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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, 2013
| ¨ | 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 $4,953,650,000 as of March 31, 2013.
Common Stock, par value $1.00 per share, outstanding as of October 31, 2013: 83,692,481 shares.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrant’s definitive Proxy Statement for its 2014 Annual Meeting of Stockholders, to be filed with the Securities and Exchange Commission within 120 days of September 30, 2013, are incorporated by reference into Part III of this report.
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Glossary of Terms
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For the Fiscal Year Ended September 30, 2013
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| ITEM 1 |
BUSINESS | 6 | ||||
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| ITEM 1A |
RISK FACTORS | 14 | ||||
| ITEM 1B |
UNRESOLVED STAFF COMMENTS | 24 | ||||
| ITEM 2 |
PROPERTIES | 24 | ||||
| 24 | ||||||
| 25 | ||||||
| ITEM 3 |
LEGAL PROCEEDINGS | 30 | ||||
| ITEM 4 |
MINE SAFETY DISCLOSURES | 30 | ||||
| Part II | ||||||
| ITEM 5 |
MARKET FOR THE REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES | 31 | ||||
| ITEM 6 |
SELECTED FINANCIAL DATA | 33 | ||||
| ITEM 7 |
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS | 34 | ||||
| ITEM 7A |
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK | 70 | ||||
| ITEM 8 |
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA | 71 | ||||
| ITEM 9 |
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE | 131 | ||||
| ITEM 9A |
CONTROLS AND PROCEDURES | 131 | ||||
| ITEM 9B |
OTHER INFORMATION | 132 | ||||
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| Part III | ||||||
| ITEM 10 |
DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE | 132 | ||||
| ITEM 11 |
EXECUTIVE COMPENSATION | 132 | ||||
| ITEM 12 |
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS | 132 | ||||
| ITEM 13 |
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE | 133 | ||||
| ITEM 14 |
PRINCIPAL ACCOUNTANT FEES AND SERVICES | 133 | ||||
| Part IV | ||||||
| ITEM 15 |
EXHIBITS AND FINANCIAL STATEMENT SCHEDULES | 133 | ||||
| 140 | ||||||
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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 and reports financial results for five business segments.
1. 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 735,000 customers through a local distribution system located in western New York and northwestern Pennsylvania. The principal metropolitan areas served by Distribution Corporation include Buffalo, Niagara Falls and Jamestown, New York and Erie and Sharon, Pennsylvania.
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). The Millennium Pipeline serves the New York City area. The Empire Connector was placed into service on December 10, 2008, and the Tioga County Extension was fully placed into service on November 22, 2011.
3. The Exploration and Production segment operations are carried out by Seneca Resources Corporation (Seneca), a Pennsylvania corporation. Seneca Western Minerals Corp., formerly an indirect, wholly owned subsidiary of Seneca, was merged into Seneca in October 2012. 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, 2013, Seneca had U.S. proved developed and undeveloped reserves of 41,598 Mbbl of oil and 1,299,515 MMcf of natural gas.
4. The Energy Marketing segment operations are carried out by National Fuel Resources, Inc. (NFR), a New York corporation, which markets natural gas to industrial, wholesale, commercial, public authority and residential customers primarily in western and central New York and northwestern Pennsylvania, offering competitively priced natural gas for its customers.
5. 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.
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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, 2013, the Company owned approximately 95,000 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 2013.
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 Utility segment contributed approximately 25.3% of the Company’s 2013 net income available for common stock.
Additional discussion of the Utility segment appears below in this Item 1 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 Pipeline and Storage Segment
The Pipeline and Storage segment contributed approximately 24.3% of the Company’s 2013 net income available for common stock.
Supply Corporation has service agreements for all of its firm storage capacity, totaling 68,393 MDth. The Utility segment has contracted for 29,743 MDth or 44% of the total firm storage capacity, and the Energy Marketing segment accounts for another 4,810 MDth or 7% of the total firm storage capacity. Nonaffiliated customers have contracted for the remaining 33,840 MDth or 49% of the total firm storage capacity. The majority of Supply Corporation’s storage and transportation services are performed under contracts that allow Supply Corporation or the shipper to terminate the contract upon six or twelve months’ notice effective
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at the end of the contract term. The contracts also typically include “evergreen” language designed to allow the contracts to extend year-to-year at the end of the primary term. At the beginning of 2014, 81% of Supply Corporation’s total firm storage capacity was committed under contracts that, subject to 2013 shipper or Supply Corporation notifications, could have been terminated effective in 2014. Supply Corporation received storage contract termination notifications in 2013 totaling approximately 4,113 MDth of storage capacity. An additional contract without evergreen provisions, representing 1,171 MDth of storage capacity, will expire March 31, 2014. Supply Corporation expects to remarket all terminating capacity with service beginning April 1, 2014.
Supply Corporation’s firm transportation capacity is not a fixed quantity, due to the diverse web-like nature of its pipeline system, and 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 2,578 MDth per day (contracted transportation capacity), compared to 2,175 MDth per day last year. The Utility segment accounts for approximately 1,035 MDth per day or 40% of contracted transportation capacity, and the Energy Marketing and Exploration and Production segments represent another 178 MDth per day or 7% of contracted transportation capacity. The remaining 1,365 MDth or 53% of contracted transportation capacity is subject to firm contracts with nonaffiliated customers.
At the beginning of 2014, 42% of Supply Corporation’s contracted transportation capacity was committed under affiliate contracts that were scheduled to expire in 2014 or, subject to 2013 shipper or Supply Corporation notifications, could have been terminated effective in 2014. Based on contract expirations and termination notices received in 2013 for 2014 termination, and taking into account any known contract additions, contracted transportation capacity with affiliates is expected to decrease 2% in 2014. Similarly, 17% of contracted transportation capacity was committed under unaffiliated shipper contracts that were scheduled to expire in 2014 or, subject to 2013 shipper or Supply Corporation notifications, could have been terminated effective in 2014. Based on contract expirations and termination notices received in 2013 for 2014 termination, and taking into account any known contract additions, contracted transportation capacity with unaffiliated shippers is expected to increase 12% in 2014.
At the beginning of 2014, Empire had service agreements in place for firm transportation capacity totaling up to approximately 1,067 MDth per day, compared to 950 MDth per day at the beginning of 2013. The majority of Empire’s transportation services are performed under contracts that allow Empire or the shipper to terminate the contract upon six or twelve months’ notice effective at the end of the contract term. The contracts also typically include “evergreen” language designed to allow the contracts to extend year-to-year at the end of the primary term. At the beginning of 2014, most of Empire’s firm contracted capacity (95%) was contracted as long-term, full-year deals. None of the long-term contracts will expire in 2014. The remainder of Empire’s firm contracted capacity (5%) was contracted as seasonal (winter-only), single-year or shorter-term contracts. At the beginning of 2014, the Utility segment accounted for 4% of Empire’s firm contracted capacity, with the remaining 96% subject to contracts with nonaffiliated customers.
In recent years, the relatively high price of natural gas supplies available at receipt points on the United States/Canadian border in the Niagara region, together with shifting gas supply dynamics, reduced the amount of firm capacity Supply Corporation and Empire contract from those receipt points. However, Supply Corporation and Empire have been successful in marketing and obtaining long-term firm contracts for transportation capacity designed to move Marcellus Shale production to market. For example, Supply Corporation added 160 MDth per day of contracted incremental transportation associated with its Line N 2011 project in 2012, and 483 MDth per day of contracted incremental transportation associated with its Line N 2012 and Northern Access projects in 2013. In addition, in 2012 Empire placed into service two long-term contracts for firm transportation service associated with its Tioga County Extension project. These two contracts now account for 350 MDth per day of firm contracted capacity. Supply Corporation expects additional Marcellus-driven transportation contracts to commence in 2014.
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.
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The Exploration and Production Segment
The Exploration and Production segment contributed approximately 44.4% of the Company’s 2013 net income available for common stock.
Additional discussion of the Exploration and Production segment appears below 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 Energy Marketing segment contributed approximately 1.8% of the Company’s 2013 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.
The Gathering segment contributed approximately 5.1% of the Company’s 2013 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.
All Other Category and Corporate Operations
The All Other category and Corporate operations incurred a net loss in 2013. The impact of this net loss in relation to the Company’s 2013 net income available for common stock was negative 0.9%.
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
Natural gas is the principal raw material for the Utility segment. In 2013, the Utility segment purchased 60.0 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 43% of these purchases. Purchases of gas on the spot market (contracts for one month or less) accounted for 57% of the Utility segment’s 2013 purchases. Purchases from South Jersey Resources Group, LLC (24%), Virginia Power Energy Marketing, Inc. (22%), Southwestern Energy Services Company (12%) and Chevron Natural Gas (11%), accounted for 69% of the Utility’s 2013 gas purchases. No other producer or supplier provided the Utility segment with more than 10% of its gas requirements in 2013.
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 southwestern, mid-continent and Appalachian regions 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 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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The Energy Marketing segment depends on an adequate supply of natural gas to deliver to its customers. In 2013, this segment purchased 47.4 Bcf of gas, including 46.9 Bcf for delivery to its customers. The remaining 0.5 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.
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.
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 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 22%, and in Pennsylvania, approximately 14%, 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 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. 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
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Marcellus Shale and transport it to key markets of Canada and 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, Empire has constructed the Empire Connector project, which expands its 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 is designed to facilitate transportation of Marcellus Shale gas to key markets of Canada and the northeastern United States. For further discussion of this project, refer to Item 7, MD&A under the headings “Investing Cash Flow” and “Rate and Regulatory Matters.”
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 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.
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.
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.
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.
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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.
A discussion of capital expenditures by business segment is included in Item 7, MD&A under the heading “Investing Cash Flow.”
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.
The Company and its wholly owned or majority-owned subsidiaries had a total of 1,912 full-time employees at September 30, 2013.
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, and agreements covering employees in collective bargaining units in Pennsylvania are scheduled to expire in April 2014 and May 2014. In November 2013, the Company entered into a new agreement with one of the collective bargaining units in Pennsylvania. That agreement will go into effect in April 2014 and expire in April 2018. Also in November 2013, the Company reached a new agreement with the local leadership of another collective bargaining unit in Pennsylvania. If ratified by the members of that collective bargaining unit, the agreement will go into effect in May 2014 and expire in 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, 2013(1)
| Name and Age (as of November 15, 2013) |
Current Company Positions and Other Material Business Experience During Past Five Years | |
| David F. Smith |
Executive Chairman of the Board of Directors of the Company since April 2013. Mr. Smith previously served as Chairman of the Board of Directors of the Company from March 2010 through March 2013; Chief Executive Officer of the Company from February 2008 through March 2013; and President of the Company from February 2006 through June 2010. | |
| Ronald J. Tanski |
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 |
Senior Vice President of the Company since July 2010 and President of Seneca since December 2006. | |
| Anna Marie Cellino |
President of Distribution Corporation since July 2008. | |
| John R. Pustulka |
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 |
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 |
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 |
Senior Vice President of Distribution Corporation since January 2008. | |
| Paula M. Ciprich |
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 |
Vice President Business Development of the Company since October 2007. | |
| James D. Ramsdell |
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.
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The Company’s credit ratings may not reflect all the risks of an investment in its securities.
The Company’s credit ratings are an independent assessment of its ability to pay its obligations. Consequently, real or anticipated changes in the Company’s credit ratings will generally affect the market value of the specific debt instruments that are rated, as well as the market value of the Company’s common stock. The Company’s credit ratings, however, may not reflect the potential impact on the value of its common stock of risks related to structural, market or other factors discussed in this Form 10-K.
The 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
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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 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 Company’s liquidity, and in certain circumstances, its earnings, could be adversely affected by the cost of purchasing natural gas during periods in which natural gas prices are rising significantly.
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. Nevertheless, increases in the cost of purchased gas affect cash flows and can therefore impact the amount or availability of the Company’s capital resources. The
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Company has issued commercial paper and used short-term borrowings in the past to temporarily finance storage inventories and purchased gas costs, and although the Company expects to do so in the future, it may not be able to access the markets for such borrowings at attractive interest rates or at all. 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. Due to the nature of the regulatory process, there is a risk of a disallowance of full recovery of these costs during any period in which there has been a substantial upward spike in these costs. Any material disallowance of purchased gas costs could have a material adverse effect on cash flow and earnings. In addition, even when Distribution Corporation is allowed full recovery of these purchased gas costs, during periods when natural gas prices are significantly higher than historical levels, customers may have trouble paying the resulting higher bills, and Distribution Corporation’s bad debt expenses may increase and ultimately reduce earnings.
Changes in interest rates may affect the Company’s ability to finance capital expenditures and to refinance maturing debt.
The Company’s ability to cost-effectively finance capital expenditures and to refinance maturing debt will depend in part upon interest rates. The direction in which interest rates may move is uncertain. Declining interest rates have generally been believed to be favorable to utilities, while rising interest rates are generally believed to be unfavorable, because of the levels of debt that utilities may have outstanding. In addition, the Company’s authorized rate of return in its regulated businesses is based upon certain assumptions regarding interest rates. If interest rates are lower than assumed rates, the Company’s authorized rate of return could be reduced. If interest rates are higher than assumed rates, the Company’s ability to earn its authorized rate of return may be adversely impacted.
Fluctuations in oil and natural gas prices could adversely affect revenues, cash flows and profitability.
Operations in the Company’s Exploration and Production segment are materially dependent on prices received for its oil and natural gas production. Both short-term and long-term price trends affect the economics of exploring for, developing, producing, gathering and processing oil and natural gas. Oil and natural gas prices can be volatile and can be affected by: weather conditions, natural disasters, the supply and price of foreign oil and natural gas, the level of consumer product demand, national and worldwide economic conditions, economic disruptions caused by terrorist activities, acts of war or major accidents, political conditions in foreign countries, the price and availability of alternative fuels, the proximity to, and availability of, capacity on transportation facilities, regional levels of supply and demand, energy conservation measures; and government regulations, such as regulation of greenhouse gas emissions and natural gas transportation, royalties, and price controls. The Company sells 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
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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 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
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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 significant impact on the Company. For example, banking regulators have proposed a rule that would require swap dealers and major swap participants subject to their jurisdiction to collect initial and variation margin from counterparties that are non-financial end users, though such swap dealers and major swap participants would have the discretion to set thresholds for posting margin (unsecured credit limits). Regardless of the levels of margin that might be required, concern remains that swap dealers and major swap participants will pass along their increased costs through higher transaction costs and prices, and reductions in thresholds for posting margin. 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.
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You should not place undue reliance on reserve information because such information represents estimates.
This Form 10-K contains estimates of the Company’s proved 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 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
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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.
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 or discharge of contaminants 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.
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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 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.
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, 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 and public disclosure of hydraulic fracturing fluid constituents. Implementing regulations, which will include new permit requirements, must be adopted by January 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 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
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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.
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.
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 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.
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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.
| Item 2 | Properties |
General Information on Facilities
The net investment of the Company in property, plant and equipment was $5.2 billion at September 30, 2013. Approximately 45.1% of this investment was in the Utility and Pipeline and Storage segments, whose operations are located primarily in western and central New York and northwestern Pennsylvania. The Exploration and Production segment comprises 50.5% of the Company’s investment in net property, plant and equipment, and is primarily located in California and in the Appalachian region of the United States. The Gathering segment comprises 3.1% 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 (1.3%). 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 $2.0 billion, or 63.3%, since 2008. 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 Utility segment had a net investment in property, plant and equipment of $1.2 billion at September 30, 2013. The net investment in its gas distribution network (including 14,759 miles of distribution pipeline) and its service connections to customers represent approximately 50% and 35%, respectively, of the Utility segment’s net investment in property, plant and equipment at September 30, 2013.
The Pipeline and Storage segment had a net investment of $1.1 billion in property, plant and equipment at September 30, 2013. Transmission pipeline represents 38% of this segment’s total net investment and includes 2,368 miles of pipeline utilized to move large volumes of gas throughout its service area. Storage facilities represent 18% 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 430 miles of pipeline. Net investment in storage facilities includes $81.7 million of gas stored underground-noncurrent, representing the cost of the gas utilized to maintain pressure levels for normal operating purposes as well as gas maintained for system balancing and other purposes, including
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that needed for no-notice transportation service. The Pipeline and Storage segment has 33 compressor stations with 141,704 installed compressor horsepower that represent 21% of this segment’s total net investment in property, plant and equipment.
The Exploration and Production segment had a net investment in property, plant and equipment of $2.6 billion at September 30, 2013.
The Gathering segment had a net investment of $0.2 billion in property, plant and equipment at September 30, 2013. Gathering lines and related compressors comprise substantially all of this segment’s total net investment, including 57 miles of lines utilized to move Appalachian production (including Marcellus Shale) to various transmission pipeline receipt points.
The Utility and Pipeline and Storage segments’ facilities provided the capacity to meet Supply Corporation’s 2013 peak day sendout, including transportation service, of 1,824 MMcf, which occurred on January 24, 2013. Withdrawals from storage of 615.9 MMcf provided approximately 33.8% 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.
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, 2013, 2012 and 2011 reserves shown in Note M have been impacted by the SEC’s final rule on Modernization of Oil and Gas Reporting. The most notable change of the final rule includes the replacement of the single day period-end pricing used to value oil and gas reserves with 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.
The Company’s proved oil and gas reserve estimates are prepared by the Company’s reservoir engineers who meet the qualifications of Reserve Estimator per the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserve Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007. The Company maintains comprehensive internal reserve guidelines and a continuing education program designed to keep its staff up to date with current SEC regulations and guidance.
The Company’s Vice President of Reservoir Engineering is the primary technical person responsible for overseeing the Company’s reserve estimation process and engaging and overseeing the third party reserve audit. His qualifications include a Bachelor of Science Degree in Petroleum Engineering and over 25 years of Petroleum Engineering experience with both major and independent oil and gas companies. He has maintained oversight of the Company’s reserve estimation process for the past ten years. He is a member of the Society of Petroleum Engineers and a Registered Professional Engineer in the State of Texas.
The Company maintains a system of internal controls over the reserve estimation process. Management reviews the price, heat content, lease operating cost and future investment assumptions used in the economic model to determine the reserves. The Vice President of Reservoir Engineering reviews and approves all new reserve assignments and significant reserve revisions. Access to the Reserve database is restricted. Significant changes to the reserve report are reviewed by senior management on a quarterly basis. Periodically, the Company’s internal audit department assesses the design of these controls and performs testing to determine the effectiveness of such controls.
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All of the Company’s reserve estimates are audited annually by Netherland, Sewell and Associates, Inc. (NSAI). Since 1961, NSAI has evaluated gas and oil properties and independently certified petroleum reserve quantities in the United States and internationally under the Texas Board of Professional Engineers Registration No. F-002699. The primary technical persons (employed by NSAI) that are responsible for leading the audit include a professional engineer registered with the State of Texas (with 15 years of experience in petroleum engineering and consulting at NSAI since 2004) and a professional geoscientist registered in the State of Texas (with 16 years of experience in petroleum geosciences and consulting at NSAI since 2008). NSAI was satisfied with the methods and procedures used by the Company to prepare its reserve estimates at September 30, 2013 and did not identify any problems which would cause it to take exception to those estimates.
The reliable technologies that were utilized in estimating the reserves include wire line open-hole log data, performance data, log cross sections, core data, 2D and 3D seismic data and statistical analysis. The statistical method utilized production performance from both the Company’s and competitors’ wells. Geophysical data includes data from the Company’s wells, published documents and state data-sites, and 2D and 3D seismic data. These were used to confirm continuity of the formation.
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 is attributed to extensions and discoveries of 362 Bcf (355 Bcf in the Marcellus Shale) and positive revisions of previous estimates of 53 Bcf which was partially offset by production of 104 Bcf. Total gas revisions of 53 Bcf were comprised 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.
Seneca’s proved developed and undeveloped natural gas reserves increased from 675 Bcf at September 30, 2011 to 988 Bcf at September 30, 2012. This increase was attributed primarily to extensions and discoveries of 436 Bcf, primarily in the Appalachian region (435 Bcf), which were partially offset by production of 66 Bcf and negative revisions of previous estimates of 56 Bcf. Total gas revisions of negative 56 Bcf were comprised of negative 61 Bcf in gas pricing revisions, partially offset by 5 Bcf in positive performance revisions. Negative price related revisions were mainly a result of lower trailing twelve month average gas prices (Dominion South Point average gas price fell $1.45 per MMBtu from $4.29 per MMBtu to $2.84 per MMBtu) making a number of undeveloped gas wells uneconomic at those prices. Of the 61 Bcf in negative price related revisions, 28 Bcf were related to the non-operated Marcellus joint venture, primarily in Clearfield County, Pennsylvania. Poor well performance from non-operated Marcellus joint venture activity, primarily in Clearfield County, also resulted in 38 Bcf in negative performance revisions. These were more than offset by 43 Bcf of positive performance revisions from Seneca operated Marcellus Shale activity.
Seneca’s proved developed and undeveloped oil reserves decreased from 43,345 Mbbl at September 30, 2011 to 42,862 Mbbl at September 30, 2012. Extensions and discoveries of 1,257 Mbbl and positive revisions of previous estimates of 1,130 Mbbl were exceeded by production of 2,870 Mbbl, primarily occurring in the West Coast region (2,834 Mbbl). On a Bcfe basis, Seneca’s proved developed and undeveloped reserves increased from 935 Bcfe at September 30, 2011 to 1,246 Bcfe at September 30, 2012.
The Company’s proved undeveloped (PUD) reserves increased from 410 Bcfe at September 30, 2012 to 452 Bcfe at September 30, 2013. Undeveloped reserves in the Marcellus Shale increased from 381 Bcf at September 30, 2012 to 432 Bcf at September 30, 2013. The Company’s total PUD reserves are 29% of total proved reserves at September 30, 2013, down from 33% of total proved reserves at September 30, 2012.
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The Company’s proved undeveloped (PUD) reserves increased from 295 Bcfe at September 30, 2011 to 410 Bcfe at September 30, 2012. PUD reserves in the Marcellus Shale increased from 253 Bcf at September 30, 2011 to 381 Bcf at September 30, 2012. There was a material increase in PUD reserves at September 30, 2012 and 2011 as a result of Marcellus Shale reserve additions. The Company’s total PUD reserves are 33% of total proved reserves at September 30, 2012, up from 32% of total proved reserves at September 30, 2011.
The increase in PUD reserves in 2013 of 42 Bcfe is a result of 221 Bcfe in new PUD reserve additions (219 Bcfe from the Marcellus Shale), offset by 160 Bcfe in PUD conversions to developed reserves and 19 Bcfe in downward PUD revisions. The downward revisions were primarily due to reductions to planned lateral lengths for several horizontal wells in the Marcellus Shale.
The increase in PUD reserves in 2012 of 115 Bcfe was a result of 289 Bcfe in new PUD reserve additions (286 Bcfe from the Marcellus Shale), offset by 97 Bcfe in PUD conversions to proved developed reserves, and 77 Bcfe in downward PUD revisions of previous estimates. The downward revisions were primarily from the removal of proved locations in the Marcellus Shale due to a significant decrease in trailing twelve-month average gas prices at Dominion South Point. The decrease in prices made the reserves uneconomic to develop. Of these downward revisions, the majority (66 Bcfe) were related to non-operated Marcellus activity, primarily in Clearfield County.
The Company invested $149 million during the year ended September 30, 2013 to convert 160 Bcfe (171 Bcfe including revisions) of PUD reserves to developed reserves. This represents 39% of the PUD reserves booked at September 30, 2012. The Company invested $217 million during the year ended September 30, 2012 to convert 97 Bcfe of September 30, 2011 PUD reserves to proved developed reserves. This represented 33% of the PUD reserves booked at September 30, 2011. In 2014, the Company estimates that it will invest approximately $169 million to develop its PUD reserves. The Company is committed to developing its PUD reserves within five years as required by the SEC’s final rule on Modernization of Oil and Gas Reporting. Since that rule, the Company developed 19% of its beginning year PUD reserves in fiscal 2010, 47% of its beginning year PUD reserves in fiscal 2011, 33% of its beginning year PUD reserves in fiscal 2012 and 39% of its beginning year PUD reserves in fiscal 2013.
At September 30, 2013, the Company does not have a material concentration of proved undeveloped reserves that have been on the books for more than five years at the corporate level, country level or field level. All of the Company’s proved reserves are in the United States.
At September 30, 2013, the Company’s Exploration and Production segment had delivery commitments of 504 Bcf. The Company expects to meet those commitments through proved reserves and the future development of reserves that are currently classified as proved undeveloped reserves and does not anticipate any issues or constraints that would prevent the Company from meeting these commitments.
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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 | ||||||||||||
| 2013 | 2012 | 2011 | ||||||||||
| United States |
||||||||||||
| Appalachian Region |
||||||||||||
| Average Sales Price per Mcf of Gas |
$ | 3.49 | (2) | $ | 2.71 | (2) | $ | 4.37 | (2) | |||
| Average Sales Price per Barrel of Oil |
$ | 96.48 | $ | 93.94 | $ | 86.58 | ||||||
| Average Sales Price per Mcf of Gas (after hedging) |
$ | 4.00 | $ | 4.19 | $ | 5.24 | ||||||
| Average Sales Price per Barrel of Oil (after hedging) |
$ | 96.48 | $ | 93.94 | $ | 86.58 | ||||||
| Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced |
$ | 0.67 | (2) | $ | 0.68 | (2) | $ | 0.59 | (2) | |||
| Average Production per Day (in MMcf Equivalent of Gas and Oil Produced) |
276 | (2) | 172 | (2) | 118 | (2) | ||||||
| West Coast Region |
||||||||||||
| Average Sales Price per Mcf of Gas (3) |
$ | 6.61 | $ | 6.27 | $ | 7.63 | ||||||
| Average Sales Price per Barrel of Oil |
$ | 103.14 | $ | 107.13 | $ | 96.45 | ||||||
| Average Sales Price per Mcf of Gas (after hedging) (3) |
$ | 7.12 | $ | 8.54 | $ | 10.27 | ||||||
| Average Sales Price per Barrel of Oil (after hedging) |
$ | 98.23 | $ | 90.84 | $ | 80.51 | ||||||
| Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced |
$ | 2.61 | $ | 1.98 | $ | 2.06 | ||||||
| Average Production per Day (in MMcf Equivalent of Gas and Oil Produced) |
55 | 56 | 53 | |||||||||
| Gulf Coast Region |
||||||||||||
| Average Sales Price per Mcf of Gas |
— | — | $ | 5.02 | ||||||||
| Average Sales Price per Barrel of Oil |
— | — | $ | 88.57 | ||||||||
| Average Sales Price per Mcf of Gas (after hedging) |
— | — | $ | 5.50 | ||||||||
| Average Sales Price per Barrel of Oil (after hedging) |
— | — | $ | 88.57 | ||||||||
| Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced |
— | — | $ | 1.59 | ||||||||
| Average Production per Day (in MMcf Equivalent of Gas and Oil Produced) |
— | — | 25 | (1) | ||||||||
| Total Company |
||||||||||||
| Average Sales Price per Mcf of Gas |
$ | 3.58 | $ | 2.89 | $ | 4.64 | ||||||
| Average Sales Price per Barrel of Oil |
$ | 103.07 | $ | 106.97 | $ | 95.78 | ||||||
| Average Sales Price per Mcf of Gas (after hedging) |
$ | 4.10 | $ | 4.42 | $ | 5.60 | ||||||
| Average Sales Price per Barrel of Oil (after hedging) |
$ | 98.21 | $ | 90.88 | $ | 81.13 | ||||||
| Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced |
$ | 0.99 | $ | 1.00 | $ | 1.08 | ||||||
| Average Production per Day (in MMcf Equivalent of Gas and Oil Produced) |
331 | 228 | 185 | |||||||||
| (1) | The Gulf Coast Region’s off-shore properties were sold in April 2011. |
| (2) | The Marcellus Shale fields (which exceed 15% of total reserves at 9/30/2013, 9/30/2012 and 9/30/2011) contributed 258 MMcfe, 152 MMcfe and 97 MMcfe of daily production in 2013, 2012 and 2011, respectively. The average sales price (per Mcfe) was $3.49 ($4.04 after hedging) in 2013, $2.67 ($3.66 after hedging) in 2012 and $4.34 ($4.68 after hedging) in 2011. The average lifting costs (per Mcfe) were $0.64 in 2013, $0.61 in 2012 and $0.48 in 2011. |
| (3) | Prices for all periods presented reflect revenues from gas produced on the West Coast, including natural gas liquids. In previous years, natural gas liquids were reported as gas processing plant revenues as opposed to natural gas revenues. |
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Productive Wells
| Appalachian Region |
West Coast Region |
Total Company | ||||||||||||||||||||||
| At September 30, 2013 |
Gas | Oil | Gas | Oil | Gas | Oil | ||||||||||||||||||
| Productive Wells — Gross |
2,902 | 1 | — | 1,895 | 2,902 | 1,896 | ||||||||||||||||||
| Productive Wells — Net |
2,849 | 1 | — | 1,866 | 2,849 | 1,867 | ||||||||||||||||||
Developed and Undeveloped Acreage
| At September 30, 2013 |
Appalachian Region |
West Coast Region |
Total Company |
|||||||||
| Developed Acreage |
||||||||||||
| — Gross |
558,690 | 21,474 | 580,164 | |||||||||
| — Net |
548,959 | 18,931 | 567,890 | |||||||||
| Undeveloped Acreage |
||||||||||||
| — Gross |
377,657 | 27,576 | 405,233 | |||||||||
| — Net |
359,108 | 14,695 | 373,803 | |||||||||
| Total Developed and Undeveloped Acreage |
||||||||||||
| — Gross |
936,347 | 49,050 | 985,397 | |||||||||
| — Net |
908,067 | 33,626 | 941,693 | |||||||||
As of September 30, 2013, the aggregate amount of gross undeveloped acreage expiring in the next three years and thereafter are as follows: 6,400 acres in 2014 (4,818 net acres), 20,434 acres in 2015 (17,689 net acres), 8,112 acres in 2016 (6,442 net acres), and 62,778 acres thereafter (50,314 net acres). The remaining 307,509 gross acres (294,540 net acres) represent non-expiring oil and gas rights owned by the Company.
Drilling Activity
| Productive | Dry | |||||||||||||||||||||||
| For the Year Ended September 30 |
2013 | 2012 | 2011 | 2013 | 2012 | 2011 | ||||||||||||||||||
| United States |
||||||||||||||||||||||||
| Appalachian Region |
||||||||||||||||||||||||
| Net Wells Completed |
||||||||||||||||||||||||
| — Exploratory |
— | 7.00 | 13.00 | 1.00 | — | — | ||||||||||||||||||
| — Development |
39.50 | 50.50 | 48.76 | 2.50 | 2.00 | — | ||||||||||||||||||
| West Coast Region |
||||||||||||||||||||||||
| Net Wells Completed |
||||||||||||||||||||||||
| — Exploratory |
0.63 | — | 0.25 | — | — | — | ||||||||||||||||||
| — Development |
75.00 | 56.99 | 43.31 | — | — | — | ||||||||||||||||||
| Gulf Coast Region |
||||||||||||||||||||||||
| Net Wells Completed |
||||||||||||||||||||||||
| — Exploratory |
— | — | — | — | — | — | ||||||||||||||||||
| — Development |
— | — | 0.40 | — | — | — | ||||||||||||||||||
| Total Company |
||||||||||||||||||||||||
| Net Wells Completed |
||||||||||||||||||||||||
| — Exploratory |
0.63 | 7.00 | 13.25 | 1.00 | — | — | ||||||||||||||||||
| — Development |
114.50 | 107.49 | 92.47 | 2.50 | 2.00 | — | ||||||||||||||||||
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Present Activities
| At September 30, 2013 |
Appalachian Region |
West Coast Region |
Total Company |
|||||||||
| Wells in Process of Drilling(1) |
||||||||||||
| — Gross |
76.00 | — | 76.00 | |||||||||
| — Net |
61.00 | — | 61.00 | |||||||||
| (1) | Includes wells awaiting completion. |
| Item 3 | Legal Proceedings |
On November 14, 2012, the PaDEP sent a draft Consent Assessment of Civil Penalty to a subsidiary of Midstream Corporation. The draft consent offers 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 amount of the penalty sought by the PaDEP is not material to the Company. The Company disputes many of the alleged violations and will vigorously defend its position in negotiations with the PaDEP. The alleged violations occurred during construction of the Company’s Trout Run Gathering System following historic rainfall and flooding in the fall of 2011. The Company has spent over $128 million in constructing this project.
On August 7, 2013, the PaDEP sent a draft Consent Assessment of Civil Penalty to Seneca, alleging certain violations of state laws and regulations relating to Seneca’s drilling activities. The draft consent addressed environmental and administrative violations identified by PaDEP during inspections of 15 well sites in four counties over the course of nearly three years. In October 2013, Seneca settled this matter with the PaDEP and paid a civil penalty of $198,500.
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. In addition to these matters, the Company is involved in other litigation and regulatory matters arising in the normal course of business. These other matters may include, for example, negligence claims and tax, regulatory or other governmental audits, inspections, investigations or other proceedings. These matters may involve state and federal taxes, safety, compliance with regulations, rate base, cost of service, and purchased gas cost issues, among other things. While these normal-course matters could have a material effect on earnings and cash flows in the quarterly and annual period in which they are resolved, they are not expected to change materially the Company’s present liquidity position, nor are they expected to have a material adverse effect on the financial condition of the Company.
| Item 4 | Mine Safety Disclosures |
Not Applicable.
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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, 2013, 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, 2013. 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, 2013 |
5,679 | $ | 62.82 | — | 6,971,019 | |||||||||||
| Aug. 1-31, 2013 |
9,674 | $ | 65.56 | — | 6,971,019 | |||||||||||
| Sept. 1-30, 2013 |
6,891 | $ | 67.35 | — | 6,971,019 | |||||||||||
|
|
|
|||||||||||||||
| Total |
22,244 | $ | 65.42 | — | 6,971,019 | |||||||||||
|
|
|
|||||||||||||||
| (a) | Represents (i) shares of common stock of the Company purchased on the open market with Company “matching contributions” for the accounts of participants in the Company’s 401(k) plans, and (ii) shares of common stock of the Company tendered to the Company by holders of stock options, SARs or shares of restricted stock for the payment of option exercise prices or applicable withholding taxes. During the quarter ended September 30, 2013, the Company did not purchase any shares of its common stock pursuant to its publicly announced share repurchase program. Of the 22,244 shares purchased other than through a publicly announced share repurchase program, 16,784 were purchased for the Company’s 401(k) plans and 5,460 were purchased as a result of shares tendered to the Company by holders of stock options, SARs or shares of restricted stock. |
| (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. |
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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, 2008 through September 30, 2013. The graph assumes that the value of the investment in the Company’s common stock and in each index was $100 on September 30, 2008 and that all dividends were reinvested.
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.
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| Item 6 | Selected Financial Data |
| Year Ended September 30 | ||||||||||||||||||||
| 2013 | 2012 | 2011 | 2010 | 2009 | ||||||||||||||||
| (Thousands, except per share amounts and number of registered shareholders) | ||||||||||||||||||||
| Summary of Operations |
||||||||||||||||||||
| Operating Revenues |
$ | 1,829,551 | $ | 1,626,853 | $ | 1,778,842 | $ | 1,760,503 | $ | 2,051,543 | ||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Operating Expenses: |
||||||||||||||||||||
| Purchased Gas |
460,432 | 415,589 | 628,732 | 658,432 | 997,216 | |||||||||||||||
| Operation and Maintenance |
442,090 | 401,397 | 400,519 | 394,569 | 401,200 | |||||||||||||||
| Property, Franchise and Other Taxes |
82,431 | 90,288 | 81,902 | 75,852 | 72,102 | |||||||||||||||
| Depreciation, Depletion and Amortization |
326,760 | 271,530 | 226,527 | 191,199 | 170,620 | |||||||||||||||
| Impairment of Oil and Gas Producing Properties |
— | — | — | — | 182,811 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| 1,311,713 | 1,178,804 | 1,337,680 | 1,320,052 | 1,823,949 | ||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Operating Income |
517,838 | 448,049 | 441,162 | 440,451 | 227,594 | |||||||||||||||
| Other Income (Expense): |
||||||||||||||||||||
| Gain on Sale of Unconsolidated Subsidiaries |
— | — | 50,879 | — | — | |||||||||||||||
| Impairment of Investment in Partnership |
— | — | — | — | (1,804 | ) | ||||||||||||||
| Other Income |
4,697 | 5,133 | 5,947 | 6,126 | 11,566 | |||||||||||||||
| Interest Income |
4,335 | 3,689 | 2,916 | 3,729 | 5,776 | |||||||||||||||
| Interest Expense on Long-Term Debt |
(90,273 | ) | (82,002 | ) | (73,567 | ) | (87,190 | ) | (79,419 | ) | ||||||||||
| Other Interest Expense |
(3,838 | ) | (4,238 | ) | (4,554 | ) | (6,756 | ) | (7,370 | ) | ||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Income from Continuing Operations Before Income Taxes |
432,759 | 370,631 | 422,783 | 356,360 | 156,343 | |||||||||||||||
| Income Tax Expense |
172,758 | 150,554 | 164,381 | 137,227 | 52,859 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Income from Continuing Operations |
260,001 | 220,077 | 258,402 | 219,133 | 103,484 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Discontinued Operations: |
||||||||||||||||||||
| Income (Loss) from Operations, Net of Tax |
— | — | — | 470 | (2,776 | ) | ||||||||||||||
| Gain on Disposal, Net of Tax |
— | — | — | 6,310 | — | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Income (Loss) from Discontinued Operations, Net of Tax |
— | — | — | 6,780 | (2,776 | ) | ||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Net Income Available for Common Stock |
$ | 260,001 | $ | 220,077 | $ | 258,402 | $ | 225,913 | $ | 100,708 | ||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Per Common Share Data |
||||||||||||||||||||
| Basic Earnings from Continuing Operations per Common Share |
$ | 3.11 | $ | 2.65 | $ | 3.13 | $ | 2.70 | $ | 1.29 | ||||||||||
| Diluted Earnings from Continuing Operations per Common Share |
$ | 3.08 | $ | 2.63 | $ | 3.09 | $ | 2.65 | $ | 1.28 | ||||||||||
| Basic Earnings per Common Share(1) |
$ | 3.11 | $ | 2.65 | $ | 3.13 | $ | 2.78 | $ | 1.26 | ||||||||||
| Diluted Earnings per Common Share(1) |
$ | 3.08 | $ | 2.63 | $ | 3.09 | $ | 2.73 | $ | 1.25 | ||||||||||
| Dividends Declared |
$ | 1.48 | $ | 1.44 | $ | 1.40 | $ | 1.36 | $ | 1.32 | ||||||||||
| Dividends Paid |
$ | 1.47 | $ | 1.43 | $ | 1.39 | $ | 1.35 | $ | 1.31 | ||||||||||
| Dividend Rate at Year-End |
$ | 1.50 | $ | 1.46 | $ | 1.42 | $ | 1.38 | $ | 1.34 | ||||||||||
| At September 30: |
||||||||||||||||||||
| Number of Registered Shareholders |
13,215 | 13,800 | 14,355 | 15,549 | 16,098 | |||||||||||||||
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| Year Ended September 30 | ||||||||||||||||||||
| 2013 | 2012 | 2011 | 2010 | 2009 | ||||||||||||||||
| (Thousands, except per share amounts and number of registered shareholders) | ||||||||||||||||||||
| Net Property, Plant and Equipment |
||||||||||||||||||||
| Utility |
$ | 1,246,943 | $ | 1,217,431 | $ | 1,189,030 | $ | 1,165,240 | $ | 1,144,002 | ||||||||||
| Pipeline and Storage |
1,074,079 | 1,069,070 | 954,554 | 858,231 | 839,424 | |||||||||||||||
| Exploration and Production |
2,600,448 | 2,273,030 | 1,753,194 | 1,338,956 | 1,041,846 | |||||||||||||||
| Energy Marketing |
2,002 | 1,530 | 850 | 436 | 71 | |||||||||||||||
| Gathering |
161,111 | 110,269 | 31,962 | 15,585 | 8,116 | |||||||||||||||
| All Other(2) |
62,554 | 63,245 | 65,266 | 65,518 | 92,988 | |||||||||||||||
| Corporate |
4,589 | 5,228 | 5,668 | 6,263 | 6,915 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Total Net Plant |
$ | 5,151,726 | $ | 4,739,803 | $ | 4,000,524 | $ | 3,450,229 | $ | 3,133,362 | ||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Total Assets |
$ | 6,218,347 | $ | 5,935,142 | $ | 5,221,084 | $ | 5,047,054 | $ | 4,769,129 | ||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Capitalization |
||||||||||||||||||||
| Comprehensive Shareholders’ Equity |
$ | 2,194,729 | $ | 1,960,095 | $ | 1,891,885 | $ | 1,745,971 | $ | 1,589,236 | ||||||||||
| Long-Term Debt, Net of Current Portion |
1,649,000 | 1,149,000 | 899,000 | 1,049,000 | 1,249,000 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Total Capitalization |
$ | 3,843,729 | $ | 3,109,095 | $ | 2,790,885 | $ | 2,794,971 | $ | 2,838,236 | ||||||||||
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|
|
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| (1) | Includes discontinued operations. |
| (2) | Includes net plant of landfill gas discontinued operations as follows: $0 for 2013, 2012, 2011 and 2010 and $9,296 for 2009. |
| Item 7 | Management’s Discussion and Analysis of Financial Condition and Results of Operations |
OVERVIEW
The Company is a diversified energy company and reports financial results for five business segments: Utility, Pipeline and Storage, Exploration and Production, Energy Marketing, and Gathering. Prior to this Form 10-K, the Company had reported financial results for Midstream Corporation within the All Other category, however Midstream Corporation’s financial results are now presented as the Gathering segment. Strong growth in Marcellus Shale production within the Appalachian region and recent and projected growth in gathering facilities led to the decision to report Midstream Corporation’s financial results as a separate segment. Prior year segment information has been restated to reflect this change in presentation. 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) 2013 and projected 2014 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. |
The information in MD&A should be read in conjunction with the Company’s financial statements in Item 8 of this report.
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For the year ended September 30, 2013 compared to the year ended September 30, 2012, the Company experienced an increase in earnings of $39.9 million. The earnings increase reflects increases in all of the Company’s segments. For further discussion of the Company’s earnings, refer to the Results of Operations section below.
The Company’s natural gas reserve base has grown substantially in recent years 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 775,000 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 925 Bcf at September 30, 2012 to 1,239 Bcf at September 30, 2013. The Company has spent significant amounts of capital in this region related to the development of such reserves. For the year ended September 30, 2013, the Company’s Exploration and Production segment had capital expenditures of $428.5 million in the Appalachian region, of which $393.3 million was spent towards the development of the Marcellus Shale. The Company’s fiscal 2014 estimated capital expenditures in the Exploration and Production segment’s Appalachian region are expected to be approximately $530.1 million. Forecasted production in the Exploration and Production segment’s Appalachian region for fiscal 2014 is expected to be in the range of 125 to 143 Bcfe, up from actual production of 101 Bcfe in fiscal 2013.
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. In February 2013, the Company issued $500.0 million of 3.75% notes due in March 2023 to, among other matters, refund $250.0 million of 5.25% notes that matured in March 2013 and to reduce short-term debt. It is expected that the Company will use short-term debt as necessary during fiscal 2014 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. Hydraulic fracturing is a well stimulation technique that has been used for many years, and in the Company’s experience, one that the Company believes has little negative impact to the environment. Nonetheless, 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 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,
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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, 2013, the ceiling exceeded the book value of the Company’s oil and gas properties by approximately $159.4 million. The 12-month average of the first day of the month price for crude oil for each month during 2013, based on posted Midway Sunset prices, was $101.52 per Bbl. The 12-month average of the first day of the month price for natural gas for each month during 2013, based on the quoted Henry Hub spot price for natural gas, was $3.605 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 2013.) If natural gas average prices used in the ceiling test calculation at September 30, 2013 had been $1 per MMBtu lower, the book value of the Company’s oil and gas properties would have exceeded the ceiling by approximately $135.5 million, which would have resulted in an impairment charge. If crude oil average prices used in the ceiling test calculation at September 30, 2013 had been $5 per Bbl lower, the ceiling would have exceeded the book value of the Company’s oil and gas properties by approximately $118.1 million which would not have resulted in an impairment charge. If both natural gas and crude oil average prices used in the ceiling test
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calculation at September 30, 2013 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 $176.7 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. Some instruments are accounted for as economic hedges. Gains or losses on economic hedges are marked-to-market. As discussed below, the Company recorded pre-tax mark to market losses of $3.7 million in its Exploration and Production segment in 2013. This included $1.7 million associated with economic hedges that do not qualify as cash flow or fair value hedges.
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The Company uses both exchange-traded and non exchange-traded derivative financial instruments. The Company follows the authoritative guidance for fair value measurements. As such, the fair value of such derivative financial instruments is determined under the provisions of this guidance. The fair value of exchange traded derivative financial instruments is determined from Level 1 inputs, which are quoted prices in active markets. The Company determines the fair value of non exchange-traded derivative financial instruments based on an internal model, which uses both observable and unobservable inputs other than quoted prices. These inputs are considered Level 2 or Level 3 inputs. All derivative financial instrument assets and liabilities are evaluated for the probability of default by either the counterparty or the Company. Credit reserves are applied against the fair values of such assets or liabilities. Refer to the “Market Risk Sensitive Instruments” section below for further discussion of the Company’s derivative financial instruments.
Pension and Other Post-Retirement Benefits. The amounts reported in the Company’s financial statements related to its pension and other post-retirement benefits are determined on an actuarial basis, which uses many assumptions in the calculation of such amounts. These assumptions include the discount rate, the expected return on plan assets, the rate of compensation increase and, for other post-retirement benefits, the expected annual rate of increase in per capita cost of covered medical and prescription benefits. 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 3.50% in 2012 to 4.75% in 2013. The change in the discount rate from 2012 to 2013 decreased the Retirement Plan projected benefit obligation by $147.9 million and the accumulated post-retirement benefit obligation by $75.9 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 2013, the actual return on plan assets exceeded the expected return, which improved the funded status of the Retirement Plan ($41.4 million) as well as the VEBA trusts and 401(h) accounts ($28.8 million). The actual versus expected benefit payments for 2013 caused a decrease of $4.6 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 8 years for the Retirement Plan and 7 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.
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RESULTS OF OPERATIONS
EARNINGS
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. 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 2013 and 2012:
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. |
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. See further discussion of the impact fee that follows under the heading “Exploration and Production.” |
2012 Compared with 2011
The Company’s earnings were $220.1 million in 2012 compared with earnings of $258.4 million in 2011. The decrease in earnings of $38.3 million is primarily the result of lower earnings in the All Other category, Exploration and Production segment, Utility segment and Energy Marketing segment. Higher earnings in the Pipeline and Storage segment and the Gathering segment, as well as a lower loss in the Corporate category partly offset these decreases. Earnings were impacted by the 2012 events discussed above and the following event in 2011:
2011 Event
| • | A $50.9 million ($31.4 million after tax) gain on the sale of unconsolidated subsidiaries as a result of the Company’s sale of its 50% equity method investments in Seneca Energy and Model City. |
Earnings (Loss) by Segment
| Year Ended September 30 | ||||||||||||
| 2013 | 2012 | 2011 | ||||||||||
| (Thousands) | ||||||||||||
| Utility |
$ | 65,686 | $ | 58,590 | $ | 63,228 | ||||||
| Pipeline and Storage |
63,245 | 60,527 | 31,515 | |||||||||
| Exploration and Production |
115,391 | 96,498 | 124,189 | |||||||||
| Energy Marketing |
4,589 | 4,169 | 8,801 | |||||||||
| Gathering |
13,321 | 6,855 | 4,873 | |||||||||
|
|
|
|
|
|
|
|||||||
| Total Reported Segments |
262,232 | 226,639 | 232,606 | |||||||||
| All Other |
894 | 13 | 33,629 | |||||||||
| Corporate |
(3,125 | ) | (6,575 | ) | (7,833 | ) | ||||||
|
|
|
|
|
|
|
|||||||
| Total Consolidated |
$ | 260,001 | $ | 220,077 | $ | 258,402 | ||||||
|
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UTILITY
Revenues
Utility Operating Revenues
| Year Ended September 30 | ||||||||||||
| 2013 | 2012 | 2011 | ||||||||||
| (Thousands) | ||||||||||||
| Retail Revenues: |
||||||||||||
| Residential |
$ | 513,654 | $ | 493,354 | $ | 603,838 | ||||||
| Commercial |
66,602 | 61,314 | 80,811 | |||||||||
| Industrial |
6,096 | 5,359 | 5,849 | |||||||||
|
|
|
|
|
|
|
|||||||
| 586,352 | 560,027 | 690,498 | ||||||||||
|
|
|
|
|
|
|
|||||||
| Off-System Sales |
25,020 | 27,010 | 33,968 | |||||||||
| Transportation |
135,273 | 122,316 | 123,729 | |||||||||
| Other |
(306 | ) | 9,769 | 4,300 | ||||||||
|
|
|
|
|
|
|
|||||||
| $ | 746,339 | $ | 719,122 | $ | 852,495 | |||||||
|
|
|
|
|
|
|
|||||||
Utility Throughput — million cubic feet (MMcf)
| Year Ended September 30 | ||||||||||||
| 2013 | 2012 | 2011 | ||||||||||
| Retail Sales: |
||||||||||||
| Residential |
52,753 | 47,036 | 57,466 | |||||||||
| Commercial |
7,486 | 6,682 | 8,517 | |||||||||
| Industrial |
947 | 837 | 723 | |||||||||
|
|
|
|
|
|
|
|||||||
| 61,186 | 54,555 | 66,706 | ||||||||||
|
|
|
|
|
|
|
|||||||
| Off-System Sales |
6,717 | 9,544 | 7,151 | |||||||||
| Transportation |
69,149 | 61,027 | 66,273 | |||||||||
|
|
|
|
|
|
|
|||||||
| 137,052 | 125,126 | 140,130 | ||||||||||
|
|
|
|
|
|
|
|||||||
Degree Days
| Percent (Warmer) Colder Than |
||||||||||||||||||||
| Year Ended September 30 |
Normal | Actual | Normal | Prior Year |
||||||||||||||||
| 2013(1): |
Buffalo | 6,617 | 6,139 | (7.2 | )% | 15.9 | % | |||||||||||||
| Erie | 6,147 | 5,888 | (4.2 | )% | 17.8 | % | ||||||||||||||
| 2012(2): |
Buffalo | 6,729 | 5,296 | (21.3 | )% | (21.6 | )% | |||||||||||||
| Erie | 6,277 | 4,999 | (20.4 | )% | (21.4 | )% | ||||||||||||||
| 2011(3): |
Buffalo | 6,692 | 6,751 | 0.9 | % | 7.3 | % | |||||||||||||
| Erie | 6,243 | 6,359 | 1.9 | % | 6.9 | % | ||||||||||||||
| (1) | 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. |
| (2) | 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. |
| (3) | Percents compare actual 2011 degree days to normal degree days and actual 2011 degree days to actual 2010 degree days. |
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Table of Contents
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 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.
2012 Compared with 2011
Operating revenues for the Utility segment decreased $133.4 million in 2012 compared with 2011. This decrease largely resulted from a $130.5 million decrease in retail gas sales revenues and a $7.0 million decrease in off-system sales revenue. These were partially offset by a $5.5 million increase in other operating revenues.
The $130.5 million decrease in retail gas sales revenues was largely a function of lower volume (12.2 Bcf) due to warmer weather combined with the recovery of lower gas costs. Subject to certain timing variations, gas costs are recovered dollar for dollar in customer rates. See further discussion of purchased gas below under the heading “Purchased Gas.” The $7.0 million decrease in off-system sales was largely the result of a change in gas purchase strategy whereby Distribution Corporation eliminated contractual commitments to purchase gas from the southwest region of the United States during the April through October time period. With the elimination of such commitments, there was a corresponding reduction in the ability to conduct off-system sales during that period. Due to profit sharing with retail customers, the margins resulting from off-system sales are minimal and there is not a material impact to margins. The $5.5 million increase in other operating revenues largely reflects the fact that there was a downward adjustment to the carrying value of certain regulatory asset accounts in the fourth quarter of 2011 that did not recur in 2012.
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 $362.3 million, $340.3 million and $460.1 million of Purchased Gas expense during 2013, 2012 and 2011, 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
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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
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.
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 addition, in periods of colder than normal weather, the WNC benefits the Utility segment’s New York customers. For 2013 and 2012, the WNC preserved earnings of approximately $2.1 million and $5.9 million, respectively, as the weather was warmer than normal.
2012 Compared with 2011
The Utility segment’s earnings in 2012 were $58.6 million, a decrease of $4.6 million when compared with earnings of $63.2 million in 2011. The decrease in earnings was largely attributable to warmer weather ($10.1 million) and higher depreciation of $1.3 million (largely the result of depreciation adjustments for certain assets). These decreases were partially offset by regulatory true-up adjustments of $2.5 million (mostly due to adjustments of the carrying value of regulatory assets discussed above), lower income tax expense of $1.1 million (as a result of the benefits associated with the tax sharing agreement with affiliated companies), the positive earnings impact of lower interest expense of $0.8 million (largely due to lower interest on deferred gas costs), lower property, franchise and other taxes of $0.9 million, higher interest income of $0.6 million (due to higher money market investment balances) and lower operating expenses of $0.3 million (largely due to decreased bad debt expense). The decrease in property, franchise and other taxes, which includes FICA taxes, was largely due to lower personnel costs and lower property taxes (as a result of a decrease in assessed property values).
For 2011, the WNC reduced earnings by approximately $1.0 million, as the weather was colder than normal.
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PIPELINE AND STORAGE
Revenues
Pipeline and Storage Operating Revenues
| Year Ended September 30 | ||||||||||||
| 2013 | 2012 | 2011 | ||||||||||
| (Thousands) | ||||||||||||
| Firm Transportation |
$ | 190,470 | $ | 164,652 | $ | 134,652 | ||||||
| Interruptible Transportation |
2,152 | 1,431 | 1,341 | |||||||||
|
|
|
|
|
|
|
|||||||
| 192,622 | 166,083 | 135,993 | ||||||||||
|
|
|
|
|
|
|
|||||||
| Firm Storage Service |
70,555 | 67,929 | 66,712 | |||||||||
| Interruptible Storage Service |
5 | 7 | 19 | |||||||||
|
|
|
|
|
|
|
|||||||
| 70,560 | 67,936 | 66,731 | ||||||||||
| Other |
4,426 | 25,256 | 12,384 | |||||||||
|
|
|
|
|
|
|
|||||||
| $ | 267,608 | $ | 259,275 | $ | 215,108 | |||||||
|
|
|
|
|
|
|
|||||||
Pipeline and Storage Throughput — (MMcf)
| Year Ended September 30 | ||||||||||||
| 2013 | 2012 | 2011 | ||||||||||
| Firm Transportation |
575,805 | 369,477 | 317,917 | |||||||||
| Interruptible Transportation |
3,997 | 1,662 | 2,037 | |||||||||
|
|
|
|
|
|
|
|||||||
| 579,802 | 371,139 | 319,954 | ||||||||||
|
|
|
|
|
|
|
|||||||
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. The Line N 2012 Expansion Project and the Northern Access expansion project are discussed in the Investing Cash Flow section that follows. 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. The rate case and the settlement are discussed further in Item 8 at Note C – Regulatory Matters.
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. Volume fluctuations generally do not have a significant impact on revenues as a result of the straight fixed-variable rate design utilized by Supply Corporation and Empire.
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Table of Contents
2012 Compared with 2011
Operating revenues for the Pipeline and Storage segment increased $44.2 million in 2012 as compared with 2011. The increase was primarily due to an increase in transportation revenues of $30.1 million and an increase in storage revenues of $1.2 million. The increase in transportation revenues was largely due to new contracts for transportation service on Supply Corporation’s Line N Expansion Project, which was placed in service in October 2011, and Empire’s Tioga County Extension Project, which was placed in service in November 2011. Both 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, as noted above. These increases more than offset a reduction in transportation revenues due to the turnback of other pipeline capacity at Niagara. Other operating revenues increased due to Supply Corporation’s elimination of a $21.7 million regulatory liability associated with post-retirement benefits. The elimination of this regulatory liability was specified in Supply Corporation’s rate case settlement. Partially offsetting these increases was a decrease in efficiency gas revenues of $9.3 million (reported as a part of other revenue in the table above) resulting from lower natural gas prices, lower efficiency gas volume and adjustments to reduce the carrying value of Supply Corporation’s efficiency gas inventory to market value during the year ended September 30, 2012. The decrease in efficiency gas volume is a result of the implementation of Supply Corporation’s rate settlement in May 2012. Prior to May 2012, under Supply Corporation’s previous tariff with shippers, Supply Corporation was allowed to retain a set percentage of shipper-supplied gas as compressor fuel and for other operational purposes. To the extent that Supply Corporation did not utilize all of the gas to cover such operational needs, it was allowed to keep the excess gas as inventory. That inventory would later be sold to buyers on the open market. The excess gas that was retained as inventory, as well as any gains resulting from the sale of such inventory, represented efficiency gas revenue to Supply Corporation. Effective with the implementation of the rate settlement mentioned above, Supply Corporation implemented a tracking mechanism to adjust fuel retention rates annually to reflect actual experience, replacing the previously fixed fuel retention rates, thus eliminating the impact efficiency gas had to revenues and earnings prior to the rate settlement.
Transportation volume increased by 51.2 Bcf in 2012 as compared with 2011. Higher transportation volume for power generation on Empire’s system during the spring and summer of fiscal 2012 more than offset lower transportation volume experienced by both Supply Corporation and Empire during the fall and winter of fiscal 2012 due to warmer weather. As discussed above, volume fluctuations generally do not have a significant impact on revenues as a result of the straight fixed-variable rate design utilized by Supply Corporation and Empire.
Earnings
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
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Northern Access expansion project, which were under construction in the prior year and have since been placed in service, 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.
2012 Compared with 2011
The Pipeline and Storage segment’s earnings in 2012 were $60.5 million, an increase of $29.0 million when compared with earnings of $31.5 million in 2011. The increase in earnings was primarily due to the earnings impact of higher transportation and storage revenues of $20.3 million and the earnings impact associated with the elimination of Supply Corporation’s post-retirement regulatory liability ($12.8 million), all of which are discussed above, combined with lower operating expenses ($2.7 million) and an increase in the allowance for funds used during construction (equity component) of $0.6 million mainly due to construction during the year ended September 30, 2012 on Supply Corporation’s Northern Access and Line N 2012 expansion projects as well as Empire’s Tioga County Extension Project. The decrease in operating expenses can be attributed primarily to a decrease in other post-retirement benefits expense, a decline in compressor station maintenance costs and a decrease in the reserve for preliminary project costs. The decrease in other post-retirement benefits expense reflects the implementation of Supply Corporation’s rate settlement. These earnings increases were partially offset by the earnings impact associated with lower efficiency gas revenues ($6.1 million), as discussed above, higher depreciation expense ($0.6 million) and higher property taxes ($0.4 million). The increase in depreciation expense was mostly the result of additional projects that were placed in service in the last year offset partially by a decrease in depreciation rates as of May 2012 as a result of Supply Corporation’s rate case settlement.
EXPLORATION AND PRODUCTION
Revenues
Exploration and Production Operating Revenues
| Year Ended September 30 | ||||||||||||
| 2013 | 2012 | 2011 | ||||||||||
| (Thousands) | ||||||||||||
| Gas (after Hedging) |
$ | 424,735 | $ | 292,311 | $ | 282,646 | ||||||
| Oil (after Hedging) |
278,005 | 260,844 | 232,052 | |||||||||
| Gas Processing Plant |
4,502 | 4,813 | 3,824 | |||||||||
| Other |
(4,305 | ) | 212 | 513 | ||||||||
|
|
|
|
|
|
|
|||||||
| Operating Revenues |
$ | 702,937 | $ | 558,180 | $ | 519,035 | ||||||
|
|
|
|
|
|
|
|||||||
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Production
| Year Ended September 30 | ||||||||||||
| 2013 | 2012 | 2011 | ||||||||||
| Gas Production (MMcf) |
||||||||||||
| Appalachia |
100,633 | 62,663 | 42,979 | |||||||||
| West Coast |
3,060 | 3,468 | 3,447 | |||||||||
| Gulf Coast |
— | — | 4,041 | |||||||||
|
|
|
|
|
|
|
|||||||
| Total Production |
103,693 | 66,131 | 50,467 | |||||||||
|
|
|
|
|
|
|
|||||||
| Oil Production (Mbbl) |
||||||||||||
| Appalachia |
28 | 36 | 45 | |||||||||
| West Coast |
2,803 | 2,834 | 2,628 | |||||||||
| Gulf Coast |
— | — | 187 | |||||||||
|
|
|
|
|
|
|
|||||||
| Total Production |
2,831 | 2,870 | 2,860 | |||||||||
|
|
|
|
|
|
|
|||||||
Average Prices
| Year Ended September 30 | ||||||||||||
| 2013 | 2012 | 2011 | ||||||||||
| Average Gas Price/Mcf |
||||||||||||
| Appalachia |
$ | 3.49 | $ | 2.71 | $ | 4.37 | ||||||
| West Coast(1) |
$ | 6.61 | $ | 6.27 | $ | 7.63 | ||||||
| Gulf Coast |
— | — | $ | 5.02 | ||||||||
| Weighted Average |
$ | 3.58 | $ | 2.89 | $ | 4.64 | ||||||
| Weighted Average After Hedging(2) |
$ | 4.10 | $ | 4.42 | $ | 5.60 | ||||||
| Average Oil Price/Barrel (bbl) |
||||||||||||
| Appalachia |
$ | 96.48 | $ | 93.94 | $ | 86.58 | ||||||
| West Coast |
$ | 103.14 | $ | 107.13 | $ | 96.45 | ||||||
| Gulf Coast |
— | — | $ | 88.57 | ||||||||
| Weighted Average |
$ | 103.07 | $ | 106.97 | $ | 95.78 | ||||||
| Weighted Average After Hedging(2) |
$ | 98.21 | $ | 90.88 | $ | 81.13 | ||||||
| (1) | Prices for all periods presented reflect revenues from gas produced on the West Coast, including natural gas liquids. In previous years, natural gas liquids were reported as gas processing plant revenues as opposed to natural gas revenues. |
| (2) | 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. |
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 associated with certain crude oil hedges.
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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.
2012 Compared with 2011
Operating revenues for the Exploration and Production segment increased $39.1 million in 2012 as compared with 2011. Gas production revenue after hedging increased $9.7 million primarily due to production increases in the Appalachian division, partially offset by decreases in Gulf Coast production. The increase in Appalachian production was primarily due to increased development within the Marcellus Shale formation, primarily in Tioga County, Pennsylvania, with additional Marcellus Shale production from Lycoming County, Pennsylvania. The decrease in Gulf Coast gas production resulted from the sale of the Exploration and Production segment’s off-shore oil and natural gas properties in April 2011. Increases in natural gas production were partially offset by a $1.18 per Mcf decrease in the weighted average price of gas after hedging. Oil production revenue after hedging increased $28.8 million due to an increase in the weighted average price of oil after hedging ($9.75 per Bbl). Oil production was largely flat year over year, as increased oil production from West Coast properties was largely offset by the decrease in this segment’s off-shore oil production as a result of the aforementioned sale.
Earnings
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, as discussed below. 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. 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.
2012 Compared with 2011
The Exploration and Production segment’s earnings for 2012 were $96.5 million, compared with earnings of $124.2 million for 2011, a decrease of $27.7 million. The main drivers of the decrease were lower natural gas prices after hedging in the Appalachian and West Coast regions ($51.1 million), lower Gulf Coast natural gas and crude oil revenues as a result of this segment’s sale of its off-shore oil and natural gas properties in 2011 ($25.2 million), and higher depletion expense ($26.5 million). In addition, higher interest expense ($7.3 million), higher production costs ($6.6 million), higher property and other taxes ($7.4 million), higher income taxes ($3.2 million), and higher general, administrative and other expenses ($2.7 million) further reduced earnings. The increase in depletion expense is primarily due to an increase in
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Table of Contents
depletable base (largely due to increased capital spending in the Appalachian region, specifically related to the development of Marcellus Shale properties) and increased Appalachian natural gas production (primarily in the Marcellus Shale formation). 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 ($470 million) of the $500 million long-term debt issuance in December 2011). The increase in lease operating expense is largely attributable to higher transportation, compression costs, water disposal, equipment rental and repair costs in the Appalachian region. The increase in property and other taxes was largely due to the accrual of a new impact fee imposed by Pennsylvania in 2012. In February 2012, the Commonwealth of Pennsylvania passed legislation that includes a “natural gas impact fee.” The legislation, which covers essentially all of Seneca’s Marcellus Shale wells, imposes an annual fee for a period of 15 years on each well drilled. The per well impact fee is adjusted annually based on three factors: the age of the well, changes in the Consumer Price Index and the average monthly NYMEX price for natural gas. The fee is retroactive and applied to wells drilled in the current fiscal year and in all previous years. The impact fee increased property, franchise and other taxes in 2012 by $9.0 million, of which $4.0 million related to wells drilled prior to 2012. The increase in income taxes was largely due to higher state income taxes, which was largely the result of a larger percentage of production in higher state income tax jurisdictions in 2012 as compared to 2011. Higher personnel costs led to increases in general, administrative and other operating expenses. These earnings decreases were partially offset by higher natural gas production of $71.8 million, as well as higher crude oil prices and crude oil production of $19.1 million and $10.3 million, respectively (all amounts exclude the impact of the 2011 sale of Gulf Coast properties). Higher interest income of $0.6 million also benefitted earnings. The increase in interest income was largely due to higher money market investment balances.
ENERGY MARKETING
Revenues
Energy Marketing Operating Revenues
| Year Ended September 30 | ||||||||||||
| 2013 | 2012 | 2011 | ||||||||||
| (Thousands) | ||||||||||||
| Natural Gas (after Hedging) |
$ | 213,324 | $ | 187,969 | $ | 284,916 | ||||||
| Other |
50 | 35 | 50 | |||||||||
|
|
|
|
|
|
|
|||||||
| $ | 213,374 | $ | 188,004 | $ | 284,966 | |||||||
|
|
|
|
|
|
|
|||||||
Energy Marketing Volume
| Year Ended September 30 | ||||||||||||
| 2013 | 2012 | 2011 | ||||||||||
| Natural Gas — (MMcf) |
46,875 | 45,756 | 52,893 | |||||||||
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.
2012 Compared with 2011
Operating revenues for the Energy Marketing segment decreased $97.0 million in 2012 as compared with 2011. The decrease reflected a decline in gas sales revenue due to a lower average price of natural gas and a decrease in volume sold. Much warmer weather was primarily responsible for the decrease in volume sold.
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Earnings
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.
2012 Compared with 2011
The Energy Marketing segment’s earnings in 2012 were $4.2 million, a decrease of $4.6 million when compared with earnings of $8.8 million in 2011. This decrease was largely attributable to a decline in margin of $4.5 million, primarily driven by lower volume sold to retail customers as well as a reduction in the benefit the Energy Marketing segment derived from its contracts for storage capacity.
GATHERING
Revenues
Gathering Operating Revenues
| Year Ended September 30 | ||||||||||||
| 2013 | 2012 | 2011 | ||||||||||
| (Thousands) | ||||||||||||
| Gathering |
$ | 33,815 | $ | 16,771 | $ | 10,017 | ||||||
| Processing Revenues |
966 | 704 | 1,234 | |||||||||
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| $ | 34,781 | $ | 17,475 | $ | 11,251 | |||||||
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Gathering Volume — (MMcf)
| Year Ended September 30 | ||||||||||||
| 2013 | 2012 | 2011 | ||||||||||
| Gathered Volume |
93,598 | 48,562 | 29,988 | |||||||||
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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 45.0 Bcf increase in gathered volume. This increase was primarily due to Midstream Corporation’s Trout Run Gathering System (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.
2012 Compared with 2011
Operating revenues for the Gathering segment increased $6.2 million in 2012 as compared with 2011 primarily due to an increase in gathering revenues driven by an 18.6 Bcf increase in gathered volume. The increase was primarily due to the growth in Seneca’s Marcellus Shale production at Covington in Tioga County, Pennsylvania and Trout Run in Lycoming County, Pennsylvania. Trout Run was placed in service in May 2012, as discussed above.
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Earnings
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.
2012 Compared with 2011
The Gathering segment’s earnings in 2012 were $6.9 million, an increase of $2.0 million when compared with earnings of $4.9 million in 2011. The increase in earnings is due to higher gathering revenues ($4.0 million). This was partially offset by higher operating expenses ($0.4 million), higher depreciation expense ($0.7 million), and higher interest expense ($0.9 million). Continued production growth at Covington and the completion of Trout Run in May 2012 are the primary reasons for the revenue, operating expense and depreciation expense variations. 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 the Company’s $500 million long-term debt issuance in December 2011.
ALL OTHER AND CORPORATE OPERATIONS
All Other and Corporate operations primarily includes the operations of Seneca’s Northeast Division, Highland (which was merged into Seneca’s Northeast Division in June 2011) 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 February 2011, Horizon Power sold its 50% equity method investments in Seneca Energy and Model City for $59.4 million. Seneca Energy and Model City generated and sold electricity using methane gas obtained from landfills owned by outside parties. The sale is the result of the Company’s strategy to pursue the sale of smaller, non-core assets in order to focus on its core businesses, including the development of the Marcellus Shale and the expansion of its pipeline business throughout the Appalachian region.
Earnings
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).
2012 Compared with 2011
All Other and Corporate operations recorded a loss of $6.6 million in 2012, a decrease of $32.4 million when compared with earnings of $25.8 million in 2011. The decrease in earnings was primarily due to the
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gain recorded on the sale of Horizon Power’s investments in Seneca Energy and Model City of $31.4 million during the quarter ended March 31, 2011 that did not recur in 2012. In addition, lower income from unconsolidated subsidiaries of $0.4 million further decreased earnings.
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 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.
Interest on long-term debt increased $8.4 million in 2012 as compared to 2011. This increase was primarily the result of a higher average amount of long-term debt outstanding. The Company issued $500 million of notes at 4.90% in December 2011 and repaid $150 million of 6.70% notes that matured in November 2011. This was partially offset by an increase in capitalized interest associated with increased Exploration and Production segment capital expenditures in the Appalachian region, which decreased 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 | ||||||||||||
| 2013 | 2012 | 2011 | ||||||||||
| (Millions) | ||||||||||||
| Provided by Operating Activities |
$ | 738.6 | $ | 659.0 | $ | 654.0 | ||||||
| Capital Expenditures |
(703.5 | ) | (1,035.0 | ) | (814.3 | ) | ||||||
| Net Proceeds from Sale of Unconsolidated Subsidiaries |
— | — | 59.4 | |||||||||
| Net Proceeds from Sale of Oil and Gas Producing Properties |
— | — | 63.5 | |||||||||
| Other Investing Activities |
(2.5 | ) | 0.5 | (2.9 | ) | |||||||
| Reduction of Long-Term Debt |
(250.0 | ) | (150.0 | ) | (200.0 | ) | ||||||
| Change in Notes Payable to Banks and Commercial Paper |
(171.0 | ) | 131.0 | 40.0 | ||||||||
| Net Proceeds from Issuance of Long-Term Debt |
495.4 | 496.1 | — | |||||||||
| Net Proceeds from Issuance (Repurchase) of Common Stock |
5.4 | 10.3 | (0.6 | ) | ||||||||
| Dividends Paid on Common Stock |
(122.7 | ) | (118.8 | ) | (114.6 | ) | ||||||
| Excess Tax (Costs) Benefits Associated with Stock-Based Compensation Awards |
0.7 | 1.0 | (1.2 | ) | ||||||||
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| Net Decrease in Cash and Temporary Cash Investments |
$ | (9.6 | ) | $ | (5.9 | ) | $ | (316.7 | ) | |||
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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 and the elimination of an other post-retirement regulatory liability. Net income available for common stock is also adjusted for the gain on sale of unconsolidated subsidiaries.
Cash provided by operating activities in the Utility and Pipeline and Storage segments may vary substantially from year to year because of the impact of rate cases. In the Utility segment, supplier refunds, over- or under-recovered purchased gas costs and weather may also significantly impact cash flow. The impact of weather on cash flow is tempered in the Utility segment’s New York rate jurisdiction by its WNC and in the Pipeline and Storage segment by the straight fixed-variable rate design used by Supply Corporation and Empire.
Cash provided by operating activities in the Exploration and Production segment may vary from year to year as a result of changes in the commodity prices of natural gas and crude oil as well as changes in production. The Company uses various derivative financial instruments, including price swap agreements and futures contracts in an attempt to manage this energy commodity price risk.
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, as discussed above. 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.
Net cash provided by operating activities totaled $659.0 million in 2012, an increase of $5.0 million compared with the $654.0 million provided by operating activities in 2011. The increase in cash provided by operating activities is primarily due to an increase in cash provided by operations in the Utility segment related to the timing of gas cost recovery. Partly offsetting this increase in cash provided by operating activities, the Exploration and Production segment experienced a decrease in cash provided by operating activities due to the loss of cash flows from the Company’s former oil and natural gas properties in the Gulf of Mexico and the non-recurrence of federal tax refunds in fiscal 2011, partially offset by increases in cash provided by operating activities from hedging collateral account fluctuations and higher cash receipts from oil and natural gas production in the West Coast and Appalachian regions.
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INVESTING CASH FLOW
Expenditures for Long-Lived Assets
The Company’s expenditures for long-lived assets totaled $717.1 million, $977.4 million and $854.2 million in 2013, 2012 and 2011, 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:
| Year Ended September 30 | ||||||||||||
| 2013 | 2012 | 2011 | ||||||||||
| (Millions) | ||||||||||||
| Utility: |
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| Capital Expenditures |
$ | 72.0 | (1) | $ | 58.3 | (2) | $ | 58.4 | (3) | |||
| Pipeline and Storage: |
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| Capital Expenditures |
56.1 | (1) | 144.2 | (2) | 129.2 | (3) | ||||||
| Exploration and Production: |
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| Capital Expenditures |
533.1 | (1) | 693.8 | (2) | 648.8 | (3) | ||||||
| Gathering: |
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| Capital Expenditures |
54.8 | (1) | 80.0 | (2) | 17.0 | (3) | ||||||
| All Other and Corporate: |
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| Capital Expenditures |
1.1 | 1.1 | 0.8 | |||||||||
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| Total Expenditures |
$ | 717.1 | $ | 977.4 | $ | 854.2 | ||||||
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| (1) | 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. |
| (2) | 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. |
| (3) | 2011 capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment include $103.3 million, $16.4 million, $3.1 million and $2.3 million, respectively, of accounts payable and accrued liabilities related to capital expenditures. |
Utility
The majority of the Utility segment’s capital expenditures for 2013, 2012 and 2011 were made for replacement of mains and main extensions and for the replacement of service lines. The capital expenditures for 2013 include $9.1 million related to the planned replacement of the Utility segment’s legacy mainframe systems.
Pipeline and Storage
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), as discussed below.
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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.
The majority of the Pipeline and Storage segment’s capital expenditures for 2011 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 2011 include expenditures for the construction of Empire’s Tioga County Extension Project ($31.8 million), Supply Corporation’s Line N Expansion Project ($18.1 million) and Supply Corporation’s Lamont Phase II Project ($8.1 million).
Exploration and Production
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.
In 2011, the Exploration and Production segment capital expenditures were primarily well drilling and completion expenditures and included approximately $595.8 million for the Appalachian region (including $585.1 million in the Marcellus Shale area), $47.4 million for the West Coast region and $5.6 million for the Gulf Coast region (former off-shore oil and natural gas properties in the Gulf of Mexico). These amounts included approximately $199.2 million spent to develop proved undeveloped reserves. The capital expenditures in the Appalachian region included the Company’s acquisition of oil and gas properties in the Covington Township area of Tioga County, Pennsylvania from EOG Resources, Inc. for approximately $24.1 million in November 2010.
In April 2011, the Company completed the sale of its off-shore oil and natural gas properties in the Gulf of Mexico. The Company received net proceeds of $55.4 million from this sale. Under the full cost method of accounting for oil and natural gas properties, the sale proceeds were accounted for as a reduction of capitalized costs. Since the disposition did not significantly alter the relationship between capitalized costs and proved reserves of oil and gas attributable to the cost center, the Company did not record any gain or loss from this sale.
In May 2011, the Company sold the Sprayberry property that was accounted for in its West Coast region for $8.1 million. Under the full cost method of accounting for oil and natural gas properties, the sale proceeds were accounted for as a reduction of capitalized costs. Since the disposition did not significantly alter the relationship between capitalized costs and proved reserves of oil and gas attributable to the cost center, the Company did not record any gain or loss from this sale.
Gathering
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).
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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).
The majority of the Gathering segment’s capital expenditures for 2011 were related to the construction of Midstream Corporation’s Trout Run Gathering System ($15.4 million) and the expansion of Midstream Corporation’s Covington Gathering System ($1.6 million).
Estimated Capital Expenditures
The Company’s estimated capital expenditures for the next three years are:
| Year Ended September 30 | ||||||||||||
| 2014 | 2015 | 2016 | ||||||||||
| (Millions) | ||||||||||||
| Utility |
$ | 84.8 | $ | 87.7 | $ | 72.1 | ||||||
| Pipeline and Storage |
126.5 | 240.8 | 281.3 | |||||||||
| Exploration and Production(1) |
634.8 | 728.3 | 823.1 | |||||||||
| Gathering |
121.0 | 124.8 | 146.8 | |||||||||
| All Other |
0.6 | 0.4 | 0.3 | |||||||||
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| $ | 967.7 | $ | 1,182.0 | $ | 1,323.6 | |||||||
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| (1) | Includes estimated expenditures for the years ended September 30, 2014, 2015 and 2016 of approximately $169 million, $246 million and $101 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. |
Utility
Capital expenditures for the Utility segment in 2014 through 2016 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 2014 through 2016 also include amounts for the replacement of its legacy mainframe systems.
Pipeline and Storage
Capital expenditures for the Pipeline and Storage segment in 2014 through 2016 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
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component of Property, Plant and Equipment on the Consolidated Balance Sheet. As of September 30, 2013, the total amount reserved for the Pipeline and Storage segment’s preliminary survey and investigation costs was $7.8 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.
Supply Corporation has begun service under a transportation service agreement with Statoil Natural Gas LLC (“Statoil”) which provides 320,000 Dth per day of firm transportation capacity for a 20-year term in conjunction with Supply Corporation’s “Northern Access” expansion project. This capacity provides Statoil with a firm transportation path from the Tennessee Gas Pipeline (“TGP”) 300 Line at Ellisburg and Transcontinental Pipeline at Leidy to the TransCanada Pipeline at Niagara. These receipt points are attractive because they provide routes for Marcellus Shale gas from the TGP 300 Line and Transco Leidy Line in northern Pennsylvania, to be transported from the Marcellus supply basin to northern markets. Supply Corporation received from the FERC its NGA Section 7(c) Certificate authorization of this project on October 20, 2011, and received its Notice to Proceed on April 13, 2012. The project facilities involve approximately 9,500 horsepower of additional compression at Supply Corporation’s existing Ellisburg Station and a new approximately 5,000 horsepower compressor station in Wales, New York, along with other system enhancements including enhancements to the jointly owned Niagara Spur Loop Line. Initial service began on November 1, 2012, with full service implemented on January 16, 2013. As of September 30, 2013, approximately $68.4 million has been spent on the Northern Access Expansion Project, all of which is included in Property, Plant and Equipment on the Consolidated Balance Sheet at September 30, 2013.
Supply Corporation has also begun service under three service agreements for a total of 163,000 Dth per day of additional capacity on Line N to TETCO at Holbrook (“Line N 2012 Expansion Project”). The FERC issued the NGA Section 7(c) Certificate on March 29, 2012 authorizing construction and operation of the Line N 2012 Expansion Project, which consists of an additional 20,620 horsepower of compression at its Buffalo Compressor Station, and the replacement of 4.85 miles of 20” pipe with 24” pipe, to enhance the integrity and reliability of its system and to create the additional capacity. On October 3, 2012, Supply Corporation put in service a portion of the Project facilities and began early interim service for Range Resources. It began full service for all Project shippers on November 1, 2012. As of September 30, 2013, approximately $37.1 million has been spent on the Line N 2012 Expansion Project for the incremental capacity and system replacement, all of which is included in Property, Plant and Equipment on the Consolidated Balance Sheet at September 30, 2013.
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 at Mercer, Pennsylvania, a pooling point recently established at Tennessee’s Station 219 (“Mercer Expansion Project”). Supply Corporation has executed a precedent agreement with Range Resources for 105,000 Dth per day, all of the project capacity, for service expected to begin November 2014. The preliminary cost estimate is $30.4 million, of which $27.2 million is for expansion and $3.2 million is for system modernization. Supply Corporation expects to construct the required approximately 3,500 horsepower of compression at Mercer, and replace 2.08 miles of pipeline, all under its FERC blanket certificate authorization. These expenditures are included as Pipeline and Storage segment estimated capital expenditures in the table above, except for approximately $0.7 million already spent through September 30, 2013. The Company has determined that it is highly probable that this project will be built. Accordingly, previous reserves have been reversed and the project costs have been capitalized as Construction Work in Progress.
On April 11, 2012, Supply Corporation concluded an Open Season to increase its capacity to move gas south on its Line N system to TETCO at Holbrook (“Line N 2013 Project”). Supply Corporation has executed a service agreement with Shell Energy NA for 30,000 Dth per day, all of the project capacity, and service
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began on November 1, 2013. The estimated cost is $3.4 million. Supply Corporation replaced 1.27 miles of 20” pipeline with 24” pipeline under its FERC blanket certificate authorization. Approximately $2.8 million has been spent on the Line N 2013 Project through September 30, 2013, all of which has been capitalized as Construction Work in Progress. The remainder is expected to be spent in fiscal 2014 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 TETCO at Holbrook and TGP at Mercer (“Westside Expansion and Modernization Project”). Supply Corporation executed a precedent agreement for 145,000 Dth per day of the project capacity, for service expected to begin in 2015. A precedent agreement has been extended to one additional shipper for the remaining 30,000 Dth per day of Line N capacity. The Westside Expansion and Modernization Project facilities are expected to include the replacement of approximately 23.5 miles of 20” pipe with 24” pipe and the addition of approximately 3,600 horsepower of compression at Mercer. The preliminary cost estimate is $74 million, of which $39 million is related to expansion and the remainder is for replacement. These expenditures are included as Pipeline and Storage segment estimated capital expenditures in the table above. Approximately $0.2 million has been spent to study the Westside Expansion and Modernization Project through September 30, 2013. 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 April 12, 2013, Supply Corporation concluded an Open Season to increase its capacity to move gas south on its Line N system by an expansion of the interconnection facilities to TETCO at Holbrook (“Holbrook Expansion Project”). Supply Corporation received requests for approximately 13,000 Dth per day of capacity, for service which began November 2, 2013. The preliminary cost estimate is $0.9 million. These expenditures are included as Pipeline and Storage segment estimated capital expenditures in the table above, except for approximately $0.2 million already spent through September 30, 2013, that has been capitalized as Construction Work in Progress.
Supply Corporation and TGP have been jointly developing a project that would 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 would offer 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, NY (“Northern Access 2015”). The Northern Access 2015 project would involve the construction of a new 15,400 horsepower compressor station in Hinsdale, NY and a 7,700 horsepower addition to its compressor station in Concord, NY, for service expected to commence in late 2015. Supply Corporation and TGP are currently negotiating the terms of the lease agreement, and TGP is negotiating a precedent agreement with an anchor shipper. The preliminary cost estimate for the Northern Access 2015 project is $67 million. These expenditures are included as Pipeline and Storage segment estimated capital expenditures in the table above. No significant amounts have been spent on this project through September 30, 2013.
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. The project would require Empire to construct a 17.2 mile, 20” pipeline and interconnection between Empire’s pipeline system and Supply Corporation’s system at Tuscarora, NY, and Supply Corporation to construct 1,500 horsepower of compression at its Tuscarora compressor station (“Tuscarora Lateral Project”). It is anticipated that Supply Corporation would provide Empire with the necessary storage services under a lease agreement. Empire and Supply Corporation began the FERC pre-filing process on April 12, 2013. The preliminary cost estimate for the Tuscarora Lateral Project is $56 million. These expenditures are included as Pipeline and Storage segment estimated capital expenditures in the table above. Approximately $0.2 million has been spent to study the Tuscarora Lateral Project through September 30, 2013. The Company has determined it is
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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.
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 Tioga County, Pennsylvania, to TransCanada Pipeline and the TGP 200 Line (“Central Tioga County Extension”). The connection to Supply Corporation afforded by the Tuscarora Lateral Project could allow those Marcellus supplies to be sourced on other parts of the Supply Corporation system in addition to, or instead of, Tioga County. 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 $150 million, and for a combined project involving Empire and Supply Corporation facilities the cost estimate is $250 million. These expenditures are included as Pipeline and Storage segment estimated capital expenditures in the table above. As of September 30, 2013, approximately $0.2 million has been spent to study the Central Tioga County Extension project, which has been included in preliminary survey and investigation charges and has been fully reserved for at September 30, 2013.
Exploration and Production
Estimated capital expenditures in 2014 for the Exploration and Production segment include approximately $530.1 million for the Appalachian region and $104.7 million for the West Coast region.
Estimated capital expenditures in 2015 for the Exploration and Production segment include approximately $612.1 million for the Appalachian region and $116.2 million for the West Coast region.
Estimated capital expenditures in 2016 for the Exploration and Production segment include approximately $722.9 million for the Appalachian region and $100.2 million for the West Coast region.
Gathering
The majority of the Gathering segment capital expenditures in 2014 through 2016 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 system. The complete buildout will include in-field gathering pipelines and two compressor stations at a cost of approximately $215 million. As of September 30, 2013, the Company has spent approximately $128.0 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, 2013.
NFG Midstream Covington, LLC, a wholly owned subsidiary of Midstream Corporation, has been expanding its gathering system in Tioga County, Pennsylvania. As of September 30, 2013, the Company has spent approximately $28.3 million in costs related to the Covington gathering system. All costs associated with this gathering system are included in Property, Plant and Equipment on the Consolidated Balance Sheet at September 30, 2013.
In addition, two other wholly owned subsidiaries of Midstream Corporation, NFG Midstream Mt. Jewett, LLC and NFG Midstream Tionesta, LLC have constructed gathering pipelines and interconnects. As of September 30, 2013, approximately $3.8 million has been spent on the NFG Midstream Mt. Jewett gathering system and approximately $2.2 million has been spent on the NFG Midstream Tionesta gathering system, all of which is included in Property, Plant and Equipment on the Consolidated Balance Sheet at September 30, 2013.
NFG Midstream Clermont, LLC, a wholly owned subsidiary of Midstream Corporation, plans to build an extensive gathering system with compression in the Pennsylvania counties of McKean, Elk and Cameron. Fiscal 2014 through 2016 capital spending on the Clermont gathering system will include trunkline and
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related facilities. As of September 30, 2013, approximately $3.4 million has been spent on the NFG Midstream Clermont gathering system, all of which is included in Property, Plant and Equipment on the Consolidated Balance Sheet at September 30, 2013.
Midstream Corporation is planning the construction of several other gathering systems. As of September 30, 2013, the Company has spent approximately $0.7 million in costs related to these projects, all of which is included in Property, Plant and Equipment on the Consolidated Balance Sheet at September 30, 2013.
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. The Company issued additional long-term debt in February 2013 to enhance its liquidity position. 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 use short-term borrowings as necessary during fiscal 2014. The level of such short-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.
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 decreased $171.0 million when comparing the balance sheet at September 30, 2013 to the balance sheet at September 30, 2012. The maximum amount of short-term debt outstanding during the year ended September 30, 2013 was $272.8 million. The Company used its $500.0 million long-term debt issuance in February 2013 to substantially reduce its short-term debt. While the Company did not have any outstanding commercial paper and short-term notes payable to banks at September 30, 2013, the Company continues to consider short-term debt 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.
As for bank loans, the Company maintains a number of individual uncommitted or discretionary lines of credit with certain financial institutions for general corporate purposes. Borrowings under these lines of credit are made at competitive market rates. These credit lines, which totaled $335.0 million at September 30, 2013, 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 at amounts near current levels, 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, 2013, the commercial paper program was backed by a syndicated committed credit facility totaling $750.0 million, which commitment extends through January 6, 2017. 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, 2013, the Company’s debt to capitalization ratio (as calculated under the facility) was .43. The constraints specified in
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the committed credit facility would have permitted an additional $2.42 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.
Under the Company’s existing indenture covenants, at September 30, 2013, the Company would have been permitted to issue up to a maximum of $1.6 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, 2013) 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 $750.0 million committed credit facility also 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, 2013, the Company did not have any debt outstanding under the committed credit facility.
The Company’s embedded cost of long-term debt was 5.58% at September 30, 2013 and 6.17% at September 30, 2012. Refer to “Interest Rate Risk” in this Item for a more detailed breakdown of the Company’s embedded cost of long-term debt.
The Company repaid $250.0 million of 5.25% notes that matured in March 2013, which had been classified as Current Portion of Long-Term Debt at September 30, 2012. None of the Company’s long-term debt at September 30, 2013 will mature 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.
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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 $64.1 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.
CONTRACTUAL OBLIGATIONS
The following table summarizes the Company’s expected future contractual cash obligations as of September 30, 2013, and the twelve-month periods over which they occur:
| Payments by Expected Maturity Dates | ||||||||||||||||||||||||||||
| 2014 | 2015 | 2016 | 2017 | 2018 | Thereafter | Total | ||||||||||||||||||||||
| (Millions) | ||||||||||||||||||||||||||||
| Long-Term Debt, including interest expense(1) |
$ | 91.9 | $ | 91.9 | $ | 91.9 | $ | 91.9 | $ | 383.0 | $ | 1,563.3 | $ | 2,313.9 | ||||||||||||||
| Operating Lease Obligations |
$ | 34.4 | $ | 6.2 | $ | 6.1 | $ | 6.0 | $ | 5.8 | $ | 5.6 | $ | 64.1 | ||||||||||||||
| Purchase Obligations: |
||||||||||||||||||||||||||||
| Gas Purchase Contracts(2) |
$ | 209.3 | $ | 26.4 | $ | 2.4 | $ | — | $ | — | $ | — | $ | 238.1 | ||||||||||||||
| Transportation and Storage Contracts |
$ | 48.1 | $ | 45.1 | $ | 48.7 | $ | 48.2 | $ | 26.3 | $ | 54.3 | $ | 270.7 | ||||||||||||||
| Hydraulic Fracturing and Fuel Obligations |
$ | 13.8 | $ | 0.2 | $ | 0.2 | $ | 0.1 | $ | — | $ | — | $ | 14.3 | ||||||||||||||
| Expansion Projects Related to Exploration and Production, Pipeline and Storage, and Gathering segments |
$ | 124.3 | $ | — | $ | — | $ | — | $ | — | $ | — | $ | 124.3 | ||||||||||||||
| Mainframe Replacement Project |
$ | 9.4 | $ | 17.3 | $ | 4.7 | $ | — | $ | — | $ | — | $ | 31.4 | ||||||||||||||
| Other |
$ | 39.7 | $ | 11.9 | $ | 8.0 | $ | 7.4 | $ | 6.8 | $ | 15.3 | $ | 89.1 | ||||||||||||||
| (1) | Refer to Note E — Capitalization and Short-Term Borrowings, as well as the table under Interest Rate Risk in the Market Risk Sensitive Instruments section below, for the amounts excluding interest expense. |
| (2) | Gas prices are variable based on the NYMEX prices adjusted for basis. |
The Company has other long-term obligations recorded on its Consolidated Balance Sheets that are not reflected in the table above. Such long-term obligations include pension and other post-retirement liabilities, asset retirement obligations, deferred income tax liabilities, various regulatory liabilities, derivative financial instrument liabilities and other deferred credits (the majority of which consist of liabilities for non-qualified benefit plans, deferred compensation liabilities, environmental liabilities and workers compensation liabilities).
The Company has made certain other guarantees on behalf of its subsidiaries. The guarantees relate primarily to: (i) obligations under derivative financial instruments, which are included on the Consolidated Balance Sheets in accordance with the authoritative guidance (see Item 7, MD&A under the heading “Critical
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Accounting Estimates — Accounting for Derivative Financial Instruments”); (ii) NFR obligations to purchase gas or to purchase gas transportation/storage services where the amounts due on those obligations each month are included on the Consolidated Balance Sheets as a current liability; and (iii) other obligations which are reflected on the Consolidated Balance Sheets. The Company believes that the likelihood it would be required to make payments under the guarantees is remote, and therefore has not included them in the table above.
OTHER MATTERS
In addition to the environmental and other matters discussed in this Item 7 and in Item 8 at Note I — Commitments and Contingencies, the Company is involved in other litigation and regulatory matters arising in the normal course of business. These other matters may include, for example, negligence claims and tax, regulatory or other governmental audits, inspections, investigations or other proceedings. These matters may involve state and federal taxes, safety, compliance with regulations, rate base, cost of service and purchased gas cost issues, among other things. While these normal-course matters could have a material effect on earnings and cash flows in the period in which they are resolved, they are not expected to change materially the Company’s present liquidity position, nor are they expected to have a material adverse effect on the financial condition of the Company.
The Company has a tax-qualified, noncontributory defined-benefit retirement plan (Retirement Plan). The Company has been making contributions to the Retirement Plan over the last several years and anticipates that it will continue making contributions to the Retirement Plan. During 2013, the Company contributed $54.0 million to the Retirement Plan. The Company anticipates that the annual contribution to the Retirement Plan in 2014 will be in the range of $30.0 million to $40.0 million.
Changes in the discount rate, other actuarial assumptions, and asset performance could ultimately cause the Company to fund larger amounts to the Retirement Plan in 2014 in order to be in compliance with the Pension Protection Act of 2006 (as impacted by the Moving Ahead for Progress in the 21st Century Act). In July 2012, the Surface Transportation Extension Act, which is also referred to as the Moving Ahead for Progress in the 21st Century Act (the Act), was passed by Congress and signed by the President. The Act included pension funding stabilization provisions. The Company is continually evaluating its future contributions in light of the provisions of the Act. The Company expects that all subsidiaries having employees covered by the Retirement Plan will make contributions to the Retirement Plan. The funding of such contributions will come from amounts collected in rates in the Utility and Pipeline and Storage segments or through short-term borrowings or through cash from operations.
The Company provides health care and life insurance benefits (other post-retirement benefits) for a majority of its retired employees. The Company has established VEBA trusts and 401(h) accounts for its other post-retirement benefits. The Company has been making contributions to its VEBA trusts and 401(h) accounts over the last several years and anticipates that it will continue making contributions to the VEBA trusts and 401(h) accounts. During 2013, the Company contributed $18.1 million to its VEBA trusts and 401(h) accounts. The Company anticipates that the annual contribution to its VEBA trusts and 401(h) accounts in 2014 will be in the range of $5.0 million to $15.0 million. The funding of such contributions will come from amounts collected in rates in the Utility and Pipeline and Storage segments.
MARKET RISK SENSITIVE INSTRUMENTS
Energy Commodity Price Risk
The Company uses various derivative financial instruments (derivatives), including price swap agreements and futures contracts, as part of the Company’s overall energy commodity price risk management strategy in its Exploration and Production and Energy Marketing segments. Under this strategy, the Company manages a portion of the market risk associated with fluctuations in the price of natural gas and crude oil, thereby attempting to provide more stability to operating results. The Company has operating procedures in place that are administered by experienced management to monitor compliance with the Company’s risk management policies. The derivatives are not held for trading purposes. The fair value of
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these derivatives, as shown below, represents the amount that the Company would receive from, or pay to, the respective counterparties at September 30, 2013 to terminate the derivatives. However, the tables below and the fair value that is disclosed do not consider the physical side of the natural gas and crude oil transactions that are related to the financial instruments.
On July 21, 2010, the Dodd-Frank Act was signed into law. The Dodd-Frank Act 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 significant impact on the Company. For example, banking regulators have proposed a rule that would require swap dealers and major swap participants subject to their jurisdiction to collect initial and variation margin from counterparties that are non-financial end users, though such swap dealers and major swap participants would have the discretion to set thresholds for posting margin (unsecured credit limits). Regardless of the levels of margin that might be required, concern remains that swap dealers and major swap participants will pass along their increased costs through higher transaction costs and prices, and reductions in thresholds for posting margin. 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. The Company continues to monitor these developments but cannot predict the impact the Dodd-Frank Act may ultimately have on its operations.
In accordance with the authoritative guidance for fair value measurements, the Company has identified certain inputs used to recognize fair value as Level 3 (unobservable inputs). The Level 3 derivative net liabilities relate to crude oil swap agreements used to hedge forecasted sales at a specific location (southern California). The Company’s internal model that is used to calculate fair value applies a historical basis differential (between the sales locations and NYMEX) to a forward NYMEX curve because there is not a forward curve specific to this sales location. The Company does not believe that the fair value recorded by the Company would be significantly different from what it expects to receive upon settlement.
The Company uses the crude oil swaps classified as Level 3 to hedge against the risk of declining commodity prices and not as speculative investments. Gains or losses related to these Level 3 derivative net liabilities (including any reduction for credit risk) are deferred until the hedged commodity transaction occurs in accordance with the provisions of the existing guidance for derivative instruments and hedging activities. The Level 3 derivative net liabilities amount to $5.2 million at September 30, 2013 and represent 3.7% of the Total Net Assets shown in Item 8 at Note F — Fair Value Measurements at September 30, 2013.
The decrease in the net fair value liability of the Level 3 positions from October 1, 2012 to September 30, 2013, as shown in Item 8 at Note F, was attributable to a decrease in the commodity price of crude oil relative to the swap prices during that period. The Company believes that these fair values reasonably represent the amounts that the Company would realize upon settlement based on commodity prices that were present at September 30, 2013.
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The accounting rules for fair value measurements and disclosures require consideration of the impact of nonperformance risk (including credit risk) from a market participant perspective in the measurement of the fair value of assets and liabilities. At September 30, 2013, the Company determined that nonperformance risk would have no material impact on its financial position or results of operation. To assess nonperformance risk, the Company considered information such as any applicable collateral posted, master netting arrangements, and applied a market-based method by using the counterparty (for an asset) or the Company’s (for a liability) credit default swaps rates.
The following tables disclose natural gas and crude oil price swap information by expected maturity dates for agreements in which the Company receives a fixed price in exchange for paying a variable price as quoted in various national natural gas publications or on the NYMEX. Notional amounts (quantities) are used to calculate the contractual payments to be exchanged under the contract. The weighted average variable prices represent the weighted average settlement prices by expected maturity date as of September 30, 2013. At September 30, 2013, the Company had not entered into any natural gas or crude oil price swap agreements extending beyond 2018.
Natural Gas Price Swap Agreements
| Expected Maturity Dates | ||||||||||||||||||||||||
| 2014 | 2015 | 2016 | 2017 | 2018 | Total | |||||||||||||||||||
| Notional Quantities (Equivalent Bcf) |
76.6 | 52.6 | 40.4 | 38.9 | 5.3 | 213.8 | ||||||||||||||||||
| Weighted Average Fixed Rate (per Mcf) |
$ | 4.27 | $ | 4.28 | $ | 4.35 | $ | 4.45 | $ | 4.81 | $ | 4.33 | ||||||||||||
| Weighted Average Variable Rate (per Mcf) |
$ | 3.85 | $ | 4.09 | $ | 4.17 | $ | 4.30 | $ | 4.60 | $ | 4.07 | ||||||||||||
Of the total Bcf above, 0.5 Bcf is accounted for as fair value hedges at a weighted average fixed rate of $4.74 per Mcf. The remaining 213.3 Bcf are accounted for as cash flow hedges at a weighted average fixed rate of $4.34 per Mcf.
Crude Oil Price Swap Agreements
| Expected Maturity Dates | ||||||||||||||||||||||||
| 2014 | 2015 | 2016 | 2017 | 2018 | Total | |||||||||||||||||||
| Notional Quantities (Equivalent Bbls) |
1,968,000 | 1,056,000 | 900,000 | 300,000 | 75,000 | 4,299,000 | ||||||||||||||||||
| Weighted Average Fixed Rate (per Bbl) |
$ | 100.22 | $ | 94.95 | $ | 91.77 | $ | 91.55 | $ | 91.00 | $ | 96.39 | ||||||||||||
| Weighted Average Variable Rate (per Bbl) |
$ | 104.06 | $ | 95.11 | $ | 91.30 | $ | 91.55 | $ | 90.32 | $ | 98.08 | ||||||||||||
At September 30, 2013, the Company would have received from its respective counterparties an aggregate of approximately $54.7 million to terminate the natural gas price swap agreements outstanding at that date. The Company would have to pay its respective counterparties an aggregate of approximately $7.3 million to terminate the crude oil price swap agreements outstanding at September 30, 2013.
At September 30, 2012, the Company had natural gas price swap agreements covering 133.9 Bcf at a weighted average fixed rate of $4.37 per Mcf. The Company also had crude oil price swap agreements covering 2,316,000 Bbls at a weighted average fixed rate of $94.24 per Bbl.
The following table discloses the net contract volume purchased (sold), weighted average contract prices and weighted average settlement prices by expected maturity date for futures contracts used to manage natural gas price risk. At September 30, 2013, the Company did not hold any futures contracts with maturity dates extending beyond 2017.
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Futures Contracts
| Expected Maturity Dates | ||||||||||||||||||||
| 2014 | 2015 | 2016 | 2017 | Total | ||||||||||||||||
| Net Contract Volume Purchased (Sold) (Equivalent Bcf) |
— | (1) | 0.8 | 0.5 | 0.1 | 1.4 | ||||||||||||||
| Weighted Average Contract Price (per Mcf) |
$ | 4.20 | $ | 4.46 | $ | 4.60 | $ | 4.59 | $ | 4.25 | ||||||||||
| Weighted Average Settlement Price (per Mcf) |
$ | 4.14 | $ | 4.44 | $ | 4.59 | $ | 4.65 | $ | 4.20 | ||||||||||
| (1) | The Energy Marketing segment has long (purchased) contracts covering 6.6 Bcf of gas and short (sold) contracts covering 6.6 Bcf of gas in 2014. |
At September 30, 2013, the Company had long (purchased) contracts covering 8.7 Bcf of gas extending through 2017 at a weighted average contract price of $4.19 per Mcf and a weighted average settlement price of $4.02 per Mcf. Of this amount, 8.2 Bcf is accounted for as fair value hedges and are used by the Company’s Energy Marketing segment to hedge against rising prices, a risk to which this segment is exposed due to the fixed price gas sales commitments that it enters into with certain residential, commercial, industrial, public authority and wholesale customers. The remaining 0.5 Bcf is accounted for as cash flow hedges used to hedge against rising prices related to anticipated gas purchases for potential injections into storage. The Company would have paid $1.5 million to terminate these contracts at September 30, 2013.
At September 30, 2013, the Company had short (sold) contracts covering 7.3 Bcf of gas extending through 2016 at a weighted average contract price of $4.33 per Mcf and a weighted average settlement price of $4.00 per Mcf. Of this amount, 6.4 Bcf is accounted for as cash flow hedges as these contracts relate to the anticipated sale of natural gas by the Energy Marketing segment. The remaining 0.9 Bcf is accounted for as fair value hedges used to hedge against falling prices, a risk to which the Energy Marketing segment is exposed due to the fixed price gas purchase commitments that it enters into with certain natural gas suppliers. The Company would have received $2.4 million to terminate these contracts at September 30, 2013.
At September 30, 2012, the Company had long (purchased) contracts covering 8.7 Bcf of gas extending through 2016 at a weighted average contract price of $3.97 per Mcf and a weighted average settlement price of $4.01 per Mcf.
At September 30, 2012, the Company had short (sold) contracts covering 6.8 Bcf of gas extending through 2016 at a weighted average contract price of $4.10 per Mcf and a weighted average settlement price of $3.92 per Mcf.
The Company may be exposed to credit risk on any of the derivative financial instruments that are in a gain position. Credit risk relates to the risk of loss that the Company would incur as a result of nonperformance by counterparties pursuant to the terms of their contractual obligations. To mitigate such credit risk, management performs a credit check, and then on a quarterly basis monitors counterparty credit exposure. The majority of the Company’s counterparties are financial institutions and energy traders. The Company has over-the-counter swap positions with thirteen counterparties of which eleven are in a net gain position. On average, the Company had $4.4 million of credit exposure per counterparty in a gain position at September 30, 2013. The maximum credit exposure per counterparty in a gain position at September 30, 2013 was $8.1 million. As of September 30, 2013, the Company had not received any collateral from the counterparties. The Company’s gain position on such derivative financial instruments had not exceeded the established thresholds at which the counterparties would be required to post collateral, nor had the counterparties’ credit ratings declined to levels at which the counterparties were required to post collateral.
As of September 30, 2013, eleven of the thirteen counterparties to the Company’s outstanding derivative instrument contracts (specifically the over-the-counter swaps) had a common credit-risk related contingency feature. In the event the Company’s credit rating increases or falls below a certain threshold (applicable debt ratings), the available credit extended to the Company would either increase or decrease. A decline in the Company’s credit rating, in and of itself, would not cause the Company to be required to increase the level of
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its hedging collateral deposits (in the form of cash deposits, letters of credit or treasury debt instruments). If the Company’s outstanding derivative instrument contracts were in a liability position (or if the liability were larger) and/or the Company’s credit rating declined, then additional hedging collateral deposits may be required. At September 30, 2013, the fair market value of the derivative financial instrument assets with a credit-risk related contingency feature was $34.7 million according to the Company’s internal model (discussed in Item 8 at Note F — Fair Value Measurements). At September 30, 2013, the fair market value of the derivative financial instrument liabilities with a credit-risk related contingency feature was $0.6 million according to the Company’s internal model (discussed in Item 8 at Note F — Fair Value Measurements). For its over-the-counter swap agreements, the Company was not required to post any hedging collateral deposits at September 30, 2013.
For its exchange traded futures contracts, which are in an asset position, the Company was required to post $1.1 million in hedging collateral deposits as of September 30, 2013. As these are exchange traded futures contracts, there are no specific credit-risk related contingency features. The Company posts hedging collateral based on open positions and margin requirements it has with its counterparties.
The Company’s requirement to post hedging collateral deposits is based on the fair value determined by the Company’s counterparties, which may differ from the Company’s assessment of fair value. Hedging collateral deposits may also include closed derivative positions in which the broker has not cleared the cash from the account to offset the derivative liability. The Company records liabilities related to closed derivative positions in Other Accruals and Current Liabilities on the Consolidated Balance Sheet. These liabilities are relieved when the broker clears the cash from the hedging collateral deposit account. This is discussed in Item 8 at Note A under Hedging Collateral Deposits.
Interest Rate Risk
The fair value of long-term fixed rate debt is $1.8 billion at September 30, 2013. This fair value amount is not intended to reflect principal amounts that the Company will ultimately be required to pay. The following table presents the principal cash repayments and related weighted average interest rates by expected maturity date for the Company’s long-term fixed rate debt:
| Principal Amounts by Expected Maturity Dates | ||||||||||||||||||||||||||||
| 2014 | 2015 | 2016 | 2017 | 2018 | Thereafter | Total | ||||||||||||||||||||||
| (Dollars in millions) | ||||||||||||||||||||||||||||
| Long-Term Fixed Rate Debt |
$ | — | $ | — | $ | — | $ | — | $ | 300.0 | $ | 1,349.0 | $ | 1,649.0 | ||||||||||||||
| Weighted Average Interest Rate Paid |
— | — | — | — | 6.5 | % | 5.4 | % | 5.6 | % | ||||||||||||||||||
RATE AND REGULATORY MATTERS
Utility Operation
Delivery rates for both the New York and Pennsylvania divisions are regulated by the states’ respective public utility commissions and typically are changed only when approved through a procedure known as a “rate case.” Although neither division has a rate case on file, see below for a description of other rate proceedings affecting the New York division. In both jurisdictions, delivery rates do not reflect the recovery of purchased gas costs. Prudently-incurred gas costs are recovered through operation of automatic adjustment clauses, and are collected primarily through a separately-stated “supply charge” on the customer bill.
New York Jurisdiction
Customer delivery rates charged by Distribution Corporation’s New York division were established in a rate order issued on December 21, 2007 by the NYPSC. In connection with an efficiency and conservation program, the rate order approved a revenue decoupling mechanism. The revenue decoupling mechanism “decouples” revenues from throughput by enabling the Company to collect from small volume customers its
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allowed margin on average weather normalized usage per customer. The effect of the revenue decoupling mechanism is to render the Company financially indifferent to throughput decreases resulting from conservation.
Following discussions with regulatory staff with respect to earnings levels, on March 27, 2013, Distribution Corporation filed a plan (“Plan”) with the NYPSC proposing to adopt an “earnings stabilization and sharing mechanism” that would allocate earnings above a rate of return on equity of 9.96% evenly between shareholders and an accounting reserve (“Reserve”). The Reserve would be utilized to stabilize Distribution Corporation’s earnings and to fund customer benefit programs. The Plan also proposed to increase capital spending and to aid new customer system expansion efforts. Discussions were held with NYPSC staff and others with respect to the Plan.
In a related development, on April 19, 2013, the NYPSC issued an order directing Distribution Corporation to either agree to make its rates and charges temporary subject to refund effective June 1, 2013, or show cause why its gas rates and charges should not be set on a temporary basis subject to refund (“Order”). The Order recognized Distribution Corporation’s Plan and, while acknowledging the Company’s cost-cutting and efficiency achievements, determined nonetheless that the Plan did not propose to adjust “existing rates . . . enough to compensate for the imbalance between ratepayer and shareholder interests that has developed since . . . 2007 . . .” Pursuant to the Order, the NYPSC commenced a “temporary rate” proceeding and, following hearings, on June 14, 2013, the NYPSC issued an order (“Temporary Rates Order”) making Distribution Corporation’s rates and charges temporary and subject to refund pending the determination of permanent gas rates through further rate proceedings. Discussions for settlement of Distribution Corporation’s rates and charges were commenced and are expected to continue as the formal case to establish permanent rates proceeds along a parallel path. The Consolidated Balance Sheet at September 30, 2013 reflects a $7.5 million ($4.9 million after-tax) refund provision in anticipation of a potential settlement.
In addition to authorizing a “temporary rate” proceeding, the Order also suggested an examination of the applicability of a provision of New York public utility law, PSL §66(20), that provides the NYPSC with stated authority to direct a refund of revenues received by a utility “in excess of its authorized rate of return for a period of twelve months.” On May 17, 2013, Distribution Corporation commenced an action in New York Supreme Court, Erie County, seeking the court’s declaration that PSL §66(20) is unconstitutional. On October 25, 2013, the court dismissed Distribution Corporation’s complaint without prejudice to recommence the action after a decision is rendered in the rate proceeding before the NYPSC. In addition, on September 25, 2013, Distribution Corporation commenced an appeal in New York Supreme Court, Albany County, seeking to annul the Temporary Rates Order on various grounds. Distribution Corporation is unable to predict the outcome of the administrative or judicial proceedings at this time.
Pennsylvania Jurisdiction
Distribution Corporation’s current delivery charges in its Pennsylvania jurisdiction were approved by the PaPUC on November 30, 2006 as part of a settlement agreement that became effective January 1, 2007.
Pipeline and Storage
Supply Corporation currently does not have a rate case on file with the FERC. A rate settlement approved by the FERC on August 6, 2012 requires Supply Corporation to make a general rate filing no later than January 1, 2016. In addition, Supply Corporation is not barred from filing a general rate case before such date or at any time.
Empire also has no rate case currently on file with the FERC, but is not subject to any requirement to make any future general rate filing. Empire is also not barred from filing a general rate case at any time.
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ENVIRONMENTAL MATTERS
The Company is subject to various federal, state and local laws and regulations relating to the protection of the environment. The Company has established procedures for the ongoing evaluation of its operations to identify potential environmental exposures and comply with regulatory policies and procedures. It is the Company’s policy to accrue estimated environmental clean-up costs (investigation and remediation) when such amounts can reasonably be estimated and it is probable that the Company will be required to incur such costs. At September 30, 2013, the Company has estimated its remaining clean-up costs related to former manufactured gas plant sites and third party waste disposal sites will be approximately $14.7 million. This estimated liability has been recorded in Other Deferred Credits on the Consolidated Balance Sheet at September 30, 2013. The Company expects to recover its environmental clean-up costs through rate recovery. Other than as discussed in Note I (referred to below), the Company is currently not aware of any material additional exposure to environmental liabilities. However, changes in environmental laws and regulations, new information or other factors could adversely impact the Company.
For further discussion refer to Item 8 at Note I — Commitments and Contingencies under the heading “Environmental Matters.”
Legislative and regulatory measures to address climate change and greenhouse gas emissions are in various phases of discussion or implementation. In the United States, these efforts include legislative proposals and EPA regulations at the federal level, actions at the state level, and private party litigation related to greenhouse gas emissions. While the U.S. Congress has from time to time considered legislation aimed at reducing emissions of greenhouse gases, Congress has not yet passed any federal climate change legislation and we cannot predict when or if Congress will pass such legislation and in what form. In the absence of such legislation, the EPA is regulating greenhouse gas emissions pursuant to the authority granted to it by the federal Clean Air Act. For example, in April 2012, the EPA adopted rules which restrict emissions associated with oil and natural gas drilling. Compliance with these new rules will not materially change the Company’s ongoing emissions–limiting technologies and practices, and is not expected to have a significant impact on the Company. 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 carbon emissions could increase the Company’s cost of environmental compliance by requiring the Company to install new equipment to reduce emissions from larger facilities and/or purchase emission allowances. International, federal, state or regional climate change and greenhouse gas measures 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. But legislation or regulation that sets a price on or otherwise restricts carbon emissions could also benefit the Company by increasing demand for natural gas, because substantially fewer carbon emissions per Btu of heat generated are associated with the use of natural gas than with certain alternate fuels such as coal and oil. The effect (material or not) on the Company of any new legislative or regulatory measures will depend on the particular provisions that are ultimately adopted.
NEW AUTHORITATIVE ACCOUNTING AND FINANCIAL REPORTING GUIDANCE
In December 2011, the FASB issued authoritative guidance requiring enhanced disclosures regarding offsetting assets and liabilities. Companies are required to disclose both gross information and net information about both instruments and transactions eligible for offset in the statement of financial position and instruments and transactions subject to an agreement similar to a master netting arrangement. This authoritative guidance will be effective as of the Company’s first quarter of fiscal 2014 and is not expected to have a significant impact on the Company’s financial statements.
In February 2013, the FASB issued authoritative guidance requiring enhanced disclosures regarding the reporting of amounts reclassified out of accumulated other comprehensive income. The authoritative guidance requires parenthetical disclosure on the face of the financial statements or a single footnote that
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would provide more detail about the components of reclassification adjustments that are reclassified in their entirety to net income. If a component of a reclassification adjustment is not reclassified in its entirety to net income, a cross reference would be made to the footnote disclosure that provides a more thorough discussion of the component involved in that reclassification adjustment. This authoritative guidance will be effective as of the Company’s first quarter of fiscal 2014. The Company does not expect this guidance to have a material impact.
EFFECTS OF INFLATION
Although the rate of inflation has been relatively low over the past few years, the Company’s operations remain sensitive to increases in the rate of inflation because of its capital spending and the regulated nature of a significant portion of its business.
SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS
The Company is including the following cautionary statement in this Form 10-K to make applicable and take advantage of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by, or on behalf of, the Company. Forward-looking statements include statements concerning plans, objectives, goals, projections, strategies, future events or performance, and underlying assumptions and other statements which are other than statements of historical facts. From time to time, the Company may publish or otherwise make available forward-looking statements of this nature. All such subsequent forward-looking statements, whether written or oral and whether made by or on behalf of the Company, are also expressly qualified by these cautionary statements. Certain statements contained in this report, including, without limitation, statements regarding future prospects, plans, objectives, goals, projections, estimates of oil and gas quantities, strategies, future events or performance and underlying assumptions, capital structure, anticipated capital expenditures, completion of construction projects, projections for pension and other post-retirement benefit obligations, impacts of the adoption of new accounting rules, and possible outcomes of litigation or regulatory proceedings, as well as statements that are identified by the use of the words “anticipates,” “estimates,” “expects,” “forecasts,” “intends,” “plans,” “predicts,” “projects,” “believes,” “seeks,” “will,” “may,” and similar expressions, are “forward-looking statements” as defined in the Private Securities Litigation Reform Act of 1995 and accordingly involve risks and uncertainties which could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. The Company’s expectations, beliefs and projections are expressed in good faith and are believed by the Company to have a reasonable basis, but there can be no assurance that management’s expectations, beliefs or projections will result or be achieved or accomplished. In addition to other factors and matters discussed elsewhere herein, the following are important factors that, in the view of the Company, could cause actual results to differ materially from those discussed in the forward-looking statements:
| 1. | Factors affecting the Company’s ability to successfully identify, drill for and produce economically viable natural gas and oil reserves, including among others geology, lease availability, title disputes, weather conditions, shortages, delays or unavailability of equipment and services required in drilling operations, insufficient gathering, processing and transportation capacity, the need to obtain governmental approvals and permits, and compliance with environmental laws and regulations; |
| 2. | Changes in laws, regulations or judicial interpretations to which the Company is subject, including those involving derivatives, taxes, safety, employment, climate change, other environmental matters, real property, and exploration and production activities such as hydraulic fracturing; |
| 3. | Governmental/regulatory actions, initiatives and proceedings, including those involving rate cases (which address, among other things, allowed rates of return, rate design and retained natural gas), environmental/safety requirements, affiliate relationships, industry structure, and franchise renewal; |
| 4. | Changes in the price of natural gas or oil; |
| 5. | Impairments under the SEC’s full cost ceiling test for natural gas and oil reserves; |
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| 6. | Uncertainty of oil and gas reserve estimates; |
| 7. | Significant differences between the Company’s projected and actual production levels for natural gas or oil; |
| 8. | Changes in demographic patterns and weather conditions; |
| 9. | Changes in the availability, price or accounting treatment of derivative financial instruments; |
| 10. | Delays or changes in costs or plans with respect to Company projects or related projects of other companies, including difficulties or delays in obtaining necessary governmental approvals, permits or orders or in obtaining the cooperation of interconnecting facility operators; |
| 11. | Financial and economic conditions, including the availability of credit, and occurrences affecting the Company’s ability to obtain financing on acceptable terms for working capital, capital expenditures and other investments, including any downgrades in the Company’s credit ratings and changes in interest rates and other capital market conditions; |
| 12. | Changes in economic conditions, including global, national or regional recessions, and their effect on the demand for, and customers’ ability to pay for, the Company’s products and services; |
| 13. | The creditworthiness or performance of the Company’s key suppliers, customers and counterparties; |
| 14. | Economic disruptions or uninsured losses resulting from major accidents, fires, severe weather, natural disasters, terrorist activities, acts of war, cyber attacks or pest infestation; |
| 15. | Changes in price differential between similar quantities of natural gas at different geographic locations, and the effect of such changes on natural gas revenues and production, and on the demand for pipeline transportation capacity to or from such locations; |
| 16. | Other changes in price differentials between similar quantities of oil or natural gas having different quality, heating value, geographic location or delivery date; |
| 17. | Significant differences between the Company’s projected and actual capital expenditures and operating expenses; |
| 18. | Changes in laws, actuarial assumptions, the interest rate environment and the return on plan/trust assets related to the Company’s pension and other post-retirement benefits, which can affect future funding obligations and costs and plan liabilities; |
| 19. | The cost and effects of legal and administrative claims against the Company or activist shareholder campaigns to effect changes at the Company; |
| 20. | Increasing health care costs and the resulting effect on health insurance premiums and on the obligation to provide other post-retirement benefits; or |
| 21. | Increasing costs of insurance, changes in coverage and the ability to obtain insurance. |
The Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date hereof.
| Item 7A | Quantitative and Qualitative Disclosures About Market Risk |
Refer to the “Market Risk Sensitive Instruments” section in Item 7, MD&A.
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| Item 8 | Financial Statements and Supplementary Data |
Index to Financial Statements
| Page | ||||
| Financial Statements and Financial Statement Schedule: |
||||
| 72 | ||||
| 73 | ||||
| Consolidated Statements of Comprehensive Income, three years ended September 30, 2013 |
74 | |||
| 75 | ||||
| Consolidated Statements of Cash Flows, three years ended September 30, 2013 |
76 | |||
| 77 | ||||
| Schedule II — Valuation and Qualifying Accounts for the three years ended September 30, 2013 |
131 | |||
All other schedules are omitted because they are not applicable or the required information is shown in the Consolidated Financial Statements or Notes thereto.
Supplementary Data
Supplementary data that is included in Note K — Quarterly Financial Data (unaudited) and Note M — Supplementary Information for Oil and Gas Producing Activities (unaudited), appears under this Item, and reference is made thereto.
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of National Fuel Gas Company:
In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of National Fuel Gas Company and its subsidiaries at September 30, 2013 and 2012, and the results of their operations and their cash flows for each of the three years in the period ended September 30, 2013 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the accompanying index presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of September 30, 2013, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on these financial statements, on the financial statement schedule, and on the Company’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
PRICEWATERHOUSECOOPERS LLP
Buffalo, New York
November 22, 2013
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CONSOLIDATED STATEMENTS OF INCOME AND EARNINGS
REINVESTED IN THE BUSINESS
| Year Ended September 30 | ||||||||||||
| 2013 | 2012 | 2011 | ||||||||||
| (Thousands of dollars, except per common share amounts) |
||||||||||||
| INCOME |
||||||||||||
| Operating Revenues |
$ | 1,829,551 | $ | 1,626,853 | $ | 1,778,842 | ||||||
|
|
|
|
|
|
|
|||||||
| Operating Expenses |
||||||||||||
| Purchased Gas |
460,432 | 415,589 | 628,732 | |||||||||
| Operation and Maintenance |
442,090 | 401,397 | 400,519 | |||||||||
| Property, Franchise and Other Taxes |
82,431 | 90,288 | 81,902 | |||||||||
| Depreciation, Depletion and Amortization |
326,760 | 271,530 | 226,527 | |||||||||
|
|
|
|
|
|
|
|||||||
| 1,311,713 | 1,178,804 | 1,337,680 | ||||||||||
|
|
|
|
|
|
|
|||||||
| Operating Income |
517,838 | 448,049 | 441,162 | |||||||||
| Other Income (Expense): |
||||||||||||
| Gain on Sale of Unconsolidated Subsidiaries |
— | — | 50,879 | |||||||||
| Other Income |
4,697 | 5,133 | 5,947 | |||||||||
| Interest Income |
4,335 | 3,689 | 2,916 | |||||||||
| Interest Expense on Long-Term Debt |
(90,273 | ) | (82,002 | ) | (73,567 | ) | ||||||
| Other Interest Expense |
(3,838 | ) | (4,238 | ) | (4,554 | ) | ||||||
|
|
|
|
|
|
|
|||||||
| Income Before Income Taxes |
432,759 | 370,631 | 422,783 | |||||||||
| Income Tax Expense |
172,758 | 150,554 | 164,381 | |||||||||
|
|
|
|
|
|
|
|||||||
| Net Income Available for Common Stock |
260,001 | 220,077 | 258,402 | |||||||||
|
|
|
|
|
|
|
|||||||
| EARNINGS REINVESTED IN THE BUSINESS |
||||||||||||
| Balance at Beginning of Year |
1,306,284 | 1,206,022 | 1,063,262 | |||||||||
|
|
|
|
|
|
|
|||||||
| 1,566,285 | 1,426,099 | 1,321,664 | ||||||||||
| Dividends on Common Stock |
(123,668 | ) | (119,815 | ) | (115,642 | ) | ||||||
|
|
|
|
|
|
|
|||||||
| Balance at End of Year |
$ | 1,442,617 | $ | 1,306,284 | $ | 1,206,022 | ||||||
|
|
|
|
|
|
|
|||||||
| Earnings Per Common Share: |
||||||||||||
| Basic: |
||||||||||||
| Net Income Available for Common Stock |
$ | 3.11 | $ | 2.65 | $ | 3.13 | ||||||
|
|
|
|
|
|
|
|||||||
| Diluted: |
||||||||||||
| Net Income Available for Common Stock |
$ | 3.08 | $ | 2.63 | $ | 3.09 | ||||||
|
|
|
|
|
|
|
|||||||
| Weighted Average Common Shares Outstanding: |
||||||||||||
| Used in Basic Calculation |
83,518,857 | 83,127,844 | 82,514,015 | |||||||||
|
|
|
|
|
|
|
|||||||
| Used in Diluted Calculation |
84,341,220 | 83,739,771 | 83,670,802 | |||||||||
|
|
|
|
|
|
|
|||||||
See Notes to Consolidated Financial Statements
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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
| Year Ended September 30 | ||||||||||||
| 2013 | 2012 | 2011 | ||||||||||
| (Thousands of dollars) | ||||||||||||
| Net Income Available for Common Stock |
$ | 260,001 | $ | 220,077 | $ | 258,402 | ||||||
|
|
|
|
|
|
|
|||||||
| Other Comprehensive Income (Loss), Before Tax: |
||||||||||||
| Increase (Decrease) in the Funded Status of the Pension and Other Post-Retirement Benefit Plans |
55,940 | (27,552 | ) | (24,172 | ) | |||||||
| Reclassification Adjustment for Amortization of Prior Year Funded Status of the Pension and Other Post-Retirement Benefit Plans |
15,282 | 10,270 | 8,536 | |||||||||
| Foreign Currency Translation Adjustment |
— | — | 17 | |||||||||
| Reclassification Adjustment for Realized Foreign Currency Translation Loss in Net Income |
— | — | 34 | |||||||||
| Unrealized Gain (Loss) on Securities Available for Sale Arising During the Period |
5,041 | 3,545 | (1,199 | ) | ||||||||
| Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period |
91,790 | (7,248 | ) | 30,238 | ||||||||
| Reclassification Adjustment for Realized Gains on Derivative Financial Instruments in Net Income |
(36,029 | ) | (65,691 | ) | (15,485 | ) | ||||||
|
|
|
|
|
|
|
|||||||
| Other Comprehensive Income (Loss), Before Tax |
132,024 | (86,676 | ) | (2,031 | ) | |||||||
|
|
|
|
|
|
|
|||||||
| Income Tax Expense (Benefit) Related to the Increase (Decrease) in the Funded Status of the Pension and Other Post-Retirement Benefit Plans |
21,304 | (10,144 | ) | (8,735 | ) | |||||||
| Reclassification Adjustment for Income Tax Benefit Related to the Amortization of the Prior Year Funded Status of the Pension and Other Post-Retirement Benefit Plans |
5,650 | 3,836 | 3,221 | |||||||||
| Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) on Securities Available for Sale Arising During the Period |
1,847 | 1,311 | (453 | ) | ||||||||
| Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period |
38,236 | (8,244 | ) | 12,836 | ||||||||
| Reclassification Adjustment for Income Tax Expense on Realized Gains on Derivative Financial Instruments in Net Income |
(14,799 | ) | (22,114 | ) | (6,186 | ) | ||||||
|
|
|
|
|
|
|
|||||||
| Income Taxes — Net |
52,238 | (35,355 | ) | 683 | ||||||||
|
|
|
|
|
|
|
|||||||
| Other Comprehensive Income (Loss) |
79,786 | (51,321 | ) | (2,714 | ) | |||||||
|
|
|
|
|
|
|
|||||||
| Comprehensive Income |
$ | 339,787 | $ | 168,756 | $ | 255,688 | ||||||
|
|
|
|
|
|
|
|||||||
See Notes to Consolidated Financial Statements
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CONSOLIDATED BALANCE SHEETS
| At September 30 | ||||||||
| 2013 | 2012 | |||||||
| (Thousands of dollars) |
||||||||
| ASSETS | ||||||||
| Property, Plant and Equipment |
$ | 7,313,203 | $ | 6,615,813 | ||||
| Less — Accumulated Depreciation, Depletion and Amortization |
2,161,477 | 1,876,010 | ||||||
|
|
|
|
|
|||||
| 5,151,726 | 4,739,803 | |||||||
|
|
|
|
|
|||||
| Current Assets |
||||||||
| Cash and Temporary Cash Investments |
64,858 | 74,494 | ||||||
| Hedging Collateral Deposits |
1,094 | 364 | ||||||
| Receivables — Net of Allowance for Uncollectible Accounts of $27,144 and $30,317, Respectively |
133,182 | 115,818 | ||||||
| Unbilled Utility Revenue |
19,483 | 19,652 | ||||||
| Gas Stored Underground |
51,484 | 49,795 | ||||||
| Materials and Supplies — at average cost |
29,904 | 28,577 | ||||||
| Unrecovered Purchased Gas Costs |
12,408 | — | ||||||
| Other Current Assets |
56,905 | 56,121 | ||||||
| Deferred Income Taxes |
79,359 | 10,755 | ||||||
|
|
|
|
|
|||||
| 448,677 | 355,576 | |||||||
|
|
|
|
|
|||||
| Other Assets |
||||||||
| Recoverable Future Taxes |
163,355 | 150,941 | ||||||
| Unamortized Debt Expense |
16,645 | 13,409 | ||||||
| Other Regulatory Assets |
252,568 | 546,851 | ||||||
| Deferred Charges |
9,382 | 7,591 | ||||||
| Other Investments |
96,308 | 86,774 | ||||||
| Goodwill |
5,476 | 5,476 | ||||||
| Prepaid Post-Retirement Benefit Costs |
22,774 | — | ||||||
| Fair Value of Derivative Financial Instruments |
48,989 | 27,616 | ||||||
| Other |
2,447 | 1,105 | ||||||
|
|
|
|
|
|||||
| 617,944 | 839,763 | |||||||
|
|
|
|
|
|||||
| Total Assets |
$ | 6,218,347 | $ | 5,935,142 | ||||
|
|
|
|
|
|||||
| CAPITALIZATION AND LIABILITIES | ||||||||
| Capitalization: |
||||||||
| Comprehensive Shareholders’ Equity |
||||||||
| Common Stock, $1 Par Value |
||||||||
| Authorized — 200,000,000 Shares; Issued and Outstanding — 83,661,969 Shares and 83,330,140 Shares, Respectively |
$ | 83,662 | $ | 83,330 | ||||
| Paid In Capital |
687,684 | 669,501 | ||||||
| Earnings Reinvested in the Business |
1,442,617 | 1,306,284 | ||||||
| Accumulated Other Comprehensive Loss |
(19,234 | ) | (99,020 | ) | ||||
|
|
|
|
|
|||||
| Total Comprehensive Shareholders’ Equity |
2,194,729 | 1,960,095 | ||||||
| Long-Term Debt, Net of Current Portion |
1,649,000 | 1,149,000 | ||||||
|
|
|
|
|
|||||
| Total Capitalization |
3,843,729 | 3,109,095 | ||||||
|
|
|
|
|
|||||
| Current and Accrued Liabilities |
||||||||
| Notes Payable to Banks and Commercial Paper |
— | 171,000 | ||||||
| Current Portion of Long-Term Debt |
— | 250,000 | ||||||
| Accounts Payable |
105,283 | 87,985 | ||||||
| Amounts Payable to Customers |
12,828 | 19,964 | ||||||
| Dividends Payable |
31,373 | 30,416 | ||||||
| Interest Payable on Long-Term Debt |
29,960 | 29,491 | ||||||
| Customer Advances |
21,959 | 24,055 | ||||||
| Customer Security Deposits |
16,183 | 17,942 | ||||||
| Other Accruals and Current Liabilities |
83,946 | 79,099 | ||||||
| Fair Value of Derivative Financial Instruments |
639 | 24,527 | ||||||
|
|
|
|
|
|||||
| 302,171 | 734,479 | |||||||
|
|
|
|
|
|||||
| Deferred Credits |
||||||||
| Deferred Income Taxes |
1,347,007 | 1,065,757 | ||||||
| Taxes Refundable to Customers |
85,655 | 66,392 | ||||||
| Unamortized Investment Tax Credit |
1,579 | 2,005 | ||||||
| Cost of Removal Regulatory Liability |
157,622 | 139,611 | ||||||
| Other Regulatory Liabilities |
61,549 | 21,014 | ||||||
| Pension and Other Post-Retirement Liabilities |
158,014 | 516,197 | ||||||
| Asset Retirement Obligations |
119,511 | 119,246 | ||||||
| Other Deferred Credits |
141,510 | 161,346 | ||||||
|
|
|
|
|
|||||
| 2,072,447 | 2,091,568 | |||||||
|
|
|
|
|
|||||
| Commitments and Contingencies |
— | — | ||||||
|
|
|
|
|
|||||
| Total Capitalization and Liabilities |
$ | 6,218,347 | $ | 5,935,142 | ||||
|
|
|
|
|
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See Notes to Consolidated Financial Statements
- 75 -
Table of Contents
CONSOLIDATED STATEMENTS OF CASH FLOWS
| Year Ended September 30 | ||||||||||||
| 2013 | 2012 | 2011 | ||||||||||
| (Thousands of dollars) | ||||||||||||
| Operating Activities |
||||||||||||
| Net Income Available for Common Stock |
$ | 260,001 | $ | 220,077 | $ | 258,402 | ||||||
| Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities: |
||||||||||||
| Gain on Sale of Unconsolidated Subsidiaries |
— | — | (50,879 | ) | ||||||||
| Depreciation, Depletion and Amortization |
326,760 | 271,530 | 226,527 | |||||||||
| Deferred Income Taxes |
167,887 | 144,150 | 164,251 | |||||||||
| Excess Tax Costs (Benefits) Associated with Stock-Based Compensation Awards |
(675 | ) | (985 | ) | 1,224 | |||||||
| Elimination of Other Post-Retirement Regulatory Liability |
— | (21,672 | ) | — | ||||||||
| Stock-Based Compensation |
12,446 | 7,939 | 7,683 | |||||||||
| Other |
14,965 | 5,013 | 7,968 | |||||||||
| Change in: |
||||||||||||
| Hedging Collateral Deposits |
(730 | ) | 19,337 | (8,567 | ) | |||||||
| Receivables and Unbilled Utility Revenue |
(17,135 | ) | ||||||||||