. Stock-based
compensation expense is subject
compensation of $0.1 million was capitalized under these rules during each of the years ended September 30,
2023, 2022 and 2021. The tax benefit related to stock-based compensation exercises and vestings was $1.2
million for the year ended September 30, 2023.
Pursuant to registration statements for these plans, there were 1,510,900 shares available for future grant
at September 30, 2023. These shares include shares available for future options, SARs, restricted stock and
performance share grants.
-94-
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
SARs
Transactions for 2023 involving SARs for all plans are summarized as follows:
Outstanding at September 30, 2022 . . . . . . . . . . . . . . . . . . . . . . . .
Granted in 2023 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Exercised in 2023 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Forfeited in 2023 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Expired in 2023 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Outstanding at September 30, 2023 . . . . . . . . . . . . . . . . . . . . . . . .
SARs exercisable at September 30, 2023 . . . . . . . . . . . . . . . . . . . .
Number of
Shares Subject
To Option
72,008
Weighted
Average
Exercise Price
53.05
$
— $
—
53.05
(72,008) $
—
— $
—
— $
— $
— $
— $
— $
Aggregate
Intrinsic
Value
(In thousands)
—
—
The Company did not grant any SARs during the years ended September 30, 2022 and 2021. The
Company’s SARs included both performance-based and nonperformance-based SARs, but the performance
conditions associated with the performance-based SARs at the time of grant were all 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, 2023 and 2022 totaled
approximately $0.8 million and $2.0 million, respectively. During the year ended September 30, 2021, no
SARs were exercised. There were no SARs that became fully vested during the years ended September 30,
2023, 2022 and 2021. The SARs that were outstanding at September 30, 2022 had been fully vested since fiscal
2017.
Restricted Stock Units
Transactions for 2023 involving nonperformance-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, 2022 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Granted in 2023 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Vested in 2023 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Forfeited in 2023 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Outstanding at September 30, 2023 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
347,427
$
133,173
(119,147) $
(19,267) $
$
342,186
44.58
58.10
44.82
46.88
49.63
The Company also granted 128,950 and 172,513 nonperformance-based restricted stock units during the
years ended September 30, 2022 and 2021,
respectively. The weighted average fair value of such
nonperformance-based restricted stock units granted in 2022 and 2021 was $54.10 per share and $37.98 per
share, respectively. As of September 30, 2023, unrecognized compensation expense related to nonperformance-
based restricted stock units totaled approximately $7.5 million, which will be recognized over a weighted
average period of 2.2 years.
Vesting restrictions for the nonperformance-based restricted stock units outstanding at September 30,
2023 will lapse as follows: 2024 — 115,652 units; 2025 — 98,343 units; 2026 — 79,021 units; 2027 — 33,527
units; and 2028 — 15,643 units.
-95-
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Performance Shares
Transactions for 2023 involving performance shares for all plans are summarized as follows:
Number of
Performance
Shares
Weighted Average
Fair Value per
Award
Outstanding at September 30, 2022 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Granted in 2023 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Vested in 2023 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Forfeited in 2023 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Change in Units Based on Performance Achieved . . . . . . . . . . . . . . . . . . . .
Outstanding at September 30, 2023 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
607,179
202,259
$
(278,687) $
(22,805) $
$
78,845
$
586,791
48.60
64.28
42.58
57.20
40.69
55.46
The Company also granted 195,397 and 309,470 performance shares during the years ended
September 30, 2022 and 2021, respectively. The weighted average grant date fair value of such performance
shares granted in 2022 and 2021 was $65.39 per share and $39.19 per share, respectively. As of September 30,
2023, unrecognized compensation expense related to performance shares totaled approximately $12.8 million,
which will be recognized over a weighted average period of 1.7 years. Vesting restrictions for the outstanding
performance shares at September 30, 2023 will lapse as follows: 2024 — 214,158 shares; 2025 — 179,320
shares; and 2026 — 193,313 shares.
The performance shares granted during the years ended September 30, 2023, 2022 and 2021 include
awards that must meet a performance goal related to either relative return on capital over a three-year
performance cycle ("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 2023, 2022 and 2021 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-
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 the 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 performance goal over the respective performance cycles for the ESG performance shares granted
during 2023 and 2022 consists of two parts: reductions in the rates 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 is intended to incentivize and reward performance to
the extent management achieves methane intensity and greenhouse gas reduction targets making progress
towards the Company's 2030 goals. 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 greenhouse 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 vesting term of the award.
-96-
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The fair value is recorded as compensation expense over the vesting term of the award. There were no ESG
performance shares granted in 2021.
The performance goal over the respective performance cycles for the TSR performance shares granted
during 2023, 2022 and 2021 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 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
In calculating the fair value of the
recorded as compensation expense over the vesting term of the award.
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
2023
2022
2021
Risk-Free Interest Rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Remaining Term at Date of Grant (Years) . . . . . . . . . . . . . . . . . . . .
Expected Volatility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Expected Dividend Yield (Quarterly) . . . . . . . . . . . . . . . . . . . . . . . .
4.03 %
2.80
31.6 %
N/A
0.85 %
2.80
29.7 %
N/A
0.19 %
2.80
29.1 %
N/A
Redeemable Preferred Stock
As of September 30, 2023, 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
2023
2022
(Thousands)
Medium-Term Notes(1):
7.4% due June 2025 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
50,000
$
99,000
Notes(1)(2)(3):
2.95% to 5.50% due July 2025 to March 2031 . . . . . . . . . . . . . . . . . . . . . . . . .
Total Long-Term Debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less Unamortized Discount and Debt Issuance Costs . . . . . . . . . . . . . . . . . . . . .
Less Current Portion(4) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2,350,000
2,400,000
15,515
—
$ 2,384,485
2,550,000
2,649,000
16,591
549,000
$ 2,083,409
(1) The Medium-Term Notes and Notes are unsecured.
-97-
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,
$500.0 million of 2.95% notes and $300.0 million of 5.50% 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) None of the Company's long-term debt as of September 30, 2023 had a maturity date within the following
twelve-month period. Current Portion of Long-Term Debt at September 30, 2022 consisted of
$500.0 million of 3.75% notes and $49.0 million of 7.395% notes. The Company redeemed
$150.0 million of the 3.75% notes on November 25, 2022 using a portion of the proceeds from short-term
borrowings, as discussed below. In March 2023, the Company redeemed the remaining $350.0 million of
the 3.75% notes as well as the $49.0 million of 7.395% notes.
On May 18, 2023, the Company issued $300.0 million of 5.50% notes due October 1, 2026. After
deducting underwriting discounts, commissions and other debt issuance costs, the net proceeds to the Company
amounted to $297.3 million. The proceeds of this debt issuance were used for general corporate purposes,
including to repay all indebtedness under the $250.0 million unsecured committed delayed draw term loan
under the 364-Day Credit Agreement, discussed below.
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.
As of September 30, 2023, the aggregate principal amounts of long-term debt maturing during the next
five years and thereafter are as follows: zero in 2024, $500.0 million in 2025, $500.0 million in 2026, $600.0
million in 2027, $300.0 million in 2028, and $500.0 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 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 provided 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 used the proceeds for general corporate purposes, which included using $150.0 million for the
-98-
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
November 25, 2022 redemption of a portion of the Company's outstanding long-term debt with a maturity date
of March 1, 2023. All indebtedness under the 364-Day Credit Agreement was repaid on May 18, 2023.
The Company also has uncommitted lines of credit with financial institutions for general corporate
purposes. Borrowings under these uncommitted lines of credit would be made at competitive market rates. The
uncommitted credit lines are revocable at the option of the financial institution and are reviewed on an annual
basis. The Company anticipates that its uncommitted lines of credit generally will be renewed or substantially
replaced by similar lines. Other financial institutions may also provide the Company with uncommitted or
discretionary lines of credit in the future. The total amount available to be issued under the Company’s
commercial paper program is $500.0 million. The commercial paper program is backed by the Credit
Agreement.
At September 30, 2023, the Company had outstanding commercial paper of $287.5 million with a
weighted average interest rate on the commercial paper of 6.13%. The Company did not have any outstanding
short-term notes payable to banks at September 30, 2023. 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.
Debt Restrictions
The Credit Agreement provides that the Company's debt to capitalization ratio will not exceed 0.65 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, 2023, $190.7 million was added back to the Company's total capitalization for
purposes of the calculation under the 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
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.
At September 30, 2023, the Company’s debt to capitalization ratio, as calculated under the Credit Agreement
was 0.46. The constraints specified in the Credit Agreement would have permitted an additional $3.17 billion in
short-term and/or long-term debt to be outstanding at September 30, 2023 before the Company’s debt to
capitalization ratio exceeded 0.65.
losses on other derivative financial
A downgrade in the Company’s credit ratings could increase borrowing costs, negatively impact the
availability of capital from banks, commercial paper purchasers and other sources, and require the Company's
subsidiaries to post letters of credit, cash or other assets as collateral with certain counterparties. If the Company
is not able to maintain investment grade credit ratings, it may not be able to access commercial paper markets.
However, the Company expects that it could borrow under its credit facilities or rely upon other liquidity
sources.
The Credit Agreement contains a cross-default provision whereby the failure by the Company or its
significant subsidiaries to make payments under other borrowing arrangements, or the occurrence of certain
events affecting those other borrowing arrangements, could trigger an obligation to repay any amounts
outstanding under the Credit Agreement. In particular, a repayment obligation could be triggered if (i) the
Company or any of its significant subsidiaries fails to make a payment when due of any principal or interest on
-99-
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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, 2023, the Company would have been permitted to
issue up to a maximum of approximately $3.43 billion in additional unsubordinated long-term indebtedness at
then current market interest rates, in addition to being able to issue new indebtedness to replace existing debt
(further limited by the debt to capitalization ratio constraint under the Company's Credit Agreement, as
discussed above). The Company's present liquidity position is believed to be adequate to satisfy known
demands. It is possible, depending on amounts reported in various income statement and balance sheet line
items, that the indenture covenants could, for a period of time, prevent the Company from issuing incremental
unsubordinated long-term debt, or significantly limit the amount of such debt that could be issued. Losses
incurred as a result of significant impairments of oil and gas properties have in the past resulted in such
temporary restrictions. The indenture covenants would not preclude the Company from issuing new long-term
debt to replace existing long-term debt, or from issuing additional short-term debt. Please refer to 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 $50.0 million (or 2.1%) of the Company’s long-term
debt (as of September 30, 2023) was issued, contains a cross-default provision whereby the failure by the
Company to perform certain obligations under other borrowing arrangements could trigger an obligation to
repay the debt outstanding under the indenture. In particular, a repayment obligation could be triggered if the
Company fails (i) to pay any scheduled principal or interest on any debt under any other indenture or agreement,
or (ii) to perform any other term in any other such indenture or agreement, and the effect of the failure causes,
or would permit the holders of the debt to cause, the debt under such indenture or agreement to become due
prior to its stated maturity, unless cured or waived.
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, 2023 and
2022. Financial assets and liabilities are classified in their entirety based on the lowest level of input that is
significant to the fair value measurement.
-100-
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Recurring Fair Value Measures
Level 1
Level 2
Level 3
Netting
Adjustments(1)
Total(1)
At Fair Value as of September 30, 2023
(Dollars in thousands)
Assets:
Cash Equivalents — Money Market Mutual Funds . . . $ 39,332
Derivative Financial Instruments:
$
— $ — $
— $ 39,332
Over the Counter Swaps — Gas . . . . . . . . . . . . . . .
Over the Counter No Cost Collars — Gas . . . . . . . .
Contingent Consideration for Asset Sale . . . . . . . . .
Foreign Currency Contracts . . . . . . . . . . . . . . . . . . .
—
—
—
—
65,800
30,966
7,277
150
—
—
—
—
(37,508)
(14,745)
—
(1,453)
28,292
16,221
7,277
(1,303)
Other Investments:
Balanced Equity Mutual Fund . . . . . . . . . . . . . . . . .
Fixed Income Mutual Fund . . . . . . . . . . . . . . . . . . .
15,837
15,897
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 71,066
Liabilities:
Derivative Financial Instruments:
—
—
$ 104,193
—
—
$ — $
—
—
15,837
15,897
(53,706) $ 121,553
Over the Counter Swaps — Gas . . . . . . . . . . . . . . . $
Over the Counter No Cost Collars — Gas . . . . . . . .
Foreign Currency Contracts . . . . . . . . . . . . . . . . . . .
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Total Net Assets/(Liabilities) . . . . . . . . . . . . . . . . . . . . . . $ 71,066
— $ 68,311
14,950
—
—
1,454
— $ 84,715
$ 19,478
$ — $
—
—
$ — $
$ — $
(37,508) $ 30,803
205
(14,745)
1
(1,453)
(53,706) $ 31,009
— $ 90,544
Recurring Fair Value Measures
Level 1
Level 2
Level 3
Netting
Adjustments(1)
Total(1)
At Fair Value as of September 30, 2022
(Dollars in thousands)
Assets:
Cash Equivalents — Money Market Mutual Funds . . . $ 35,015
Hedging Collateral Deposits . . . . . . . . . . . . . . . . . . . . .
91,670
Derivative Financial Instruments:
$
— $ — $
—
—
— $ 35,015
91,670
—
Over the Counter Swaps — Gas . . . . . . . . . . . . . . .
Contingent Consideration for Asset Sale . . . . . . . . .
Foreign Currency Contracts . . . . . . . . . . . . . . . . . . .
—
—
—
5,177
8,176
128
—
—
—
(4,178)
—
(128)
999
8,176
—
Other Investments:
Balanced Equity Mutual Fund . . . . . . . . . . . . . . . . .
Fixed Income Mutual Fund . . . . . . . . . . . . . . . . . . .
19,506
33,348
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 179,539
Liabilities:
Derivative Financial Instruments:
—
—
$ 13,481
—
—
$ — $
—
—
19,506
33,348
(4,306) $ 188,714
Over the Counter Swaps — Gas . . . . . . . . . . . . . . . $
Over the Counter No Cost Collars — Gas . . . . . . . .
Foreign Currency Contracts . . . . . . . . . . . . . . . . . . .
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Total Net Assets/(Liabilities) . . . . . . . . . . . . . . . . . . . . . . $ 179,539
— $ 517,464
— 270,453
—
2,048
— $ 789,965
$ — $
—
—
$ — $
$(776,484) $ — $
(4,178) $ 513,286
— 270,453
1,920
(4,306) $ 785,659
— $(596,945)
(128)
(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.
-101-
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Derivative Financial Instruments
At September 30, 2023, 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. Hedging collateral deposits of $91.7 million at September 30,
2022, 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. SOFR 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 is 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, 2023, 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, 2023 and 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 Divestitures and 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, 2023 and 2022, 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
2023
Carrying
Amount
2023
Fair Value
2022
Carrying
Amount
2022
Fair Value
(Thousands)
Long-Term Debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 2,384,485
$ 2,210,478
$ 2,632,409
$ 2,453,209
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 Sheets approximate fair value. The fair value of long-term debt was calculated using observable inputs
(U.S. Treasuries 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
-102-
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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):
Life Insurance Contracts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Equity Mutual Fund . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fixed Income Mutual Fund . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
At September 30
2023
2022
(Thousands)
42,242
15,837
15,897
73,976
$
$
42,171
19,506
33,348
95,025
Investments in life insurance contracts are stated at their cash surrender values or net present value.
Investments in an equity mutual fund and a fixed income mutual fund are stated at fair value based on quoted
market prices with changes in fair value recognized in net income. The insurance contracts and equity mutual
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. The Company enters into over-the-counter no cost collar and swap agreements for
natural gas to manage the price risk associated with forecasted sales of 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 duration of the Company’s cash flow hedges does not
typically exceed 5 years while the foreign currency forward contracts do not exceed 7 years.
On June 30, 2022, the Company completed the sale of Seneca’s California assets. 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 Company has determined that this contingent consideration
meets the definition of a derivative 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 $7.3 million and $8.2 million at September 30, 2023 and September 30, 2022,
respectively. A $0.9 million mark-to-market adjustment was recorded during the year ended September 30,
2023.
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, 2023 and September 30, 2022.
Cash Flow Hedges
For derivative financial instruments that are designated and qualify as a cash flow hedge, 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.
-103-
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
As of September 30, 2023, the Company had 411.3 Bcf of natural gas commodity derivative contracts
(swaps and no cost collars) outstanding.
As of September 30, 2023, the Company was hedging a total of $56.9 million of forecasted transportation
costs denominated in Canadian dollars with foreign currency forward contracts.
As of September 30, 2023, the Company had $4.6 million of net hedging gains after taxes included in the
accumulated other comprehensive income (loss) balance. Of this amount, it is expected that $11.5 million of
unrealized gains after taxes will be reclassified into the Consolidated Statement of Income within the next
12 months as the underlying hedged transactions are recorded in earnings. The remaining unrealized losses will
be being reclassified into the Consolidated Statement of Income in subsequent periods.
The Effect of Derivative Financial Instruments on the Statement of Financial Performance for the
Year Ended September 30, 2023 and 2022 (Dollar Amounts in Thousands)
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,
2023
2022
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,
2023
2022
Derivatives in Cash
Flow Hedging
Relationships
Commodity Contracts
Foreign Currency Contracts
Total
$
$
708,234
$(1,048,200)
Operating Revenue
(28)
(2,631)
Operating Revenue
708,206
$(1,050,831)
$
$
(88,015) $ (882,594) (1)
(641)
13
(88,656) $ (882,581)
(1) On June 30, 2022, the Company completed 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 Operating Revenues on the Consolidated Statement of
Income for the year ended September 30, 2022. This loss is included in the reported reclassification
amounts.
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-counter swap positions, no cost collars and applicable foreign currency forward contracts with nineteen
counterparties of which eleven are in a net gain position. On average, the Company had $3.9 million of credit
exposure per counterparty in a gain position at September 30, 2023. The maximum credit exposure per
counterparty in a gain position at September 30, 2023 was $16.1 million. As of September 30, 2023, 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, 2023, sixteen of the nineteen counterparties to the Company’s outstanding derivative
financial contracts (specifically the over-the-counter swaps, over-the-counter no cost collars and applicable
-104-
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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 hedging collateral
deposits or an increase to such deposits could be required. At September 30, 2023, the fair market value of the
derivative financial instrument liabilities with a credit-risk related contingency feature was $7.7 million
according to the Company's internal model (discussed in Note I — Fair Value Measurements) and no hedging
collateral deposits were required to be posted by the Company at September 30, 2023. Depending on the
movement of commodity prices in the future, it is possible that these liability positions could swing into asset
positions, at which point the Company would be exposed to credit risk on its derivative financial instruments. In
that case, the Company's counterparties could be required to post hedging collateral 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.
Note K — 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 $5.7 million, $5.3 million
and $4.8 million for the years ended September 30, 2023, 2022 and 2021, 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 $8.2 million, $7.8 million and $7.2 million for
the years ended
September 30, 2023, 2022 and 2021, 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
-105-
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(from previous years) that have not been reflected in net periodic benefit costs. The expected return on other
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 2023,
2022 and 2021.
Retirement Plan
Other Post-Retirement Benefits
Year Ended September 30
Year Ended September 30
2023
2022
2021
2023
2022
2021
(Thousands)
Change in Benefit Obligation
Benefit Obligation at Beginning of
Period . . . . . . . . . . . . . . . . . . . . . $ 813,828
$ 1,098,456
$ 1,139,105
$ 299,283
$ 431,213
$ 476,722
Service Cost
. . . . . . . . . . . . . . . . . .
Interest Cost
. . . . . . . . . . . . . . . . . .
Plan Participants’ Contributions . . .
Retiree Drug Subsidy Receipts . . . .
5,187
42,516
—
—
8,758
22,827
—
—
9,865
21,686
—
—
587
15,648
3,297
2,969
1,328
9,066
3,271
312
Actuarial Gain . . . . . . . . . . . . . . . . .
(27,313)
(251,173)
(8,141)
(20,789)
(120,276)
Benefits Paid . . . . . . . . . . . . . . . . . .
Benefit Obligation at End of
(65,468)
(65,040)
(64,059)
(26,717)
(25,631)
1,602
9,303
3,216
1,244
(34,729)
(26,145)
Period . . . . . . . . . . . . . . . . . . . . . $ 768,750
$ 813,828
$ 1,098,456
$ 274,278
$ 299,283
$ 431,213
Change in Plan Assets
Fair Value of Assets at Beginning
of Period . . . . . . . . . . . . . . . . . . . $ 845,205
$ 1,095,729
$ 1,016,796
$ 461,438
$ 575,565
$ 547,885
Actual Return on Plan Assets . . . . .
4,975
(205,884)
—
—
20,400
—
122,992
20,000
—
17,449
(94,849)
235
3,297
3,082
3,271
47,541
3,068
3,216
(65,468)
(65,040)
(64,059)
(26,717)
(25,631)
(26,145)
Employer Contributions . . . . . . . . .
Plan Participants’ Contributions . . .
Benefits Paid . . . . . . . . . . . . . . . . . .
Fair Value of Assets at End of
Period . . . . . . . . . . . . . . . . . . . . . $ 784,712
$ 845,205
$ 1,095,729
$ 455,702
$ 461,438
$ 575,565
Net Amount Recognized at End
of Period (Funded Status)
Amounts Recognized in the
. . . . $
Balance Sheets Consist of:
15,962
$
31,377
$
(2,727)
$ 181,424
$ 162,155
$ 144,352
Non-Current Liabilities . . . . . . . . . . $
— $
— $
(2,727)
$ (2,915)
$ (3,065)
$ (4,799)
Non-Current Assets . . . . . . . . . . . . .
Net Amount Recognized at End of
15,962
31,377
—
184,339
165,220
149,151
Period . . . . . . . . . . . . . . . . . . . . . $
15,962
$
31,377
$
(2,727)
$ 181,424
$ 162,155
$ 144,352
Accumulated Benefit Obligation . $ 751,912
$ 793,555
$ 1,060,659
N/A
N/A
N/A
Weighted Average Assumptions
Used to Determine Benefit
Obligation at September 30
Discount Rate . . . . . . . . . . . . . . . . .
Rate of Compensation Increase . . .
5.99 %
4.60 %
5.57 %
4.60 %
2.75 %
4.70 %
5.99 %
4.60 %
5.56 %
4.60 %
2.76 %
4.70 %
-106-
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Retirement Plan
Other Post-Retirement Benefits
Year Ended September 30
Year Ended September 30
2023
2022
2021
2023
2022
2021
(Thousands)
Components of Net Periodic
Benefit Cost
Service Cost
. . . . . . . . . . . . . . . . . . $
5,187
$
8,758
$
9,865
$
587
$
Interest Cost
. . . . . . . . . . . . . . . . . .
42,516
Expected Return on Plan Assets . . .
(66,593)
22,827
(52,294)
21,686
15,648
1,328
9,066
$
1,602
9,303
(58,148)
(25,612)
(29,359)
(28,964)
Amortization of Prior Service Cost
(Credit) . . . . . . . . . . . . . . . . . . . .
Recognition of Actuarial (Gain)
436
537
631
(429)
(429)
(429)
Loss(1) . . . . . . . . . . . . . . . . . . . .
(7,680)
26,405
36,814
(8,755)
(7,610)
849
Net Amortization and Deferral for
Regulatory Purposes . . . . . . . . . .
21,512
16,854
14,063
15,157
21,340
28,010
Net Periodic Benefit Cost (Income) $
(4,622)
$
23,087
$
24,911
$ (3,404)
$ (5,664)
$ 10,371
Weighted Average Assumptions
Used to Determine Net Periodic
Benefit Cost at September 30
Effective Discount Rate for Benefit
Obligations . . . . . . . . . . . . . . . . .
Effective Rate for Interest on
5.57 %
2.75 %
2.66 %
5.56 %
2.76 %
2.71 %
Benefit Obligations . . . . . . . . . . .
5.45 %
2.14 %
1.96 %
5.45 %
2.17 %
2.01 %
Effective Discount Rate for Service
Cost . . . . . . . . . . . . . . . . . . . . . . .
Effective Rate for Interest on
Service Cost
. . . . . . . . . . . . . . . .
Expected Return on Plan Assets . . .
Rate of Compensation Increase . . .
5.49 %
2.95 %
3.01 %
5.35 %
3.00 %
3.20 %
5.53 %
6.90 %
4.60 %
2.70 %
5.20 %
4.70 %
2.60 %
6.00 %
4.70 %
5.47 %
5.70 %
4.60 %
2.93 %
5.20 %
4.70 %
2.98 %
5.40 %
4.70 %
(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 $8.3 million, $8.9
-107-
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
million and $8.3 million in 2023, 2022 and 2021, 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 $58.5 million,
$64.9 million and $76.9 million at September 30, 2023, 2022 and 2021, respectively. The projected benefit
obligations for the plans were $69.5 million, $77.2 million and $95.8 million at September 30, 2023, 2022 and
2021, respectively. At September 30, 2023, $13.1 million of the projected benefit obligation is recorded in
Other Accruals and Current Liabilities and the remaining $56.4 million is recorded in Other Liabilities on the
Consolidated Balance Sheets. At September 30, 2022, $17.5 million of the projected benefit obligation was
recorded in Other Accruals and Current Liabilities and the remaining $59.7 million was recorded in Other
Liabilities on the Consolidated Balance Sheets. At September 30, 2021, $15.4 million of the projected benefit
obligation was recorded in Other Accruals and Current Liabilities and the remaining $80.4 million was recorded
in Other Liabilities on the Consolidated Balance Sheets. The weighted average discount rates for these plans
were 5.91%, 5.49% and 2.15% as of September 30, 2023, 2022 and 2021, respectively and the weighted
average rate of compensation increase for these plans was 8.00% as of September 30, 2023, 2022 and 2021.
The cumulative amounts recognized in accumulated other comprehensive income (loss), regulatory
assets, and regulatory liabilities through fiscal 2023, as well as the changes in such amounts during 2023, are
presented in the table below:
Retirement
Plan
Other
Post-Retirement
Benefits
(Thousands)
Non-Qualified
Benefit Plans
Amounts Recognized in Accumulated Other
Comprehensive Income (Loss), Regulatory Assets and
Regulatory Liabilities(1)
Net Actuarial Gain (Loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ (128,118) $
Prior Service (Cost) Credit
Net Amount Recognized . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ (130,154) $
Changes to Accumulated Other Comprehensive Income
(Loss), Regulatory Assets and Regulatory Liabilities
Recognized During Fiscal 2023(1)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(2,036)
Increase in Actuarial Gain (Loss), excluding amortization(2) . . $
Change due to Amortization of Actuarial (Gain) Loss . . . . . . . .
Prior Service (Cost) Credit
. . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net Change . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
(34,305) $
(7,680)
436
(41,549) $
18,440
1,115
19,555
12,626
(8,755)
(429)
3,442
$
$
$
$
(17,286)
—
(17,286)
(2,139)
3,572
—
1,433
(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 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, 2023, the Company recorded a $28.7 million increase to Other
Regulatory Assets in the Company’s Utility and Pipeline and Storage segments and a $8.0 million (pre-tax)
decrease to Accumulated Other Comprehensive Income.
The effect of the discount rate change for the Retirement Plan in 2023 was to decrease the projected
benefit obligation of the Retirement Plan by $28.4 million. The mortality improvement projection scale was
updated, which decreased the projected benefit obligation of the Retirement Plan in 2023 by $0.7 million.
Other actuarial experience increased the projected benefit obligation for the Retirement Plan in 2023 by $1.8
million. The effect of the discount rate change for the Retirement Plan in 2022 was to decrease the projected
-108-
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
benefit obligation of the Retirement Plan by $262.2 million. The effect of the discount rate change for the
Retirement Plan in 2021 was to decrease the projected benefit obligation of the Retirement Plan by $11.2
million.
The Company did not make any cash contributions to the Retirement Plan during the year ended
September 30, 2023. The Company expects that the annual contribution to the Retirement Plan in 2024 will be
in the range of zero to $5.0 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: $67.9 million in 2024; $67.4
million in 2025; $66.9 million in 2026; $66.2 million in 2027; $65.5 million in 2028; and $310.4 million in the
five years thereafter.
The effect of the discount rate change in 2023 was to decrease the other post-retirement benefit obligation
by $10.7 million. The mortality improvement projection scale was updated, which decreased the other post-
retirement benefit obligation in 2023 by $0.4 million. The health care cost trend rates were updated, which
increased the other post-retirement benefit obligation in 2023 by $3.2 million. Other actuarial experience
decreased the other post-retirement benefit obligation in 2023 by $12.9 million, the 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 2022 was to decrease the other post-retirement benefit obligation
by $98.9 million. The mortality improvement projection scale was updated, which increased the other post-
retirement benefit obligation in 2022 by $1.1 million. Other actuarial experience decreased the other post-
retirement benefit obligation in 2022 by $22.5 million, the 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 2021 was to decrease the other post-retirement benefit obligation
by $2.5 million. The mortality improvement projection scale was updated, which decreased the other post-
retirement benefit obligation in 2021 by $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, the 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 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):
2024 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
2025 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
2026 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
2027 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
2028 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
2029 through 2033 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Benefit Payments
25,334
25,479
25,466
25,389
25,260
120,390
Subsidy Receipts
(1,787)
$
(1,881)
$
(1,969)
$
(2,039)
$
$
(2,091)
(10,896)
$
-109-
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Assumed health care cost trend rates as of September 30 were:
2023
2022
2021
Rate of Medical Cost Increase for Pre Age 65 Participants . . . . . . . . . . 6.25 % (1)
Rate of Medical Cost Increase for Post Age 65 Participants . . . . . . . . . . 5.00 % (1)
Annual Rate of Increase in the Per Capita Cost of Covered Prescription
Drug Benefits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.85 % (1)
5.30 % (2)
4.84 % (2)
5.38 % (2)
4.84 % (2)
6.29 % (2)
6.53 % (2)
Annual Rate of Increase in the Per Capita Medicare Part B
Reimbursement
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.00 % (1)
Annual Rate of Increase in the Per Capita Medicare Part D Subsidy . . . 6.60 % (1)
4.84 % (2)
5.96 % (2)
4.84 % (2)
6.15 % (2)
(1) It was assumed that this rate would gradually decline to 4% by 2048.
(2) It was assumed that this rate would gradually decline to 4% by 2046.
The Company did not make any cash contributions to its VEBA trusts during the year ended September
30, 2023. In addition, the Company made direct payments of $0.2 million to retirees not covered by the VEBA
trusts and 401(h) accounts during the year ended September 30, 2023. The Company does not expect to make
any contributions to its VEBA trusts in 2024.
Investment Valuation
The Retirement Plan assets and other post-retirement benefit assets are valued under the current fair value
framework. See Note I — 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, 2023 and 2022, 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):
Retirement Plan Investments
Domestic Equities(1) . . . . . . . . . . . . . . . . . $
International Equities(2) . . . . . . . . . . . . . . .
Global Equities(3) . . . . . . . . . . . . . . . . . . . .
Domestic Fixed Income(4) . . . . . . . . . . . . .
International Fixed Income(5) . . . . . . . . . .
Real Estate (6) . . . . . . . . . . . . . . . . . . . . . . .
Cash Held in Collective Trust Funds . . . . .
Total Retirement Plan Investments . . . . .
401(h) Investments . . . . . . . . . . . . . . . . . . .
Total Retirement Plan Investments
At September 30, 2023
Total
Fair Value
Level 1
Level 2
Level 3
Measured
at NAV(7)
$
37,611
—
36,088
612,820
7,778
123,859
36,800
854,956
(73,319)
37,611
—
—
—
—
—
—
37,611
(3,212)
$
— $
—
—
556,504
7,778
—
—
564,282
(48,184)
—
— $
—
—
36,088
—
56,316
—
—
—
— 123,859
36,800
—
— 253,063
— (21,923)
(excluding 401(h) Investments) . . . . . . $
781,637
$
34,399
$ 516,098
$
— $ 231,140
Miscellaneous Accruals, Interest
Receivables, and Non-Interest Cash . . . .
Total Retirement Plan Assets . . . . . . . . . . $
3,075
784,712
-110-
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Retirement Plan Investments
Domestic Equities(1) . . . . . . . . . . . . . . . . . $
International Equities(2) . . . . . . . . . . . . . . .
Global Equities(3) . . . . . . . . . . . . . . . . . . . .
Domestic Fixed Income(4) . . . . . . . . . . . . .
International Fixed Income(5) . . . . . . . . . .
Real Estate (6) . . . . . . . . . . . . . . . . . . . . . . .
Cash Held in Collective Trust Funds . . . . .
Total Retirement Plan Investments . . . . .
401(h) Investments . . . . . . . . . . . . . . . . . . .
Total Retirement Plan Investments
At September 30, 2022
Total
Fair Value
Level 1
Level 2
Level 3
Measured
at NAV(7)
$
41,633
1,363
44,434
658,833
7,782
140,739
17,388
912,172
(73,044)
41,633
—
—
—
—
—
—
41,633
(3,310)
$
— $
—
—
579,606
7,782
—
—
587,388
(46,694)
—
— $
1,363
—
44,434
—
79,227
—
—
—
— 140,739
—
17,388
— 283,151
— (23,040)
(excluding 401(h) Investments) . . . . . . $
839,128
$
38,323
$ 540,694
$
— $ 260,111
Miscellaneous Accruals, Interest
Receivables, and Non-Interest Cash . . . .
Total Retirement Plan Assets . . . . . . . . . . $
6,077
845,205
(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) Real Estate consists of investments held in a collective trust fund and a real estate investment trust.
(7) Reflects the authoritative guidance related to investments measured at net asset value (NAV).
Other Post-Retirement Benefit Assets
held in VEBA Trusts
Collective Trust Funds — Global Equities . $
Exchange Traded Funds — Fixed Income .
Cash Held in Collective Trust Funds . . . . .
Total VEBA Trust Investments . . . . . . . .
401(h) Investments . . . . . . . . . . . . . . . . . . .
Total Investments (including 401(h)
Investments) . . . . . . . . . . . . . . . . . . . . . . $
Miscellaneous Accruals (including Current
and Deferred Taxes, Claims Incurred But
Not Reported, Administrative) . . . . . . . .
Total Other Post-Retirement Benefit
At September 30, 2023
Total
Fair Value
Level 1
Level 2
Level 3
Measured
at NAV(1)
72,285
289,666
9,637
371,588
73,319
$
— $
289,666
—
289,666
3,212
— $
—
—
—
48,184
— $ 72,285
—
—
—
9,637
81,922
—
21,923
—
444,907
$ 292,878
$
48,184
$
— $103,845
10,795
Assets . . . . . . . . . . . . . . . . . . . . . . . . . . . $
455,702
-111-
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Other Post-Retirement Benefit Assets
held in VEBA Trusts
Collective Trust Funds — Global Equities . $
Exchange Traded Funds — Fixed Income .
Cash Held in Collective Trust Funds . . . . .
Total VEBA Trust Investments . . . . . . . .
401(h) Investments . . . . . . . . . . . . . . . . . . .
Total Investments (including 401(h)
Investments) . . . . . . . . . . . . . . . . . . . . . . $
Miscellaneous Accruals (Including Current
and Deferred Taxes, Claims Incurred But
Not Reported, Administrative) . . . . . . . .
Total Other Post-Retirement Benefit
At September 30, 2022
Total
Fair Value
Level 1
Level 2
Level 3
Measured
at NAV(1)
104,554
270,581
10,635
385,770
73,044
$
— $
270,581
—
270,581
3,310
— $
—
—
—
46,694
— $104,554
—
—
—
10,635
— 115,189
23,040
—
458,814
$ 273,891
$
46,694
$
— $138,229
2,624
Assets . . . . . . . . . . . . . . . . . . . . . . . . . . . $
461,438
(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, 2023 and
September 30, 2022, 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, 2021 . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Unrealized Gains/(Losses) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Balance at September 30, 2022 . . . . . . . . . . . . . . . . . . . . . . . . . . .
Unrealized Gains/(Losses) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Balance at September 30, 2023 . . . . . . . . . . . . . . . . . . . . . . . . . . . $
$
319
234
(553)
—
—
—
— $
(24) $
(18)
42
—
—
—
— $
295
216
(511)
—
—
—
—
-112-
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Other Post-Retirement
Benefit Level 3 Assets
(Thousands)
401(h)
Investments
Balance at September 30, 2021 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Unrealized Gains/(Losses) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Balance at September 30, 2022 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Unrealized Gains/(Losses) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Balance at September 30, 2023 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
24
18
(42)
—
—
—
—
The Company’s assumption regarding the expected long-term rate of return on plan assets is 7.40%
(Retirement Plan) and 6.00% (other post-retirement benefits), effective for fiscal 2024. 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 a mix of equities, fixed income and other securities (including real estate). Risk tolerance is established
through consideration of plan liabilities, plan funded status and corporate financial condition. The assets of the
Retirement Plan 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, 2023 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.
The Company determines the service and interest cost components of net periodic benefit cost using the
spot rate approach, which 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 are
determined by an above mean methodology in that the coupon interest rates that are in the lower 50th percentile
are excluded based on the assumption that the Company would not utilize more expensive (i.e. lower yield)
instruments to settle its liabilities.
-113-
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note L — 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, 2023, the Company has estimated its remaining clean-up costs
related to former manufactured gas plant sites will be approximately $3.7 million. The Company's liability for
such clean-up costs has been recorded in Other Liabilities on the Consolidated Balance Sheet at September 30,
2023. The Company has recovered its environmental clean-up costs through rate recovery 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 have an adverse financial impact on the Company.
Northern Access Project
On February 3, 2017, Supply Corporation and Empire received FERC approval of the Northern Access
project described herein. Shortly thereafter, the NYDEC issued a Notice of Denial of the federal Clean Water
Act Section 401 Water Quality Certification and other state stream and wetland permits for the New York
portion of the project (the Water Quality Certification for the Pennsylvania portion of the project was received
in January of 2017). Subsequently, FERC issued an Order finding that the NYDEC exceeded the statutory time
frame to take action under the Clean Water Act and, therefore, waived its opportunity to approve or deny the
Water Quality Certification. FERC denied rehearing requests associated with its Order and FERC's decisions
were appealed. The Second Circuit Court of Appeals issued an order upholding the FERC waiver orders. In
addition, in the Company's state court litigation challenging the NYDEC's actions with regard to various state
permits, the New York State Supreme Court issued a decision finding these permits to be preempted. The
Company remains committed to the project and, on June 29, 2022, received an extension of time from FERC,
until December 31, 2024, to construct the project, which is the subject of an ongoing appeal at the U.S. Court of
Appeals for the D.C. Circuit. As of September 30, 2023, the Company has spent approximately $55.9 million
on the project, all of which is recorded on the balance sheet.
Other
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. The future gas purchase, transportation
and storage contract commitments during the next five years and thereafter are as follows: $201.7 million in
2024, $91.1 million in 2025, $113.8 million in 2026, $118.3 million in 2027, $121.7 million in 2028 and $768.9
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, 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, 2023, the future contractual commitments related to
the system modernization and expansion projects are $74.9 million in 2024, $8.4 million in 2025, $7.2 million
in 2026, $5.9 million in 2027, $3.3 million in 2028 and $4.7 million thereafter.
The Company, in its Exploration and Production segment, has entered into contractual obligations to
support its development activities and operations in Pennsylvania, including hydraulic fracturing and other well
-114-
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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 $279.5 million in 2024, $185.1 million in 2025, and $47.3 million in 2026. There are no
contractual commitments extending beyond 2026.
In addition to the regulatory matters discussed in Note F — Regulatory Matters, the Company is involved
in other regulatory and litigation matters arising in the normal course of business. These other regulatory and
litigation matters may include, for example,
inspections,
investigations, negligence claims 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.
tax, regulatory or other governmental audits,
Note M — Business Segment Information
The Company reports financial results for four segments: Exploration and Production, Pipeline and
Storage, Gathering, and 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 reserves in the Appalachian region of the United States.
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, 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 and exploration and production companies (including Seneca) from natural
gas producing areas in Pennsylvania to markets in New York and to interstate pipeline delivery points with
access to additional markets in the northeastern United States and Canada.
The Gathering segment is comprised of Midstream Company’s operations. Midstream Company 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 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 (when applicable). When this is not applicable,
the Company evaluates
performance based on net income.
-115-
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Year Ended September 30, 2023
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) . . . . . . . . . . . . $
958,455
$ 259,646
$
13,891
$ 941,779
$ 2,173,771
Intersegment Revenues . . . . . . . . $
— $ 119,545
$ 216,426
Interest Income . . . . . . . . . . . . . . $
3,259
Interest Expense . . . . . . . . . . . . . $
54,317
Depreciation, Depletion and
Amortization . . . . . . . . . . . . . . . $
241,142
Income Tax Expense (Benefit) . . $
87,796
$
$
$
$
7,052
43,499
70,827
34,489
Segment Profit: Net Income
(Loss) . . . . . . . . . . . . . . . . . . . . $
232,275
$ 100,501
$
$
$
$
$
534
14,989
35,725
36,128
99,724
$
$
$
$
$
$
581
6,296
34,233
61,450
7,267
48,395
$
$
$
$
$
$
336,552
17,141
147,038
409,144
165,680
480,895
Expenditures for Additions to
Long-Lived Assets . . . . . . . . . . $
737,725
$ 141,877
$ 103,295
$ 139,922
$ 1,122,819
$
$
$
$
$
$
$
$
— $
— $
2,173,771
— $
(336,552)
— $
(5,662)
157
$
(15,309)
— $
(164)
(531)
$
$
429
(983)
(3,498)
— $
754
$
$
$
$
$
$
$
—
11,479
131,886
409,573
164,533
476,866
1,123,573
Segment Assets . . . . . . . . . . . . . . $ 2,814,218
$2,427,214
$ 912,923
$2,247,743
$ 8,402,098
$
4,795
$
(126,633)
$
8,280,260
At September 30, 2023
(Thousands)
Year Ended September 30, 2022
Exploration
and
Production
Pipeline
and
Storage
Gathering
Utility
Total
Reportable
Segments
All
Other
(Thousands)
Corporate
and
Intersegment
Elimination
Total
Consolidated
Revenue from External
Customers(1)(3) . . . . . . . . . . . . $ 1,010,464
$ 265,415
$
12,086
$ 897,916
$ 2,185,881
Intersegment Revenues . . . . . . . . $
— $ 111,629
$ 202,757
Interest Income . . . . . . . . . . . . . . $
1,929
Interest Expense . . . . . . . . . . . . . $
53,401
Depreciation, Depletion and
Amortization . . . . . . . . . . . . . . . $
208,148
Income Tax Expense (Benefit) . . $
43,898
Significant Item:
Gain on Sale of Assets . . . . . . . $
12,736
$
$
$
$
$
Segment Profit: Net Income
2,275
42,492
67,701
35,043
$
$
$
$
198
16,488
33,998
24,949
$
$
$
$
$
305
2,730
24,115
59,760
17,165
$
$
$
$
$
314,691
7,132
136,496
369,607
121,055
— $
— $
— $
12,736
(Loss) . . . . . . . . . . . . . . . . . . . . $
306,064
$ 102,557
$ 101,111
$
68,948
Expenditures for Additions to
Long-Lived Assets . . . . . . . . . . $
565,791
$
95,806
$
55,546
$ 111,033
$
$
578,680
828,176
At September 30, 2022
(Thousands)
$
$
$
$
$
$
$
$
$
— $
165
6
3
4
$
$
$
— $
3
$
(314,697)
(1,024)
(6,143)
183
(4,429)
$
$
$
$
$
$
2,186,046
—
6,111
130,357
369,790
116,629
— $
— $
12,736
(9)
$
(12,650)
— $
1,212
$
$
566,021
829,388
Segment Assets . . . . . . . . . . . . . . $ 2,507,541
$2,394,697
$ 878,796
$2,299,473
$ 8,080,507
$
2,036
$
(186,281)
$
7,896,262
-116-
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Year Ended September 30, 2021
Exploration
and
Production
Pipeline
and
Storage
Gathering
Utility
Total
Reportable
Segments
All
Other
(Thousands)
Corporate
and
Intersegment
Eliminations
Total
Consolidated
Revenue from External
Customers(1) . . . . . . . . . . . . . . $
836,697
$ 234,397
$
3,116
$ 666,920
$ 1,741,130
Intersegment Revenues . . . . . . . . $
— $ 109,160
$ 190,148
Interest Income . . . . . . . . . . . . . . $
211
Interest Expense . . . . . . . . . . . . . $
69,662
Depreciation, Depletion and
Amortization . . . . . . . . . . . . . . . $
182,492
Income Tax Expense (Benefit) . . $
33,370
$
$
$
$
1,085
40,976
62,431
28,812
$
$
$
$
259
17,493
32,350
28,876
$
$
$
$
$
331
2,117
21,795
57,457
14,007
$
$
$
$
$
299,639
3,672
149,926
334,730
$
$
$
$
$
1,173
49
230
$
$
$
356
(299,688)
486
— $
(3,569)
$
$
$
$
$
$
1,742,659
—
4,388
146,357
335,303
114,682
105,065
$ 11,438
394
$
$
179
(1,821)
Significant Non-Cash Item:
Impairment of Oil and Gas
Producing Properties . . . . . . . . $
Significant Item:
Gain on Sale of Assets . . . . . . . $
Segment Profit: Net Income
76,152
$
— $
— $
— $
76,152
$
— $
— $
76,152
— $
— $
— $
— $
— $ 51,066
— $
51,066
$
$
(Loss) . . . . . . . . . . . . . . . . . . . . $
101,916
$
92,542
Expenditures for Additions to
Long-Lived Assets . . . . . . . . . . $
381,408
$ 252,316
$
$
80,274
$
54,335
34,669
$ 100,845
$
$
329,067
$ 37,645
(3,065)
769,238
$
— $
673
$
$
363,647
769,911
At September 30, 2021
(Thousands)
Segment Assets . . . . . . . . . . . . . . $ 2,286,058
$2,296,030
$ 837,729
$2,148,267
$ 7,568,084
$
4,146
$
(107,405)
$
7,464,825
(1) All Revenue from External Customers originated in the United States.
(2) Revenue from one customer of the Company's Exploration and Production segment, exclusive of hedging
losses transacted with separate parties, represented approximately $208 million of the Company's
consolidated revenue for the year ended September 30, 2023. This one customer was also a customer of
the Company's Pipeline and Storage segment, accounting for an additional $14 million of the Company's
consolidated revenue for the year ended September 30, 2023.
(3) Revenues from three customers of the Company's Exploration and Production segment, exclusive of
hedging losses transacted with separate parties, represented approximately $850 million of the Company's
consolidated 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 of the
Company's consolidated revenue for the year ended September 30, 2022.
Geographic Information
At September 30
2023
2022
2021
(Thousands)
Long-Lived Assets:
United States . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 7,865,832
$ 7,135,131
$ 6,942,376
Note N — 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.
-117-
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The following supplementary information is presented in accordance with the authoritative guidance
regarding disclosures about oil and gas producing activities and related SEC authoritative guidance. As
discussed in Note B — Asset Acquisitions and Divestitures, 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.
Capitalized Costs Relating to Oil and Gas Producing Activities
At September 30
2023
2022
(Thousands)
Proved Properties(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 6,555,088
161,097
Unproved Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
6,716,185
4,269,959
$ 2,446,226
Less — Accumulated Depreciation, Depletion and Amortization . . . . . . . . . . . .
$ 5,915,807
65,994
5,981,801
4,034,266
$ 1,947,535
(1) Includes asset retirement costs of $129.2 million and $120.8 million at September 30, 2023 and 2022,
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 2028. It expects the majority of its
development and exploration costs associated with unproved properties to be transferred into the amortization
base by 2026. Following is a summary of costs excluded from amortization at September 30, 2023:
Total as of
September 30,
2023
Year Costs Incurred
2023
2022
2021
Prior
Acquisition Costs . . . . . . . . . . . . . . . . . . . $
Development Costs . . . . . . . . . . . . . . . . . .
Exploration Costs . . . . . . . . . . . . . . . . . . .
Capitalized Interest . . . . . . . . . . . . . . . . . .
$
143,860
17,207
—
30
161,097
$ 120,349
8,034
—
30
$ 128,413
(Thousands)
$
— $
3,001
—
—
3,001
$
$
— $
3,704
—
—
3,704
$
23,511
2,468
—
—
25,979
-118-
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities
Year Ended September 30
2023
2022
2021
(Thousands)
United States
Property Acquisition Costs:
Proved . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Unproved . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Exploration Costs(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Development Costs(2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Asset Retirement Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
33,190
129,061
10,055
553,469
8,363
734,138
$
$
2,491
10,665
9,631
528,684
9,768
561,239
$
$
1,801
5,102
15,413
329,368
20,194
371,878
(1) Amounts for 2023, 2022 and 2021 include capitalized interest of zero, zero and $0.1 million respectively.
(2) Amounts for 2023, 2022 and 2021 include capitalized interest of $0.1 million, $0.6 million and $0.4
million, respectively.
For the years ended September 30, 2023, 2022 and 2021, the Company spent $342.0 million, $154.3
million and $81.2 million, respectively, developing proved undeveloped reserves.
Results of Operations for Producing Activities
Year Ended September 30
2023
2022
2021
(Thousands, except per Mcfe amounts)
United States
Operating Revenues:
Gas (includes transfers to operations of $1,957, $5,696 and
$3,061, respectively)(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 1,036,499
2,261
Oil, Condensate and Other Liquids . . . . . . . . . . . . . . . . . . . . . . . . .
1,038,760
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total Operating Revenues(2)
253,555
Production/Lifting Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
17,532
Franchise/Ad Valorem Taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
—
Purchased Emission Allowance Expense . . . . . . . . . . . . . . . . . . . . .
5,673
Accretion Expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Depreciation, Depletion and Amortization ($0.63, $0.57 and $0.54
per Mcfe of production, respectively) . . . . . . . . . . . . . . . . . . . . . . .
Impairment of Oil and Gas Producing Properties . . . . . . . . . . . . . . .
Income Tax Expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Results of Operations for Producing Activities (excluding corporate
235,694
—
145,574
$
$ 1,730,723
150,957
1,881,680
283,914
25,112
1,305
7,530
202,418
—
368,925
780,477
135,191
915,668
267,316
22,128
2,940
7,743
177,055
76,152
98,593
overheads and interest charges) . . . . . . . . . . . . . . . . . . . . . . . . . . . $
380,732
$
992,476
$
263,741
(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.
-119-
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Reserve Quantity Information
The Company's proved oil and gas reserve estimates are prepared by the Company's petroleum 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 June 25, 2019.
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 President 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 14 years of
Petroleum Engineering experience with independent oil and gas companies,
licensure as a Professional
Engineer and is a member of the Society of Petroleum 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 President of Reservoir Engineering reviews and approves all new
reserve assignments and significant reserve revisions. Access to the reserve database is restricted. Significant
changes to the reserve report are reviewed by senior management on a quarterly basis. Periodically, the
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 & 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 a professional engineer registered with the State of Texas (consulting at NSAI since 2019 and with over
6 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, 2023 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.
-120-
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, 2020 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Extensions and Discoveries . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Revisions of Previous Estimates . . . . . . . . . . . . . . . . . . . . . . . . . .
Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
September 30, 2021 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Extensions and Discoveries . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Revisions of Previous Estimates . . . . . . . . . . . . . . . . . . . . . . . . . .
Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Sale of Minerals in Place . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
September 30, 2022 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Extensions and Discoveries . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Revisions of Previous Estimates . . . . . . . . . . . . . . . . . . . . . . . . . .
Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Purchases of Minerals in Place . . . . . . . . . . . . . . . . . . . . . . . . . . .
September 30, 2023 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Proved Developed Reserves:
September 30, 2020 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
September 30, 2021 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
September 30, 2022 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
September 30, 2023 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Proved Undeveloped Reserves:
September 30, 2020 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
September 30, 2021 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
September 30, 2022 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
September 30, 2023 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
3,296,113
689,395 (1)
19,940
(312,300) (2)
3,693,148
837,510 (1)
2,882
(341,700) (2)
(21,178)
4,170,662
670,438 (1)
32,379
(372,271) (2)
33,876
4,535,084
2,744,851
3,061,178
3,312,568
3,550,034
551,262
631,970
858,094
985,050
28,972
—
3,033
(1,720)
30,285
—
71
(1,211)
(29,145)
3,325,085
689,395
22,973
(314,020)
3,723,433
837,510
2,953
(342,911)
(50,323)
— 4,170,662
670,438
—
32,379
—
(372,271)
—
—
33,876
— 4,535,084
28,972
30,285
2,773,823
3,091,463
— 3,312,568
— 3,550,034
—
—
—
—
551,262
631,970
858,094
985,050
(1) Extensions and discoveries include 180 Bcf (during 2021), 301 Bcf (during 2022) and 163 Bcf (during
2023), of Marcellus Shale gas (which exceed 15% of total reserves) in the Appalachian region.
Extensions and discoveries include 497 Bcf (during 2021), 537 Bcf (during 2022) and 507 Bcf (during
2023), of Utica Shale gas (which exceed 15% of total reserves) in the Appalachian region.
(2) Production includes 218,016 MMcf (during 2021), 209,463 MMcf (during 2022) and 190,290 MMcf
(during 2023), from Marcellus Shale fields. Production includes 93,253 MMcf (during 2021), 130,240
MMcf (during 2022) and 180,750 MMcf (during 2023), from Utica Shale fields.
-121-
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Proved Developed and Undeveloped Reserves:
September 30, 2020 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Extensions and Discoveries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Revisions of Previous Estimates . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
September 30, 2021 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Extensions and Discoveries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Revisions of Previous Estimates . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Sales of Minerals in Place . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
September 30, 2022 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Revisions of Previous Estimates . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
September 30, 2023 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Proved Developed Reserves:
September 30, 2020 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
September 30, 2021 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
September 30, 2022 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
September 30, 2023 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Proved Undeveloped Reserves:
September 30, 2020 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
September 30, 2021 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
September 30, 2022 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
September 30, 2023 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Oil Mbbl
U.S.
Appalachian
Region
West Coast
Region
Total
Company
12
—
1
(2)
11
—
255
(16)
—
250
(4)
(30)
216
12
11
250
216
—
—
—
—
22,088
1,041
630
(2,233)
21,526
296
532
(1,588)
(20,766)
—
—
—
—
22,088
20,930
—
—
—
596
—
—
22,100
1,041
631
(2,235)
21,537
296
787
(1,604)
(20,766)
250
(4)
(30)
216
22,100
20,941
250
216
—
596
—
—
The Company’s proved undeveloped (PUD) reserves increased from 858 Bcfe at September 30, 2022 to
985 Bcfe at September 30, 2023. PUD reserves in the Utica Shale increased from 503 Bcfe at September 30,
2022 to 873 Bcfe at September 30, 2023. PUD reserves in the Marcellus Shale decreased from 355 Bcfe at
September 30, 2022 to 112 Bcfe at September 30, 2023. The Company’s total PUD reserves were 21.7% of
total proved reserves at September 30, 2023, up from 20.6% of total proved reserves at September 30, 2022.
The Company’s PUD reserves increased from 636 Bcfe at September 30, 2021 to 858 Bcfe at
September 30, 2022. PUD reserves in the Utica Shale increased from 411 Bcfe at September 30, 2021 to 503
Bcfe at September 30, 2022. PUD reserves in the Marcellus Shale increased from 220 Bcfe at September 30,
2021 to 355 Bcfe at September 30, 2022. PUD reserves in 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 increase in PUD reserves in 2023 of 127 Bcfe is a result of 554 Bcfe in new PUD reserve additions,
14 Bcfe for one PUD well added back into the schedule and 23 Bcfe in upward revisions to remaining PUD
reserves. These upward revisions were partially offset by 402 Bcfe in PUD conversions to developed reserves
(275 Bcfe from the Marcellus Shale and 127 Bcfe from the Utica Shale), and 62 Bcfe in PUD reserves removed
for seven PUD locations due to schedule and pad layout changes.
-122-
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The increase in PUD reserves in 2022 of 222 Bcfe is a result of 502 Bcfe in new PUD reserve additions
and 23 Bcfe in upward revisions to remaining PUD reserves, partially offset by 287 Bcfe in PUD conversions to
developed reserves (55 Bcfe from the Marcellus Shale, 231 Bcfe from the Utica Shale and 1 Bcfe from the West
Coast region), and 13 Bcfe in PUD reserves 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.
The Company invested $342 million during the year ended September 30, 2023 to convert 402 Bcfe (440
Bcfe after revisions) of predominantly Marcellus and Utica Shale PUD reserves to developed reserves. This
represents 47% of the net PUD reserves recorded at September 30, 2022. The Company developed 39 of 77
PUD locations in 2023. PUD expenditures in 2023 were higher than the 2022 estimate due to schedule changes
and changes in service costs.
The Company invested $154 million during the year ended September 30, 2022 to convert 287 Bcfe (333
Bcfe after revisions) of predominantly Marcellus and Utica Shale PUD reserves to developed reserves. This
represents 45% of the net PUD reserves recorded at September 30, 2021. In the Appalachian region, 31 of 65
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.
In 2024, the Company estimates that it will invest approximately $315 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 39% of its beginning year PUD reserves in fiscal 2019, 36% of its beginning year PUD
reserves in fiscal 2020, 34% of its beginning year PUD reserves in fiscal 2021, 45% of its beginning year PUD
reserves in fiscal 2022 and 47% of its beginning year PUD reserves in fiscal 2023.
At September 30, 2023, the Company does not have any 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 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.
-123-
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Year Ended September 30
2023
2022
2021
(Thousands)
United States
Future Cash Inflows . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 11,947,345
Less:
$ 19,209,099
$ 10,175,182
Future Production Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Future Development Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Future Income Tax Expense at Applicable Statutory Rate . . . . .
Future Net Cash Flows . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less:
3,538,389
1,095,096
1,867,457
5,446,403
3,138,226
781,847
3,876,272
11,412,754
3,423,629
597,662
1,397,175
4,756,716
10% Annual Discount for Estimated Timing of Cash Flows . . .
2,874,295
Standardized Measure of Discounted Future Net Cash Flows . . $ 2,572,108
5,964,424
$ 5,448,330
2,403,144
$ 2,353,572
The principal sources of change in the standardized measure of discounted future net cash flows were as
follows:
Year Ended September 30
2023
2022
2021
(Thousands)
United States
Standardized Measure of Discounted Future Net Cash Flows at
Beginning of Year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 5,448,330
(767,487)
(3,918,392)
237,057
(222,233)
34,346
—
342,024
959,728
33,192
425,543
Sales, Net of Production Costs . . . . . . . . . . . . . . . . . . . . . . . . . .
Net Changes in Prices, Net of Production Costs . . . . . . . . . . . .
Extensions and Discoveries . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Changes in Estimated Future Development Costs . . . . . . . . . . .
Purchases of Minerals in Place . . . . . . . . . . . . . . . . . . . . . . . . . .
Sales of Minerals in Place . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Previously Estimated Development Costs Incurred . . . . . . . . . .
Net Change in Income Taxes at Applicable Statutory Rate . . . .
Revisions of Previous Quantity Estimates . . . . . . . . . . . . . . . . .
Accretion of Discount and Other . . . . . . . . . . . . . . . . . . . . . . . .
Standardized Measure of Discounted Future Net Cash Flows at End
$ 2,353,572
(1,572,402)
4,132,889
1,355,257
(32,160)
—
(311,308)
154,253
(1,180,349)
3,316
545,262
$ 1,222,470
(626,132)
1,478,995
462,040
48,247
—
—
81,239
(415,993)
(52,383)
155,089
of Year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 2,572,108
$ 5,448,330
$ 2,353,572
-124-
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, 2023.
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, 2023. 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, 2023.
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, 2023. 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, 2023 that have materially affected, or are reasonably likely to materially affect, the
Company’s internal control over financial reporting.
Item 9B
Other Information
During the quarter ended September 30, 2023, no director or officer (as defined in Rule 16a-1(f)
promulgated under the Exchange Act) of the Company adopted or terminated any “Rule 10b5–1 trading
arrangement” or any “non-Rule 10b5–1 trading arrangement,” as each term is defined in Item 408 of Regulation
S-K.
Item 9C
Disclosure Regarding Foreign Jurisdictions that Prevent Inspections
None.
-125-
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, 2023. The information concerning directors will be set forth in the definitive Proxy Statement
under the headings entitled “Nominees for Election as Directors for One-Year Terms to Expire in 2025,” and
“Continuing Directors Whose Terms Expire in 2025,” 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.nationalfuel.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.nationalfuel.com.
Item 11
Executive Compensation
The information concerning executive compensation will be set forth in the definitive Proxy Statement
the headings “Executive Compensation” and “Compensation Committee Interlocks and Insider
under
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
-126-
independence will 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.
Item 15
Exhibits and Financial Statement Schedules
(a)1.
Financial Statements
PART IV
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
All schedules are omitted because they are not applicable or the required information is shown in the
Consolidated Financial Statements or Notes thereto.
(a)3.
Exhibits
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.
Exhibit
Number
3(i)
Articles of Incorporation:
Description of
Exhibits
•
•
Restated Certificate of Incorporation of National Fuel Gas Company dated September 21, 1998;
Certificate of Amendment of Restated Certificate of Incorporation dated March 14, 2005
(Exhibit 3.1, Form 10-K for fiscal year ended September 30, 2012)
Certificate of Amendment of Restated Certificate of Incorporation, as amended, of National Fuel
Gas Company (Exhibit 3.1, Form 8-K dated March 16, 2021)
3(ii)
By-Laws:
•
4
•
•
•
•
•
•
By-Laws of National Fuel Gas Company, as amended June 15, 2022 (Exhibit 3.1, Form 8-K
dated June 17, 2022)
Instruments Defining the Rights of Security Holders, Including Indentures:
Description of Securities (Exhibit 4.1, Form 10-K for fiscal year ended September 30, 2019)
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)
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)
Indenture dated as of October 1, 1999, between the Company and The Bank of New York Mellon
(formerly The Bank of New York) (Exhibit 4.1, Form 10-K for fiscal year ended September 30,
1999)
-127-
Exhibit
Number
•
Description of
Exhibits
Officers Certificate establishing 5.20% Notes due 2025, dated June 25, 2015 (Exhibit 4.1.1, Form
8-K dated June 25, 2015)
•
•
•
•
•
Officers Certificate establishing 3.95% Notes due 2027, dated September 27, 2017 (Exhibit 4.1.1,
Form 8-K dated September 27, 2017)
Officers Certificate establishing 4.75% Notes due 2028, dated August 17, 2018 (Exhibit 4.1.1,
Form 8-K dated August 17, 2018)
Officers Certificate establishing 5.50% Notes due 2026, dated June 3, 2020 (Exhibit 4.1.1, Form
8-K dated June 3, 2020)
Officer’s Certificate establishing 2.95% Notes due 2031, dated February 24, 2021 (Exhibit 4.1.1,
Form 8-K dated February 24, 2021)
Officer’s Certificate establishing 5.50% Notes due 2026, dated May 18, 2023 (Exhibit 4.1.1,
Form 8-K dated May 18, 2023)
10
Material Contracts:
•
•
•
•
•
•
•
•
•
•
•
•
Form of Indemnification Agreement, dated September 2006, between the Company and each
Director (Exhibit 10.1, Form 8-K dated September 18, 2006)
Purchase and Sale Agreement, dated as of 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)
Credit Agreement, dated as of February 28, 2022, among the Company, the Lenders party thereto,
and JPMorgan Chase Bank, N.A. as Administrative Agent (Exhibit 10.1, Form 8-K dated
February 28, 2022)
Amendment No. 1 to Credit Agreement, dated as of May 3, 2022, among the Company, the
Lenders party thereto, and JPMorgan Chase Bank, N.A. as Administrative Agent (Exhibit 10.1,
Form 10-Q dated May 6, 2022)
Management Contracts and Compensatory Plans and Arrangements:
Standard Form of Amended and Restated Employment Continuation and Noncompetition
Agreement among the Company, a subsidiary of the Company and executive officers
(Exhibit 10.1, Form 10-K for the fiscal year ended September 30, 2008)
National Fuel Gas Company 2010 Equity Compensation Plan, as amended and restated December
5, 2018 (Exhibit 10.1, Form 8-K dated March 11, 2019)
National Fuel Gas Company 2012 Annual At Risk Compensation Incentive Plan (Exhibit 10.2,
Form 10-Q for the quarterly period ended March 31, 2012)
National Fuel Gas Company Executive Annual Cash Incentive Program (Exhibit 10.3, Form 10-Q
for the quarterly period ended December 31, 2009)
Administrative Rules of the Compensation Committee of the Board of Directors of National Fuel
Gas Company, as amended and restated effective June 9, 2016 (Exhibit 10.1, Form 10-Q for the
quarterly period ended June 30, 2016)
National Fuel Gas Company Deferred Compensation Plan, as amended and restated through
March 20, 1997 (Exhibit 10.3, Form 10-K for fiscal year ended September 30, 1997)
Amendment to National Fuel Gas Company Deferred Compensation Plan, dated June 16, 1997
(Exhibit 10.4, Form 10-K for fiscal year ended September 30, 1997)
Amendment No. 2 to the National Fuel Gas Company Deferred Compensation Plan, dated
March 13, 1998 (Exhibit 10.1, Form 10-K for fiscal year ended September 30, 1998)
-128-
Exhibit
Number
•
Description of
Exhibits
Amendment to the National Fuel Gas Company Deferred Compensation Plan, dated February 18,
1999 (Exhibit 10.1, Form 10-Q for the quarterly period ended March 31, 1999)
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
Amendment to National Fuel Gas Company Deferred Compensation Plan, dated June 15, 2001
(Exhibit 10.3, Form 10-K for fiscal year ended September 30, 2001)
Amendment to the National Fuel Gas Company Deferred Compensation Plan, dated October 21,
2005 (Exhibit 10.5, Form 10-K for fiscal year ended September 30, 2005)
Amendment to National Fuel Gas Company Deferred Compensation Plan, dated December 14,
2020 (Exhibit 10.3, Form 10-Q for the quarterly period ended December 31, 2020)
National Fuel Gas Company Deferred Compensation Plan for Directors and Officers (Amended
and Restated Effective September 1, 2021) (Exhibit 10.1, Form 8-K dated June 23, 2021)
Form of Letter Regarding Tophat Plan and Internal Revenue Code Section 409A, dated July 12,
2005 (Exhibit 10.7, Form 10-K for fiscal year ended September 30, 2005)
National Fuel Gas Company Tophat Plan, as amended September 20, 2007 (Exhibit 10.3,
Form 10-K for the fiscal year ended September 30, 2007)
Amendment to National Fuel Gas Company Tophat Plan, dated December 14, 2020 (Exhibit 10.5,
Form 10-Q for the quarterly period ended December 31, 2020)
Split Dollar Insurance and Death Benefit Agreement, dated September 15, 1997, between the
Company and David F. Smith (Exhibit 10.13, Form 10-K for fiscal year ended September 30,
1999)
Amendment Number 1 to Split Dollar Insurance and Death Benefit Agreement by and between
the Company and David F. Smith, dated March 29, 1999 (Exhibit 10.14, Form 10-K for fiscal
year ended September 30, 1999)
National Fuel Gas Company Parameters for Executive Life Insurance Plan (Exhibit 10.1,
Form 10-K for fiscal year ended September 30, 2004)
National Fuel Gas Company and Participating Subsidiaries Executive Retirement Plan, Amended
and Restated as of September 24, 2008 (Exhibit 10.5, Form 10-K for the fiscal year ended
September 30, 2008)
Amendment to National Fuel Gas Company and Participating Subsidiaries Executive Retirement
Plan, dated June 1, 2010 (Exhibit 10.1, Form 10-Q for the quarterly period ended June 30, 2010)
Amendment to National Fuel Gas Company and Participating Subsidiaries Executive Retirement
Plan, dated August 13, 2015 (Exhibit 10.2, Form 10-K for the fiscal year ended September 30,
2015)
Amendment to National Fuel Gas Company and Participating Subsidiaries Executive Retirement
Plan, dated December 14, 2020 (Exhibit 10.4, Form 10-Q for the quarterly period ended
December 31, 2020)
National Fuel Gas Company 2009 Non-Employee Director Equity Compensation Plan, as
amended and restated March 11, 2020 (Exhibit 10.1, Form 10-Q for the quarterly period ended
March 31, 2020)
Form of Award Notice for Return on Capital Performance Shares under the National Fuel Gas
Company 2010 Equity Compensation Plan (Exhibit 10.1, Form 10-Q for the quarterly period
ended December 31, 2022)
Form of Award Notice for Total Shareholder Return Performance Shares under the National Fuel
Gas Company 2010 Equity Compensation Plan (Exhibit 10.2, Form 10-Q for the quarterly period
ended December 31, 2022)
-129-
Exhibit
Number
•
Description of
Exhibits
Form of Award Notice for ESG Performance Shares under the National Fuel Gas Company 2010
Equity Compensation Plan (Exhibit 10.3, Form 10-Q for the quarterly period ended December 31,
2022)
•
•
•
•
•
•
21
23
23.1
23.2
31
31.1
31.2
32••
99
99.1
99.2
101
Form of Award Notice for Return on Capital Performance Shares under the National Fuel Gas
Company 2010 Equity Compensation Plan (Exhibit 10.1, Form 10-Q for the quarterly period
ended December 31, 2021)
Form of Award Notice for Total Shareholder Return Performance Shares under the National Fuel
Gas Company 2010 Equity Compensation Plan (Exhibit 10.2, Form 10-Q for the quarterly period
ended December 31, 2021)
Form of Award Notice for ESG Performance Shares under the National Fuel Gas Company 2010
Equity Compensation Plan (Exhibit 10.3, Form 10-Q for the quarterly period ended December 31,
2021)
Form of Award Notice for Return on Capital Performance Shares under the National Fuel Gas
Company 2010 Equity Compensation Plan (Exhibit 10.1, Form 10-Q for the quarterly period
ended December 31, 2020)
Form of Award Notice for Total Shareholder Return Performance Shares under the National Fuel
Gas Company 2010 Equity Compensation Plan (Exhibit 10.2, Form 10-Q for the quarterly period
ended December 31, 2020)
Retirement and Consulting Services Agreement, dated as of March 9, 2023, between National
Fuel Gas Distribution Corporation and Karen M. Camiolo (Exhibit 10.1, Form 10-Q for the
quarterly period ended March 31, 2023)
Subsidiaries of the Registrant
Consents of Experts:
Consent of Netherland, Sewell & Associates, Inc. regarding Seneca Resources Company, LLC
Consent of Independent Registered Public Accounting Firm
Rule 13a-14(a)/15d-14(a) Certifications:
Written statements of Chief Executive Officer pursuant to Rule 13a-14(a)/15d-14(a) of the
Exchange Act
Written statements of Principal Financial Officer pursuant to Rule 13a-14(a)/15d-14(a) of the
Exchange Act
Certification furnished pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
Additional Exhibits:
Report of Netherland, Sewell & Associates, Inc. regarding Seneca Resources Company, LLC
Company Maps
Interactive data files submitted pursuant to Regulation 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, 2023, 2022 and 2021, (ii) the
Consolidated Statements of Comprehensive Income for the years ended September 30, 2023,
2022 and 2021, (iii) the Consolidated Balance Sheets at September 30, 2023 and September 30,
2022, (iv) the Consolidated Statements of Cash Flows for the years ended September 30, 2023,
2022 and 2021 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.
-130-
Exhibit
Number
••
Description of
Exhibits
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.
Item 16
Form 10-K Summary
None.
-131-
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.
Signatures
National Fuel Gas Company
(Registrant)
By
/s/ D. P. Bauer
D. P. Bauer
President and Chief Executive Officer
Date: November 17, 2023
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
D. F. Smith
/s/ D. H. Anderson
D. H. Anderson
/s/ B. M. Baumann
B. M. Baumann
/s/ D. C. Carroll
D. C. Carroll
/s/ S. C. Finch
S.C. Finch
J. N. Jaggers
/s/
J. N. Jaggers
/s/ R. Ranich
R. Ranich
J. W. Shaw
/s/
J. W. Shaw
/s/ T. E. Skains
T. E. Skains
/s/ R. J. Tanski
R. J. Tanski
/s/ D. P. Bauer
D. P. Bauer
/s/ T. J. Silverstein
T. J. Silverstein
/s/ E. G. Mendel
E. G. Mendel
Chairman of the Board and
Director
Date: November 17, 2023
Director
Director
Director
Director
Director
Director
Director
Director
Director
Date: November 17, 2023
Date: November 17, 2023
Date: November 17, 2023
Date: November 17, 2023
Date: November 17, 2023
Date: November 17, 2023
Date: November 17, 2023
Date: November 17, 2023
Date: November 17, 2023
President and Chief Executive
Officer and Director
Date: November 17, 2023
Treasurer and Principal
Financial Officer
Controller and Principal
Accounting Officer
Date: November 17, 2023
Date: November 17, 2023
-132-
Investor Information
Common Stock Transfer Agent
and Registrar
EQ Shareowner Services
P.O. Box 64854
St. Paul, MN 55164-0854
Telephone: 800-648-8166
Web: http://www.shareowneronline.com
Email: stocktransfer@equiniti.com
Change of address notices and inquiries about
dividends should be sent to the Transfer Agent
at the address listed above.
National Fuel Direct Stock Purchase
and Dividend Reinvestment Plan
National Fuel offers a simple, cost-effective
method for purchasing shares of National
Fuel stock. A prospectus, which includes
details of the Plan, can be obtained by calling,
writing or emailing the administrator of the
Plan, EQ Shareowner Services, at the address
listed above.
Investor Relations
Investors or financial analysts desiring
information should contact:
Timothy J. Silverstein, Treasurer
Telephone: 716-857-6987
Brandon J. Haspett,
Director of Investor Relations
Telephone: 716-857-7697
Email: HaspettB@natfuel.com
National Fuel Gas Company
6363 Main Street
Williamsville, NY 14221
Additional Shareholder Reports
Additional copies of this report, the 2023
Form 10-K and the 2023 Financial and
Statistical Report can be obtained without
charge by writing to or calling:
Michael W. Reville, Corporate Secretary
Telephone: 716-857-7313
Brandon J. Haspett,
Director of Investor Relations
Telephone: 716-857-7697
National Fuel Gas Company
6363 Main Street
Williamsville, NY 14221
Stock Exchange Listing
New York Stock Exchange
(Stock Symbol: NFG)
Trustee for Debentures
The Bank of New York Mellon
Corporate Trust
240 Greenwich Street, 7 East
New York, NY 10286
Annual Meeting
The Annual Meeting of Stockholders
will be held on Friday, March 8, 2024,
conducted via live webcast at www.
virtualshareholdermeeting.com/NFG2024.
Stockholders of record as of the close of
business on January 8, 2024, will receive a
formal notice of the meeting, proxy statement
and proxy.
Units of Measure
Bbl
Bcf
Bcfe
Dth
Mbbl
Mcf
Mcfe
Barrel
(of oil)
Billion cubic feet
(of natural gas)
Bcf equivalent
(of natural gas and oil)
Dekatherm
(approx. 1 Mcf of natural
gas)
Thousand barrels
(of oil)
Thousand cubic feet
(of natural gas)
Mcf equivalent
(of natural gas and oil)
MMcf
Million cubic feet
(of natural gas)
MMcfe
Million cubic feet
equivalent
This Annual Report contains “forward-looking statements” as defined by the Private Securities Litigation Reform Act of 1995. Forward-looking statements should be
read with the cautionary statements and important factors included in the Company’s Form 10-K at Item 7, MD&A, under the heading “Safe Harbor for Forward-Looking
Statements,” and with the “Risk Factors” included in the Company’s Form 10-K at Item 1A. Forward-looking statements are all statements other than statements of
historical fact, including, without limitation, statements regarding future prospects, plans, objectives, goals, projections, estimates of gas quantities, estimates of the
time and resources necessary to meet emissions targets, strategies, future events or performance and underlying assumptions, capital structure, anticipated capital
expenditures, completion of construction and other projects, projections for pension and other post-retirement benefit obligations, impacts of the adoption of new
accounting rules, 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. Forward-looking statements include estimates of
gas quantities. Proved gas reserves are those quantities of gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be
economically producible under existing economic conditions, operating methods and government regulations. Other estimates of gas quantities, including estimates of
probable reserves, possible reserves, and resource potential, are by their nature more speculative than estimates of proved reserves. Accordingly, estimates other than
proved reserves are subject to substantially greater risk of being actually realized. This Annual Report and the statements contained herein are submitted for the general
information of stockholders and employees of the Company and are not intended to induce any sale or purchase of securities or to be used in connection therewith. For
up-to-date investor information, please visit the Investor Relations section of National Fuel Gas Company’s Corporate Web site at http://www.nationalfuel.com. If you
would like to receive news releases automatically by email, simply visit the News section and subscribe.
2023 ANNUAL REPORT
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National Fuel Gas Company
National Fuel Gas Company
6363 Main Street
6363 Main Street
Williamsville, New York 14221
Williamsville, New York 14221
716-857-7000
716-857-7000
www.nationalfuel.com
www.nationalfuel.com
NYSE: NFG
NYSE: NFG
Left:
Left:
Our Utility’s robust pipeline modernization program
Our Utility’s robust pipeline modernization program
reached a milestone on June 1, 2023, removing the last
reached a milestone on June 1, 2023, removing the
last cast iron main on the system in NY. National Fuel’s
cast iron main on the system, located in Buffalo, NY.
pipeline integrity management program is one of many
National Fuel’s pipeline integrity management program
initiatives to mitigate potential risks on our system and
is one of many initiatives to mitigate potential risks on
our system and ensure pipeline safety and reliability.
ensure pipeline safety and reliability.
Seneca works with state agencies and local
Seneca works with state agencies and local
conservation groups to identify strategies to enhance
conservation groups to identify strategies to enhance
safety and biodiversity, including a recent stream
safety and biodiversity, including a recent stream
culvert replacement that improved water flow and
culvert replacement that improved water flow and
aquatic wildlife.
aquatic wildlife.
The Farmington Compressor Station solar array came
Supply’s Farmington Compressor Station solar
online and began producing power in February 2022,
array came online and began producing power in
continuing National Fuel’s tradition of continuously
February 2023, continuing National Fuel’s tradition
of continuously improving and implementing
improving and implementing innovative technologies
and processes to reduce emissions and drive long-term
innovative technologies and processes to reduce
sustainability. Our operations are a notable example of
emissions and drive long-term sustainability.
how hydrocarbons and renewables can work together
Our operations are a notable example of how
to deliver clean and reliable low-cost energy.
hydrocarbons and renewables can work together
to deliver clean and reliable low-cost energy.