10-K 1 nfg-2014930x10k.htm 10-K NFG-2014.9.30-10K
 
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
 
þ
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year Ended September 30, 2014
 
¨
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
 
Name of Each Exchange
on Which Registered
Common Stock, par value $1.00 per share, and
Common Stock Purchase Rights
 
New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes  þ        No  ¨
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15 (d) of the Act.    Yes  ¨        No  þ
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months and (2) has been subject to such filing requirements for the past 90 days.    Yes  þ        No  ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  þ        No  ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.    þ
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer  þ
    
Accelerated filer  ¨
 
Non-accelerated filer  ¨
Smaller reporting company  ¨
 
 
 
 
(Do not check if a smaller reporting company)
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).    Yes  ¨        No  þ
The aggregate market value of the voting stock held by nonaffiliates of the registrant amounted to $5,688,675,000 as of March 31, 2014.
Common Stock, par value $1.00 per share, outstanding as of October 31, 2014: 84,190,266 shares.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrant’s definitive Proxy Statement for its 2015 Annual Meeting of Stockholders, to be filed with the Securities and Exchange Commission within 120 days of September 30, 2014, are incorporated by reference into Part III of this report.





Glossary of Terms

Frequently used abbreviations, acronyms, or terms used in this report:
National Fuel Gas Companies
Company The Registrant, the Registrant and its subsidiaries or the Registrant’s subsidiaries as appropriate in the context of the disclosure
Distribution Corporation National Fuel Gas Distribution Corporation
Empire Empire Pipeline, Inc.
ESNE Energy Systems North East, LLC
Horizon Power Horizon Power, Inc.
Midstream Corporation National Fuel Gas Midstream Corporation
National Fuel National Fuel Gas Company
NFR National Fuel Resources, Inc.
Registrant National Fuel Gas Company
Seneca Seneca Resources Corporation
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
NYDEC New York State Department of Environmental Conservation
NYPSC State of New York Public Service Commission
PaDEP Pennsylvania Department of Environmental Protection
PaPUC Pennsylvania Public Utility Commission
PHMSA Pipeline and Hazardous Materials Safety Administration
SEC Securities and Exchange Commission
Other
Bbl Barrel (of oil)
Bcf Billion cubic feet (of natural gas)
Bcfe (or Mcfe) — represents Bcf (or Mcf) Equivalent The total heat value (Btu) of natural gas and oil expressed as a volume of natural gas. The Company uses a conversion formula of 1 barrel of oil = 6 Mcf of natural gas.
Btu British thermal unit; the amount of heat needed to raise the temperature of one pound of water one degree Fahrenheit.
Capital expenditure Represents additions to property, plant, and equipment, or the amount of money a company spends to buy capital assets or upgrade its existing capital assets.
Cashout revenues A cash resolution of a gas imbalance whereby a customer pays Supply Corporation and/or Empire for gas the customer receives in excess of amounts delivered into Supply Corporation’s and Empire’s systems by the customer’s shipper.
Degree day A measure of the coldness of the weather experienced, based on the extent to which the daily average temperature falls below a reference temperature, usually 65 degrees Fahrenheit.
Derivative A financial instrument or other contract, the terms of which include an underlying variable (a price, interest rate, index rate, exchange rate, or other variable) and a notional amount (number of units, barrels, cubic feet, etc.). The terms also permit for the instrument or contract to be settled net and no initial net investment is required to enter into the financial instrument or contract. Examples include futures contracts, options, no cost collars and swaps.
Development costs Costs incurred to obtain access to proved oil and gas reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas.
Development well A well drilled to a known producing formation in a previously discovered field.
 
Dodd-Frank Act Dodd-Frank Wall Street Reform and Consumer Protection Act.
Dth Decatherm; one Dth of natural gas has a heating value of 1,000,000 British thermal units, approximately equal to the heating value of 1 Mcf of natural gas.
Exchange Act Securities Exchange Act of 1934, as amended
Expenditures for long-lived assets Includes capital expenditures, stock acquisitions and/or investments in partnerships.
Exploitation Development of a field, including the location, drilling, completion and equipment of wells necessary to produce the commercially recoverable oil and gas in the field.
Exploration costs Costs incurred in identifying areas that may warrant examination, as well as costs incurred in examining specific areas, including drilling exploratory wells.
FERC 7(c) application An application to the FERC under Section 7(c) of the federal Natural Gas Act for authority to construct, operate (and provide services through) facilities to transport or store natural gas in interstate commerce.
Exploratory well A well drilled in unproven or semi-proven territory for the purpose of ascertaining the presence underground of a commercial hydrocarbon deposit.
Firm transportation and/or storage The transportation and/or storage service that a supplier of such service is obligated by contract to provide and for which the customer is obligated to pay whether or not the service is utilized.
GAAP Accounting principles generally accepted in the United States of America
Goodwill An intangible asset representing the difference between the fair value of a company and the price at which a company is purchased.
Hedging A method of minimizing the impact of price, interest rate, and/or foreign currency exchange rate changes, often times through the use of derivative financial instruments.
Hub Location where pipelines intersect enabling the trading, transportation, storage, exchange, lending and borrowing of natural gas.
ICE Intercontinental Exchange. An exchange which maintains a futures market for crude oil and natural gas.
Interruptible transportation and/or storage The transportation and/or storage service that, in accordance with contractual arrangements, can be interrupted by the supplier of such service, and for which the customer does not pay unless utilized.
LDC Local distribution company
LIBOR London Interbank Offered Rate
LIFO Last-in, first-out
Marcellus Shale A Middle Devonian-age geological shale formation that is present nearly a mile or more below the surface in the Appalachian region of the United States, including much of Pennsylvania and southern New York.
Mbbl Thousand barrels (of oil)
Mcf Thousand cubic feet (of natural gas)
MD&A Management’s Discussion and Analysis of Financial Condition and Results of Operations
MDth Thousand decatherms (of natural gas)
MMBtu Million British thermal units (heating value of one dekatherm of natural gas)
MMcf Million cubic feet (of natural gas)
MMcfe Million cubic feet equivalent
NEPA National Environmental Policy Act of 1969, as amended
NGA The Natural Gas Act of 1938, as amended; the federal law regulating interstate natural gas pipeline and storage companies, among other things, codified beginning at 15 U.S.C. Section 717.
NYMEX New York Mercantile Exchange. An exchange which maintains a futures market for crude oil and natural gas.



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Open Season A bidding procedure used by pipelines to allocate firm transportation or storage capacity among prospective shippers, in which all bids submitted during a defined time period are evaluated as if they had been submitted simultaneously.
PCB Polychlorinated Biphenyl
Precedent Agreement An agreement between a pipeline company and a potential customer to sign a service agreement after specified events (called “conditions precedent”) happen, usually within a specified time.
Proved developed reserves Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.
Proved undeveloped (PUD) reserves Reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required to make those reserves productive.
PRP Potentially responsible party
Reliable technology Technology that a company may use to establish reserves estimates and categories that has been proven empirically to lead to correct conclusions.
Reserves The unproduced but recoverable oil and/or gas in place in a formation which has been proven by production.
Restructuring Generally referring to partial “deregulation” of the pipeline and/or utility industry by statutory or regulatory process. Restructuring of federally regulated natural gas pipelines resulted in the separation (or “unbundling”) of gas commodity service from transportation service for wholesale and large-volume retail markets. State restructuring programs attempt to extend the same process to retail mass markets.






























 
Revenue decoupling mechanism A rate mechanism which adjusts customer rates to render a utility financially indifferent to throughput decreases resulting from conservation.
S&P Standard & Poor’s Ratings Service
SAR Stock appreciation right
Service Agreement The binding agreement by which the pipeline company agrees to provide service and the shipper agrees to pay for the service.
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.
VEBA Voluntary Employees’ Beneficiary Association
WNC Weather normalization clause; a clause in utility rates which adjusts customer rates to allow a utility to recover its normal operating costs calculated at normal temperatures. If temperatures during the measured period are warmer than normal, customer rates are adjusted upward in order to recover projected operating costs. If temperatures during the measured period are colder than normal, customer rates are adjusted downward so that only the projected operating costs will be recovered.



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For the Fiscal Year Ended September 30, 2014
CONTENTS
 
 
Page
Part I
ITEM 1
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
ITEM 1A
ITEM 1B
ITEM 2
 
 
ITEM 3
ITEM 4
Part II
ITEM 5
ITEM 6
ITEM 7
ITEM 7A
ITEM 8
ITEM 9
ITEM 9A
ITEM 9B




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PART I
 
Item 1
Business
The Company and its Subsidiaries
National Fuel Gas Company (the Registrant), incorporated in 1902, is a holding company organized under the laws of the State of New Jersey. Except as otherwise indicated below, 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, distribution and marketing of natural gas. The Company operates an integrated business model centered in western New York and Pennsylvania, an area critical to the production and transportation of natural gas from the Marcellus Shale basin. 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 Marcellus Shale to markets in Canada and the eastern United States. The Company also develops and produces oil reserves, primarily in California. The Company reports financial results for five business segments: Exploration and Production, Pipeline and Storage, Gathering, Utility, and Energy Marketing.
1. The Exploration and Production segment operations are carried out by Seneca Resources Corporation (Seneca), a Pennsylvania corporation. Seneca is engaged in the exploration for, and the development and production of, natural gas and oil reserves in California, in the Appalachian region of the United States, and in Kansas. At September 30, 2014, Seneca had U.S. proved developed and undeveloped reserves of 38,477 Mbbl of oil and 1,682,884 MMcf of natural gas.
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 provides interstate natural gas transportation and storage services for affiliated and nonaffiliated companies through (i) an integrated gas pipeline system extending from southwestern Pennsylvania to the New York-Canadian border at the Niagara River and eastward to Ellisburg and Leidy, Pennsylvania, and (ii) 27 underground natural gas storage fields owned and operated by Supply Corporation as well as four other underground natural gas storage fields owned and operated jointly with other interstate gas pipeline companies. Empire, an interstate pipeline company, transports natural gas for Distribution Corporation and for other utilities, large industrial customers and power producers in New York State. Empire owns the Empire Pipeline, a 249-mile integrated pipeline system comprising three principal components: a legacy 157-mile pipeline that extends from the United States/Canadian border at the Niagara River near Buffalo, New York to near Syracuse, New York; a 76-mile pipeline extension from near Rochester, New York to an interconnection with the unaffiliated Millennium Pipeline near Corning, New York (the Empire Connector), and a 16-mile pipeline extension from Corning into Tioga County, Pennsylvania (the Tioga County Extension).
3. The Gathering segment operations are carried out by wholly-owned subsidiaries of National Fuel Gas Midstream Corporation (Midstream Corporation), a Pennsylvania corporation. Through these subsidiaries, Midstream Corporation builds, owns and operates natural gas processing and pipeline gathering facilities in the Appalachian region.
4. The Utility segment operations are carried out by National Fuel Gas Distribution Corporation (Distribution Corporation), a New York corporation. Distribution Corporation sells natural gas or provides natural gas transportation services to approximately 737,800 customers through a local distribution system located in western New York and northwestern Pennsylvania. The principal metropolitan areas served by Distribution Corporation include Buffalo, Niagara Falls and Jamestown, New York and Erie and Sharon, Pennsylvania.
5. The Energy Marketing segment operations are carried out by National Fuel Resources, Inc. (NFR), a New York corporation, which markets natural gas to industrial, wholesale, commercial, public authority and residential

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customers primarily in western and central New York and northwestern Pennsylvania, offering competitively priced natural gas for its customers.
Financial information about each of the Company’s business segments can be found in Item 7, MD&A and also in Item 8 at Note J — Business Segment Information.
The following business is not included in any of the five reported business segments:
 
Seneca’s Northeast Division, which markets timber from Appalachian land holdings. At September 30, 2014, the Company owned approximately 93,000 acres of timber property and managed approximately 3,000 additional acres of timber cutting rights.
No single customer, or group of customers under common control, accounted for more than 10% of the Company’s consolidated revenues in 2014.
Rates and Regulation
The Utility segment’s rates, services and other matters are regulated by the NYPSC with respect to services provided within New York and by the PaPUC with respect to services provided within Pennsylvania. For additional discussion of the Utility segment’s rates and regulation, see Item 7, MD&A under the heading “Rate and Regulatory Matters” and Item 8 at Note A — Summary of Significant Accounting Policies (Regulatory Mechanisms) and Note C — Regulatory Matters.
The Pipeline and Storage segment’s rates, services and other matters are regulated by the FERC. For additional discussion of the Pipeline and Storage segment’s rates and regulation, see Item 7, MD&A under the heading “Rate and Regulatory Matters” and Item 8 at Note A — Summary of Significant Accounting Policies (Regulatory Mechanisms) and Note C — Regulatory Matters.
The discussion under Item 8 at Note C — Regulatory Matters includes a description of the regulatory assets and liabilities reflected on the Company’s Consolidated Balance Sheets in accordance with applicable accounting standards. To the extent that the criteria set forth in such accounting standards are not met by the operations of the Utility segment or the Pipeline and Storage segment, as the case may be, the related regulatory assets and liabilities would be eliminated from the Company’s Consolidated Balance Sheets and such accounting treatment would be discontinued.
In addition, the Company and its subsidiaries are subject to the same federal, state and local (including foreign) regulations on various subjects, including environmental matters, to which other companies doing similar business in the same locations are subject.
The Exploration and Production Segment
The Exploration and Production segment contributed approximately 40.6% of the Company’s 2014 net income available for common stock.
Additional discussion of the Exploration and Production segment appears below in this Item 1 under the headings “Sources and Availability of Raw Materials” and “Competition: The Exploration and Production Segment,” in Item 7, MD&A and in Item 8, Financial Statements and Supplementary Data.
The Pipeline and Storage Segment
The Pipeline and Storage segment contributed approximately 25.9% of the Company’s 2014 net income available for common stock.
Supply Corporation’s firm transportation capacity is subject to change as the market identifies different transportation paths and receipt/delivery point combinations. Supply Corporation currently has firm transportation service agreements for approximately 2,674 MDth per day (contracted transportation capacity). The Utility segment accounts for approximately 1,035 MDth per day or 39% of contracted transportation capacity, and the Energy Marketing and Exploration and Production segments represent another 174 MDth per day or 7%. The remaining 1,465 MDth or 54% is subject to firm contracts with nonaffiliated customers. Contracted transportation capacity with both affiliated and unaffiliated shippers is expected to increase 4% in 2015.

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Supply Corporation has service agreements for essentially all of its firm storage capacity, totaling 67,967 MDth. The Utility segment has contracted for 28,491 MDth or 42% of the total firm storage capacity, and the Energy Marketing segment accounts for another 3,097 MDth or 5%. Nonaffiliated customers have contracted for the remaining 36,379 MDth or 53%. Supply Corporation expects 2% of its contracted firm storage capacity to expire or terminate and be available for remarketing in 2015.
At the end of 2014, Empire had service agreements in place for firm transportation capacity totaling up to approximately 952 MDth per day, with 98% of that capacity contracted as long-term, full-year deals. The Utility segment accounted for 4% of Empire’s firm contracted capacity, with the remaining 96% subject to contracts with nonaffiliated customers. None of the long-term contracts will expire or terminate in 2015.
The majority of Supply Corporation’s transportation and storage contracts, and the majority of Empire’s transportation contracts, allow either party to terminate the contract upon six or twelve months’ notice effective at the end of the primary term, and include “evergreen” language that allows for annual term extension(s).
Additional discussion of the Pipeline and Storage segment appears below under the headings “Sources and Availability of Raw Materials,” “Competition: The Pipeline and Storage Segment” and “Seasonality,” in Item 7, MD&A and in Item 8, Financial Statements and Supplementary Data.
The Gathering Segment
The Gathering segment contributed approximately 10.9% of the Company’s 2014 net income available for common stock.
Additional discussion of the Gathering segment appears below under the headings “Sources and Availability of Raw Materials” and “Competition: The Gathering Segment,” in Item 7, MD&A and in Item 8, Financial Statements and Supplementary Data.
The Utility Segment
The Utility segment contributed approximately 21.4% of the Company’s 2014 net income available for common stock.
Additional discussion of the Utility segment appears below under the headings “Sources and Availability of Raw Materials,” “Competition: The Utility Segment” and “Seasonality,” in Item 7, MD&A and in Item 8, Financial Statements and Supplementary Data.
The Energy Marketing Segment
The Energy Marketing segment contributed approximately 2.2% of the Company’s 2014 net income available for common stock.
Additional discussion of the Energy Marketing segment appears below under the headings “Sources and Availability of Raw Materials,” “Competition: The Energy Marketing Segment” and “Seasonality,” in Item 7, MD&A and in Item 8, Financial Statements and Supplementary Data.
All Other Category and Corporate Operations
The All Other category and Corporate operations incurred a net loss in 2014. The impact of this net loss in relation to the Company’s 2014 net income available for common stock was negative 1.0%.
Additional discussion of the All Other category and Corporate operations appears below in Item 7, MD&A and in Item 8, Financial Statements and Supplementary Data.
Sources and Availability of Raw Materials
The Exploration and Production segment seeks to discover and produce raw materials (natural gas, oil and hydrocarbon liquids) as further described in this report in Item 7, MD&A and Item 8 at Note J — Business Segment Information and Note M — Supplementary Information for Oil and Gas Producing Activities.

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Supply Corporation transports and stores gas owned by its customers, whose gas originates in the southwestern, mid-continent and Appalachian regions of the United States as well as in Canada. Empire transports gas owned by its customers, whose gas originates in the Appalachian region of the United States as well as in 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 gas that is produced by Seneca in the Appalachian region of the United States. Additional discussion of proposed gathering projects appears below in Item 7, MD&A.
Natural gas is the principal raw material for the Utility segment. In 2014, the Utility segment purchased 71.0 Bcf of gas for delivery to its customers. Gas purchased from producers and suppliers in the United States under firm contracts (seasonal and longer) accounted for 52% of these purchases. Purchases of gas on the spot market (contracts for one month or less) accounted for 48% of the Utility segment’s 2014 purchases. Purchases from South Jersey Resources Group, LLC (20%), Tenaska Marketing Ventures (13%), Statoil Natural Gas, LLC (9%) and DTE Energy Trading, Inc. (8%) accounted for 50% of the Utility’s 2014 gas purchases. No other producer or supplier provided the Utility segment with more than 10% of its gas requirements in 2014.
The Energy Marketing segment depends on an adequate supply of natural gas to deliver to its customers. In 2014, this segment purchased 53.4 Bcf of gas, including 52.7 Bcf for delivery to its customers. The remaining 0.7 Bcf largely represents gas used in operations. The gas purchased by the Energy Marketing segment originates primarily in either the Appalachian or mid-continent regions of the United States.
Competition
Competition in the natural gas industry exists among providers of natural gas, as well as between natural gas and other sources of energy, such as fuel oil and electricity. Management believes that the environmental advantages of natural gas have enhanced its competitive position relative to other fuels.
The Company competes on the basis of price, service and reliability, product performance and other factors. Sources and providers of energy, other than those described under this “Competition” heading, do not compete with the Company to any significant extent.
Competition: The Exploration and Production Segment
The Exploration and Production segment competes with other oil and natural gas producers and marketers with respect to sales of oil and natural gas. The Exploration and Production segment also competes, by competitive bidding and otherwise, with other oil and natural gas producers with respect to exploration and development prospects and mineral leaseholds.
To compete in this environment, Seneca originates and acts as operator on certain of its prospects, seeks to minimize the risk of exploratory efforts through partnership-type arrangements, utilizes technology for both exploratory studies and drilling operations, and seeks market niches based on size, operating expertise and financial criteria.
Competition: The Pipeline and Storage Segment
Supply Corporation competes for market growth in the natural gas market with other pipeline companies transporting gas in the northeast United States and with other companies providing gas storage services. Supply Corporation has some unique characteristics which enhance its competitive position, as described below. Most of Supply Corporation’s facilities are in or near areas overlying the Marcellus Shale production area in Pennsylvania. Its facilities are also located adjacent to Canada and the northeastern United States and provide part of the traditional link between gas-consuming regions of the eastern United States and gas-producing regions of Canada and the southwestern, southern and other continental regions of the United States. While costlier natural gas pricing at Niagara has decreased the importation and transportation of gas from that receipt point, new productive areas in the Appalachian region related to the development of the Marcellus Shale formation have increased transportation services from that region. Supply Corporation has developed its Northern Access and Line N pipeline expansion projects to receive natural gas produced from the Marcellus Shale and transport it to key markets of Canada and

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the northeastern United States. For further discussion of these projects, refer to Item 7, MD&A under the headings “Investing Cash Flow” and “Rate and Regulatory Matters.”
Empire competes for market growth in the natural gas market 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-sourced gas as well as gas received at the Niagara River at Chippawa. Empire’s location provides it the opportunity to compete for an increased share of the gas transportation markets. As noted above, the Empire Connector project expanded Empire’s natural gas pipeline and enables Empire to serve new markets in New York and elsewhere in the Northeast. In November 2011, Empire also completed its Tioga County Extension project, which stretches approximately 16 miles south from its existing interconnection with Millennium Pipeline at Corning, New York, into Tioga County, Pennsylvania. Like Supply Corporation’s Northern Access project, Empire’s Tioga County Extension project facilitates transportation of Marcellus Shale gas to key markets of Canada and the northeastern United States.
Competition: The Gathering Segment
The Gathering segment provides gathering services for Seneca’s production and 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 New York, approximately 23%, and in Pennsylvania, approximately 16%, of Distribution Corporation’s small-volume residential and commercial customers purchase their supplies from unregulated marketers. In contrast, almost all large-volume load is served by unregulated retail marketers. However, retail competition for gas commodity service does not pose an acute competitive threat for Distribution Corporation, because in both jurisdictions, utility cost of service is recovered through rates and charges for gas delivery service, not gas commodity service. Over the longer run, it is possible that rate design changes resulting from further customer migration to marketer service could expose utility companies such as Distribution Corporation to stranded costs and revenue erosion in the absence of compensating rate relief.
Competition for transportation service to large-volume customers continues with local producers or pipeline companies attempting to sell or transport gas directly to end-users located within the Utility segment’s service territories without use of the utility’s facilities (i.e., bypass). In addition, competition continues with fuel oil suppliers.
The Utility segment competes in its most vulnerable markets (the large commercial and industrial markets) by offering unbundled, flexible, high quality services. The Utility segment continues to develop or promote new uses of natural gas or new services, rates and contracts.
Competition: The Energy Marketing Segment
The Energy Marketing segment competes with other marketers of natural gas and with other providers of energy supply. Competition in this area is well developed with regard to price and services from local, regional and national marketers.
Seasonality
Variations in weather conditions can materially affect the volume of natural gas delivered by the Utility segment, as virtually all of its residential and commercial customers use natural gas for space heating. The effect that this has on Utility segment margins in New York is mitigated by a WNC, which covers the eight-month period from October through May. Weather that is warmer than normal results in an upward adjustment to customers’ current bills, while weather that is colder than normal results in a downward adjustment, so that in either case projected operating costs calculated at normal temperatures will be recovered.

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Volumes transported and stored by Supply Corporation and volumes transported by Empire may vary materially depending on weather, without materially affecting the revenues of those companies. Supply Corporation’s and Empire’s allowed rates are based on a straight fixed-variable rate design which allows recovery of fixed costs in fixed monthly reservation charges. Variable charges based on volumes are designed to recover only the variable costs associated with actual transportation or storage of gas.
Variations in weather conditions materially affect the volume of gas consumed by customers of the Energy Marketing segment. Volume variations have a corresponding impact on revenues within this segment.
Capital Expenditures
A discussion of capital expenditures by business segment is included in Item 7, MD&A under the heading “Investing Cash Flow.”
Environmental Matters
A discussion of material environmental matters involving the Company is included in Item 7, MD&A under the heading “Environmental Matters” and in Item 8, Note I — Commitments and Contingencies.
Miscellaneous
The Company and its wholly owned or majority-owned subsidiaries had a total of 2,010 full-time employees at September 30, 2014.
The Company has agreements in place with collective bargaining units in New York and Pennsylvania. Agreements covering employees in collective bargaining units in New York are scheduled to expire in February 2017. Agreements covering employees in collective bargaining units in Pennsylvania are scheduled to expire in April 2018 and May 2018.
The Utility segment has numerous municipal franchises under which it uses public roads and certain other rights-of-way and public property for the location of facilities. When necessary, the Utility segment renews such franchises.
The Company makes its annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and any amendments to those reports, available free of charge on the Company’s internet website, www.nationalfuelgas.com, as soon as reasonably practicable after they are electronically filed with or furnished to the SEC. The information available at the Company’s internet website is not part of this Form 10-K or any other report filed with or furnished to the SEC.


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Executive Officers of the Company as of November 15, 2014(1)
 
Name and Age (as of
November 15, 2014)
  
Current Company
Positions and
Other Material
Business Experience
During Past
Five Years
Ronald J. Tanski
(62)
  
Chief Executive Officer of the Company since April 2013 and President of the Company since July 2010. Mr. Tanski previously served as Chief Operating Officer of the Company from July 2010 through March 2013; Treasurer and Principal Financial Officer of the Company from April 2004 through June 2010; and President of Supply Corporation from July 2008 through June 2010.
Matthew D. Cabell
(56)
  
Senior Vice President of the Company since July 2010 and President of Seneca since December 2006.
Anna Marie Cellino
(61)
  
President of Distribution Corporation since July 2008.
John R. Pustulka
(62)
  
President of Supply Corporation since July 2010. Mr. Pustulka previously served as Senior Vice President of Supply Corporation from July 2001 through June 2010.
David P. Bauer
(45)
  
Treasurer and Principal Financial Officer of the Company since July 2010; Treasurer of Midstream Corporation since April 2013; Treasurer of Supply Corporation since June 2007; Treasurer of Empire since June 2007; and Assistant Treasurer of Distribution Corporation since April 2004.
Karen M. Camiolo
(55)
  
Controller and Principal Accounting Officer of the Company since April 2004; Controller of Midstream Corporation since April 2013; and Controller of Distribution Corporation and Supply Corporation since April 2004.
Carl M. Carlotti
(59)
  
Senior Vice President of Distribution Corporation since January 2008.
Paula M. Ciprich
(54)
  
Secretary of the Company since July 2008; General Counsel of the Company since January 2005; Secretary of Distribution Corporation since July 2008.
Donna L. DeCarolis
(55)
  
Vice President Business Development of the Company since October 2007.
James D. Ramsdell
(59)
  
Senior Vice President and Chief Safety Officer of the Company since May 2011. Mr. Ramsdell previously served as Senior Vice President of Distribution Corporation from July 2001 to May 2011.
 
(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.

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Item 1A
Risk Factors
As a holding company, the Company depends on its operating subsidiaries to meet its financial obligations.
The Company is a holding company with no significant assets other than the stock of its operating subsidiaries. In order to meet its financial needs, the Company relies exclusively on repayments of principal and interest on intercompany loans made by the Company to its operating subsidiaries and income from dividends and other cash flow from the subsidiaries. Such operating subsidiaries may not generate sufficient net income to pay upstream dividends or generate sufficient cash flow to make payments of principal or interest on such intercompany loans.
The Company is dependent on capital and credit markets to successfully execute its business strategies.
The Company relies upon short-term bank borrowings, commercial paper markets and longer-term capital markets to finance capital requirements not satisfied by cash flow from operations. The Company is dependent on these capital sources to provide capital to its subsidiaries to fund operations, acquire, maintain and develop properties, and execute growth strategies. The availability and cost of credit sources may be cyclical and these capital sources may not remain available to the Company. Turmoil in credit markets may make it difficult for the Company to obtain financing on acceptable terms or at all for working capital, capital expenditures and other investments, or to refinance maturing debt on favorable terms. 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. In addition, the Company’s short-term bank loans 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 the ability of the Company to issue commercial paper are affected by its debt credit ratings published by S&P, Moody’s Investors Service, Inc. and Fitch Ratings. A downgrade in the Company’s credit ratings could increase borrowing costs and negatively impact the availability of capital from banks, commercial paper purchasers and other sources.
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. Economic conditions in the Company’s utility service territories and energy marketing territories also impact its collections of accounts receivable. All of the Company’s segments are exposed to risks associated with the creditworthiness or performance of key suppliers and customers, many of which may be adversely affected by volatile conditions in the financial markets. These conditions could result in financial instability or other adverse effects at any of our suppliers or customers. For example, counterparties to the Company’s commodity hedging arrangements or commodity sales contracts might not be able to perform their obligations under these arrangements or contracts. Customers of the Company’s Utility and Energy Marketing segments may have particular trouble paying their bills during periods of declining economic activity and 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. Any of these events could have a material adverse effect on the Company’s results of operations, financial condition and cash flows.
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

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debt instruments that are rated, as well as the market value of the Company’s common stock. The Company’s credit ratings, however, may not reflect the potential impact on the value of its common stock of risks related to structural, market or other factors discussed in this Form 10-K.
The Company’s need to comply with comprehensive, complex, and sometimes unpredictable government regulations may increase its costs and limit its revenue growth, which may result in reduced earnings.
While the Company generally refers to its Utility segment and its Pipeline and Storage segment as its “regulated segments,” there are many governmental regulations that have an impact on almost every aspect of the Company’s businesses. Existing statutes and regulations may be revised or reinterpreted and new laws and regulations may be adopted or become applicable to the Company, which may increase the Company’s costs or affect its business in ways that the Company cannot predict.
In the Company’s Utility segment, the operations of Distribution Corporation are subject to the jurisdiction of the NYPSC, the PaPUC and, with respect to certain transactions, the FERC. The NYPSC and the PaPUC, among other things, approve the rates that Distribution Corporation may charge to its utility customers. Those approved rates also impact the returns that Distribution Corporation may earn on the assets that are dedicated to those operations. If Distribution Corporation is required in a rate proceeding to reduce the rates it charges its utility customers, or to the extent Distribution Corporation is unable to obtain approval for rate increases from these regulators, particularly when necessary to cover increased costs (including costs that may be incurred in connection with governmental investigations or proceedings or mandated infrastructure inspection, maintenance or replacement programs), earnings may decrease.
In addition to their historical methods of utility regulation, both the PaPUC and NYPSC have established competitive markets in which customers may purchase gas commodity from unregulated marketers, in addition to utility companies. Retail competition for gas commodity service does not pose an acute competitive threat for Distribution Corporation because in both jurisdictions it recovers its cost of service through delivery rates and charges, and not through any mark-up on the gas commodity purchased by its customers. Over the longer run, however, rate design changes resulting from further customer migration to marketer service (“unbundling”) can expose utilities such as Distribution Corporation to stranded costs and revenue erosion in the absence of compensating rate relief.
Both the NYPSC and the PaPUC have instituted proceedings for the purpose of promoting conservation of energy commodities, including natural gas. In New York, Distribution Corporation implemented a Conservation Incentive Program that promotes conservation and efficient use of natural gas by offering customer rebates for high-efficiency appliances, among other things. The intent of conservation and efficiency programs is to reduce customer usage of natural gas. Under traditional volumetric rates, reduced usage by customers results in decreased revenues to the Utility. To prevent revenue erosion caused by conservation, the NYPSC approved a “revenue decoupling mechanism” that renders Distribution Corporation’s New York division financially indifferent to the effects of conservation. In Pennsylvania, although a generic statewide proceeding is pending, the PaPUC has not yet directed Distribution Corporation to implement conservation measures. If the NYPSC were to revoke the revenue decoupling mechanism in a future proceeding or the PaPUC were to adopt a conservation program without a revenue decoupling mechanism or other changes in rate design, reduced customer usage could decrease revenues, forcing Distribution Corporation to file for rate relief. If Distribution Corporation were unable to obtain adequate rate relief, its financial condition, results of operations and cash flows would be adversely affected.
In New York, aggressive generic statewide programs created under the label of efficiency or conservation continue to generate a sizable utility funding requirement for state agencies that administer those programs. Although utilities are authorized to recover the cost of efficiency and conservation program funding through special rates and surcharges, the resulting upward pressure on customer rates, coupled with increased assessments and taxes, could affect future tolerance for traditional utility rate increases, especially if natural gas commodity costs were to increase.
The Company is subject to the jurisdiction of the FERC with respect to Supply Corporation, Empire and some transactions performed by other Company subsidiaries, including Seneca, Distribution Corporation and NFR. The FERC, among other things, approves the rates that Supply Corporation and Empire may charge to their natural

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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 reduce those rates prospectively. If Supply Corporation or Empire is required in a rate proceeding to reduce the rates it charges its natural gas transportation and/or storage customers, or if either Supply Corporation or Empire is unable to obtain approval for rate increases, particularly when necessary to cover increased costs, Supply Corporation’s or Empire’s earnings may decrease. The FERC also possesses significant penalty authority with respect to violations of the laws and regulations it administers. Supply Corporation, Empire and, to the extent subject to FERC jurisdiction, the Company’s other subsidiaries are subject to the FERC’s penalty authority. In addition, the FERC exercises jurisdiction over the construction and operation of facilities used in interstate gas transmission. Also, decisions of Canadian regulators such as the National Energy Board and the Ontario Energy Board could affect the viability and profitability of Supply Corporation and Empire projects designed to transport gas from New York into Ontario.
In January 2012, President Obama signed into law the Pipeline Safety, Regulatory Certainty, and Job Creation Act. The legislation increases civil penalties for pipeline safety violations and addresses matters such as pipeline damage prevention, automatic and remote-controlled shut-off valves, excess flow valves, pipeline integrity management, documentation and testing of maximum allowable operating pressure, and reporting of pipeline accidents. The legislation requires the Pipeline and Hazardous Materials Safety Administration (PHMSA) to issue or revise certain regulations and to conduct various reviews, studies and evaluations. In addition, PHMSA in August 2011 issued an Advance Notice of Proposed Rulemaking regarding pipeline safety. As described in the notice, PHMSA is considering regulations regarding, among other things, the designation of additional high consequence areas along pipelines, minimum requirements for leak detection systems, installation of emergency flow restricting devices, and revision of valve spacing requirements. Unrelated to these safety initiatives, the EPA in April 2010 issued an Advance Notice of Proposed Rulemaking reassessing its regulations governing the use and distribution in commerce of PCBs. The EPA had projected that it would issue a Notice of Proposed Rulemaking by April 2013, but it has not done so. If as a result of these or similar new laws or regulations the Company incurs material costs that it is unable to recover fully through rates or otherwise offset, the Company’s financial condition, results of operations, and cash flows would be adversely affected.
In the Company’s Exploration and Production segment, various aspects of Seneca’s operations are subject to regulation by, among others, the EPA, the U.S. Fish and Wildlife Service, the U.S. Forestry Service, the PaDEP, the Pennsylvania Department of Conservation and Natural Resources, the Division of Oil, Gas and Geothermal Resources of the California Department of Conservation, the California Department of Fish and Wildlife, and the Oil and Gas Conservation Division of the Kansas Corporation Commission. Administrative proceedings or increased regulation by these or other agencies could lead to operational delays or restrictions and increased expense for Seneca.
The nature of the Company’s operations presents inherent risks of loss that could adversely affect its results of operations, financial condition and cash flows.
The Company’s operations in its various reporting segments are subject to inherent hazards and risks such as: fires; natural disasters; explosions; geological formations with abnormal pressures; blowouts during well drilling; collapses of wellbore casing or other tubulars; pipeline ruptures; spills; and other hazards and risks that may cause personal injury, death, property damage, environmental damage or business interruption losses. Additionally, the Company’s facilities, machinery, and equipment may be subject to sabotage. Any of these events could cause a loss of hydrocarbons, environmental pollution, claims for personal injury, death, property damage or business interruption, or governmental investigations, recommendations, claims, fines or penalties. As protection against operational hazards, the Company maintains insurance coverage against some, but not all, potential losses. In addition, many of the agreements that the Company executes with contractors provide for the division of responsibilities between the contractor and the Company, and the Company seeks to obtain an indemnification from the contractor for certain of these risks. The Company is not always able, however, to secure written agreements with its contractors that contain indemnification, and sometimes the Company is required to indemnify others.

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Insurance or indemnification agreements, when obtained, may not adequately protect the Company against liability from all of the consequences of the hazards described above. The occurrence of an event not fully insured or indemnified against, the imposition of fines, penalties or mandated programs by governmental authorities, the failure of a contractor to meet its indemnification obligations, or the failure of an insurance company to pay valid claims could result in substantial losses to the Company. In addition, insurance may not be available, or if available may not be adequate, to cover any or all of these risks. It is also possible that insurance premiums or other costs may rise significantly in the future, so as to make such insurance prohibitively expensive.
Hazards and risks faced by the Company, and insurance and indemnification obtained or provided by the Company, may subject the Company to litigation or administrative proceedings from time to time. Such litigation or proceedings could result in substantial monetary judgments, fines or penalties against the Company or be resolved on unfavorable terms, the result of which could have a material adverse effect on the Company’s results of operations, financial condition and cash flows.
Environmental regulation significantly affects the Company’s business.
The Company’s business operations are subject to federal, state, and local laws and regulations relating to environmental protection. These laws and regulations concern the generation, storage, transportation, disposal, emission or discharge of pollutents, contaminants, hazardous substances and greenhouse gases into the environment, the reporting of such matters, and the general protection of public health, natural resources, wildlife and the environment. For example, currently applicable environmental laws and regulations restrict the types, quantities and concentrations of materials that can be released into the environment in connection with regulated activities, limit or prohibit activities in certain protected areas, and may require the Company to investigate and/or remediate contamination at certain current and former properties regardless of whether such contamination resulted from the Company’s actions or whether such actions were in compliance with applicable laws and regulations at the time they were taken. Moreover, spills or releases of regulated substances or the discovery of currently unknown contamination could expose the Company to material losses, expenditures and environmental, health and safety liabilities. Such liabilities could include penalties, sanctions or claims for damages to persons, property or natural resources brought on behalf of the government or private litigants that could cause the Company to incur substantial costs or uninsured losses.
In addition, the Company must obtain, maintain and comply with numerous permits, leases, approvals, consents and certificates from various governmental authorities before commencing regulated activities. In connection with such activities, the Company may need to make significant capital and operating expenditures to control air emissions and water discharges or to perform certain corrective actions to meet the conditions of the permits issued pursuant to applicable environmental laws and regulations. Any failure to comply with applicable environmental laws and regulations and the terms and conditions of its environmental permits and authorizations could result in the assessment of significant administrative, civil and/or criminal penalties, the imposition of investigatory or remedial obligations and corrective actions, the revocation of required permits, or the issuance of injunctions limiting or prohibiting certain of the Company’s operations.
Costs of compliance and liabilities could negatively affect the Company’s results of operations, financial condition and cash flows. In addition, compliance with environmental laws and regulations could require unexpected capital expenditures at the Company’s facilities or delay or cause the cancellation of expansion projects or oil and natural gas drilling activities. Because the costs of complying with environmental regulations are significant, additional regulation could negatively affect the Company’s business. Although the Company cannot predict the impact of the interpretation or enforcement of EPA standards or other federal, state and local laws or regulations, the Company’s costs could increase if environmental laws and regulations change.
Legislative and regulatory measures to address climate change and greenhouse gas emissions are in various phases of discussion or implementation. Under the Federal Clean Air Act, the EPA requires that new stationary sources of significant greenhouse gas emissions or major modifications of existing facilities obtain permits covering such emissions. The EPA is also considering other regulatory options to regulate greenhouse emissions from the energy industry. In addition, the U.S. Congress has from time to time considered bills that would establish a cap-and-trade program to reduce emissions of greenhouse gases. Legislation or regulation that restricts greenhouse gas emissions could increase the Company’s cost of environmental compliance by requiring the Company to install

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new equipment to reduce emissions from larger facilities and/or purchase emission allowances. International, federal, state or regional climate change and greenhouse gas initiatives could also delay or otherwise negatively affect efforts to obtain permits and other regulatory approvals with regard to existing and new facilities, or impose additional monitoring and reporting requirements. Climate change and greenhouse gas initiatives, and incentives to conserve energy or use alternative energy sources, could also reduce demand for oil and natural gas. 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.
Third parties may attempt to breach the Company’s network security, which could disrupt the Company’s operations and adversely affect its financial results.
The Company’s information technology systems are subject to attempts by others to gain unauthorized access through the Internet, or to otherwise introduce malicious software. These attempts might be the result of industrial or other espionage, or actions by hackers seeking to harm the Company, its services or customers. Attempts to breach the Company’s network security may result in disruption of the Company’s business operations and services, delays in production, theft of sensitive and valuable data, damage to our physical systems, and reputational harms. These harms may require significant expenditures to remedy breaches, including restoration of customer service and enhancement of information technology systems. The Company seeks to prevent, detect and investigate these security incidents, but in some cases the Company might be unaware of an incident or its magnitude and effects. The Company has experienced attempts to breach its network security, and although the scope of such incidents is sometimes unknown, they could prove to be material to the Company. These security incidents may have an adverse impact on the Company’s operations, earnings and financial condition.
The Company could be adversely affected by the disallowance of purchased gas costs incurred by the Utility segment.
Tariff rate schedules in each of the Utility segment’s service territories contain purchased gas adjustment clauses which permit Distribution Corporation to file with state regulators for rate adjustments to recover increases in the cost of purchased gas. Assuming those rate adjustments are granted, increases in the cost of purchased gas have no direct impact on profit margins. Distribution Corporation is required to file an accounting reconciliation with the regulators in each of the Utility segment’s service territories regarding the costs of purchased gas. There is a risk of disallowance of full recovery of these costs if regulators determine that Distribution Corporation was imprudent in making its gas purchases. Any material disallowance of purchased gas costs could have a material adverse effect on cash flow and earnings.
Changes in interest rates may affect the Company’s ability to finance capital expenditures and to refinance maturing debt.
The Company’s ability to cost-effectively finance capital expenditures and to refinance maturing debt will depend in part upon interest rates. The direction in which interest rates may move is uncertain. Declining interest rates have generally been believed to be favorable to utilities, while rising interest rates are generally believed to be unfavorable, because of the levels of debt that utilities may have outstanding. In addition, the Company’s authorized rate of return in its regulated businesses is based upon certain assumptions regarding interest rates. If interest rates are lower than assumed rates, the Company’s authorized rate of return could be reduced. If interest rates are higher than assumed rates, the Company’s ability to earn its authorized rate of return may be adversely impacted.
Fluctuations in oil and natural gas prices could adversely affect revenues, cash flows and profitability.
Operations in the Company’s Exploration and Production segment are materially dependent on prices received for its oil and natural gas production. Both short-term and long-term price trends affect the economics of exploring for, developing, producing, gathering and processing oil and natural gas. Oil and natural gas prices can be volatile and can be affected by: weather conditions, natural disasters, the supply and price of foreign oil and natural gas, the level of consumer product demand, national and worldwide economic conditions, economic disruptions caused by terrorist activities, acts of war or major accidents, political conditions in foreign countries, the price and availability of alternative fuels, the proximity to, and availability of, capacity on transportation

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facilities, regional levels of supply and demand, energy conservation measures; and government regulations, such as regulation of greenhouse gas emissions and natural gas transportation, royalties, and price controls. The Company sells most of the oil and natural gas that it produces at current market and/or indexed prices rather than through fixed-price contracts, although as discussed below, the Company frequently hedges the price of a significant portion of its future production in the financial markets. The prices the Company receives depend upon factors beyond the Company’s control, including the factors affecting price mentioned above. The Company believes that any prolonged reduction in oil and natural gas prices could restrict its ability to continue the level of exploration and production activity the Company otherwise would pursue, which could have a material adverse effect on its revenues, cash flows and results of operations.
The natural gas the Company produces is priced in local markets where production occurs, and price is therefore affected by local or regional supply and demand factors as well as other local market dynamics such as regional pipeline capacity. The prices the Company receives for its natural gas production are generally lower than the relevant benchmark prices, such as NYMEX, that are used for commodity trading purposes. The difference between the benchmark price and the price the Company receives is called a differential. The Company may be unable to accurately predict natural gas differentials, which may widen significantly in the future. Numerous factors may influence local commodity pricing, such as pipeline takeaway capacity and specifications, localized storage capacity, disruptions in the midstream or downstream sectors of the industry, trade restrictions and governmental regulations. Insufficient pipeline or storage capacity, or a lack of demand or surplus of supply in any given operating area may cause the differential to widen in that area compared to other natural gas producing areas. Increases in the differential could lead to production curtailments or otherwise have a material adverse effect on the Company’s revenues, cash flows and results of operations.
In the Company’s Pipeline and Storage segment, significant changes in the price differential between equivalent quantities of natural gas at different geographic locations could adversely impact the Company. For example, if the price of natural gas at a particular receipt point on the Company’s pipeline system increases relative to the price of natural gas at other locations, then the volume of natural gas received by the Company at the relatively more expensive receipt point may decrease, or the price the Company charges to transport that natural gas may decrease. Supply Corporation and Empire experienced such a change at the Canada/United States border at the Niagara River, where gas prices increased relative to prices available at Leidy, Pennsylvania. This change in price differential caused shippers to seek alternative lower priced gas supplies and, consequently, alternative transportation routes. Supply Corporation and Empire saw transportation volumes decrease in 2009 and 2010 as a result of this situation, and in some cases, shippers decided not to renew transportation contracts. While much of the impact of lower volumes under existing contracts is offset by the straight fixed-variable rate design utilized by Supply Corporation and Empire, this rate design does not protect Supply Corporation or Empire where shippers do not contract for expiring capacity at the same quantity and rate. As contract renewals decrease, revenues and earnings in the Pipeline and Storage segment may decrease, as they did in 2010 and 2011. Supply Corporation and Empire responded to this changed gas price environment by developing projects designed to reverse the flow on their existing systems, as described elsewhere in this report, including Item 7, MD&A under the heading “Investing Cash Flow.”
Significant changes in the price differential between futures contracts for natural gas having different delivery dates could also adversely impact the Company. For example, if the prices of natural gas futures contracts for winter deliveries to locations served by the Pipeline and Storage segment decline relative to the prices of such contracts for summer deliveries (as a result, for instance, of increased production of natural gas within the Pipeline and Storage segment’s geographic area or other factors), then demand for the Company’s natural gas storage services driven by that price differential could decrease. Such changes in price differential could also affect the Energy Marketing segment’s ability to offset its natural gas storage costs through hedging transactions. These changes could adversely affect revenues, cash flows and results of operations.
The Company has significant transactions involving price hedging of its oil and natural gas production as well as its fixed price purchase and sale commitments.
In order to protect itself to some extent against unusual price volatility and to lock in fixed pricing on oil and natural gas production for certain periods of time, the Company’s Exploration and Production segment regularly

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enters into commodity price derivatives contracts (hedging arrangements) with respect to a portion of its expected production. These contracts may at any time cover as much as approximately 80% of the Company’s expected energy production during the upcoming 12-month period. These contracts reduce exposure to subsequent price drops but can also limit the Company’s ability to benefit from increases in commodity prices. In addition, the Energy Marketing segment enters into certain hedging arrangements, primarily with respect to its fixed price purchase and sales commitments and its gas stored underground.
Under applicable accounting rules currently in effect, the Company’s hedging arrangements are subject to quarterly effectiveness tests. Inherent within those effectiveness tests are assumptions concerning the long-term price differential between different types of crude oil, assumptions concerning the difference between published natural gas price indexes established by pipelines into which hedged natural gas production is delivered and the reference price established in the hedging arrangements, assumptions regarding the levels of production that will be achieved and, with regard to fixed price commitments, assumptions regarding the creditworthiness of certain customers and their forecasted consumption of natural gas. Depending on market conditions for natural gas and crude oil and the levels of production actually achieved, it is possible that certain of those assumptions may change in the future, and, depending on the magnitude of any such changes, it is possible that a portion of the Company’s hedges may no longer be considered highly effective. In that case, gains or losses from the ineffective derivative financial instruments would be marked-to-market on the income statement without regard to an underlying physical transaction. For example, in the Exploration and Production segment, where the Company uses short positions (i.e. positions that pay off in the event of commodity price decline) to hedge forecasted sales, gains would occur to the extent that natural gas and crude oil hedge prices exceed market prices for the Company’s natural gas and crude oil production, and losses would occur to the extent that market prices for the Company’s natural gas and crude oil production exceed hedge prices.
Use of energy commodity price hedges also exposes the Company to the risk of non-performance by a contract counterparty. These parties might not be able to perform their obligations under the hedge arrangements. In addition, the Company enters into certain commodity price hedges that are cleared through the NYMEX or ICE by futures commission merchants. Under NYMEX and ICE rules, the Company is required to post collateral in connection with such hedges, with such collateral being held by its futures commission merchants. The Company is exposed to the risk of loss of such collateral from occurrences such as financial failure of its futures commission merchants, or misappropriation or mishandling of clients’ funds or other similar actions by its futures commission merchants. In addition, the Company is exposed to potential hedging ineffectiveness in the event of a failure by one of its futures commission merchants or contract counterparties.
It is the Company’s policy that the use of commodity derivatives contracts comply with various restrictions in effect in respective business segments. For example, in the Exploration and Production segment, commodity derivatives contracts must be confined to the price hedging of existing and forecast production, and in the Energy Marketing segment, commodity derivatives with respect to fixed price purchase and sales commitments must be matched against commitments reasonably certain to be fulfilled. The Company maintains a system of internal controls to monitor compliance with its policy. However, unauthorized speculative trades, if they were to occur, could expose the Company to substantial losses to cover positions in its derivatives contracts. In addition, in the event the Company’s actual production of oil and natural gas falls short of hedged forecast production, the Company may incur substantial losses to cover its hedges.
The Dodd-Frank Act includes provisions related to the swaps and over-the-counter derivatives markets. Certain provisions of the Dodd-Frank Act related to derivatives became effective July 16, 2011, but other provisions related to derivatives have or will become effective as federal agencies (including the CFTC, various banking regulators and the SEC) adopt rules to implement the law. Among other things, the Dodd-Frank Act (1) regulates certain participants in the swaps markets, including new entities defined as “swap dealers” and “major swap participants,” (2) requires clearing and exchange-trading of certain swaps that the CFTC determines must be cleared, (3) requires reporting and recordkeeping of swaps, and (4) enhances the CFTC’s enforcement authority, including the authority to establish position limits on derivatives and increases penalties for violations of the Commodity Exchange Act. For purposes of the Dodd-Frank Act, under rules adopted by the SEC and/or CFTC, the Company believes that it qualifies as a non-financial end user of derivatives, that is, as a non-financial entity that uses derivatives to hedge or mitigate commercial risk. Nevertheless, other rules that are being developed could have a

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significant impact on the Company. For example, the CFTC has imposed numerous registration, swaps documentation, business conduct, reporting, and recordkeeping requirements on swap dealers and major swap participants, which frequently are counterparties to the Company’s derivative hedging transactions. Similarly, the CFTC and various banking regulators have proposed rules that would require swap dealers and major swap participants subject to their jurisdiction to comply with certain obligations relating to capitalization and the collection of initial and variation margin from certain counterparties, although the recent proposals do not mandate the collection of margin from counterparties that qualify as non-financial end users, such as the Company. Regardless of the final capital and margin rules, concern remains that swap dealers and major swap participants will pass along their increased costs stemming from the final and proposed rules through higher transaction costs and prices or other direct or indirect costs. In addition, while the Company expects to be exempt from the Dodd-Frank Act’s requirement that swaps be cleared and traded on exchanges or swap execution facilities, the cost of entering into a non-exchange cleared swap that is available as an exchange cleared swap may be greater. The Dodd-Frank Act may also increase costs for derivative recordkeeping, reporting, position limit compliance, and other compliance; cause parties to materially alter the terms of derivative contracts; cause parties to restructure certain derivative contracts; reduce the availability of derivatives to protect against risks that the Company encounters or to optimize assets; reduce the Company’s ability to monetize or restructure existing derivative contracts; and increase the Company’s exposure to less creditworthy counterparties, all of which could increase the Company’s business costs.
You should not place undue reliance on reserve information because such information represents estimates.
This Form 10-K contains estimates of the Company’s proved oil and natural gas reserves and the future net cash flows from those reserves that were prepared by the Company’s petroleum engineers and audited by independent petroleum engineers. Petroleum engineers consider many factors and make assumptions in estimating oil and natural gas reserves and future net cash flows. These factors include: historical production from the area compared with production from other producing areas; the assumed effect of governmental regulation; and assumptions concerning oil and natural gas prices, production and development costs, severance and excise taxes, and capital expenditures. Lower oil and natural gas prices generally cause estimates of proved reserves to be lower. Estimates of reserves and expected future cash flows prepared by different engineers, or by the same engineers at different times, may differ substantially. Ultimately, actual production, revenues and expenditures relating to the Company’s reserves will vary from any estimates, and these variations may be material. Accordingly, the accuracy of the Company’s reserve estimates is a function of the quality of available data and of engineering and geological interpretation and judgment.
If conditions remain constant, then the Company is reasonably certain that its reserve estimates represent economically recoverable oil and natural gas reserves and future net cash flows. If conditions change in the future, then subsequent reserve estimates may be revised accordingly. You should not assume that the present value of future net cash flows from the Company’s proved reserves is the current market value of the Company’s estimated oil and natural gas reserves. In accordance with SEC requirements, the Company bases the estimated discounted future net cash flows from its proved reserves on 12-month average prices for oil and natural gas (based on first day of the month prices and adjusted for hedging) and on costs as of the date of the estimate. Actual future prices and costs may differ materially from those used in the net present value estimate. Any significant price changes will have a material effect on the present value of the Company’s reserves.
Petroleum engineering is a subjective process of estimating underground accumulations of natural gas and other hydrocarbons that cannot be measured in an exact manner. The process of estimating oil and natural gas reserves is complex. The process involves significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. Future economic and operating conditions are uncertain, and changes in those conditions could cause a revision to the Company’s reserve estimates in the future. Estimates of economically recoverable oil and natural gas reserves and of future net cash flows depend upon a number of variable factors and assumptions, including historical production from the area compared with production from other comparable producing areas, and the assumed effects of regulations by governmental agencies. Because all reserve estimates are to some degree subjective, each of the following items may differ materially from those assumed in estimating reserves: the quantities of oil and natural gas that are ultimately

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recovered, the timing of the recovery of oil and natural gas reserves, the production and operating costs incurred, the amount and timing of future development and abandonment expenditures, and the price received for the production.
The amount and timing of actual future oil and natural gas production and the cost of drilling are difficult to predict and may vary significantly from reserves and production estimates, which may reduce the Company’s earnings.
There are many risks in developing oil and natural gas, including numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves and in projecting future rates of production and timing of development expenditures. The future success of the Company’s Exploration and Production segment depends on its ability to develop additional oil and natural gas reserves that are economically recoverable, and its failure to do so may reduce the Company’s earnings. The total and timing of actual future production may vary significantly from reserves and production estimates. The Company’s drilling of development wells can involve significant risks, including those related to timing, success rates, and cost overruns, and these risks can be affected by lease and rig availability, geology, and other factors. Drilling for oil and natural gas can be unprofitable, not only from non-productive wells, but from productive wells that do not produce sufficient revenues to return a profit. Also, title problems, weather conditions, governmental requirements, including completion of environmental impact analyses and compliance with other environmental laws and regulations, and shortages or delays in the delivery of equipment and services can delay drilling operations or result in their cancellation. The cost of drilling, completing, and operating wells is significant and often uncertain, and new wells may not be productive or the Company may not recover all or any portion of its investment. Production can also be delayed or made uneconomic if there is insufficient gathering, processing and transportation capacity available at an economic price to get that production to a location where it can be profitably sold. Without continued successful exploitation or acquisition activities, the Company’s reserves and revenues will decline as a result of its current reserves being depleted by production. The Company cannot make assurances that it will be able to find or acquire additional reserves at acceptable costs.
Financial accounting requirements regarding exploration and production activities may affect the Company’s profitability.
The Company accounts for its exploration and production activities under the full cost method of accounting. Each quarter, the Company must compare 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 12-month average prices for oil and natural gas (based on first day of the month prices and adjusted for hedging). If, at the end of any quarter, the amount of the unamortized investment exceeds the net present value of the projected future cash flows, such investment may be considered to be “impaired,” and the full cost accounting rules require that the investment must be written down to the calculated net present value. Such an instance would require the Company to recognize an immediate expense in that quarter, and its earnings would be reduced. Depending on the magnitude of any decrease in average prices, that charge could be material.
Increased regulation of exploration and production activities, including hydraulic fracturing, could adversely impact the Company.
Due to the burgeoning Marcellus Shale natural gas play in the northeast United States, together with the fiscal difficulties faced by state governments in New York and Pennsylvania, various state legislative and regulatory initiatives regarding the exploration and production business have been proposed. These initiatives include potential new or updated statutes and regulations governing the drilling, casing, cementing, testing, abandonment and monitoring of wells, the protection of water supplies and restrictions on water use and water rights, hydraulic fracturing operations, surface owners’ rights and damage compensation, the spacing of wells, use and disposal of potentially hazardous materials, and environmental and safety issues regarding natural gas pipelines. New permitting fees and/or severance taxes for oil and gas production are also possible. Additionally, legislative initiatives in the U.S. Congress and regulatory studies, proceedings or rule-making initiatives at federal or state agencies focused on the hydraulic fracturing process and related operations could result in additional permitting,

-21-



compliance, reporting and disclosure requirements. For example, the EPA has adopted regulations that establish emission performance standards for hydraulic fracturing operations as well as natural gas gathering and transmission operations. Other EPA initiatives could expand water quality and hazardous waste regulation of hydraulic fracturing and related operations. In California, legislation regarding well stimulation, including hydraulic fracturing, has been adopted. The law mandates technical standards for well construction, hydraulic fracturing water management, groundwater monitoring, seismicity monitoring during hydraulic fracturing operations and public disclosure of hydraulic fracturing fluid constituents. Implementing regulations, which will include new permit requirements, must be adopted to go into effect on July 1, 2015. These and any other new state or federal legislative or regulatory measures could lead to operational delays or restrictions, increased operating costs, additional regulatory burdens and increased risks of litigation for the Company.
The increasing costs of certain employee and retiree benefits could adversely affect the Company’s results.
The Company’s earnings and cash flow may be impacted by the amount of income or expense it expends or records for employee benefit plans. This is particularly true for pension and other post-retirement benefit plans, which are dependent on actual plan asset returns and factors used to determine the value and current costs of plan benefit obligations. In addition, if medical costs rise at a rate faster than the general inflation rate, the Company might not be able to mitigate the rising costs of medical benefits. Increases to the costs of pension, other post-retirement and medical benefits could have an adverse effect on the Company’s financial results.
Significant shareholders or potential shareholders may attempt to effect changes at the Company or acquire control over the Company, which could adversely affect the Company’s results of operations and financial condition.
Shareholders of the Company may from time to time engage in proxy solicitations, advance shareholder proposals or otherwise attempt to effect changes or acquire control over the Company. Campaigns by shareholders to effect changes at publicly traded companies are sometimes led by investors seeking to increase short-term shareholder value through actions such as financial restructuring, increased debt, special dividends, stock repurchases or sales of assets or the entire company. 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.


-22-



Item 2
Properties
General Information on Facilities
The net investment of the Company in property, plant and equipment was $5.7 billion at September 30, 2014. The Exploration and Production segment comprises 50.5% of this investment, and is primarily located in California and in the Appalachian region of the United States. Approximately 43.2% 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 northwestern Pennsylvania. The Gathering segment comprises 5.1% of the Company’s investment in net property, plant and equipment, and is located in northwestern Pennsylvania. The remaining net investment in property, plant and equipment consisted of the All Other category and Corporate operations (1.2%). During the past five years, the Company has made additions to property, plant and equipment in order to expand its exploration and production operations in the Appalachian region of the United States and to expand and improve transmission facilities for transportation customers in New York and Pennsylvania. Net property, plant and equipment has increased $2.6 billion, or 83.3%, since 2009. As part of its strategy to focus its exploration and production activities within the Appalachian region of the United States, specifically within the Marcellus Shale, the Company sold its off-shore oil and natural gas properties in the Gulf of Mexico in April 2011. The net property, plant and equipment associated with these properties was $55.4 million. The Company also sold on-shore oil and natural gas properties in its West Coast region in May 2011 with net property, plant and equipment of $8.1 million. In September 2010, the Company sold its landfill gas operations in the states of Ohio, Michigan, Kentucky, Missouri, Maryland and Indiana. The net property, plant and equipment of the landfill gas operations at the date of sale was $8.8 million.
The Exploration and Production segment had a net investment in property, plant and equipment of $2.9 billion at September 30, 2014.
The Pipeline and Storage segment had a net investment of $1.2 billion in property, plant and equipment at September 30, 2014. Transmission pipeline represents 38% of this segment’s total net investment and includes 2,350 miles of pipeline utilized to move large volumes of gas throughout its service area. Storage facilities represent 17% of this segment’s total net investment and consist of 31 storage fields operating at a combined working gas level of 73.4 Bcf, four of which are jointly owned and operated with other interstate gas pipeline companies, and 432 miles of pipeline. Net investment in storage facilities includes $81.6 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 33 compressor stations with 141,704 installed compressor horsepower that represent 20% of this segment’s total net investment in property, plant and equipment.
The Gathering segment had a net investment of $0.3 billion in property, plant and equipment at September 30, 2014. Gathering lines and related compressors comprise substantially all of this segment’s total net investment, including 61 miles of lines utilized to move Appalachian production (including Marcellus Shale) to various transmission pipeline receipt points. The Gathering segment has 2 compressor stations with 17,940 installed compressor horsepower.
The Utility segment had a net investment in property, plant and equipment of $1.3 billion at September 30, 2014. The net investment in its gas distribution network (including 14,782 miles of distribution pipeline) and its service connections to customers represent approximately 49% and 34%, respectively, of the Utility segment’s net investment in property, plant and equipment at September 30, 2014.
The Pipeline and Storage segments’ facilities provided the capacity to meet Supply Corporation’s 2014 peak day sendout for transportation service of 2,350 MMcf, which occurred on January 7, 2014. Withdrawals from storage of 802.5 MMcf provided approximately 34% of the requirements on that day.
Company maps are included in exhibit 99.2 of this Form 10-K and are incorporated herein by reference.

-23-



Exploration and Production Activities
The Company is engaged in the exploration for, and the development and purchase of, natural gas and oil reserves in California, the Appalachian region of the United States and Kansas. The Company has been increasing its emphasis in the Appalachian region, primarily in the Marcellus Shale, and sold its off-shore oil and natural gas properties in the Gulf of Mexico during 2011, as mentioned above. Further discussion of oil and gas producing activities is included in Item 8, Note M - Supplementary Information for Oil and Gas Producing Activities. Note M sets forth proved developed and undeveloped reserve information for Seneca. The September 30, 2014, 2013 and 2012 reserves shown in Note M are valued using an unweighted arithmetic average of the first day of the month oil and gas prices for each month within the twelve-month period prior to the end of the reporting period. The reserves were estimated by Seneca’s geologists and engineers and were audited by independent petroleum engineers from Netherland, Sewell & Associates, Inc. Note M discusses the qualifications of the Company's reservoir 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 1,300 Bcf at September 30, 2013 to 1,683 Bcf at September 30, 2014. This increase is attributed to extensions and discoveries of 447 Bcf, acquisitions of 34 Bcf (both primarily Marcellus Shale) and positive revisions of previous estimates of 45 Bcf which were partially offset by production of 142 Bcf. Upward performance revisions of 45 Bcf were primarily performance revisions in the Marcellus Shale and included a 20 Bcf upward revision to Marcellus PUD reserves transferred to developed and a 13 Bcf upward revision to remaining Marcellus PUD reserves.
Seneca’s proved developed and undeveloped oil reserves decreased from 41,598 Mbbl at September 30, 2013 to 38,477 Mbbl at September 30, 2014. Extensions and discoveries of 1,539 Mbbl were exceeded by production of 3,036 Mbbl primarily occurring in the West Coast region (3,005 Mbbl), and downward revisions of previous estimates of 1,694 Mbbl. Downward revisions were primarily a result of removing 1,501 Mbbl of proved undeveloped reserves at the Midway Sunset field in the Tulare reservoir as the Company has no near term plans to develop these reserves as it is employing its capital elsewhere. On a Bcfe basis, Seneca’s proved developed and undeveloped reserves increased from 1,549 Bcfe at September 30, 2013 to 1,914 Bcfe at September 30, 2014. Total revisions of previous estimates increased 35 Bcfe.
Seneca’s proved developed and undeveloped natural gas reserves increased from 988 Bcf at September 30, 2012 to 1,300 Bcf at September 30, 2013. This increase was attributed to extensions and discoveries of 362 Bcf (355 Bcf in the Marcellus Shale) and positive revisions of previous estimates of 53 Bcf which were partially offset by production of 104 Bcf. Total gas revisions of 53 Bcf were composed of 8 Bcf in upward gas pricing revisions and 45 Bcf in upward performance revisions. Price related revisions were a result of higher trailing twelve month average gas prices (Dominion South Point average gas price increased $0.64 per MMBtu from $2.84 per MMBtu to $3.48 per MMBtu). Upward performance revisions of 45 Bcf were primarily in the Marcellus Shale and included an 11 Bcf upward revision to Marcellus PUD reserves transferred to developed and a 19 Bcf downward revision to remaining Marcellus PUD reserves.
Seneca’s proved developed and undeveloped oil reserves decreased from 42,862 Mbbl at September 30, 2012 to 41,598 Mbbl at September 30, 2013. Extensions and discoveries of 2,443 Mbbl were exceeded by production of 2,831 Mbbl, primarily occurring in the West Coast region (2,803 Mbbl), and downward revisions of previous estimates of 876 Mbbl. On a Bcfe basis, Seneca’s proved developed and undeveloped reserves increased from 1,246 Bcfe at September 30, 2012 to 1,549 Bcfe at September 30, 2013.
At September 30, 2014, the Company’s Exploration and Production segment had delivery commitments of 1,893 Bcfe (mostly natural gas as commitments for crude oil, gasoline, butane and propane was insignificant). The Company expects to meet those commitments through proved reserves, including the future development of reserves that are currently classified as proved undeveloped reserves, the growth of proved gas reserves (which has averaged 30 percent over the past two years through the development of Seneca's large Appalachian acreage position) and (if necessary) from the purchase of natural gas and crude oil at index-related prices.



-24-



The following is a summary of certain oil and gas information taken from Seneca’s records. All monetary amounts are expressed in U.S. dollars.
Production
 
 
For The Year Ended September 30
 
 
2014
 
 
2013
 
 
2012
 
United States
 
 
 
 
 
 
 
 
Appalachian Region
 
 
 
 
 
 
 
 
Average Sales Price per Mcf of Gas
$
3.55

(1)
 
$
3.49

(1)
 
$
2.71

(1)
Average Sales Price per Barrel of Oil
$
96.34

  
 
$
96.48

  
 
$
93.94

  
Average Sales Price per Mcf of Gas (after hedging)
$
3.49

  
 
$
4.00

  
 
$
4.19

  
Average Sales Price per Barrel of Oil (after hedging)
$
96.34

  
 
$
96.48

  
 
$
93.94

  
Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced
$
0.74

(1)
 
$
0.67

(1)
 
$
0.68

(1)
Average Production per Day (in MMcf Equivalent of Gas and Oil Produced)
382

(1)
 
276

(1)
 
172

(1)
West Coast Region
 
 
 
 
 
 
 
 
Average Sales Price per Mcf of Gas
$
6.75

  
 
$
6.61

  
 
$
6.27

  
Average Sales Price per Barrel of Oil
$
98.25

  
 
$
103.14

  
 
$
107.13

  
Average Sales Price per Mcf of Gas (after hedging)
$
6.65

  
 
$
7.12

  
 
$
8.54

  
Average Sales Price per Barrel of Oil (after hedging)
$
95.54

  
 
$
98.23

  
 
$
90.84

  
Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced
$
2.96

  
 
$
2.61

  
 
$
1.98

  
Average Production per Day (in MMcf Equivalent of Gas and Oil Produced)
58

  
 
55

  
 
56

  
Total Company
 
 
 
 
 
 
 
 
Average Sales Price per Mcf of Gas
$
3.62

  
 
$
3.58

  
 
$
2.89

  
Average Sales Price per Barrel of Oil
$
98.23

  
 
$
103.07

  
 
$
106.97

  
Average Sales Price per Mcf of Gas (after hedging)
$
3.56

  
 
$
4.10

  
 
$
4.42

  
Average Sales Price per Barrel of Oil (after hedging)
$
95.55

  
 
$
98.21

  
 
$
90.88

  
Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced
$
1.03

  
 
$
0.99

  
 
$
1.00

  
Average Production per Day (in MMcf Equivalent of Gas and Oil Produced)
440

  
 
331

  
 
228

  

(1)
The Marcellus Shale fields (which exceed 15% of total reserves at 9/30/2014, 9/30/2013 and 9/30/2012) contributed 361 MMcfe, 258 MMcfe and 152 MMcfe of daily production in 2014, 2013 and 2012, respectively. The average sales price (per Mcfe) was $3.53 ($3.47 after hedging) in 2014, $3.49 ($4.04 after hedging) in 2013 and $2.67 ($3.66 after hedging) in 2012. The average lifting costs (per Mcfe) were $0.72 in 2014, $0.64 in 2013 and $0.61 in 2012.

Productive Wells
 
 
Appalachian
Region
 
West Coast
Region
 
Total Company
At September 30, 2014
Gas
 
Oil
 
Gas
 
Oil
 
Gas
 
Oil
Productive Wells — Gross
2,841

 
1

 

 
2,054

 
2,841

 
2,055

Productive Wells — Net
2,768

 
1

 

 
1,995

 
2,768

 
1,996


-25-



Developed and Undeveloped Acreage
 
At September 30, 2014
Appalachian
Region
 
West Coast
Region
 
Total
Company
Developed Acreage
 
 
 
 
 
— Gross
559,044

 
24,730

 
583,774

— Net
549,296

 
21,457

 
570,753

Undeveloped Acreage
 
 
 
 
 
— Gross
376,225

 
21,327

 
397,552

— Net
358,722

 
11,930

 
370,652

Total Developed and Undeveloped Acreage
 
 
 
 
 
— Gross
935,269

 
46,057

 
981,326

— Net
908,018

 
33,387

 
941,405

As of September 30, 2014, the aggregate amount of gross undeveloped acreage expiring in the next three years and thereafter are as follows: 20,941 acres in 2015 (17,336 net acres), 11,930 acres in 2016 (9,621 net acres), 12,756 acres in 2017 (9,104 net acres) and 43,561 acres thereafter (39,195 net acres). The remaining 308,364 gross acres (295,396 net acres) represent non-expiring oil and gas rights owned by the Company. Of the acreage that is currently scheduled to expire in 2015, 2016 and 2017, Seneca holds 56 Bcfe of proved undeveloped gas reserves, with 30 Bcfe subject to lease expirations in 2016 and 26 Bcfe subject to lease expirations in 2017. This total represents approximately 11% of Seneca's proved undeveloped reserves in the Marcellus Shale. Seneca intends to develop these reserves prior to the expiration of the leases as part of its management approved development plan.
Drilling Activity
 
 
Productive
 
Dry
For the Year Ended September 30
2014
 
2013
 
2012
 
2014
 
2013
 
2012
United States
 
 
 
 
 
 
 
 
 
 
 
Appalachian Region
 
 
 
 
 
 
 
 
 
 
 
Net Wells Completed
 
 
 
 
 
 
 
 
 
 
 
— Exploratory
4.832

 

 
7.000

 

 
1.000

 

— Development
53.000

 
39.500

 
50.500

 
2.000

 
2.500

 
2.000

West Coast Region
 
 
 
 
 
 
 
 
 
 
 
Net Wells Completed
 
 
 
 
 
 
 
 
 
 
 
— Exploratory
1.533

 
0.625

 

 

 

 

— Development
84.720

 
74.996

 
56.990

 
1.000

 

 

Total Company
 
 
 
 
 
 
 
 
 
 
 
Net Wells Completed
 
 
 
 
 
 
 
 
 
 
 
— Exploratory
6.365

 
0.625

 
7.000

 

 
1.000

 

— Development
137.720

 
114.496

 
107.490

 
3.000

 
2.500

 
2.000

Present Activities
 
At September 30, 2014
Appalachian
Region
 
West Coast Region
 
Total Company
Wells in Process of Drilling(1)
 
 
 
 
 
— Gross
80.000

 
2.000

 
82.000

— Net
65.500

 
2.000

 
67.500

 
(1)
Includes wells awaiting completion.

-26-



Item 3
Legal Proceedings
As previously reported, on November 14, 2012, the PaDEP sent a draft Consent Assessment of Civil Penalty to a subsidiary of Midstream Corporation. The draft Consent offered to settle various alleged violations of the Pennsylvania Clean Streams Law and the PaDEP’s rules and regulations regarding erosion and sedimentation control if the Company would consent to a civil penalty. The alleged violations occurred during construction of the Company’s Trout Run Gathering System following historic rainfall and flooding in the fall of 2011. In September 2014, the Company settled this matter with the PaDEP and paid a civil penalty of $250,000.
For a discussion of various environmental and other matters, refer to Part II, Item 7, MD&A and Item 8 at Note I — Commitments and Contingencies.

Item 4
Mine Safety Disclosures
Not Applicable.
PART II

Item 5
Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
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, Item 8 at Note E — Capitalization and Short-Term Borrowings, and at Note L — Market for Common Stock and Related Shareholder Matters (unaudited).
On July 1, 2014, the Company issued a total of 3,850 unregistered shares of Company common stock to the seven non-employee directors of the Company then serving on the Board of Directors of the Company, 550 shares to each such 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, 2014. These transactions were exempt from registration under Section 4(a)(2) of the Securities Act of 1933, as transactions not involving a public offering.
Issuer Purchases of Equity Securities
 
Period
Total Number
of Shares
Purchased(a)
 
Average Price
Paid per
Share
 
Total Number of
Shares Purchased
as Part of
Publicly Announced
Share Repurchase
Plans or Programs
 
Maximum Number
of Shares that May
Yet Be Purchased Under
Share Repurchase
Plans or
Programs(b)
July 1-31, 2014
195

 
$
72.30

 

 
6,971,019

Aug. 1-31, 2014
11,480

 
$
75.67

 

 
6,971,019

Sept. 1-30, 2014
6,944

 
$
76.30

 

 
6,971,019

Total
18,619

 
$
75.87

 

 
6,971,019

 
 
(a)
Represents shares of common stock of the Company tendered to the Company by holders of stock options, SARs, restricted stock units or shares of restricted stock for the payment of option exercise prices or applicable withholding taxes. During the quarter ended September 30, 2014, the Company did not purchase any shares of its common stock pursuant to its publicly announced share repurchase program.
(b)
In September 2008, the Company’s Board of Directors authorized the repurchase of eight million shares of the Company’s common stock. The repurchase program has no expiration date. The Company, however, stopped repurchasing shares after September 17, 2008. Since that time, the Company has increased its emphasis on Marcellus Shale development and pipeline expansion. As such, the Company does not anticipate repurchasing any shares in the near future.

-27-



Performance Graph
The following graph compares the Company’s common stock performance with the performance of the S&P 500 Index, the PHLX Utility Sector Index and the SIG Oil Exploration & Production Index for the period September 30, 2009 through September 30, 2014. The graph assumes that the value of the investment in the Company’s common stock and in each index was $100 on September 30, 2009 and that all dividends were reinvested.

 
2009
2010
2011
2012
2013
2014
National Fuel
$100
$116
$112
$127
$166
$173
S&P 500 Index
$100
$110
$111
$145
$173
$207
PHLX Utility Sector Index (UTY)
$100
$112
$125
$139
$145
$168
SIG Oil Exploration & Production Index (EPX)
$100
$108
$103
$119
$139
$138
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.

-28-



Item 6
Selected Financial Data
 
Year Ended September 30
 
2014

2013

2012

2011

2010
 
(Thousands, except per share amounts and number of registered shareholders)
Summary of Operations
 
 
 
 
 
 
 
 
 
Operating Revenues
$
2,113,081

 
$
1,829,551

 
$
1,626,853

 
$
1,778,842

 
$
1,760,503

Operating Expenses:
 
 
 
 
 
 
 
 
 
Purchased Gas
605,838

 
460,432

 
415,589

 
628,732

 
658,432

Operation and Maintenance
463,078

 
442,090

 
401,397

 
400,519

 
394,569

Property, Franchise and Other Taxes
90,711

 
82,431

 
90,288

 
81,902

 
75,852

Depreciation, Depletion and Amortization
383,781

 
326,760

 
271,530

 
226,527

 
191,199

 
1,543,408

 
1,311,713

 
1,178,804

 
1,337,680

 
1,320,052

Operating Income
569,673

 
517,838

 
448,049

 
441,162

 
440,451

Other Income (Expense):
 
 
 
 
 
 
 
 
 
Gain on Sale of Unconsolidated Subsidiaries

 

 

 
50,879

 

Other Income
9,461

 
4,697

 
5,133

 
5,947

 
6,126

Interest Income
4,170

 
4,335

 
3,689

 
2,916

 
3,729

Interest Expense on Long-Term Debt
(90,194
)
 
(90,273
)
 
(82,002
)
 
(73,567
)
 
(87,190
)
Other Interest Expense
(4,083
)
 
(3,838
)
 
(4,238
)
 
(4,554
)
 
(6,756
)
Income from Continuing Operations Before Income Taxes
489,027

 
432,759

 
370,631

 
422,783

 
356,360

Income Tax Expense
189,614

 
172,758

 
150,554

 
164,381

 
137,227

Income from Continuing Operations
299,413

 
260,001

 
220,077

 
258,402

 
219,133

Discontinued Operations:
 
 
 
 
 
 
 
 
 
Income from Operations, Net of Tax

 

 

 

 
470

Gain on Disposal, Net of Tax

 

 

 

 
6,310

Income from Discontinued Operations, Net of Tax

 

 

 

 
6,780

Net Income Available for Common Stock
$
299,413

 
$
260,001

 
$
220,077

 
$
258,402

 
$
225,913

Per Common Share Data
 
 
 
 
 
 
 
 
 
Basic Earnings from Continuing Operations per Common Share
$
3.57

 
$
3.11

 
$
2.65

 
$
3.13

 
$
2.70

Diluted Earnings from Continuing Operations per Common Share
$
3.52

 
$
3.08

 
$
2.63

 
$
3.09

 
$
2.65

Basic Earnings per Common Share(1)
$
3.57

 
$
3.11

 
$
2.65

 
$
3.13

 
$
2.78

Diluted Earnings per Common Share(1)
$
3.52

 
$
3.08

 
$
2.63

 
$
3.09

 
$
2.73

Dividends Declared
$
1.52

 
$
1.48

 
$
1.44

 
$
1.40

 
$
1.36

Dividends Paid
$
1.51

 
$
1.47

 
$
1.43

 
$
1.39

 
$
1.35

Dividend Rate at Year-End
$
1.54

 
$
1.50

 
$
1.46

 
$
1.42

 
$
1.38

At September 30:
 
 
 
 
 
 
 
 
 
Number of Registered Shareholders
12,654

 
13,215

 
13,800

 
14,355

 
15,549

 
 
 
 
 
 
 
 
 
 

-29-



 
Year Ended September 30
 
2014

2013

2012

2011

2010
 
(Thousands, except per share amounts and number of registered shareholders)
Net Property, Plant and Equipment
 
 
 
 
 
 
 
 
 
Exploration and Production
$
2,897,744

 
$
2,600,448

 
$
2,273,030

 
$
1,753,194

 
$
1,338,956

Pipeline and Storage
1,187,924

 
1,074,079

 
1,069,070

 
954,554

 
858,231

Gathering
292,793

 
161,111

 
110,269

 
31,962

 
15,585

Utility
1,297,179

 
1,246,943

 
1,217,431

 
1,189,030

 
1,165,240

Energy Marketing
2,070

 
2,002

 
1,530

 
850

 
436

All Other
61,236

 
62,554

 
63,245

 
65,266

 
65,518

Corporate
4,145

 
4,589

 
5,228

 
5,668

 
6,263

Total Net Plant
$
5,743,091

 
$
5,151,726

 
$
4,739,803

 
$
4,000,524

 
$
3,450,229

Total Assets
$
6,739,597

 
$
6,218,347

 
$
5,935,142

 
$
5,221,084

 
$
5,047,054

Capitalization
 
 
 
 
 
 
 
 
 
Comprehensive Shareholders’ Equity
$
2,410,683

 
$
2,194,729

 
$
1,960,095

 
$
1,891,885

 
$
1,745,971

Long-Term Debt, Net of Current Portion
1,649,000

 
1,649,000

 
1,149,000

 
899,000

 
1,049,000

Total Capitalization
$
4,059,683

 
$
3,843,729

 
$
3,109,095

 
$
2,790,885

 
$
2,794,971

 
 
(1)
Includes discontinued operations.

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, distribution and marketing of natural gas. The Company operates an integrated business model centered in western New York and Pennsylvania, an area critical to the production and transportation of natural gas from the Marcellus Shale basin. 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 Marcellus Shale to markets in Canada and the eastern United States. The Company also develops and produces oil reserves, primarily in California. The Company reports financial results for five business segments. Refer to Item 1, Business, for a more detailed description of each of the segments. This Item 7, MD&A, provides information concerning: 
1.
The critical accounting estimates of the Company;
2.
Changes in revenues and earnings of the Company under the heading, “Results of Operations;”
3.
Operating, investing and financing cash flows under the heading “Capital Resources and Liquidity;”
4.
Off-Balance Sheet Arrangements;
5.
Contractual Obligations; and
6.
Other Matters, including: (a) 2014 and projected 2015 funding for the Company’s pension and other post-retirement benefits; (b) disclosures and tables concerning market risk sensitive instruments; (c) rate and regulatory matters in the Company’s New York, Pennsylvania and FERC-regulated jurisdictions; (d) environmental matters; and (e) new authoritative accounting and financial reporting guidance.


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The information in MD&A should be read in conjunction with the Company’s financial statements in Item 8 of this report.

For the year ended September 30, 2014 compared to the year ended September 30, 2013, the Company experienced an increase in earnings of $39.4 million. The earnings increase is primarily due to higher earnings in the Pipeline and Storage segment, Gathering segment, Exploration and Production segment and Energy Marketing segment, slightly offset by lower earnings in the Utility segment and a higher loss in the Corporate category. For further discussion of the Company’s earnings, refer to the Results of Operations section below.
The Company’s natural gas reserve base continues to grow due to its development of reserves in the Marcellus Shale, a Middle Devonian-age geological shale formation that is present nearly a mile or more below the surface in the Appalachian region of the United States, including much of Pennsylvania and southern New York. The Company controls the natural gas interests associated with approximately 780,000 net acres within the Marcellus Shale area, with a majority of the interests held in fee, carrying no royalty and no lease expirations. Natural gas proved developed and undeveloped reserves in the Appalachian region increased from 1,239 Bcf at September 30, 2013 to 1,624 Bcf at September 30, 2014. The Company has spent significant amounts of capital in this region related to the development of such reserves. For the year ended September 30, 2014, the Company’s Exploration and Production segment had capital expenditures of $519.9 million in the Appalachian region, of which $502.9 million was spent towards the development of the Marcellus Shale. The amount spent towards the development of the Marcellus Shale represented approximately 52% of the Company's capital expenditures for the year ended September 30, 2014. The Company’s fiscal 2015 estimated capital expenditures in the Exploration and Production segment’s Appalachian region are expected to be approximately $585 million. Forecasted production in the Exploration and Production segment’s Appalachian region for fiscal 2015 is expected to be in the range of 159 to 197 Bcfe, up from actual Appalachia production of 139 Bcfe in fiscal 2014.
To facilitate the flow of natural gas from the Marcellus Shale, the Company continues to expand its gathering and pipeline infrastructure in the Gathering segment and the Pipeline and Storage segment. For the year ended September 30, 2014, the Gathering segment had capital expenditures of $137.8 million and its estimated capital expenditures in fiscal 2015 are expected to be approximately $175 million. The Pipeline and Storage segment's capital expenditures for the year ended September 30, 2014 were $139.8 million and its estimated capital expenditures in fiscal 2015 are expected to be approximately $250 million. The amount spent towards the development of gathering and pipeline infrastructure in fiscal 2014 represented approximately 29% of the Company's capital expenditures.
From a capital resources perspective, the Company has largely been able to meet its capital expenditure needs by using cash from operations as well as both short and long-term debt.  It is expected that the Company will issue short-term and long-term debt as necessary during fiscal 2015 to help meet its capital expenditure needs. 
The well completion technology referred to as hydraulic fracturing used in conjunction with horizontal drilling continues to be debated. In Pennsylvania, where the Company is focusing its Marcellus Shale development efforts, the permitting and regulatory processes seem to strike a balance between the environmental concerns associated with hydraulic fracturing and the benefits of increased natural gas production. The potential for increased state or federal regulation of hydraulic fracturing could impact future costs of drilling in the Marcellus Shale and lead to operational delays or restrictions. There is also the risk that drilling could be prohibited on certain acreage that is prospective for the Marcellus Shale. Please refer to the Risk Factors section above for further discussion.
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

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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, oil and gas property acquisition, exploration and development costs are capitalized under the full cost method of accounting. Under this accounting methodology, all costs associated with property acquisition, exploration and development activities are capitalized, including internal costs directly identified with acquisition, exploration and development activities. The internal costs that are capitalized do not include any costs related to production, general corporate overhead, or similar activities. The Company does not recognize any gain or loss on the sale or other disposition of oil and gas properties unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of oil and gas attributable to a cost center.
Proved reserves are estimated quantities of reserves that, based on geologic and engineering data, appear with reasonable certainty to be producible under existing economic and operating conditions. Such estimates of proved reserves are inherently imprecise and may be subject to substantial revisions as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. The estimates involved in determining proved reserves are critical accounting estimates because they serve as the basis over which capitalized costs are depleted under the full cost method of accounting (on a units-of-production basis). Unproved properties are excluded from the depletion calculation until proved reserves are found or it is determined that the unproved properties are impaired. All costs related to unproved properties are reviewed quarterly to determine if impairment has occurred. The amount of any impairment is transferred to the pool of capitalized costs being amortized.
In addition to depletion under the units-of-production method, proved reserves are a major component in the SEC full cost ceiling test. The full cost ceiling test is an impairment test prescribed by SEC Regulation S-X Rule 4-10. The ceiling test, which is performed each quarter, determines a limit, or ceiling, on the amount of property acquisition, exploration and development costs that can be capitalized. The ceiling under this test represents (a) the present value of estimated future net cash flows, excluding future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, using a discount factor of 10%, which is computed by applying an unweighted arithmetic average of the first day of the month oil and gas prices for each month within the twelve-month period prior to the end of the reporting period (as adjusted for hedging) to estimated future production of proved oil and gas reserves as of the date of the latest balance sheet, less estimated future expenditures, plus (b) the cost of unevaluated properties not being depleted, less (c) income tax effects related to the differences between the book and tax basis of the properties. The estimates of future production and future expenditures are based on internal budgets that reflect planned production from current wells and expenditures necessary to sustain such future production. The amount of the ceiling can fluctuate significantly from period to period because of additions to or subtractions from proved reserves and significant fluctuations in oil and 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, 2014, the ceiling exceeded the book value of the Company’s oil and gas properties by approximately $148.4 million. The 12-month average of the first day of the month price for crude oil for each month during 2014, based on posted Midway Sunset prices, was $97.30 per Bbl. The 12-month average of the first day of the month price for natural gas for each month during 2014, based on the quoted Henry Hub spot price for natural gas, was $4.24 per MMBtu. (Note — Because actual pricing of the Company’s various producing properties varies depending on their location and hedging, the actual various prices received for such production is utilized to calculate the ceiling, rather than the Midway Sunset and Henry Hub prices, which are only indicative of 12-month average prices for 2014.) If natural gas average prices used in the ceiling test calculation at September 30, 2014 had been $1 per MMBtu lower, the book value of the Company’s oil and gas properties would have exceeded the ceiling by approximately $254.2 million, which would have resulted in an impairment charge. If crude oil average prices used in the ceiling test calculation at September 30, 2014 had been $5 per Bbl lower, the ceiling

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would have exceeded the book value of the Company’s oil and gas properties by approximately $106.8 million which would not have resulted in an impairment charge. If both natural gas and crude oil average prices used in the ceiling test calculation at September 30, 2014 were lower by $1 per MMBtu and $5 per Bbl, respectively, the book value of the Company’s oil and gas properties would have exceeded the ceiling by approximately $295.9 million, which would have resulted in an impairment charge. These calculated amounts are based solely on price changes and do not take into account any other changes to the ceiling test calculation.
It is difficult to predict what factors could lead to future impairments under the SEC’s full cost ceiling test. As discussed above, fluctuations in or subtractions from proved reserves and significant fluctuations in oil and gas prices have an impact on the amount of the ceiling at any point in time.
In accordance with the current authoritative guidance for asset retirement obligations, the Company records an asset retirement obligation for plugging and abandonment costs associated with the Exploration and Production segment’s crude oil and natural gas wells and capitalizes such costs in property, plant and equipment (i.e. the full cost pool). Under the current authoritative guidance for asset retirement obligations, since plugging and abandonment costs are already included in the full cost pool, the units-of-production depletion calculation excludes from the depletion base any estimate of future plugging and abandonment costs that are already recorded in the full cost pool.
As discussed above, the full cost method of accounting provides a ceiling to the amount of costs that can be capitalized in the full cost pool. In accordance with current authoritative guidance, the future cash outflows associated with plugging and abandoning wells are excluded from the computation of the present value of estimated future net revenues for purposes of the full cost ceiling calculation.
Regulation.    The Company is subject to regulation by certain state and federal authorities. The Company, in its Utility and Pipeline and Storage segments, has accounting policies which conform to the FASB authoritative guidance regarding accounting for certain types of regulations, and which are in accordance with the accounting requirements and ratemaking practices of the regulatory authorities. The application of these accounting principles for certain types of rate-regulated activities provide that certain actual or anticipated costs that would otherwise be charged to expense can be deferred as regulatory assets, based on the expected recovery from customers in future rates. Likewise, certain actual or anticipated credits that would otherwise reduce expense can be deferred as regulatory liabilities, based on the expected flowback to customers in future rates. Management’s assessment of the probability of recovery or pass through of regulatory assets and liabilities requires judgment and interpretation of laws and regulatory commission orders. If, for any reason, the Company ceases to meet the criteria for application of regulatory accounting treatment for all or part of its operations, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the balance sheet and included in the income statement for the period in which the discontinuance of regulatory accounting treatment occurs. Such amounts would be classified as an extraordinary item. For further discussion of the Company’s regulatory assets and liabilities, refer to Item 8 at Note C — Regulatory Matters.
Accounting for Derivative Financial Instruments.    The Company uses a variety of derivative financial instruments to manage a portion of the market risk associated with fluctuations in the price of natural gas and crude oil in its Exploration and Production and Energy Marketing segments. These instruments are categorized as price swap agreements and futures contracts. In accordance with the authoritative guidance for derivative instruments and hedging activities, the Company primarily accounts for these instruments as effective cash flow hedges or fair value hedges. Gains or losses associated with the derivative financial instruments that are accounted for as cash flow or fair value hedges are matched with gains or losses resulting from the underlying physical transaction that is being hedged. To the extent that such derivative financial instruments would ever be deemed to be ineffective based on effectiveness testing, mark-to-market gains or losses from such derivative financial instruments would be recognized in the income statement without regard to an underlying physical transaction. Refer to the “Market Risk Sensitive Instruments” section below for further discussion of the Company’s derivative financial instruments and refer to Item 8 at Note F— Fair Value Measurements for discussion of the determination of fair value for derivative financial instruments.
Pension and Other Post-Retirement Benefits.    The amounts reported in the Company’s financial statements related to its pension and other post-retirement benefits are determined on an actuarial basis, which uses many

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assumptions in the calculation of such amounts. These assumptions include the discount rate, the expected return on plan assets, the rate of compensation increase and, for other post-retirement benefits, the expected annual rate of increase in per capita cost of covered medical and prescription benefits. The Company utilizes the Mercer Yield Curve Above Mean Model to determine the discount rate. The yield curve is a spot rate yield curve that provides a zero-coupon interest rate for each year into the future. Each year’s anticipated benefit payments are discounted at the associated spot interest rate back to the measurement date. The discount rate is then determined based on the spot interest rate that results in the same present value when applied to the same anticipated benefit payments. In determining the spot rates, the model will exclude coupon interest rates that are in the lower 50th percentile based on the assumption that the Company would not utilize more expensive (i.e. lower yield) instruments to settle its liabilities. The expected return on plan assets assumption used by the Company reflects the anticipated long-term rate of return on the plan’s current and future assets. The Company utilizes historical investment data, projected capital market conditions, and the plan’s target asset class and investment manager allocations to set the assumption regarding the expected return on plan assets. Changes in actuarial assumptions and actuarial experience, including deviations between actual versus expected return on plan assets, could have a material impact on the amount of pension and post-retirement benefit costs and funding requirements experienced by the Company. However, the Company expects to recover a substantial portion of its net periodic pension and other post-retirement benefit costs attributable to employees in its Utility and Pipeline and Storage segments in accordance with the applicable regulatory commission authorization, subject to applicable accounting requirements for rate-regulated activities, as discussed above under “Regulation.”
Changes in actuarial assumptions and actuarial experience could also have an impact on the benefit obligation and the funded status related to the Company’s pension and other post-retirement benefits and could impact the Company’s equity. For example, the discount rate was changed from 4.75% in 2013 to 4.25% in 2014. The change in the discount rate from 2013 to 2014 increased the Retirement Plan projected benefit obligation by $53.7 million and the accumulated post-retirement benefit obligation by $26.4 million. Other examples include actual versus expected return on plan assets, which has an impact on the funded status of the plans, and actual versus expected benefit payments, which has an impact on the pension plan projected benefit obligation and the accumulated post-retirement benefit obligation. For 2014, the actual return on plan assets exceeded the expected return, which improved the funded status of the Retirement Plan ($33.3 million) as well as the VEBA trusts and 401(h) accounts ($7.5 million). The actual versus expected benefit payments for 2014 caused a decrease of $3.7 million to the accumulated post-retirement benefit obligation. In calculating the projected benefit obligation for the Retirement Plan and the accumulated post-retirement obligation, the actuary takes into account the average remaining service life of active participants. The average remaining service life of active participants is 7 years for the Retirement Plan and 6 years for those eligible for other post-retirement benefits. For further discussion of the Company’s pension and other post-retirement benefits, refer to Other Matters in this Item 7, which includes a discussion of funding for the current year, and to Item 8 at Note H — Retirement Plan and Other Post Retirement Benefits.

RESULTS OF OPERATIONS
EARNINGS
2014 Compared with 2013
The Company’s earnings were $299.4 million in 2014 compared with earnings of $260.0 million in 2013. The increase in earnings of $39.4 million is primarily a result of higher earnings in the Exploration and Production segment, Pipeline and Storage segment, Gathering segment and Energy Marketing segment. Lower earnings in the Utility segment and a higher loss in the Corporate category slightly offset these increases. 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 2014 and 2013:
2014 Event
 
A $3.6 million death benefit gain on life insurance proceeds recorded in the Corporate category.

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2013 Event
 
A $4.9 million refund provision recorded in the Utility segment related to various issues raised in Distribution Corporation’s rate proceeding in New York.
2013 Compared with 2012
The Company’s earnings were $260.0 million in 2013 compared with earnings of $220.1 million in 2012. The increase in earnings of $39.9 million is the result of higher earnings in all segments. Higher earnings in the All Other category and a lower loss in the Corporate category also contributed to the increase in earnings. Earnings were impacted by the 2013 event discussed above and the following events in 2012:
2012 Events
 
The elimination of Supply Corporation’s other post-retirement regulatory liability of $12.8 million recorded in the Pipeline and Storage segment, as specified by Supply Corporation’s rate case settlement; and
A natural gas impact fee imposed by the Commonwealth of Pennsylvania in 2012 on the drilling of wells in the Marcellus Shale by the Exploration and Production segment. This fee included $4.0 million related to wells drilled prior to 2012.
Earnings (Loss) by Segment
 
 
Year Ended September 30
 
2014
 
2013
 
2012
 
(Thousands)
Exploration and Production
$
121,569

 
$
115,391

 
$
96,498

Pipeline and Storage
77,559

 
63,245

 
60,527

Gathering
32,709

 
13,321

 
6,855

Utility
64,059

 
65,686

 
58,590

Energy Marketing
6,631

 
4,589

 
4,169

Total Reported Segments
302,527

 
262,232

 
226,639

All Other
1,160

 
894

 
13

Corporate
(4,274
)
 
(3,125
)
 
(6,575
)
Total Consolidated
$
299,413

 
$
260,001

 
$
220,077

EXPLORATION AND PRODUCTION
Revenues
Exploration and Production Operating Revenues
 
 
Year Ended September 30
 
2014
 
2013
 
2012
 
(Thousands)
Gas (after Hedging)
$
506,491

 
$
424,735

 
$
292,311

Oil (after Hedging)
290,030

 
278,005

 
260,844

Gas Processing Plant
4,831

 
4,502

 
4,813

Other
2,744

 
(4,305
)
 
212

Operating Revenues
$
804,096

 
$
702,937

 
$
558,180



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Production
 
 
Year Ended September 30
 
2014
 
2013
 
2012
Gas Production (MMcf)
 
 
 
 
 
Appalachia
139,097

 
100,633

 
62,663

West Coast
3,210

 
3,060

 
3,468

Total Production
142,307

 
103,693

 
66,131

Oil Production (Mbbl)
 
 
 
 
 
Appalachia
31

 
28

 
36

West Coast
3,005

 
2,803

 
2,834

Total Production
3,036

 
2,831

 
2,870

Average Prices
 
 
Year Ended September 30
 
2014
 
2013
 
2012
Average Gas Price/Mcf
 
 
 
 
 
Appalachia
$
3.55

 
$
3.49

 
$
2.71

West Coast
$
6.75

 
$
6.61

 
$
6.27

Weighted Average
$
3.62

 
$
3.58

 
$
2.89

Weighted Average After Hedging(1)
$
3.56

 
$
4.10

 
$
4.42

Average Oil Price/Barrel (bbl)
 
 
 
 
 
Appalachia
$
96.34

 
$
96.48

 
$
93.94

West Coast
$
98.25

 
$
103.14

 
$
107.13

Weighted Average
$
98.23

 
$
103.07

 
$
106.97

Weighted Average After Hedging(1)
$
95.55

 
$
98.21

 
$
90.88

 
 
(1)
Refer to further discussion of hedging activities below under “Market Risk Sensitive Instruments” and in Note G — Financial Instruments in Item 8 of this report.
2014 Compared with 2013
Operating revenues for the Exploration and Production segment increased $101.2 million in 2014 as compared with 2013. Gas production revenue after hedging increased $81.8 million primarily due to production increases in the Appalachian division. The increase in Appalachian production was primarily due to increased development within the Marcellus Shale formation, primarily in Lycoming County, Pennsylvania. This was partially offset by a $0.54 per Mcf decrease in the weighted average price of gas after hedging. Oil production revenue after hedging increased $12.0 million due to an increase in production, which was partially offset by a $2.66 per Bbl decrease in the weighted average price of oil after hedging. The increase in crude oil production was largely due to increased development in the East Coalinga, Sespe and South Midway Sunset fields in California. The increase in other revenue ($7.0 million) was largely due to a $3.6 million positive variance in mark-to-market charges related to hedging ineffectiveness, settlement proceeds received in 2014 related to former insurance policies ($1.9 million) and the non-recurrence of a royalty adjustment (including interest) recorded in 2013 ($1.8 million).

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.

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2013 Compared with 2012
Operating revenues for the Exploration and Production segment increased $144.8 million in 2013 as compared with 2012. Gas production revenue after hedging increased $132.4 million primarily due to production increases in the Appalachian division. The increase in Appalachian production was primarily due to increased development within the Marcellus Shale formation, primarily in Lycoming County, Pennsylvania. This was partially offset by a $0.32 per Mcf decrease in the weighted average price of gas after hedging. Oil production revenue after hedging increased $17.2 million due to an increase in the weighted average price of oil after hedging ($7.33 per Bbl). Oil production was slightly lower year over year, largely the result of a continued constraint in a third-party pipeline used to transport natural gas production within the Sespe Field. The constraint on natural gas transportation capacity impacts oil production in that natural gas is a byproduct of the Exploration and Production segment’s oil production at the Sespe Field. The decrease in other revenue ($4.5 million) was largely due to a $3.7 million mark-to-market charge related to hedging ineffectiveness.
Earnings
2014 Compared with 2013
The Exploration and Production segment’s earnings for 2014 were $121.6 million, compared with earnings of $115.4 million for 2013, an increase of $6.2 million. The main drivers of the increase were higher natural gas production ($102.8 million), higher crude oil production ($13.1 million) and lower income taxes ($11.2 million). In addition, the earnings impact of the increase in other revenues ($4.6 million) also contributed to the increase in earnings, as discussed above. The decrease in income taxes was largely due to an increase in firm transportation of natural gas to Canadian delivery points, which decreased the effective tax rate used in the calculation of deferred tax expense. These earnings increases were partially offset by the earnings impact of higher depletion expense ($34.3 million), lower natural gas prices after hedging ($49.7 million), higher production costs ($30.1 million), higher general, administrative and other expense ($2.7 million), higher interest expense ($1.6 million), higher property and other taxes ($2.3 million) and lower crude oil prices after hedging ($5.3 million). The increase in depletion expense is primarily due to increased Appalachian natural gas production (primarily in the Marcellus Shale formation). The increase in production costs was largely attributable to higher transportation costs. The increase in general, administrative and other expense was largely due to an increase in personnel costs and the accrual of plugging and abandonment costs associated with offshore properties no longer owned by the Exploration and Production segment. The increase in interest expense was attributable to an increase in the weighted average amount of debt due to the Exploration and Production segment’s share of the Company’s $500 million long-term debt issuance in February 2013.
2013 Compared with 2012
The Exploration and Production segment’s earnings for 2013 were $115.4 million, compared with earnings of $96.5 million for 2012, an increase of $18.9 million. The main drivers of the increase were higher natural gas production ($107.9 million) and higher crude oil prices after hedging ($13.5 million). In addition, there was a decrease in property and other taxes ($4.2 million) which largely reflects the non-recurrence of a $4.0 million natural gas impact fee accrual recorded during the quarter ended March 31, 2012 related to Marcellus Shale wells drilled prior to fiscal 2012. These earnings increases were partially offset by the earnings impact of higher depletion expense ($36.3 million), lower natural gas prices after hedging ($21.8 million), higher production costs ($23.3 million), higher general, administrative and other expense ($9.0 million), higher interest expense ($6.8 million), higher income taxes ($4.0 million), a derivative mark-to-market charge ($2.7 million) and lower crude oil production ($2.3 million). The increase in depletion expense is primarily due to increased Appalachian natural gas production (primarily in the Marcellus Shale formation). The increase in production costs was largely attributable to higher transportation costs resulting from higher production. In addition, compression and water disposal costs in the Appalachian region coupled with higher well repair, maintenance and labor costs in the West Coast region led to further increases in production costs. The increase in general, administrative and other expense was largely due to an increase in personnel costs. The increase in interest expense was attributable to an increase in the weighted average amount of debt due to the Exploration and Production segment’s share of both the Company’s $500 million long-term debt issuance in February 2013 and the Company’s $500 million long-term debt issuance in December 2011. The increase in income tax expense is largely attributable to higher state income taxes.

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PIPELINE AND STORAGE
Revenues
Pipeline and Storage Operating Revenues
 
 
Year Ended September 30
 
2014
 
2013
 
2012
 
(Thousands)
Firm Transportation
$
207,892

 
$
190,470

 
$
164,652

Interruptible Transportation
2,666

 
2,152

 
1,431

 
210,558

 
192,622

 
166,083

Firm Storage Service
69,878

 
70,555

 
67,929

Interruptible Storage Service
13

 
5

 
7

 
69,891

 
70,560

 
67,936

Other
3,959

 
4,426

 
25,256

 
$
284,408

 
$
267,608

 
$
259,275

Pipeline and Storage Throughput — (MMcf)
 
 
Year Ended September 30
 
2014
 
2013
 
2012
Firm Transportation
731,271

 
575,805

 
369,477

Interruptible Transportation
4,724

 
3,997

 
1,662

 
735,995

 
579,802

 
371,139

2014 Compared with 2013
Operating revenues for the Pipeline and Storage segment increased $16.8 million in 2014 as compared with 2013. The increase was primarily due to an increase in transportation revenues of $17.9 million slightly offset by a decrease in storage revenues of $0.7 million.  The increase in transportation revenues was largely due to demand and commodity charges on new contracts for transportation service on Supply Corporation’s Northern Access expansion project, which was placed fully in service in January 2013, Supply Corporation’s Line N 2012 Expansion Project, which was placed fully in service in November 2012 and Supply Corporation's Line N 2013 Project, which was placed in service in November 2013. In addition, the increase in transportation revenues was due to additional demand charges associated with the full-ramp up of a transportation contract for an anchor shipper on Empire's Tioga County Extension Project as well as additional commodity charges associated with that contract due to higher throughput flowing through a secondary receipt point. These projects provide pipeline capacity for Marcellus Shale production.    Also contributing to the increase in transportation revenues was additional non-expansion revenue as a result of new short-term contracts for both Empire and Supply Corporation and new contracts for transportation service from an Open Season Supply Corporation held near the end of fiscal 2013. Partially offsetting these increases was a decrease in storage revenues due to a decline in demand charges as a result of contract restructuring.
Transportation volume increased by 156.2 Bcf in 2014 as compared with 2013. The large increase in transportation volume primarily reflects the impact of the above mentioned expansion projects being placed in service and new contracts for transportation service.  The increase was enhanced by weather that was significantly colder than the prior year and colder than normal. 


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2013 Compared with 2012
Operating revenues for the Pipeline and Storage segment increased $8.3 million in 2013 as compared with 2012. The increase was primarily due to an increase in transportation revenues of $26.5 million and an increase in storage revenues of $2.6 million. The increase in transportation revenues was largely due to demand charges on new contracts for transportation service on Supply Corporation’s Line N 2012 Expansion Project, which was placed fully in service in November 2012, and Supply Corporation’s Northern Access expansion project, which was placed fully in service in January 2013. These projects provide pipeline capacity for Marcellus Shale production. Additionally, effective May 2012, both transportation and storage revenues increased due to an overall net increase in tariff rates as a result of the implementation of Supply Corporation’s rate case settlement which was approved by FERC on August 6, 2012. Partially offsetting these increases was a decrease in other operating revenues. Other operating revenues in fiscal 2012 included the impact of Supply Corporation’s elimination of a $21.7 million regulatory liability associated with post-retirement benefits. The elimination of the regulatory liability was specified in Supply Corporation’s rate case settlement.
Transportation volume increased by 208.7 Bcf in 2013 as compared with 2012. The large increase in transportation volume primarily reflects the impact of the above mentioned expansion projects being placed in service.
Earnings
2014 Compared with 2013
The Pipeline and Storage segment’s earnings in 2014 were $77.6 million, an increase of $14.4 million when compared with earnings of $63.2 million in 2013. The increase in earnings is primarily due to the earnings impact of higher transportation revenues of $11.7 million, as discussed above, combined with lower operating expenses ($6.3 million). The decrease in operating expenses primarily reflects lower pension and other post-retirement benefit costs and a decrease in the reserve for preliminary project costs offset partially by higher pipeline integrity program expenses.  These earnings increases were partially offset by an increase in depreciation expense ($1.0 million), higher property taxes ($0.9 million), a decrease in the allowance for funds used during construction (equity component) of $0.4 million, higher income taxes ($0.5 million) and the earnings impact of lower storage revenue ($0.4 million), as discussed above.  The increase in depreciation expense is attributable to incremental depreciation expense related to the projects that were placed in service within the last year. The increase in property taxes is primarily due to the addition of new plant. The decrease in the allowance for funds used during construction is mainly due to Supply Corporation’s Line N 2012 Expansion Project and Supply Corporation’s Northern Access expansion project, which remained under construction in the first quarter of the prior year and have since been placed in service. The increase in income taxes is a result of higher state taxes combined with a reduction in benefits associated with the tax sharing agreement with affiliated companies.
2013 Compared with 2012
The Pipeline and Storage segment’s earnings in 2013 were $63.2 million, an increase of $2.7 million when compared with earnings of $60.5 million in 2012. The increase in earnings is primarily due to the earnings impact of higher transportation and storage revenues of $19.0 million, as discussed above, combined with a decrease in depreciation expense ($2.0 million). The decrease in depreciation expense primarily reflects a decrease in depreciation rates as specified in Supply Corporation’s rate case settlement offset partly by incremental depreciation expense related to the projects that were placed in service within the last year. Partially offsetting these increases was the non-recurrence of the fiscal 2012 elimination of Supply Corporation’s post-retirement regulatory liability ($12.8 million), as discussed above. The earnings increases were also partially offset by higher operating expenses ($2.6 million), a decrease in the allowance for funds used during construction (equity component) of $1.4 million, higher property taxes ($0.5 million), higher interest expense ($0.4 million) and higher income taxes ($1.0 million). The increase in operating expenses can be attributed primarily to higher pension expense and an increase in compressor station costs, offset partly by lower post-retirement benefit costs. The decrease in the allowance for funds used during construction is mainly due to Supply Corporation’s Line N 2012 Expansion Project and Supply Corporation’s Northern Access expansion project, which were under construction in the prior year and were placed

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in service during fiscal 2013, and Empire’s Tioga County Expansion Project, which remained under construction during a portion of the first quarter of fiscal 2012 before being placed in service in November 2011. The increase in property taxes was primarily a result of a higher tax base due to capital additions. Increased intercompany borrowings contributed to the increase in interest expense. The increase in income taxes is a result of a favorable federal return to provision adjustment in 2012 that did not recur in the current year combined with a reduced benefit associated with the allowance for funds used during construction.
GATHERING
Revenues
Gathering Operating Revenues
 
 
Year Ended September 30
 
2014
 
2013
 
2012
 
(Thousands)
Gathering
$
69,937

 
$
33,815

 
$
16,771

Processing and Other Revenues
673

 
966

 
704

 
$
70,610

 
$
34,781

 
$
17,475

Gathering Volume — (MMcf)
 
 
Year Ended September 30
 
2014
 
2013
 
2012
Gathered Volume
138,726

 
93,449

 
48,562

2014 Compared with 2013
Operating revenues for the Gathering segment increased $35.8 million in 2014 as compared with 2013. This increase was largely due to an increase in gathering revenues driven by a 45.3 Bcf increase in gathered volume combined with higher gathering rates.  The overall increase in gathered volume was largely due to a 40.7 Bcf increase in gathered volume on Midstream Corporation’s Trout Run Gathering System (Trout Run) and a 4.5 Bcf increase in gathered volume on Midstream Corporation’s Clermont Gathering System (Clermont). Most of the increase in gathered volume is attributable to an increase in Seneca's Marcellus Shale production, primarily in Lycoming County, Pennsylvania.
2013 Compared with 2012
Operating revenues for the Gathering segment increased $17.3 million in 2013 as compared with 2012 largely due to an increase in gathering revenues driven by a 44.9 Bcf increase in gathered volume. This increase was primarily due to Trout Run which was placed in service in May 2012 and the expansion of Midstream Corporation’s Covington Gathering System (Covington). Trout Run and Covington provide gathering services for Seneca’s production.
Earnings
2014 Compared with 2013
The Gathering segment’s earnings in 2014 were $32.7 million, an increase of $19.4 million when compared with earnings of $13.3 million in 2013.  The increase in earnings is mainly due to the earnings impact of higher gathering revenues ($23.5 million) and lower interest expense ($0.4 million).  These earnings increases were partially offset by higher income tax expense ($1.9 million), higher depreciation expense ($1.4 million) and higher operating expenses ($1.0 million).  The significant growth of Trout Run is primarily responsible for the revenue, depreciation expense and operating expense variations.  The increase in income tax expense was largely due to higher state taxes. The decrease in interest expense is largely due to an increase in capitalized interest, which more

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than offset the impact of an increase in the weighted average amount of debt due to the Gathering segment’s share of the $500 million long-term debt issuance in February 2013.
2013 Compared with 2012
The Gathering segment’s earnings in 2013 were $13.3 million, an increase of $6.4 million when compared with earnings of $6.9 million in 2012. The increase in earnings is due to higher gathering and processing revenues ($11.2 million). This was partially offset by higher operating expenses ($1.5 million), higher depreciation expense ($1.5 million), higher income tax expense ($1.3 million), and higher interest expense ($0.5 million). The completion of Trout Run and the expansion of Covington are primarily responsible for the revenue, operating expense and depreciation expense variations. The increase in income tax expense was largely due to higher state taxes and a true-up adjustment related to the filed federal return. The increase in interest expense was due to an increase in the weighted average amount of debt due to the Gathering segment’s share of both the Company’s $500 million long-term debt issuance in February 2013 and the Company’s $500 million long-term debt issuance in December 2011.
UTILITY
Revenues
Utility Operating Revenues
 
 
Year Ended September 30
 
2014
 
2013
 
2012
 
(Thousands)
Retail Revenues:
 
 
 
 
 
Residential
$
590,080

 
$
513,654

 
$
493,354

Commercial
78,036

 
66,602

 
61,314

Industrial
3,692

 
6,096

 
5,359

 
671,808

 
586,352

 
560,027

Off-System Sales
19,712

 
25,020

 
27,010

Transportation
150,158

 
135,273

 
122,316

Other
7,940

 
(306
)
 
9,769

 
$
849,618

 
$
746,339

 
$
719,122

Utility Throughput — million cubic feet (MMcf)
 
 
Year Ended September 30
 
2014
 
2013
 
2012
Retail Sales:
 
 
 
 
 
Residential
60,101

 
52,753

 
47,036

Commercial
8,834

 
7,486

 
6,682

Industrial
393

 
947

 
837

 
69,328

 
61,186

 
54,555

Off-System Sales
4,564

 
6,717

 
9,544

Transportation
80,949

 
69,149

 
61,027

 
154,841

 
137,052

 
125,126


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Degree Days
 
 
 
 
 
 
 
 
Percent (Warmer)
Colder Than
Year Ended September 30
 
 
Normal
 
Actual
 
Normal
 
Prior
Year
2014(1)
Buffalo
 
6,617

 
7,087

 
7.1
 %
 
15.4
 %
 
Erie
 
6,147

 
6,742

 
9.7
 %
 
14.5
 %
2013(2)
Buffalo
 
6,617

 
6,139

 
(7.2
)%
 
15.9
 %
 
Erie
 
6,147

 
5,888

 
(4.2
)%
 
17.8
 %
2012(3)
Buffalo
 
6,729

 
5,296

 
(21.3
)%
 
(21.6
)%
 
Erie
 
6,277

 
4,999

 
(20.4
)%
 
(21.4
)%
 
 
(1)
Percents compare actual 2014 degree days to normal degree days and actual 2014 degree days to actual 2013 degree days.
(2)
Percents compare actual 2013 degree days to normal degree days and actual 2013 degree days to actual 2012 degree days. Normal degree days for 2013 reflect a revision from the National Oceanic and Atmospheric Administration.
(3)
Percents compare actual 2012 degree days to normal degree days and actual 2012 degree days to actual 2011 degree days. Normal degree days for 2012 reflect the fact that 2012 was a leap year.

2014 Compared with 2013
Operating revenues for the Utility segment increased $103.3 million in 2014 compared with 2013. This increase largely resulted from an $85.5 million increase in retail gas sales revenues and a $14.9 million increase in transportation revenue. In addition, there was an $8.2 million increase in other operating revenues. These were partially offset by a $5.3 million decrease in off-system sales (due to lower volume). The decrease in off-system sales volume was due to the Utility segment’s greater utilization of pipeline capacity in order to reliably meet the increased demand for its retail gas brought on by colder weather experienced during the winter of the current year. Due to profit sharing with retail customers, the margins resulting from off-system sales are minimal.
The $85.5 million increase in retail gas sales revenues was largely a function of higher volume (8.1 Bcf) due to colder weather. The $14.9 million increase in transportation revenues was primarily due to an 11.8 Bcf increase in transportation throughput, largely the result of colder weather compared to the prior period and the migration of customers from retail sales to transportation services. The $8.2 million increase in other operating revenues was largely due to the non-recurrence of a $7.5 million refund provision recorded during fiscal 2013 related to various issues raised in a New York rate proceeding. During 2014, the Utility segment recorded an earnings share adjustment pursuant to the settlement resulting from that rate proceeding ($2.5 million reduction to revenues). However, this was largely offset by a 2014 true-up of regulatory asset balances associated with insurance proceeds on site remediation claims ($2.3 million).
2013 Compared with 2012
Operating revenues for the Utility segment increased $27.2 million in 2013 compared with 2012. This increase largely resulted from a $26.3 million increase in retail gas sales revenues and a $13.0 million increase in transportation revenue. These were partially offset by a $10.1 million decrease in other operating revenues and a $2.0 million decrease in off-system sales (due to lower volume). Due to profit sharing with retail customers, the margins resulting from off-system sales are minimal.
The $26.3 million increase in retail gas sales revenues was largely a function of higher volume (6.6 Bcf) due to colder weather. The $13.0 million increase in transportation revenues was primarily due to an 8.1 Bcf increase in transportation throughput, largely the result of colder weather compared to the prior period and the migration of customers from retail sales to transportation services. The $10.1 million decrease in other operating revenues was largely due to a $7.5 million refund provision recorded during fiscal 2013 related to various issues raised in

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a New York rate proceeding combined with a downward adjustment in the carrying value of certain regulatory assets during the fourth quarter of fiscal 2013. In addition, a decline in capacity release revenues led to a decline in other revenues. As a result of the unusually warm winter during fiscal 2012, the demand for capacity release volume decreased as contracts for Distribution Corporation’s fiscal 2013 capacity were being executed, which led to a decrease in the capacity release rates and revenues.
Purchased Gas
The cost of purchased gas is the Company’s single largest operating expense. 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 $446.9 million, $362.3 million and $340.3 million of Purchased Gas expense during 2014, 2013 and 2012, respectively. Under its purchased gas adjustment clauses in New York and Pennsylvania, Distribution Corporation is not allowed to profit from fluctuations in gas costs. Purchased gas expense recorded on the consolidated income statement matches the revenues collected from customers, a component of Operating Revenues on the consolidated income statement. Under mechanisms approved by the NYPSC in New York and the PaPUC in Pennsylvania, any difference between actual purchased gas costs and what has been collected from the customer is deferred on the consolidated balance sheet as either an asset, Unrecovered Purchased Gas Costs, or a liability, Amounts Payable to Customers. These deferrals are subsequently collected from the customer or passed back to the customer, subject to review by the NYPSC and the PaPUC. Absent disallowance of full recovery of Distribution Corporation’s purchased gas costs, such costs do not impact the profitability of the Company. Purchased gas costs impact cash flow from operations due to the timing of recovery of such costs versus the actual purchased gas costs incurred during a particular period. Distribution Corporation’s purchased gas adjustment clauses seek to mitigate this impact by adjusting revenues on either a quarterly or monthly basis.
Currently, Distribution Corporation has contracted for long-term firm transportation capacity with Supply Corporation, Empire and seven other upstream pipeline companies, for long-term gas supplies with a combination of producers and marketers, and for storage service with Supply Corporation and two nonaffiliated companies. In addition, Distribution Corporation satisfies a portion of its gas requirements through spot market purchases. Additional discussion of the Utility segment’s gas purchases appears under the heading “Sources and Availability of Raw Materials” in Item 1.
Earnings
2014 Compared with 2013
The Utility segment’s earnings in 2014 were $64.1 million, a decrease of $1.6 million when compared with earnings of $65.7 million in 2013. The decrease in earnings is largely attributable to an increase in operating expenses ($9.1 million), an increase in income tax expense ($2.4 million), the impact of an earnings sharing adjustment ($1.6 million) and an increase in property and other taxes ($0.8 million). The increase in operating expenses is largely attributable to increased costs associated with defined benefit and defined contribution retirement plans as a result of a recent settlement with the NYPSC and an increase in bad debt expense. The increase in income tax expense is largely due to higher state income taxes and the reversal of tax expense that occurred in 2013 (as a result of a favorable tax settlement), which did not recur in 2014. The increase in property and other taxes is largely due to increases in FICA, school, town and county taxes. These earnings decreases were partially offset by the impact of colder weather in Pennsylvania ($5.8 million), the positive earnings impact of the non-recurrence of the refund provision recorded in fiscal 2013 ($4.9 million), a true-up of regulatory asset balances associated with a NYPSC settlement concerning insurance proceeds on site remediation claims ($1.5 million) and the earnings impact of lower interest expense ($0.9 million). The decrease in interest expense is due to a decrease in the weighted average amount of debt outstanding due to the Utility segment’s share of the Company’s $250 million of notes that matured in March 2013.
The impact of weather variations on earnings in the Utility segment’s New York rate jurisdiction is mitigated by that jurisdiction’s weather normalization clause (WNC). 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

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addition, in periods of colder than normal weather, the WNC benefits the Utility segment’s New York customers. For 2014, the WNC reduced earnings by approximately $3.0 million as the weather was colder than normal. In 2013, the WNC preserved earnings of approximately $2.1 million as the weather was warmer than normal.
2013 Compared with 2012
The Utility segment’s earnings in 2013 were $65.7 million, an increase of $7.1 million when compared with earnings of $58.6 million in 2012. The increase in earnings is largely attributable to colder weather ($7.0 million), the positive earnings impact of lower interest expense ($2.7 million), lower income tax expense ($1.2 million), and higher usage ($0.7 million). These increases were partially offset by a $4.9 million refund provision discussed above. Usage refers to average gas consumption per account after factoring out any impact that weather may have had on consumption. The decrease in interest expense is due to a decrease in the weighted average amount of debt outstanding due to the Utility segment’s share of the Company’s $250 million of notes that matured in March 2013. The decrease in income tax expense is a result of a favorable tax settlement.
For 2012, the WNC preserved earnings of approximately $5.9 million as the weather was warmer than normal.
ENERGY MARKETING
Revenues
Energy Marketing Operating Revenues
 
 
Year Ended September 30
 
2014
 
2013
 
2012
 
(Thousands)
Natural Gas (after Hedging)
$
273,099

 
$
213,324

 
$
187,969

Other
53

 
50

 
35

 
$
273,152

 
$
213,374

 
$
188,004

Energy Marketing Volume
 
 
Year Ended September 30
 
2014
 
2013
 
2012
Natural Gas — (MMcf)
52,694

 
46,875

 
45,756

2014 Compared with 2013
Operating revenues for the Energy Marketing segment increased $59.8 million in 2014 as compared with 2013. The increase reflects an increase in gas sales revenue due to a higher average price of natural gas period over period and an increase in volume sold to retail customers as a result of colder weather. Effective with the first quarter of 2014, the Energy Marketing segment began recording unbilled revenue. Operating revenues for the year ended September 30, 2014 include an $8.5 million accrual for unbilled revenue while operating revenues for the year ended September 30, 2013 do not include such an accrual. The volume associated with unbilled revenue at September 30, 2014 was 2,122 MMcf.
2013 Compared with 2012
Operating revenues for the Energy Marketing segment increased $25.4 million in 2013 as compared with 2012. The increase reflects an increase in gas sales revenue due to a higher average price of natural gas as well as an increase in volume sold due to colder weather.

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Earnings
2014 Compared with 2013
The Energy Marketing segment’s earnings in 2014 were $6.6 million, an increase of $2.0 million when compared with earnings of $4.6 million in 2013. This increase in earnings was largely attributable to higher margin of $2.2 million, which primarily reflects the positive impact on margin from the increase in volume sold to retail customers due to colder weather during 2014 combined with improved average margin per Mcf. To a lesser extent, margin was also positively impacted by the recording of unbilled revenues and related gas costs at September 30, 2014, as discussed below. These earnings increases were partially offset by a decline in the benefit the Energy Marketing segment realized from its contracts for storage capacity.
Energy Marketing segment revenues and related purchased gas costs in prior year periods were recorded when billed, resulting in a one month lag. Effective with the first quarter of 2014, the Energy Marketing segment began recording unbilled revenue and related gas costs. The impact of this change for the year ended September 30, 2014 was to increase operating revenues and margin by $8.5 million and $0.6 million, respectively.  Management has determined that the impact of not recording unbilled revenue and related gas costs was immaterial in all prior periods.
2013 Compared with 2012
The Energy Marketing segment’s earnings in 2013 were $4.6 million, an increase of $0.4 million when compared with earnings of $4.2 million in 2012. This increase in earnings was largely attributable to higher margin of $0.5 million, primarily driven by an increase in the benefit the Energy Marketing segment derived from its contracts for storage capacity.
ALL OTHER AND CORPORATE OPERATIONS
All Other and Corporate operations primarily includes the operations of Seneca’s Northeast Division and corporate operations. Seneca’s Northeast Division markets timber from its New York and Pennsylvania land holdings. In September 2012, the Company recorded an impairment charge ($1.1 million) to write-off the remaining value of Horizon Power’s investment in ESNE, a dormant 80-megawatt, combined cycle, natural gas-fired power plant in North East, Pennsylvania. In March 2014, ESNE sold its turbine assets associated with this plant.
Earnings
2014 Compared with 2013
All Other and Corporate operations recorded a loss of $3.1 million in 2014, which was $0.9 million higher than the loss of $2.2 million in 2013. The increase in loss was primarily due to higher income tax expense of $4.7 million (primarily due to consolidated tax sharing and an adjustment for an intercompany deferred tax reallocation recorded in 2013 that did not recur in 2014) and higher property, franchise and other taxes of $0.7 million (largely due to a reduction in franchise taxes recorded in 2013 that did not recur in 2014). These increases were offset partially by a $3.6 million death benefit gain on life insurance policies that was recorded in 2014, which is recorded in Other Income. In addition, earnings were increased by an increase in income from unconsolidated subsidiaries of $0.4 million (due to the sale of turbine assets held by Horizon Power’s investment in ESNE).
2013 Compared with 2012
All Other and Corporate operations recorded a loss of $2.2 million in 2013, which was $4.4 million lower than the loss of $6.6 million in 2012. The decrease in loss was primarily due to lower income tax expense of $3.4 million (primarily due to an intercompany deferred tax reallocation), lower property, franchise and other taxes of $1.8 million (largely due to a reduction in New York State capital stock tax) and a reduction in loss from unconsolidated subsidiaries of $0.8 million (as noted above, a $1.1 million impairment charge was recorded in September 2012 that did not recur in 2013). This was partially offset by higher operating costs of $1.2 million (largely due to higher personnel costs).

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INTEREST CHARGES
Although most of the variances in Interest Charges are discussed in the earnings discussion by segment above, the following is a summary on a consolidated basis (amounts below are pre-tax amounts):
Interest on long-term debt decreased $0.1 million in 2014 as compared to 2013. This decrease is due to an increase in capitalized interest (mostly in Midstream Corporation) for the year ended September 30, 2014 as compared to the year ended September 30, 2013. This was partially offset by the impact of a higher average amount of long-term debt outstanding (partially offset by a decrease in the weighted average interest on such debt). The Company issued $500 million of 3.75% notes in February 2013 and repaid $250 million of 5.25% notes that matured in March 2013.
Interest on long-term debt increased $8.3 million in 2013 as compared to 2012. This increase is due to a higher average amount of long-term debt outstanding partially offset by a decrease in the weighted average interest rate on such debt. The Company issued $500 million of 3.75% notes in February 2013 and repaid $250 million of 5.25% notes that matured in March 2013. In addition, there was a decrease in capitalized interest associated with decreased Exploration and Production segment capital expenditures in the Appalachian region, which increased interest expense in comparison to the prior year.

CAPITAL RESOURCES AND LIQUIDITY
The primary sources and uses of cash during the last three years are summarized in the following condensed statement of cash flows:
 
 
Year Ended September 30
 
2014
 
2013
 
2012
 
(Millions)
Provided by Operating Activities
$
909.4

 
$
738.6

 
$
659.0

Capital Expenditures
(914.4
)
 
(703.5
)
 
(1,035.0
)
Other Investing Activities
6.0

 
(2.5
)
 
0.5

Reduction of Long-Term Debt

 
(250.0
)
 
(150.0
)
Change in Notes Payable to Banks and Commercial Paper
85.6

 
(171.0
)
 
131.0

Net Proceeds from Issuance of Long-Term Debt

 
495.4

 
496.1

Net Proceeds from Issuance of Common Stock
7.5

 
5.4

 
10.3

Dividends Paid on Common Stock
(126.7
)
 
(122.7
)
 
(118.8
)
Excess Tax Benefits Associated with Stock-Based Compensation Awards
4.6

 
0.7

 
1.0

Net Decrease in Cash and Temporary Cash Investments
$
(28.0
)
 
$
(9.6
)
 
$
(5.9
)

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 and changes in operating assets and liabilities. Non-cash items include depreciation, depletion and amortization, deferred income taxes, stock-based compensation and the elimination of an other post-retirement regulatory liability.
Cash provided by operating activities in the Utility and Pipeline and Storage segments may vary substantially from year to year because of the impact of rate cases. In the Utility segment, supplier refunds, over- or under-recovered purchased gas costs and weather may also significantly impact cash flow. The impact of weather on cash flow is tempered in the Utility segment’s New York rate jurisdiction by its WNC and in the Pipeline and Storage segment by the straight fixed-variable rate design used by Supply Corporation and Empire.
Cash provided by operating activities in the Exploration and Production segment may vary from year to year as a result of changes in the commodity prices of natural gas and crude oil as well as changes in production. The

-46-



Company uses various derivative financial instruments, including price swap agreements and futures contracts in an attempt to manage this energy commodity price risk.
Net cash provided by operating activities totaled $909.4 million in 2014, an increase of $170.8 million compared with the $738.6 million provided by operating activities in 2013. The increase in cash provided by operating activities reflects higher cash provided by operating activities in the Exploration and Production segment, Gathering segment and Corporate category. The increase in the Exploration and Production segment is primarily due to higher cash receipts from natural gas production in the Appalachian region, specifically development in the Marcellus Shale formation. The increase in the Gathering segment is due to an increase in gathering revenues from Midstream Corporation's Trout Run Gathering System and Midstream Corporation's Clermont Gathering System. Lastly, the increase in the Corporate category is primarily due to the receipt of life insurance proceeds.
Net cash provided by operating activities totaled $738.6 million in 2013, an increase of $79.6 million compared with the $659.0 million provided by operating activities in 2012. The increase in cash provided by operating activities reflects higher cash provided by operating activities in the Exploration and Production segment and Pipeline and Storage segment, partly offset by lower cash provided by operating activities in the Utility segment. The increase in the Exploration and Production segment is primarily due to higher cash receipts from natural gas production in the Appalachian region, partially offset by a decrease in cash provided by operating activities from hedging collateral account fluctuations and higher federal and state income tax payments. The increase in the Pipeline and Storage segment is due to higher cash receipts from transportation revenues as a result of expansion projects coming on-line and higher tariff rates from the implementation of Supply Corporation’s rate case proceeding. The decrease in the Utility segment can be attributed to the timing of gas cost recovery and the timing of receivable collections. The winter of 2012 was substantially warmer than normal, resulting in lower receivable balances at September 30, 2012 that were collected in subsequent months. The winter of 2013 saw more normal temperatures, resulting in higher receivable balances at September 30, 2013 that will be collected in subsequent months.
INVESTING CASH FLOW
Expenditures for Long-Lived Assets
The Company’s expenditures for long-lived assets totaled $969.9 million, $717.1 million and $977.4 million in 2014, 2013 and 2012, respectively. These amounts include accounts payable and accrued liabilities related to capital expenditures and will differ from capital expenditures shown on the Consolidated Statement of Cash Flows. Capital expenditures recorded as liabilities are excluded from the Consolidated Statement of Cash Flows. They are included in subsequent Consolidated Statement of Cash Flows when they are paid. The table below presents these expenditures:
 

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Year Ended September 30
 
 
2014
 
 
2013
 
 
2012
 
 
(Millions)
 
Exploration and Production:
 
 
 
 
 
 
 
 
Capital Expenditures
$
602.7

(1)
 
$
533.1

(2)
 
$
693.8

(3)
Pipeline and Storage:
 
 
 
 
 
 
 
 
Capital Expenditures
139.8

(1)
 
56.1

(2)
 
144.2

(3)
Gathering:
 
 
 
 
 
 
 
 
Capital Expenditures
137.8

(1)
 
54.8

(2)
 
80.0

(3)
Utility:
 
 
 
 
 
 
 
 
Capital Expenditures
88.8

(1)
 
72.0

(2)
 
58.3

(3)
All Other and Corporate:
 
 
 
 
 
 
 
 
Capital Expenditures
0.8

  
 
1.1

  
 
1.1

  
Total Expenditures
$
969.9

  
 
$
717.1

  
 
$
977.4

  
 
(1)
2014 capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment include $80.1 million, $28.1 million, $20.1 million and $8.3 million, respectively, of accounts payable and accrued liabilities related to capital expenditures.
(2)
2013 capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment include $58.5 million, $5.6 million, $6.7 million and $10.3 million, respectively, of accounts payable and accrued liabilities related to capital expenditures.
(3)
2012 capital expenditures for the Exploration and Production segment, Pipeline and Storage segment, the Gathering segment and the Utility segment include $38.9 million, $12.7 million, $12.7 million and $3.2 million, respectively, of accounts payable and accrued liabilities related to capital expenditures.
Exploration and Production
In 2014, the Exploration and Production segment capital expenditures were primarily well drilling and completion expenditures and included approximately $519.9 million for the Appalachian region (including $502.9 million in the Marcellus Shale area) and $82.8 million for the West Coast region. These amounts included approximately $179.9 million spent to develop proved undeveloped reserves.
In 2013, the Exploration and Production segment capital expenditures were primarily well drilling and completion expenditures and included approximately $428.5 million for the Appalachian region (including $393.3 million in the Marcellus Shale area) and $104.6 million for the West Coast region. These amounts included approximately $148.5 million spent to develop proved undeveloped reserves.
In 2012, the Exploration and Production segment capital expenditures were primarily well drilling and completion expenditures and included approximately $630.9 million for the Appalachian region (including $567.9 million in the Marcellus Shale area) and $62.9 million for the West Coast region. These amounts included approximately $216.6 million spent to develop proved undeveloped reserves. The capital expenditures in the West Coast region include the Company’s establishment of a position within the Mississippian Lime crude oil play for approximately $6.2 million in August 2012, including approximately 9,300 net acres in Pratt County, Kansas. Seneca is now the operator on 4,600 net acres and has a non-operating interest on the remaining net acreage position.
Pipeline and Storage
The majority of the Pipeline and Storage segment’s capital expenditures for 2014 were related to additions, improvements, and replacements to this segment’s transmission and gas storage systems. In addition, the Pipeline and Storage segment capital expenditures for 2014 include expenditures related to Supply Corporation’s Mercer Expansion Project ($27.0 million), Supply Corporation’s Northern Access 2015 project ($11.1 million) and Supply Corporation’s Westside Expansion and Modernization Project ($4.8 million), as discussed below.

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The majority of the Pipeline and Storage segment’s capital expenditures for 2013 were related to additions, improvements, and replacements to this segment’s transmission and gas storage systems. In addition, the Pipeline and Storage segment capital expenditures for 2013 include expenditures for the construction of Supply Corporation’s Northern Access expansion project ($14.5 million), Supply Corporation’s Line N 2012 Expansion Project ($4.2 million), Supply Corporation’s Line N 2013 Project ($2.8 million) and Supply Corporation’s Mercer Expansion Project ($0.7 million).

The majority of the Pipeline and Storage segment’s capital expenditures for 2012 were related to the construction of Supply Corporation’s Northern Access expansion project ($50.8 million), Supply Corporation’s Line N 2012 Expansion Project ($30.5 million), Empire’s Tioga County Extension Project ($24.1 million) and Supply Corporation’s Line N Expansion Project ($2.9 million). The Pipeline and Storage segment capital expenditures for 2012 also include additions, improvements, and replacements to this segment’s transmission and gas storage systems.
Gathering
The majority of the Gathering segment’s capital expenditures for 2014 were for the construction of Midstream Corporation’s Clermont Gathering System ($95.2 million) and to build compressor stations on Midstream Corporation’s Trout Run Gathering System ($32.9 million), as discussed below. In addition, the Gathering segment capital expenditures for 2014 include expenditures for the expansion of Midstream Corporation's Covington Gathering System in Tioga County, Pennsylvania ($4.6 million).
The majority of the Gathering segment’s capital expenditures for 2013 were related to the expansion of Midstream Corporation’s Trout Run Gathering System ($48.0 million).
The majority of the Gathering segment’s capital expenditures for 2012 were related to the construction of Midstream Corporation’s Trout Run Gathering System ($64.5 million) and the expansion of Midstream Corporation’s Covington Gathering System ($12.2 million).
Utility
The majority of the Utility segment’s capital expenditures for 2014, 2013 and 2012 were made for replacement of mains and main extensions and for the replacement of service lines. The capital expenditures for 2014 and 2013 include $15.6 million and $9.1 million, respectively, related to the planned replacement of the Utility segment’s legacy mainframe systems, as discussed below.
Estimated Capital Expenditures
The Company’s estimated capital expenditures for the next three years are:
 
Year Ended September 30
 
2015
 
2016
 
2017
 
(Millions)
Exploration and Production(1)
$
650

 
$
715

 
$
790

Pipeline and Storage
250

 
480

 
160

Gathering
175

 
100

 
95

Utility
100

 
80

 
70

All Other

 

 

 
$
1,175

 
$
1,375

 
$
1,115

 
(1)
Includes estimated expenditures for the years ended September 30, 2015, 2016 and 2017 of approximately $239 million, $81 million and $146 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.

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Exploration and Production
Estimated capital expenditures in 2015 for the Exploration and Production segment include approximately $585 million for the Appalachian region and $65 million for the West Coast region.
Estimated capital expenditures in 2016 for the Exploration and Production segment include approximately $645 million for the Appalachian region and $70 million for the West Coast region.
Estimated capital expenditures in 2017 for the Exploration and Production segment include approximately $715 million for the Appalachian region and $75 million for the West Coast region.
Pipeline and Storage
Capital expenditures for the Pipeline and Storage segment in 2015 through 2017 are expected to include: construction of new pipeline and compressor stations to support expansion projects, the replacement of transmission and storage lines, the reconditioning of storage wells and improvements of compressor stations. Expansion projects are discussed below.
In light of the growing demand for pipeline capacity to move natural gas from new wells being drilled in Appalachia — specifically in the Marcellus and Utica Shale producing area — Supply Corporation and Empire are actively pursuing several expansion projects and paying for preliminary survey and investigation costs, which are initially recorded as Deferred Charges on the Consolidated Balance Sheet. An offsetting reserve is established as those preliminary survey and investigation costs are incurred, which reduces the Deferred Charges balance and increases Operation and Maintenance Expense on the Consolidated Statement of Income. The Company reviews all projects on a quarterly basis, and if it is determined that it is highly probable that the project will be built, the reserve is reversed. This reversal reduces Operation and Maintenance Expense and reestablishes the original balance in Deferred Charges. After the reversal of the reserve, the amounts remain in Deferred Charges until such time as capital expenditures for the project have been incurred and activities that are necessary to get the construction project ready for its intended use are in progress. At that point, the balance is transferred from Deferred Charges to Construction Work in Progress, a component of Property, Plant and Equipment on the Consolidated Balance Sheet. As of September 30, 2014, the total amount reserved for the Pipeline and Storage segment’s preliminary survey and investigation costs was $7.4 million.
Supply Corporation and Empire are moving forward with, or have recently completed, several projects designed to move anticipated Marcellus and Utica production gas to other interstate pipelines and to markets beyond the Supply Corporation and Empire pipeline systems. Projects where the Company has begun to make significant investments of preliminary survey and investigation costs and/or where shipper agreements have been executed are described below.
In 2011, Supply Corporation concluded an Open Season to increase its capability to move gas north on its Line N system and deliver gas to a new interconnection with Tennessee Gas Pipeline ("TGP") at Mercer, Pennsylvania, a pooling point recently established at Tennessee’s Station 219 (“Mercer Expansion Project”). Supply Corporation has executed a service agreement with Range Resources for 105,000 Dth per day, all of the project capacity, for service which began November 1, 2014. The cost estimate is $33.9 million, of which $29.9 million is for expansion and $4.0 million is for system modernization. Supply Corporation has received authorization to construct the required approximately 3,550 horsepower of compression at Mercer, and replace 2.08 miles of 24" pipeline, all under its FERC blanket certificate authorization. As of September 30, 2014, approximately $27.7 million has been capitalized as Construction Work in Progress for the Mercer Expansion Project. The remainder is expected to be spent in fiscal 2015 and is included as Pipeline and Storage estimated capital expenditures in the table above.
On January 18, 2013, Supply Corporation concluded an Open Season to further increase its capacity to move gas north and south on its Line N system to Texas Eastern Transmission, LP (“TETCO”) at Holbrook and TGP at Mercer (“Westside Expansion and Modernization Project”).  Supply Corporation executed two precedent agreements for all 175,000 Dth per day of project capacity, for service expected to begin in 2015.  The Westside Expansion and Modernization Project facilities are expected to include the replacement of approximately 23.3 miles of 20” pipe with 24” pipe and the addition of approximately 3,550 horsepower of compression at Mercer. 

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The preliminary cost estimate is $76.2 million, of which $39.6 million is related to expansion and the remainder is for replacement.  Supply Corporation filed the FERC 7(c) application in early February 2014 and anticipates a FERC certificate in the second quarter of fiscal 2015. As of September 30, 2014, approximately $4.8 million has been capitalized as Construction Work in Progress for the Westside Expansion and Modernization Project. The remaining expenditures expected to be spent are included as Pipeline and Storage estimated capital expenditures in the table above.
Supply Corporation and TGP have jointly developed a project that will combine expansions on both pipeline systems, providing a seamless transportation path from TGP’s 300 Line in the Marcellus fairway to the TransCanada Pipeline delivery point at Niagara.  Supply Corporation has offered 140,000 Dth per day of capacity on its system to TGP under a lease, from its Ellisburg Station for redelivery to TGP in East Eden, New York (“Northern Access 2015”).  The project will provide Seneca Resources, TGP’s anchor shipper, with an outlet to premium Dawn indexed markets in Canada, for their Clermont Area Marcellus production.  The Northern Access 2015 project involves the construction of a new 15,400 horsepower compressor station in Hinsdale, New York and a 7,700 horsepower addition to its compressor station in Concord, New York, for service expected to commence in November 2015.  Supply Corporation and TGP have executed a precedent agreement incorporating the lease agreement, and both companies filed their respective FERC 7(c) applications in early March 2014 and anticipate a FERC certificate in the first quarter of fiscal 2015.  The preliminary cost estimate for the Northern Access 2015 project is $66 million. As of September 30, 2014, approximately $11.1 million has been capitalized as Construction Work in Progress for the Northern Access 2015 project. The remaining expenditures expected to be spent are included in Pipeline and Storage estimated capital expenditures in the table above.
Supply Corporation and Empire have been working with Seneca Resources to develop a project which would move significant prospective Marcellus production from its Western Development Area at Clermont to an interconnection on Empire with TransCanada Pipeline at Chippawa (“Northern Access 2016”). Similar to the Northern Access 2015 project, this project would provide an outlet to premium Dawn indexed markets in Canada in late 2016. The Northern Access 2016 project involves the construction of approximately 101 miles of 24” pipeline and 26,000 horsepower of compression on the two systems. The preliminary cost estimate for the Northern Access 2016 project is $410 million.  These expenditures are included as Pipeline and Storage segment estimated capital expenditures in the table above. Seneca Resources executed anchor shipper agreements for 350,000 Dth per day of firm transportation delivery capacity to Chippawa on this project, and has been awarded the capacity by Supply Corporation and Empire following the close of their respective Open Seasons on June 26, 2014. On July 24, 2014, Supply Corporation and Empire initiated the FERC NEPA Pre-filing process on this project. As of September 30, 2014, approximately $3.7 million has been spent to study the Northern Access 2016 project. The Company has determined it is highly probable that the project will be built. Accordingly, previous reserves have been reversed and the project costs have been reestablished as a Deferred Charge on the Consolidated Balance Sheet.
On August 12, 2013, Empire concluded an Open Season, offering for the first time no-notice transportation and storage service to new and existing shippers on the Empire pipeline system. Rochester Gas & Electric (“RG&E”), Empire’s largest LDC connected market, has executed a precedent agreement to convert all 172,500 Dth per day of its standard firm transportation services to no-notice service, including 3.3 Bcf of no-notice storage service. The new services will provide RG&E with a superior flexible delivery service with daily and seasonal load balancing capabilities and greater access to Marcellus supplies. In addition, Empire has executed a precedent agreement with New York State Electric and Gas for 14,816 Dth per day of transportation capacity and a third agreement with Distribution Corporation for the remaining 34,500 Dth per day of project capacity, providing both LDCs with increased access to Marcellus supplies. The project would require Empire to construct a 17.2 mile, 12” pipeline and interconnection between Empire’s pipeline system and Supply Corporation’s system at Tuscarora, New York. It would also require Empire to modify its Oakfield compressor station and require Supply Corporation to construct approximately 1,380 horsepower of compression at its Tuscarora compressor station (“Tuscarora Lateral Project”).  Supply Corporation concluded an Open Season and has awarded to Empire the necessary storage services under a lease agreement.  Empire and Supply Corporation began the FERC pre-filing process on April 12, 2013, and both companies filed their FERC 7(c) applications in March 2014.  The preliminary cost estimate for the Tuscarora Lateral Project is $45.2 million. As of September 30, 2014, approximately $1.7 million has been

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capitalized as Construction Work in Progress for the Tuscarora Lateral Project. The remaining expenditures expected to be spent are included in Pipeline and Storage estimated capital expenditures in the table above.
Empire is developing an expansion of its system that would allow for the transportation of approximately 250,000 Dth per day of additional Marcellus supplies from Millennium Pipeline at Corning or from new interconnections in Tioga County, Pennsylvania, to TransCanada Pipeline and the TGP 200 Line (“Central Tioga County Extension”). In addition, the connection to Supply Corporation afforded by the Tuscarora Lateral Project could allow those Marcellus supplies to be sourced from other parts of Supply Corporation. Such a configuration would likely involve facility investments on the Supply Corporation system as well. The preliminary cost estimate for the Central Tioga County Extension is $114 million to $150 million depending on requested receipt points. These expenditures are included as Pipeline and Storage segment estimated capital expenditures in the table above. As of September 30, 2014, approximately $0.2 million has been spent to study the Central Tioga County Extension project, all of which has been included in preliminary survey and investigation charges and has been fully reserved for at September 30, 2014.
Gathering
The majority of the Gathering segment capital expenditures in 2015 through 2017 are expected to be for construction and expansion of gathering systems, as discussed below.
NFG Midstream Trout Run, LLC, a wholly owned subsidiary of Midstream Corporation, continues to develop its Trout Run Gathering System in Lycoming County, Pennsylvania. The Trout Run Gathering System was initially placed in service in May 2012. The current system consists of approximately 40 miles of backbone and in-field gathering pipelines and two compressor stations. Estimated capital expenditures in 2015 through 2017 include anticipated expenditures in the range of $15 million to $25 million for the continued expansion of the Trout Run Gathering System. As of September 30, 2014, the Company has spent approximately $161.0 million in costs related to this project, all of which is included in Property, Plant and Equipment on the Consolidated Balance Sheet at September 30, 2014.
NFG Midstream Clermont, LLC, a wholly owned subsidiary of Midstream Corporation, is building an extensive gathering system with compression in the Pennsylvania counties of McKean, Elk and Cameron. The preliminary cost estimate for the continued buildout is anticipated to be in the range of $250 million to $450 million.  As of September 30, 2014, approximately $98.5 million has been spent on the Clermont Gathering System, all of which is included in Property, Plant and Equipment on the Consolidated Balance Sheet at September 30, 2014.
Utility
Capital expenditures for the Utility segment in 2015 through 2017 are expected to be concentrated in the areas of main and service line improvements and replacements and, to a lesser extent, the purchase of new equipment. Estimated capital expenditures in the Utility segment for 2015 through 2017 also include amounts for the planned replacement of the Utility segment’s legacy mainframe systems.  This includes estimated capital expenditures in 2015 of $30.0 million related to the replacement of the customer information system, which is scheduled to be placed in service in the summer of 2015. Estimated capital expenditures for the replacement of other legacy mainframe systems amount to $6.0 million for 2016 and $3.0 million for 2017.
Project Funding
The Company has been financing the Pipeline and Storage segment and Gathering segment projects mentioned above, as well as the Exploration and Production segment capital expenditures, with cash from operations and both short and long-term borrowings. Going forward, while the Company expects to use cash from operations as the first means of financing these projects, it is expected that the Company will issue short-term and long-term debt as necessary during fiscal 2015 to help meet its capital expenditure needs. The level of such short-term and long-term borrowings will depend upon the amounts of cash provided by operations, which, in turn, will likely be impacted by natural gas and crude oil prices combined with production from existing wells.

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The Company continuously evaluates capital expenditures and potential investments in corporations, partnerships, and other business entities. The amounts are subject to modification for opportunities such as the acquisition of attractive oil and gas properties, natural gas storage facilities and the expansion of natural gas transmission line capacities. While the majority of capital expenditures in the Utility segment are necessitated by the continued need for replacement and upgrading of mains and service lines, the magnitude of future capital expenditures or other investments in the Company’s other business segments depends, to a large degree, upon market conditions.
FINANCING CASH FLOW
Consolidated short-term debt increased $85.6 million when comparing the balance sheet at September 30, 2014 to the balance sheet at September 30, 2013. The maximum amount of short-term debt outstanding during the year ended September 30, 2014 was $96.3 million. 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 and investments in corporations and/or partnerships, gas-in-storage inventory, unrecovered purchased gas costs, margin calls on derivative financial instruments, exploration and development expenditures, other working capital needs and repayment of long-term debt. Fluctuations in these items can have a significant impact on the amount and timing of short-term debt. At September 30, 2014, the Company had outstanding commercial paper of $85.6 million. The Company did not have any outstanding short-term notes payable to banks at September 30, 2014.
The Company maintains a $750.0 million syndicated committed credit facility, which commitment extends through January 6, 2017. As of the date of filing of this Form 10-K, the Company is pursuing options to refinance this facility with a substantially similar syndicated committed credit facility. The Company expects the new credit facility would total $750.0 million and would extend for five years from the date the parties enter into it. The Company also has a number of individual uncommitted or discretionary lines of credit with certain financial institutions for general corporate purposes. Borrowings under the uncommitted lines of credit are made at competitive market rates. The uncommitted credit lines are revocable at the option of the financial institutions and are reviewed on an annual basis. The Company anticipates that its uncommitted lines of credit generally will be renewed or substantially replaced by similar lines.
The total amount available to be issued under the Company’s commercial paper program is $300.0 million. At September 30, 2014, the commercial paper program was backed by the $750.0 million syndicated committed credit facility. Under the committed credit facility, the Company agreed that its debt to capitalization ratio would not exceed .65 at the last day of any fiscal quarter through January 6, 2017. At September 30, 2014, the Company’s debt to capitalization ratio (as calculated under the facility) was .42. The constraints specified in the committed credit facility would have permitted an additional $2.74 billion in short-term and/or long-term debt to be outstanding (further limited by the indenture covenants discussed below) before the Company’s debt to capitalization ratio exceeded .65.
If a downgrade in any of the Company’s credit ratings were to occur, access to the commercial paper markets might not be possible. However, the Company expects that it could borrow under its committed credit facility, uncommitted bank lines of credit or rely upon other liquidity sources, including cash provided by operations.
The Company’s $750.0 million committed credit facility 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 committed credit facility. In particular, a repayment obligation could be triggered if (i) the Company or any of its significant subsidiaries fails to make a payment when due of any principal or interest on any other indebtedness aggregating $40.0 million or more or (ii) an event occurs that causes, or would permit the holders of any other indebtedness aggregating $40.0 million or more to cause, such indebtedness to become due prior to its stated maturity. As of September 30, 2014, the Company did not have any debt outstanding under the committed credit facility.

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Under the Company’s existing indenture covenants, at September 30, 2014, the Company would have been permitted to issue up to a maximum of $1.92 billion in additional long-term unsecured indebtedness at then current market interest rates in addition to being able to issue new indebtedness to replace maturing debt. The Company’s present liquidity position is believed to be adequate to satisfy known demands. However, if the Company were to experience a significant loss in the future (for example, as a result of an impairment of oil and gas properties), it is possible, depending on factors including the magnitude of the loss, that these indenture covenants would restrict the Company’s ability to issue additional long-term unsecured indebtedness for a period of up to nine calendar months, beginning with the fourth calendar month following the loss. This would not at any time preclude the Company from issuing new indebtedness to replace maturing debt.
The Company’s 1974 indenture pursuant to which $99.0 million (or 6.0%) of the Company’s long-term debt (as of September 30, 2014) 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.
The Company’s embedded cost of long-term debt was 5.58% at both September 30, 2014 and September 30, 2013. Refer to “Interest Rate Risk” in this Item for a more detailed breakdown of the Company’s embedded cost of long-term debt.
None of the Company’s long-term debt at September 30, 2014 and 2013 had a maturity date within the following twelve-month period.
On February 15, 2013, the Company issued $500.0 million of 3.75% notes due March 1, 2023. After deducting underwriting discounts and commissions, the net proceeds to the Company amounted to $495.4 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. The proceeds of this debt issuance were used to refund the $250.0 million of 5.25% notes that matured in March 2013, as well as for general corporate purposes, including the reduction of short-term debt.
On December 1, 2011, the Company issued $500.0 million of 4.90% notes due December 1, 2021. After deducting underwriting discounts and commissions, the net proceeds to the Company amounted to $496.1 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. The proceeds of this debt issuance were used for general corporate purposes, including refinancing short-term debt that was used to pay the $150.0 million due at the maturity of the Company’s 6.70% notes in November 2011.
The Company may issue debt or equity securities in a public offering or a private placement from time to time. The amounts and timing of the issuance and sale of debt or equity securities will depend on market conditions, indenture requirements, regulatory authorizations and the capital requirements of the Company.
OFF-BALANCE SHEET ARRANGEMENTS
The Company has entered into certain off-balance sheet financing arrangements. These financing arrangements are primarily operating leases. The Company’s consolidated subsidiaries have operating leases, the majority of which are with the Exploration and Production segment and Corporate operations, having a remaining lease commitment of approximately $40.8 million. These leases have been entered into for the use of compressors, drilling rigs, buildings, meters and other items and are accounted for as operating leases.

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CONTRACTUAL OBLIGATIONS
The following table summarizes the Company’s expected future contractual cash obligations as of September 30, 2014, and the twelve-month periods over which they occur:
 
 
Payments by Expected Maturity Dates
 
2015
 
2016
 
2017
 
2018
 
2019
 
Thereafter
 
Total
 
(Millions)
Long-Term Debt, including interest expense(1)
$
91.9

 
$
91.9

 
$
91.9

 
$
383.0

 
$
313.3

 
$
1,249.9

 
$
2,221.9

Operating Lease Obligations
$
16.0

 
$
5.8

 
$
5.7

 
$
5.6

 
$
5.3

 
$
2.4

 
$
40.8

Purchase Obligations: