10-K

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-K

(Mark One)

ýANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended October 31, 2014

or

¨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 1-6196

Piedmont Natural Gas Company, Inc.

(Exact name of registrant as specified in its charter)

North Carolina	56-0556998
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

4720 Piedmont Row Drive, Charlotte, North Carolina	28210
(Address of principal executive offices)	(Zip Code)

   Registrant’s telephone number, including area code (704) 364-3120

SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:

Title of each class	Name of each exchange on which registered
Common Stock, no par value	New York Stock Exchange

Indicate by check mark if the registrant is a well-known seasoned issuer as defined in Rule 405 of the Securities Act. Yes ý No ¨

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15 (d) of the Act. Yes ¨ No ý

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý 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 ý 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 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. ¨

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.

Large accelerated filer x	Accelerated filer o
Non-accelerated filer o (Do not check if a  smaller reporting company)	Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ¨ No ý

State the aggregate market value of the voting common equity held by non-affiliates of the registrant as of April 30, 2014.

Common Stock, no par value - $2,764,512,081

Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date.

Class	Outstanding at December 12, 2014
Common Stock, no par value	78,638,925

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Proxy Statement for the Annual Meeting of Shareholders on March 5, 2015 are incorporated by reference into Part III.

Piedmont Natural Gas Company, Inc.
2014 FORM 10-K ANNUAL REPORT
TABLE OF CONTENTS
		Page
Part I.
Item 1.	Business	1
Item 1A.	Risk Factors	9
Item 1B.	Unresolved Staff Comments	15
Item 2.	Properties	15
Item 3.	Legal Proceedings	16
Item 4.	Mine Safety Disclosures	16
Part II.
Item 5.	Market for Registrant’s Common Equity, Related Stockholder   Matters and Issuer Purchases of Equity Securities	17
Item 6.	Selected Financial Data	19
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results   of Operations	20
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	44
Item 8.	Financial Statements and Supplementary Data	46
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	106
Item 9A.	Controls and Procedures	106
Item 9B.	Other Information	109
Part III.
Item 10.	Directors, Executive Officers and Corporate Governance	109
Item 11.	Executive Compensation	109
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	109
Item 13.	Certain Relationships and Related Transactions, and Director Independence	109
Item 14.	Principal Accounting Fees and Services	109
Part IV.
Item 15.	Exhibits, Financial Statement Schedules	110
	Signatures	117

PART I

Item 1. Business

Piedmont Natural Gas Company, Inc. (Piedmont) was incorporated in New York in 1950 and began operations in 1951. In 1994, we merged into a newly formed North Carolina corporation with the same name for the purpose of changing our state of incorporation to North Carolina. Unless the context requires otherwise, references to “we,” “us,” “our,” “the Company” or “Piedmont” means consolidated Piedmont Natural Gas Company, Inc. and its subsidiaries.

Piedmont is an energy services company whose principal business is the distribution of natural gas to over one million residential, commercial, industrial and power generation customers in portions of North Carolina, South Carolina and Tennessee, including customers served by municipalities. We are invested in joint venture, energy-related businesses, including unregulated retail natural gas marketing, regulated interstate natural gas transportation and storage and regulated intrastate natural gas transportation.

In the Carolinas, our service area is comprised of numerous cities, towns and communities. We provide service from resource centers in Anderson, Greenville and Spartanburg in South Carolina and Charlotte, Salisbury, Greensboro, Winston-Salem, High Point, Burlington, Hickory, Indian Trail, Spruce Pine, Reidsville, Fayetteville, New Bern, Wilmington, Tarboro, Elizabeth City, Rockingham and Goldsboro in North Carolina. In North Carolina, we also provide natural gas service to Greenville, Rocky Mount and Wilson. In Tennessee, our service area is the metropolitan area of Nashville, including wholesale natural gas service to Gallatin and Smyrna.

We have three reportable business segments, regulated utility, regulated non-utility activities and unregulated non-utility activities, with the regulated utility segment being the largest. Factors critical to the success of the regulated utility include operating a safe and reliable natural gas distribution system and the ability to recover the costs and expenses of the business in the rates charged to customers. The regulated non-utility activities segment consists of our equity method investments in joint venture regulated energy-related businesses that are held by our wholly-owned subsidiaries. The unregulated non-utility activities segment consists primarily of our equity method investment in an unregulated energy-related joint venture that is held by a wholly-owned subsidiary. The percentages of assets as of October 31, 2014 and earnings before taxes by segment for the year ended October 31, 2014 are presented below.

			Earnings
	Assets		Before Taxes
Regulated Utility	96	%	86	%
Non-utility Activities:
Regulated non-utility activities	3	%	5	%
Unregulated non-utility activities	1	%	9	%
Total non-utility activities	4	%	14	%

Operations of our segments are conducted within the United States of America. For further information on equity method investments and business segments, see Note 12 and Note 14, respectively, to the consolidated financial statements in this Form 10-K.

Operating revenues shown in the Consolidated Statements of Comprehensive Income represent revenues from the regulated utility segment. The cost of purchased gas is a component of operating revenues. Increases or decreases in prudently incurred purchased gas costs from suppliers are passed through to customers through purchased gas adjustment (PGA) procedures. Therefore, our operating revenues are impacted by changes in gas costs as well as by changes in volumes of gas sold and transported. Secondary market transactions consist of off-system sales and capacity release arrangements and asset management arrangements and are part of our regulatory gas supply management program with regulator-approved sharing mechanisms between our utility customers and our shareholders. Operations of the regulated and unregulated non-utility activities segments are included in the Consolidated Statements of Comprehensive Income in “Other Income (Expense)” in “Income from equity method investments” and “Non-operating income.”

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Operating revenues by major customer class for the years ended October 31, 2014 and 2013 are presented below.

	2014		2013
Residential customers	46	%	46	%
Commercial customers	27	%	26	%
Large volume customers, including industrial, power generation and resale customers	14	%	15	%
Secondary market activities	12	%	12	%
Other sources	1	%	1	%
Total	100	%	100	%

Our utility operations are regulated by the North Carolina Utilities Commission (NCUC), the Public Service Commission of South Carolina (PSCSC) and the Tennessee Regulatory Authority (TRA) as to rates, service area, adequacy of service, safety standards, extensions and abandonment of facilities, accounting and depreciation. The NCUC also regulates us as to the issuance of long-term debt and equity securities.

We are also subject to various federal regulations that affect our utility and non-utility operations. These federal regulations include regulations that are particular to the natural gas industry, such as regulations of the Federal Energy Regulatory Commission (FERC) that affect the certification and siting of new interstate natural gas pipeline projects, the purchase and sale of, the prices paid for, and the terms and conditions of service for the interstate transportation and storage of natural gas, regulations of the U.S. Department of Transportation (DOT) that affect the design, construction, operation, maintenance, integrity, safety and security of natural gas distribution and transmission systems, and regulations of the Environmental Protection Agency (EPA) relating to the environment, including air emissions regulations that could be expanded to address emissions of methane. In addition, we are subject to numerous other regulations, such as those relating to employment and benefit practices, which are generally applicable to companies doing business in the United States of America.

We hold non-exclusive franchises for natural gas service in many of the communities we serve, with expiration dates from December 2014 to 2058. The franchises are adequate for the operation of our gas distribution business and do not contain materially burdensome restrictions or conditions. From time to time, some of our franchise agreements expire; however, we continue to operate in those areas pursuant to the provisions of the expired franchises with no significant impact on our business. Depending on the jurisdiction, we believe that these franchises will be renewed or that service will be continued in the ordinary course of business while we negotiate renewals or continue to operate under our state-granted franchise rights without a specific franchise agreement with each city or municipality. The likelihood of cessation of service under an expired franchise is remote, and we do not believe there will be a material adverse impact on us.

Our regulatory commissions approve rates and tariffs that are designed to give us the opportunity to recover the cost of natural gas we purchased for our customers and our operating expenses and to earn a fair rate of return on invested capital for our shareholders. The traditional utility rate design provides for the collection of margin revenue based on volumetric throughput which can be affected by customer consumption patterns, weather, conservation, price levels for natural gas or general economic conditions. By continually assessing alternative rate structures and cost recovery mechanisms that are more appropriate to the changing energy economy and through requests filed with our regulatory commissions, we have secured alternative rate structures and cost recovery mechanisms designed to allow us to recover certain costs through tracking mechanisms or riders without the need to file general rate cases. Our ability to earn our authorized rates of return is based in part on our ability to reduce or eliminate regulatory lag through rate stabilization adjustment (RSA) tariffs, integrity management riders (IMRs) or similar mechanisms and also by improved rate designs that decouple the recovery of our approved margins from customer usage patterns impacted by seasonal weather patterns and customer conservation. This allows a better alignment of the interests of our shareholders and customers.

In North Carolina, we have a margin decoupling mechanism that provides for the recovery of our approved margin from residential and commercial customers on an annual basis independent of consumption patterns. The margin decoupling mechanism provides for semi-annual rate adjustments to refund any over-collection of margin or to recover any under-collection of margin. In South Carolina, we operate under a RSA tariff mechanism that achieves the objective of margin decoupling for residential and commercial customers with a one year lag. Under the RSA tariff mechanism, we reset our rates based on updated costs and revenues on an annual basis. We also have a weather normalization adjustment (WNA) mechanism for residential and commercial customers in South Carolina for bills rendered during the months of November through March and in Tennessee for bills rendered during the months of October through April that partially offsets the impact of colder- or warmer-than-normal winter weather on our margin collections. Our WNA formulas calculate the actual weather variance from normal, using 30 years of history, and increase margin revenues when weather is warmer than normal and decrease margin

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revenues when weather is colder than normal. The WNA formulas do not ensure full recovery of approved margin during periods when customer consumption patterns vary from those used to establish the WNA factors and when weather is significantly warmer or colder than normal. Weather in 2014 on average over our three-state market area was 9%colder than normal and 6%colder than 2013. For the year ended October 31, 2014, the margin decoupling mechanism in North Carolina decreased margin by $33.4 million, and the WNA mechanisms in South Carolina and Tennessee together decreased margin by $8.4 million.

With approval in North Carolina and Tennessee in December 2013, we have IMRs that separately track and recover, on an annual basis outside general rate cases, costs associated with capital expenditures to comply with pipeline safety and integrity requirements. The first Tennessee IMR rate adjustment was recognized in earnings through customer billings beginning in January 2014, and the first North Carolina IMR rate adjustment was recognized in earnings through customer billings beginning in February 2014.

In all three states, the gas cost portion of our costs is recoverable through PGA procedures and is not affected by the margin decoupling mechanism or the WNA mechanism. Through the use of various tariff mechanisms and fixed-rate contracts, we are able to achieve a higher degree of margin stabilization. For further information on state commission regulation, see Note 2 to the consolidated financial statements in this Form 10-K. The following table presents the breakdown of our gas utility margin for the years ended October 31, 2014, 2013 and 2012.

	2014		2013		2012
Fixed margin (from margin decoupling in North Carolina, facilities charges to our
customers, Tennessee and North Carolina IMRs in 2014 only and fixed-rate contracts)	72	%	73	%	72	%
Semi-fixed margin (RSA in South Carolina and WNA in South Carolina and
Tennessee)	16	%	16	%	17	%
Volumetric or periodic renegotiation (including secondary marketing activity)	12	%	11	%	11	%
Total	100	%	100	%	100	%

The natural gas distribution business is seasonal in nature as variations in weather conditions and our regulated utility rate designs generally result in greater revenues and earnings during the winter months when temperatures are colder. For further information on weather sensitivity and the impact of seasonality on working capital, see “Financial Condition and Liquidity” in Item 7 of this Form 10-K in Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Our Strategies

We monitor our progress and measure our performance related to our strategic directives and business objectives over the course of each fiscal year. The metrics we use to measure our performance include, but are not limited to, earnings per share (EPS) and EPS growth, total shareholder return compared to our industry peer group, return on invested capital, return on equity, utility margin, investment grade credit ratings, customer growth, utility customer satisfaction and loyalty, operations and maintenance (O&M) expense discipline, employee health and safety, pipeline safety, and sustainable business practices.

Safety is a critical component to our ongoing success as a company, and we have always placed the highest priority on the safety of our system, public safety and employee safety. We must comply with laws that regulate system integrity as well as new rulemaking proceedings under the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011. We are subject to DOT and state regulation of our pipeline and related facilities and have ongoing transmission and distribution pipeline integrity programs to inspect our system for anomalies, corrosion and leaks as well as monitoring key metrics of our system for its safe operation. We anticipate federal legislative and regulatory enactments will increase in scope and add further requirements and costs to our pipeline safety and integrity programs and our capital and O&M expenditure programs. Items currently being discussed by federal regulators include possible mandates addressing the integrity verification process of maximum allowable operating pressure of transmission pipelines. We will continue our efforts to educate the public about our pipeline system in an effort to decrease third-party excavation damage, which is the greatest cause of damage on our system. We encourage focused efforts to improve the safety of our industry as a whole.

We believe natural gas is a safe and reliable energy source that is clean, affordable, reliable and environmentally responsible, as well as being domestically abundant. We incorporate this message into our pursuit of growth in our core residential, commercial, industrial and power generation markets as well as complementary energy-related investments. We promote the increased awareness and use of natural gas and want our customers to choose us because of the value of natural gas and the quality of our service to them.

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Our business model supports new clean energy technologies and energy efficiencies in the end use of natural gas. We seek opportunities for regulatory innovation and strategic alliances to advance our customers’ interests in energy conservation, efficiency and environmental stewardship. We are promoting the direct use of natural gas in more homes, businesses, industries and vehicles as we strongly believe that the expanded use of clean, efficient, abundant and domestic natural gas with its relatively low emissions can help revitalize our economy, reduce both overall energy consumption and greenhouse gas emissions and enhance our national energy security.

We see an opportunity in the clean energy technology of compressed natural gas (CNG) vehicles. We have converted 28% of our nearly 1,100 vehicle fleet to CNG and intend for one-third of the vehicles in our fleet to be fueled by CNG by the end of 2015. As of October 31, 2014, we have approximately $17.8 million of utility plant related to our CNG fueling stations that is included in the Consolidated Balance Sheets in “Utility plant in service.” We are allowed by each of our three state regulatory commissions to include this utility plant in service in our utility rate base and have the opportunity to earn the allowed rate of return in each jurisdiction.

We continued to execute our plan to build CNG fueling stations in our service area for use by our own vehicle fleet as well as by third-party fleets and other customers when there is sufficient demand to allow us to earn our allowed rate of return. In the current fiscal year, we opened our second CNG fueling station in Tennessee, which was our tenth station in our three-state service territory. We are also actively pursuing building customer-owned CNG fueling stations at commercial customers’ sites for use by their commercial fleets. There are currently twelve customer owned stations in our service territory.

CNG throughput increased by 152% in 2014 compared with the same prior period, and we anticipate CNG throughput to increase by at least 30% in 2015. Between Piedmont and customer-owned CNG stations, we sold or transported 250,000 dekatherms of CNG to commercial customers for the year ended October 31, 2014, equivalent to approximately 4,350 homes, and used 17,000 dekatherms of CNG in our own fleets. Between our customers and use by our own fleet, this CNG usage displaced more than 2.1 million gallons of gasoline and diesel fuel.

Due to the environmental and cost benefits of using natural gas compared to coal in the generation of electricity, we completed five pipeline expansion projects since 2010 to provide long-term natural gas delivery service to new natural gas-fired power generation facilities in our market area. These new natural gas power plants are designed to emit significantly less carbon emissions than the coal power plants they replaced. We currently provide service to 25 power generation customer accounts. In addition to delivering the natural gas supply to the new natural gas-fired power plants, the construction of natural gas pipelines for two of these projects increased our natural gas infrastructure in the eastern part of North Carolina with enhancement of future opportunities for economic growth and development. In June 2014, we executed an agreement to construct approximately 1.5 miles of natural gas transmission pipeline and associated compression facilities to serve Duke Energy Corporation’s (Duke Energy) W.S. Lee power generation facility near Anderson, South Carolina. Piedmont’s anticipated investment of approximately $38 million in the pipeline and compression facilities is supported by a long-term service agreement with Duke Energy with a scheduled in service date of May 2017.

Our capital program primarily supports our system infrastructure and the growth in our customer base. We are investing in our pipeline integrity, safety and compliance programs, and systems and technology infrastructure to enhance our pipeline system and integrity. For further information on our forecasted capital investments for fiscal 2015 – 2017, see “Cash Flows from Investing Activities” in Item 7 of this Form 10-K in Management’s Discussion and Analysis of Financial Condition and Results of Operations.

We strive to achieve excellence in service to our customers and in our business operations with every customer contact we make. In our business practices, we promote a sustainable enterprise by reducing our impact on the environment, developing strong communities in which we operate and enhancing long-term shareholder value. We support our employees with improved processes and technology to better serve our customers while continuing to build a healthy, high performance culture in order to recruit, retain and motivate our workforce.

Our financial strength and flexibility is critical to our success as a company. We will continue our efforts to maintain our financial strength which includes a strong balance sheet, investment-grade credit ratings and continued access to capital markets. We evaluate the strength of financial institutions with which we have working relationships to ensure access to funds for operations and capital investments. Our capital plan includes maintaining a capitalization ratio of 50 – 60% in total debt and 40 – 50% in common equity. We will continue our efforts to control our operating costs, implement new technologies and work with our state regulators to maintain fair rates of return and innovative rate designs for the benefit of our customers and shareholders.

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While we will preserve our identity as a pure-play local distribution company, we pursue strategic opportunities aligned with our core natural gas or complementary energy related businesses. It is our long-term strategic intent for our joint venture portfolio to be primarily weighted towards regulated and asset-based investments in natural gas infrastructure. We analyze and evaluate potential projects based on projected rates of return commensurate with the risk of such projects. We participate in the governance of our ventures by having management representatives on the governing boards. We monitor actual performance against expectations, specifically annual approved budgets, and any decision to exit an existing joint venture would be based on many factors, including performance results and continued alignment with our business strategies.

To further our strategy of expanding our complementary energy-related businesses, we invested in Constitution Pipeline Company, LLC, whose purpose is to construct and operate approximately 120 miles of interstate natural gas pipeline and related facilities connecting shale natural gas supplies and gathering systems in Susquehanna County, Pennsylvania, to the Iroquois Gas Transmission and Tennessee Gas Pipeline systems in New York. We have committed to fund an amount in proportion to our ownership interest of 24% for the development and construction of the new pipeline, which is expected to cost approximately $730 million. For further information on this equity method investment, see Note 12 to the consolidated financial statements in this Form 10-K.

Also, in September 2014, Piedmont, Duke Energy, Dominion Resources, Inc., and AGL Resources, Inc. announced the formation of Atlantic Coast Pipeline, LLC (ACP), a Delaware limited liability company. ACP intends to construct, operate and maintain a 550 mile natural gas pipeline, with associated compression, from West Virginia through Virginia into eastern North Carolina. The pipeline will provide wholesale natural gas transportation services for Marcellus and Utica gas supplies into southeastern markets. We are a 10% equity member of ACP. We have committed to fund an amount in proportion to our ownership interest of 10% for the development and construction of the new pipeline, which is expected to cost between $4.5 billion to $5 billion. For further information on this equity method investment, see Note 12 to the consolidated financial statements in this Form 10-K.

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Operating Statistics

The following is a five-year comparison of operating statistics for the years ended October 31, 2010 through 2014.

	2014			2013			2012			2011			2010
Operating Revenues (in thousands):
Sales and Transportation:
Residential	$	683,848		$	588,546		$	534,321		$	658,892		$	743,346
Commercial	397,004			331,831			301,013			379,846			428,085
Industrial	115,515			113,182			95,177			104,774			116,122
Power Generation	85,902			64,109			36,027			28,969			21,708
For Resale	9,587			9,549			9,512			9,692			11,061
Total	1,291,856			1,107,217			976,050			1,182,173			1,320,322
Secondary Market Sales	169,543			164,130			140,380			244,824			224,973
Miscellaneous	8,589			6,882			6,350			6,908			7,000
Total	$	1,469,988		$	1,278,229		$	1,122,780		$	1,433,905		$	1,552,295
Gas Volumes - Dekatherms (in thousands)
System Throughput:
Residential	61,782			55,283			43,788			57,778			58,327
Commercial	44,259			39,602			33,774			40,749			39,994
Industrial	95,780			95,019			89,234			90,842			82,805
Power Generation	201,707			190,862			151,675			83,522			63,024
For Resale	7,174			6,834			5,829			6,870			8,465
Total	410,702			387,600			324,300			279,761			252,615
Secondary Market Sales	20,516			41,605			48,373			48,835			46,823
Number of Customers Billed (12-month average):
Residential	903,067			890,887			878,851			871,401			864,205
Commercial	97,288			96,009			95,100			94,485			94,287
Industrial	2,279			2,271			2,265			2,265			2,273
Power Generation	25			24			22			22			20
For Resale	16			15			15			15			16
Total	1,002,675			989,206			976,253			968,188			960,801
Cost of Gas (in thousands):
Natural Gas Commodity Costs	$	621,604		$	526,703		$	379,145		$	666,930		$	753,529
Capacity Demand Charges	144,313			151,369			129,090			136,139			127,137
Natural Gas Withdrawn From
(Injected Into) Storage, net	(13,578		)	(5,867		)	27,580			11,362			5,293
Regulatory Charges (Credits), net	27,441			(15,466		)	11,519			45,835			113,744
Total	$	779,780		$	656,739		$	547,334		$	860,266		$	999,703
Supply Available for Distribution (dekatherms in thousands):
Natural Gas Purchased	134,986			142,884			132,426			155,550			157,021
Transportation Gas	299,166			287,980			235,474			175,005			147,038
Natural Gas Withdrawn From
(Injected Into) Storage, net	(1,232		)	(509		)	(378		)	196			(1,309		)
Company Use	(731		)	(369		)	(296		)	(309		)	(282		)
Total	432,189			429,986			367,226			330,442			302,468

During the year ended October 31, 2014, we delivered 410.7 million dekatherms to our utility retail customers compared to 387.6 million dekatherms the year before. Of this amount, 304.7 million dekatherms of gas were sold to or transported for large volume customers compared with 292.7 million dekatherms in 2013. Of these volumes sold to or transported for large volume customers, we transported 201.7 million dekatherms in 2014 to power generation facilities compared with 190.9 million dekatherms in the prior year. The margin earned from power generation customers is largely based on fixed monthly demand charge contracts and does not vary significantly based on the volumes transported. Deliveries to temperature-sensitive residential and commercial customers, whose consumption varies with the weather, totaled 106 million

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dekatherms in 2014, compared with 94.9 million dekatherms in 2013. Weather, as measured by degree days, was 9%colder than normal in 2014 and 2% colder than normal in 2013.

With continued improvement in economic conditions resulting in growth in both the residential and commercial markets and targeted marketing programs on the benefits of natural gas, new customer additions increased in our fiscal year 2014 as compared to fiscal year 2013 as presented below.

			Percent
	2014	2013	Change
Residential new home construction	11,659	10,299	13.2	%
Residential conversion	2,814	2,463	14.3	%
Commercial	1,763	1,512	16.6	%
Industrial	15	19	(21.1	)%
Total new customers	16,251	14,293	13.7	%

We forecast continuing gross customer growth in fiscal 2015 of 1.6% on our base of approximately one million utility retail customers. Total net customers billed increased 1.3% in fiscal year 2014 compared to 2013.

Natural Gas Utility Operations

We purchase natural gas under firm contracts to meet our design-day requirements for firm sales customers. These contracts provide that we pay a reservation fee to the supplier to reserve or guarantee the availability of gas supplies for delivery. Under these provisions, absent force majeure conditions, any disruption of supply deliverability is subject to penalty and damage assessment against the supplier. We ensure the delivery of the gas supplies to our distribution system to meet the peak day, seasonal and annual needs of our firm customers by using a variety of firm transportation and storage capacity contracts. The pipeline capacity contracts require the payment of fixed monthly demand charges to reserve firm transportation or storage entitlements. We align the contractual agreements for supply with the firm capacity agreements in terms of volumes, receipt and delivery locations and demand fluctuations. We may supplement these firm contracts with other supply arrangements to serve our interruptible market.

As of October 31, 2014, we had contracts for the following pipeline firm transportation in dekatherms per day.

Williams – Transco	632,200
Kinder Morgan – Tennessee Pipeline	74,100
Spectra – Texas Eastern (partially through East Tennessee and Transco)	36,700
Oneok – Midwestern (through either Tennessee, Columbia Gulf, East Tennessee or Transco)	120,000
NiSource – Columbia Gas (through Transco and Columbia Gulf)	42,800
NiSource – Columbia Gulf	41,000
Total	946,800

As of October 31, 2014, we had the following assets or contracts for local peaking facilities and storage for seasonal or peaking capacity in dekatherms of daily deliverability to meet the firm demands of our markets with deliverability from 5 days to one year.

Piedmont Liquefied Natural Gas (LNG)	270,000	*
Pine Needle LNG (through Transco)	263,400
Williams – Transco Storage	86,100
NiSource – Columbia Gas Storage	96,400
Hardy Storage (through Columbia Gas and Transco)	68,800
Kinder Morgan – Tennessee Pipeline	55,900
Total	840,600

* During the winter heating season 2013 - 2014, deliverability was reduced due to facility restrictions.

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As of October 31, 2014, we own or have under contract 35.6 million dekatherms of storage capacity, either in the form of underground storage or LNG. This capacity is used to supplement or replace regular pipeline supplies.

As is prevalent in the industry, we inject natural gas into storage during the summer months (principally April through October) when customer demand is lower for withdrawal from storage during the winter heating season (principally November through March) when customer demand is higher. During the year ended October 31, 2014, the amount of natural gas in storage varied from 10.4 million (one dekatherm equals 1,000,000 BTUs) to 24.2 million, and the weighted average commodity cost of this gas in storage varied from $44.3 million to $97.5 million.

Natural gas development and production in North America continues to provide abundant supply and price stability and moderation for natural gas as an energy commodity. With lower gas prices over the past seven years, we have been able to significantly lower the cost of gas to our customers with multiple filings for reductions in the wholesale natural gas component of customer rates in the three jurisdictions that we serve. Currently, natural gas has a price advantage over other fuels, and it is anticipated that the cost of natural gas will remain competitive due to abundant sources of shale gas reserves.

We purchase our natural gas supplies by contracting primarily with major and independent producers and marketers. We also purchase a diverse portfolio of transportation and storage services from interstate pipelines that are regulated by the FERC. Peak-use requirements are met through the use of company owned storage facilities, pipeline transportation capacity, purchased storage services and other supply sources. We have been able to obtain sufficient supplies of natural gas to meet customer requirements, and with the prospect of abundant domestic shale natural gas supplies and our contracted pipeline capacity, we believe that we will be able to meet our market demands in the future.

When firm pipeline services or contracted gas supplies are temporarily not needed due to market demand fluctuations, we may release these services and supplies in the secondary market under FERC-approved capacity release provisions or make wholesale secondary market sales. The proceeds from those transactions are used to reduce the cost of natural gas we charge to customers through sharing mechanisms that are in place in all three jurisdictions whereby customers are allocated 75% of the savings through the incentive plans. For further information on these regulatory sharing mechanisms, see Note 2 to the consolidated financial statements in this Form 10-K.

We continue to diversify our supply portfolio by contracting to bring abundant and low cost natural gas supplies from the Marcellus supply basin to our natural gas markets in the Carolinas. In November 2012, we signed a long-term contract with Cabot Oil & Gas to purchase firm, price-competitive Marcellus gas supplies. We also signed a long-term firm capacity contract with Williams – Transco under its Leidy Southeast expansion project to transport the Marcellus based Cabot gas supplies to our markets. In December 2012, we also signed a long-term firm capacity contract with Williams – Transco under its Virginia Southside expansion project that will also allow us to further diversify our supply portfolio with Marcellus based natural gas. These new supply and capacity arrangements are scheduled to begin in late 2015, and we believe they will provide diversification, reliability and gas cost benefits to Piedmont’s customers across the Carolinas. Also, with the new ACP project that is targeted to be in service in late 2018, we will have additional pipeline capacity from the Marcellus and Utica supply basin under a long-term firm service agreement that we executed with ACP, subject to FERC approval of the project.

Competition

Our regulated utility competes with other energy products, such as electricity and propane, in the residential and commercial customer markets. The most significant product competition is with electricity for space heating, water heating and cooking. Numerous factors can influence customer demand for natural gas including price, value, availability, environmental attributes, comfort, convenience, reliability and energy efficiency. Increases in the price of natural gas can negatively impact our competitive position by decreasing the price benefits of natural gas to the consumer. This can lead to slower customer growth or customer conservation, or both, resulting in reduced gas purchases and customer billings. In turn, this can impact our capital expenditures and overall cash needs, including working capital needs. The direct use of natural gas in homes and businesses is the most efficient and cost effective use of natural gas and results in overall lower carbon emissions. However, the use of natural gas for power generation also adds significant value as a result of natural gas’ environmental attributes, competitive cost advantage and efficiency of delivery.

During the year ended October 31, 2014, approximately 4% of our margin (operating revenues less cost of gas) was generated from deliveries to industrial or large commercial customers that have the capability to burn a fuel other than natural gas, with fuel oil being the most significant competing energy alternative. Our ability to maintain industrial market share is largely dependent on relative prices of energy. The relationship between supply and demand has the greatest impact on the price of natural gas. The price of oil depends upon a number of factors beyond our control, including the relationship between worldwide supply and demand and the policies of foreign and domestic governments and organizations, as well as the value of

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the U.S. dollar versus other currencies. Our liquidity could be impacted, either positively or negatively, as a result of changes in oil and natural gas prices and the alternate fuel decisions made by industrial customers.

Under FERC policies, certain large volume customers located in proximity to the interstate pipelines delivering gas to us could bypass us and take delivery of gas directly from the pipeline or from a third party connecting with the pipeline. During the fiscal year ended October 31, 2014, no bypass occurred. The future level of bypass activity cannot be predicted.

Natural gas for power generation competes with other fuel sources for the generation of electricity, including coal, nuclear and renewable resources. Additionally, as with industrial customers, we compete with other pipeline providers to serve the power generation plants.

Other

During the year ended October 31, 2014, our largest revenue generating customer contributed $89.2 million, or 6%, of total operating revenues. Our largest margin generating customer contributed $73.8 million, or 11% of total margin. Our largest revenue and margin generating customer is the same customer.

Our costs for research and development are not material and are primarily limited to natural gas industry-sponsored research projects.

Compliance with federal, state and local environmental protection laws have had no material effect on our construction expenditures, earnings or competitive position. For further information on environmental issues, see “Environmental Matters” in Item 7 in this Form 10-K in Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Costs incurred for natural gas, labor, employee benefits, consulting and construction are the business charges that we incur that are most significantly impacted by inflation. Changes to the cost of gas are generally recovered through regulatory mechanisms and do not significantly impact net income. Labor and employee benefits are components of the cost of service, and construction costs less utility deferred income taxes are the primary components of rate base. In order to recover increased costs and earn a fair return on rate base, we file general rate cases for review and approval by regulatory authorities when necessary. The ratemaking process has a natural time lag between incurrence of additional costs and the setting of new rates. See discussion above for information on IMRs to track and recover certain capital costs in North Carolina and Tennessee outside of a general rate case. In South Carolina, we operate under a RSA mechanism that reduces regulatory lag to one year, but we reserve the right to file general rate cases when necessary. Regulatory lag can impact earnings.

As of October 31, 2014, our fiscal year end, we had 1,879 employees compared with 1,795 as of October 31, 2013.

Our reports on Form 10-K, Form 10-Q and Form 8-K, and any amendments to these reports, are available at no cost on our website at www.piedmontng.com as soon as reasonably practicable after the report is filed with or furnished to the Securities and Exchange Commission.

Item 1A. Risk Factors

An overall economic downturn could negatively impact our earnings.

Any weakening of economic activity in our markets could result in a loss of customers, a decline in customer additions, especially in the new home construction market, or a decline in energy consumption, which could adversely affect our revenues or restrict our future growth. It may become more difficult for customers to pay their gas bills, leading to slow collections and higher-than-normal levels of accounts receivable. This could increase our financing requirements and non-gas cost bad debt expense. Deteriorating economic conditions could also affect pension costs by reducing the value of the investments that fund our pension plan and negatively affect actuarial assumptions, resulting in increased pension costs. The foregoing could negatively affect earnings and liquidity, reducing our ability to grow the business.

Increases in the wholesale price of natural gas could reduce our earnings and working capital.

A supply and demand imbalance in natural gas markets could cause an increase in the price of natural gas. Recently, the increased production of U.S. shale natural gas has put downward pressure on the wholesale cost of natural gas; accordingly, restrictions or regulations on shale gas production could cause natural gas prices to increase. Additionally, the Commodity Futures Trading Commission (CFTC) under the 2010 Dodd-Frank Wall Street Reform and Consumer Protection Act has

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regulatory authority of the over-the-counter derivatives markets. Regulations affecting derivatives could increase the price of our gas supply. The prudently incurred cost we pay for natural gas is passed directly through to our customers. Therefore, significant increases in the price of natural gas may cause our existing customers to conserve or motivate them to switch to alternate sources of energy as well as cause new home developers, builders and new customers to select alternative sources of energy. Decreases in the volume of gas we sell could reduce our earnings in the absence of decoupled rate structures, and a decline in new customers could impede growth in our future earnings. In addition, during periods when natural gas prices are high, our working capital costs could increase due to higher carrying costs of gas storage inventories, adding further upward pressure on customer bills. Customers may have trouble paying those higher bills which may lead to bad debt expenses, ultimately reducing our earnings.

The availability of adequate interstate pipeline transportation capacity and natural gas supply may decrease.

We purchase almost all of our gas supply from interstate sources that must then be transported to our service territory. Interstate pipeline companies transport the gas to our system under firm service agreements that are designed to meet the requirements of our core markets. A significant disruption to or reduction in that supply or interstate pipeline capacity due to events including but not limited to, operational failures or disruptions, hurricanes, tornadoes, floods, freeze off of natural gas wells, terrorist or cyber-attacks or other acts of war, or legislative or regulatory actions or requirements, including remediation related to integrity inspections, could reduce our normal interstate supply of gas and thereby reduce our earnings. Moreover, if additional natural gas infrastructure, including but not limited to exploration and drilling rigs and platforms, processing and gathering systems, off-shore pipelines, interstate pipelines and storage, cannot be built at a pace that meets demand, then our growth opportunities would be limited and our earnings negatively impacted.

Regulatory actions at the state level could impact our ability to earn a reasonable rate of return on our invested capital and to fully recover our operating costs as well as reduce our earnings.

Our regulated utility segment is regulated by the NCUC, the PSCSC and the TRA. These agencies set the rates that we charge our customers for our services. We monitor allowed rates of return and our ability to earn appropriate rates of return based on factors, such as increased operating costs, and initiate general rate proceedings as needed. Our earnings could be negatively impacted if a state regulatory commission were to prohibit us from setting rates that allow for the timely recovery of our costs and a reasonable return, or significantly lowers our allowed return or negatively alters our cost allocation, rate design, cost trackers, including margin decoupling and cost of gas, or prohibits recovery of regulatory assets, including deferred gas costs.

In the normal course of business in the regulatory environment, assets are placed in service before rate cases can be filed that could result in an adjustment of our returns. Once rate cases are filed, regulatory bodies have the authority to suspend implementation of the new rates while studying the cases. Because of this process, we may suffer the negative financial effects of having placed in service assets that do not initially earn our authorized rate of return without the benefit of rate relief, which is commonly referred to as “regulatory lag.” Additionally, our capital investment in recent years has been and is projected to remain at higher levels, increasing the risk of cost recovery. All of this may negatively impact our results of operations and earnings.

Rate cases also involve a risk of rate reduction, because once rates have been filed, they are still subject to challenge for their reasonableness by various intervenors. State regulators have approved various mechanisms to stabilize our gas utility margin, including margin decoupling in North Carolina, rate stabilization in South Carolina, and uncollectible gas cost recovery in all states. State regulators have approved other margin stabilizing mechanisms that, for example, allow us to recover any margin losses associated with negotiated transactions designed to retain large volume customers that could use alternative fuels or that may otherwise directly access natural gas supply through their own connection to an interstate pipeline. If regulators decided to discontinue allowing us to use these tariff mechanisms, it would negatively impact our results of operations, financial condition and cash flows. In addition, regulatory authorities also review whether our gas costs are prudent and can disallow the recovery of a portion of our gas costs that we seek to recover from our customers, which would adversely impact earnings.

Our debt and equity financings are also subject to regulation by the NCUC. Delays or failure to receive NCUC approval could limit our ability to access or take advantage of changes in the capital markets. This could negatively impact our liquidity or earnings.

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Our business is subject to competition that could negatively affect our results of operations.

The natural gas business is competitive, and we face competition from other companies that supply energy, including electric companies, oil and propane dealers, renewable energy providers and coal companies in relation to sources of energy for electric power plants, as well as nuclear energy. A significant competitive factor is price.

In residential, commercial and industrial customer markets, our natural gas distribution operations compete with other energy products, primarily electricity, propane and fuel oil. Our primary product competition is with electricity for heating, water heating and cooking. Increases in the price of natural gas or decreases in the price of other energy sources could negatively impact our competitive position by decreasing the price benefits of natural gas to the consumer. In the case of industrial customers, such as manufacturing plants, adverse economic or market conditions, including higher gas costs, could cause these customers to suspend business operations or to use alternative sources of energy or bypass our systems in favor of energy sources with lower per-unit costs.

Higher gas costs or decreases in the price of other energy sources may allow competition from alternative energy sources for applications that have traditionally used natural gas, encouraging some customers to move away from natural gas-fired equipment to equipment fueled by other energy sources. Competition between natural gas and other forms of energy is also based on efficiency, performance, reliability, safety and other non-price factors. Technological improvements in other energy sources and events that impair the public perception of the non-price attributes of natural gas could erode our competitive advantage. These factors in turn could decrease the demand for natural gas, impair our ability to attract new customers, and cause existing customers to switch to other forms of energy or to bypass our systems in favor of alternative competitive sources. This could result in slow or no customer growth and could cause customers to reduce or cease using our product, thereby reducing our ability to make capital expenditures and otherwise grow our business and adversely affecting our earnings.

Our business activities are concentrated in three states.

Approximately 96% of our assets and 86% of our earnings before taxes come from our regulated utility businesses. Further, approximately 70% of our natural gas utility customers, including customers served by three North Carolina municipalities who are our wholesale customers, and most of our utility transmission and distribution pipelines are located in North Carolina, with the remainder located in South Carolina and Tennessee. Changes in the regional economies, politics, regulations and weather patterns of North Carolina, South Carolina and Tennessee could negatively impact the growth opportunities available to us and the usage patterns and financial condition of customers and could adversely affect our earnings.

We are subject to new and existing laws and regulations that may require significant expenditures, significantly increase operating costs, or significant fines or penalties for noncompliance.

Our business and operations are subject to regulation by the FERC, the NCUC, the PSCSC, the TRA, the DOT, the EPA, the CFTC and other agencies, and we are subject to numerous federal and state laws and regulations. Compliance with existing or new laws and regulations may result in increased capital, operating and other costs which may not be recoverable in rates from our customers. For example, while we have implemented an IMR mechanism in North Carolina and Tennessee to recover certain capital expenditures made in compliance with federal and state safety and integrity management laws or regulations, there is a risk that the relevant regulators will disallow some of the expenditures under the IMR mechanism, and that the costs expended in compliance with such laws would not be recoverable through such rate mechanisms (but rather through general rate cases with extended lag). Because the language in some laws and regulations is not prescriptive, there is a risk that our interpretation of these laws and regulations may not be consistent with expectations of regulators. Any compliance failure related to these laws and regulations may result in fines, penalties or injunctive measures affecting operating assets. For example, under the Energy Policy Act of 2005, the FERC has civil penalty authority under the Natural Gas Act to impose penalties for current violations of up to $1 million per day for each violation. As the regulatory environment for our industry increases in complexity, the risk of inadvertent noncompliance could also increase. All of these events could result in a material adverse effect on our business, results of operations or financial condition.

Climate change, carbon neutral or energy efficiency legislation or regulations could increase our operating costs or restrict our market opportunities, negatively affecting our growth, cash flows and earnings.

The federal and/or state governments may enact legislation or regulations that attempt to control or limit the causes of climate change, including greenhouse gas emissions such as carbon dioxide and air emissions regulations that could be expanded to address emissions of methane. Such laws or regulations could impose costs tied to carbon emissions, operational

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requirements or restrictions, or additional charges to fund energy efficiency activities. They could also provide a cost advantage to alternative energy sources, impose costs or restrictions on end users of natural gas, or result in other costs or requirements, such as costs associated with the adoption of new infrastructure and technology to respond to new mandates. The focus on climate change could negatively impact the reputation of fossil fuel products or services. The occurrence of these events could put upward pressure on the cost of natural gas relative to other energy sources, increase our costs and the prices we charge to customers, reduce the demand for natural gas, and impact the competitive position of natural gas and the ability to serve new customers, negatively affecting our growth opportunities, cash flows and earnings.

Weather conditions may cause our earnings to vary from year to year.

Our earnings can vary from year to year, depending in part on weather conditions. Warmer-than-normal weather can reduce our utility margins as customer consumption declines. We have in place regulatory mechanisms and rate design that normalize the margin we collect from certain customer classes during the winter, providing for an adjustment up or down, to take into account warmer-than-normal or colder-than-normal weather. If our rates and tariffs are modified to eliminate weather protection provisions, such as weather normalization and rate decoupling tariffs, then we would be exposed to significant risk associated with weather. Additionally, our weather normalization mechanisms do not ensure full protection, especially for significantly warmer-than-normal winter weather. As a result of these events, our results of operations and earnings could vary and be negatively impacted.

The operation of our gas distribution and transmission activities may be interrupted by accidents, work stoppage, severe weather conditions, including destructive weather patterns, such as hurricanes, tornadoes and floods, pandemic or acts of terrorism and sabotage.

Inherent in our gas distribution and transmission activities, including natural gas and LNG storage, are a variety of hazards and operational risks, such as third-party excavation damage, leaks, ruptures and mechanical problems. Severe weather conditions, as well as acts of terrorism and sabotage, could also damage our pipelines and other infrastructure and disrupt our ability to conduct our natural gas distribution and transportation business. The outbreak of a pandemic could result in a significant part of our workforce being unable to operate or maintain our infrastructure or perform other tasks necessary to conduct our business. If these events are severe enough or if they lead to operational interruptions, they could cause substantial financial losses. In addition, these risks could result in loss of human life, significant damage to property, environmental damage, impairment of our operations and substantial loss to us. The location of pipeline and storage facilities near populated areas, including residential areas, commercial business centers, industrial sites and other public gathering places, could increase the level of damages resulting from these risks. Our regulators may not allow us to recover part or all of the increased cost related to the foregoing events from our customers, which would negatively affect our earnings. The occurrence of any of these events could adversely affect our financial position, results of operations and cash flows.

We may not be able to complete necessary or desirable pipeline expansion or infrastructure development or maintenance projects, which may delay or prevent us from serving our customers or expanding our business.

In order to serve current or new customers or expand our service to existing customers, we need to maintain, expand or upgrade our distribution, transmission and/or storage infrastructure, including laying new pipeline and building compressor stations. Various factors may prevent or delay us from completing such projects or make completion more costly, such as the inability to obtain required approval from local, state and/or federal regulatory and governmental bodies, public opposition to the project, inability to obtain adequate financing, competition for labor and materials, construction delays, cost overruns, and inability to negotiate acceptable agreements relating to rights-of-way, construction or other material development components. As a result, we may not be able to adequately serve existing customers or support customer growth, or could result in higher than anticipated cost, both of which would negatively impact our earnings.

Elevated levels of capital expenditures may weaken our financial position and inhibit customer growth.

We make significant annual capital expenditures for system integrity, infrastructure and maintenance that do not immediately produce revenue. We have the ability to recover these costs either through general rate cases or alternative rate mechanisms approved by state regulatory commissions, such as RSAs and IMRs, that periodically adjust rates to reflect incurred capital expenditures. However, before rates are adjusted, we fund construction through operating cash flows and by accessing short- and long-term capital markets and as a result, we may experience reduced liquidity and deteriorating credit metrics, which may weaken our financial position and could trigger a possible downgrade from the rating agencies. In addition, after these capital costs are reflected in rates, to the extent that rates rise considerably, customers may choose alternative forms of energy to meet their needs. This would reduce our customer growth, which would weaken our financial position by reducing earnings and cash flows.

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A downgrade in our credit ratings could negatively affect our cost of and ability to access capital.

Our ability to obtain adequate and cost effective financing depends in part on our credit ratings. A negative change in our ratings outlook or any downgrade in our current investment-grade credit ratings by our rating agencies, particularly below investment grade, could adversely affect our costs of borrowing and/or access to sources of liquidity and capital. Such a downgrade could further limit our access to private credit markets and increase the costs of borrowing under available credit lines. Should our credit ratings be downgraded, the interest rate on our borrowings under our revolving credit agreement and commercial paper (CP) program, as well as on any future public or private debt issuances, would increase. An increase in borrowing costs without the ability to recover these higher costs in the rates charged to our customers could adversely affect earnings by limiting our ability to earn our allowed rate of return.

We may be unable to access capital or the cost of capital may significantly increase.

Our ability to obtain adequate and cost effective financing is dependent upon the liquidity of the financial markets, in addition to our credit ratings. Disruptions in the capital and credit markets or waning investor sentiment could adversely affect our ability to access short-term and long-term capital. Our access to funds under our CP program is dependent on investor demand for our commercial paper. Disruptions and volatility in the global credit markets could limit the demand for our commercial paper or result in the need to offer higher interest rates to investors, which would result in higher expense and could adversely impact liquidity. Tax rates on dividends may increase, which could increase the cost of equity. The inability to access adequate capital or the increase in cost of capital may require us to conserve cash, prevent or delay us from making capital expenditures, and require us to reduce or eliminate the dividend or other discretionary uses of cash. A significant reduction in our liquidity could cause a negative change in our ratings outlook or even a reduction in our credit ratings. This could in turn further limit our access to credit markets and increase our costs of borrowing.

Changes in federal and/or state fiscal, tax and monetary policy could significantly increase our costs or decrease our cash flows.

Changes in federal and/or state fiscal, tax and monetary policy may result in increased taxes, interest rates, and inflationary pressures on the costs of goods, services and labor. This could increase our expenses and decrease our earnings if we are not able to recover such increased costs from our customers. These events may increase our rates to customers and thus may negatively impact customer billings and customer growth. Changes in accounting or tax rules could negatively affect our cash flows. Any of these events may cause us to increase debt, conserve cash, negatively affect our ability to make capital expenditures to grow the business or require us to reduce or eliminate the dividend or other discretionary uses of cash, and could negatively affect earnings.

We do not generate sufficient cash flows to meet all our cash needs.

We have made, and expect to continue to make, large capital expenditures in order to finance the expansion, upgrading and maintenance of our transmission and distribution systems. We also purchase natural gas for storage. We have made several equity method investments and will continue to pursue other similar investments, all of which are and will be important to our growth and profitability. We fund a portion of our cash needs for these purposes, as well as contributions to our employee pensions and benefit plans, through borrowings under credit arrangements and by offering new debt and equity securities. Our dependency on external sources of financing creates the risk that our profits could decrease as a result of higher borrowing costs and that we may not be able to secure external sources of cash necessary to fund our operations and new investments on terms acceptable to us. Volatility in seasonal cash flow requirements, including requirements for our gas supply procurement and risk management programs, may require increased levels of borrowing that could result in non-compliance with the debt-to-equity ratios in our credit facilities as well as cause a credit rating downgrade. Any disruptions in the capital and credit markets could require us to conserve cash until the markets stabilize or until alternative credit arrangements or other funding required for our needs can be secured. Such measures could cause deferral of major capital expenditures, changes in our gas supply procurement program, the reduction or elimination of the dividend payment or other discretionary uses of cash, and could negatively affect our future growth and earnings.

As a result of cross-default provisions in our borrowing arrangements, we may be unable to satisfy all of our outstanding obligations in the event of a default on our part.

The terms of our senior indebtedness, including our revolving credit facility, contain cross-default provisions which provide that we will be in default under such agreements in the event of certain defaults under the indenture or other loan agreements. Accordingly, should an event of default occur under any of those agreements, we face the prospect of being in

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default under all of our debt agreements, obliged in such instance to satisfy all of our outstanding indebtedness and unable to satisfy all of our outstanding obligations simultaneously. In such an event, we might not be able to obtain alternative financing or, if we are able to obtain such financing, we might not be able to obtain it on terms acceptable to us, which would negatively affect our ability to implement our business plan, make capital expenditures and finance our operations.

We are exposed to credit risk of counterparties with whom we do business.

Adverse economic conditions affecting, or financial difficulties of, counterparties with whom we do business could impair the ability of these counterparties to pay for our services or fulfill their contractual obligations. We depend on these counterparties to remit payments to fulfill their contractual obligations on a timely basis. Any delay or default in payment or failure of the counterparties to meet their contractual obligations could adversely affect our financial position, results of operations or cash flows.

The cost of providing pension benefits and related funding obligations may increase.

Our costs of providing a non-contributory defined benefit pension plan are dependent on a number of factors, such as the rates of return on plan assets, discount rates, the level of interest rates used to measure the required minimum funding levels of the plan, changes in these actuarial assumptions, future government regulation, changes in life expectancy and our required or voluntary contributions made to the plan. Changes in actuarial assumptions and differences between the assumptions and actual values, as well as a significant decline in the value of investments that fund our pension plan, if not offset or mitigated by a decline in our liabilities, could increase the expense of our pension plan, and we could be required to fund our plan with significant amounts of cash. Such cash funding obligations could have a material impact on our liquidity by reducing cash flows and could negatively affect results of operations.

We may invest in companies that have risks that are inherent in their businesses, and these risks may negatively affect our earnings from those companies.

We are invested in several natural gas related businesses as an equity method investor. The businesses in which we invest are subject to laws, regulations or market conditions, or have risks inherent in their operations, that could adversely affect their performance. Those that are not directly regulated by state or federal regulatory bodies could be subject to adverse market conditions not experienced by our regulated utility segment and our regulated non-utilities segment. We do not control the day to day operations of our equity method investments, and thus the management of these businesses by our partners could adversely impact their performance. We may not be able to fully direct the management and policies of these businesses, and other participants in those relationships may take action contrary to our interests, including making operational decisions that could affect our costs and liabilities related to our investment. In addition, other participants may withdraw from the business, become financially distressed or bankrupt, or have economic or other business interests or goals that are inconsistent with ours. The results of operations from those investments may be significantly less or realized significantly later than anticipated. All the above could adversely affect our earnings from or return of our investment in these businesses. We could make future equity method investments, acquisitions, or other business arrangements involving regulated or unregulated businesses as a minority or majority owner, with the similar potential to adversely affect our earnings from or return of our investment in those businesses.

We may be unable to attract and retain professional and technical employees, which could adversely impact our earnings.

Our ability to implement our business strategy and serve our customers is dependent upon the continuing ability to employ talented professionals and attract, train, develop and retain a skilled workforce. We are subject to the risk that we will not be able to effectively replace the knowledge and expertise of an aging workforce as those workers retire. Without a properly skilled and experienced workforce, our costs, including productivity and safety costs, costs to replace employees, and costs as a result of errors may increase, and this could negatively impact our earnings.

Cybersecurity attack, acts of cyber-terrorism or failure of technology systems could disrupt our business operations, shut down our facilities or result in the loss or exposure of confidential or sensitive customer, employee or Company information.

We are placing greater reliance on technological tools that support our operations and corporate functions and processes. We may own these tools or have a license to use them, or we may rely on the technological tools of third parties to whom we outsource processes. We use such tools to manage our natural gas distribution and transmission pipeline operations, maintain customer, employee, Company and vendor data, prepare our financial statements and manage supply chain and other business processes. One or more of these technologies may fail due to physical disruption such as flooding, design defects or human error, or we may be unable to have these technologies supported, updated, expanded or integrated into other

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technologies. As technology and as our business operations change, we may replace or add systems and tools, and failure to successfully execute on these projects may result in business disruption or loss of data. Additionally, our business operations and information technology systems may be vulnerable to attack by individuals or organizations that could result in disruption to them.

Disruption or failure of business operations and information technology systems could shut down our facilities or otherwise adversely impact our ability to safely deliver natural gas to our customers, operate our pipeline systems, serve our customers effectively or manage our assets. An attack on or failure of information technology systems could result in the unauthorized release of customer, employee or other confidential or sensitive data. These events could adversely affect our business reputation, diminish customer confidence, disrupt operations, subject us to financial liability or increased regulation, increase our costs and expose us to material legal claims and liability, and our operations and financial results could be adversely affected.

Our insurance coverage may not be sufficient.

We currently have general liability and property insurance in place in amounts that we consider appropriate based on our business risk and best practices in our industry and in general business. Such policies are subject to certain limits and deductibles and include business interruption coverage for limited circumstances. Insurance coverage for risks against which we and others in our industry typically insure may not be available in the future, or may be available but at materially increased costs, reduced coverage or on terms that are not commercially reasonable. Premiums and deductibles may increase substantially. The insurance proceeds received for any loss of, or any damage to, any of our facilities or to third parties may not be sufficient to restore the total loss or damage. Further, the proceeds of any such insurance may not be paid in a timely manner. The occurrence of any of the foregoing could have a material adverse effect on our financial position, results of operations and cash flows.

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

All property included in the Consolidated Balance Sheets in “Utility Plant” is owned by us and used in our regulated utility segment. This property consists of intangible plant, other storage plant, transmission plant, distribution plant and general plant as categorized by natural gas utilities, with the majority of the total invested in utility distribution and transmission plant to serve our customers. We have approximately 2,910 linear miles of transmission pipeline up to 30 inches in diameter that connect our distribution systems with the transmission systems of our pipeline suppliers. We distribute natural gas through approximately 22,300 linear miles of distribution mains up to 16 inches in diameter. The transmission pipelines and distribution mains are generally underground, located near public streets and highways, or on property owned by others, for which we have obtained the necessary legal rights to place and operate our facilities on such property. All of these properties are located in North Carolina, South Carolina and Tennessee. Utility Plant includes “Construction work in progress," which primarily represents distribution, transmission and general plant projects that have not been placed into service pending completion.

None of our property is encumbered, and all property is in use except for “Plant held for future use” as classified in the Consolidated Balance Sheets. The amount classified as plant held for future use is comprised of land located in Robeson County, North Carolina. For further information on this Robeson County property, see Note 1 and Note 2 to the consolidated financial statements in this Form 10-K.

We own or lease for varying periods our corporate headquarters building located in Charlotte, North Carolina and our operating locations and resource centers located in North Carolina, South Carolina and Tennessee. Lease payments for these various offices totaled $4.5 million for the year ended October 31, 2014.

Property included in the Consolidated Balance Sheets in “Other Physical Property” is owned by the parent company and one of its subsidiaries. The property owned by the parent company primarily consists of natural gas water heaters leased to commercial customers. The property owned by the subsidiary is real estate. None of our other subsidiaries directly own property as their operations consist solely of participating in joint ventures as an equity member.

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Item 3. Legal Proceedings

We have only immaterial litigation or routine litigation in the normal course of business.

Item 4. Mine Safety Disclosures

Not applicable.

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PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Market Information

Our common stock (symbol PNY) is traded on the New York Stock Exchange (NYSE). The following table provides information with respect to the high and low sales prices from the NYSE Composite for each quarterly period for the years ended October 31, 2014 and 2013.

2014	High		Low		2013	High		Low
Quarter ended:					Quarter ended:
January 31	$	34.18	$	31.94	January 31	$	33.10	$	28.51
April 30	36.55		32.12		April 30	34.92		31.73
July 31	37.86		34.30		July 31	35.53		32.39
October 31	38.36		33.38		October 31	35.05		31.56

Holders

As of December 12, 2014, our common stock was owned by 13,379 shareholders of record. Holders of record exclude the individual and institutional security owners whose shares are held in street name or in the name of an investment company.

Dividends

The following table provides information with respect to quarterly dividends paid on common stock for the years ended October 31, 2014 and 2013. We expect that comparable cash dividends will continue to be paid in the future.

	Dividends Paid			Dividends Paid
2014	Per Share		2013	Per Share
Quarter ended:			Quarter ended:
January 31	31	¢	January 31	30	¢
April 30	32	¢	April 30	31	¢
July 31	32	¢	July 31	31	¢
October 31	32	¢	October 31	31	¢

The amount of cash dividends that may be paid on common stock is restricted by provisions contained in certain note agreements under which long-term debt was issued, with those for the senior notes being the most restrictive. We cannot pay or declare any dividends or make any other distribution on any class of stock or make any investments in subsidiaries or permit any subsidiary to do any of the above (all of the foregoing being “restricted payments”) except out of net earnings available for restricted payments. As of October 31, 2014, our ability to pay dividends was not restricted.

Share Repurchases

The following table provides information with respect to repurchases of our common stock under the Common Stock Open Market Purchase Program during the three months ended October 31, 2014.

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Period	Total Number of Shares Purchased	Average Price Paid Per Share	Total Number of Shares Purchased as Part of Publicly Announced Program	Maximum Number of Shares that May Yet be Purchased Under the Program (1)
Beginning of the period				2,910,074
8/1/14 – 8/31/14	—	—	—	2,910,074
9/1/14 – 9/30/14	—	—	—	2,910,074
10/1/14 – 10/31/14	—	—	—	2,910,074
Total	—	—	—

⁽¹⁾  The Common Stock Open Market Purchase Program was approved by the Board of Directors and announced on June 4, 2004 to purchase up to three million shares of common stock for reissuance under our dividend reinvestment and stock purchase, employee stock purchase and incentive compensation plans. On December 16, 2005, the Board of Directors approved an increase in the number of shares in this program from three million to six million to reflect the two-for-one stock split in 2004. On that date, the Board also approved an amendment of the Common Stock Open Market Purchase Program to provide for the purchase of up to four million additional shares of common stock to maintain our debt-to-equity capitalization ratios at target levels. The additional four million shares were referred to as our accelerated share repurchase (ASR) program. On March 6, 2009, the Board of Directors authorized the repurchase of up to an additional four million shares under the Common Stock Open Market Purchase Program and the ASR program, which were consolidated.

Discussion of our compensation plans, under which shares of our common stock are authorized for issuance, is included in the portion of our proxy statement captioned “Executive Compensation” to be filed no later than January 31, 2015, in connection with our Annual Meeting to be held on March 5, 2015, and is incorporated herein by reference.

Comparisons of Cumulative Total Shareholder Returns

The following performance graph compares our cumulative total shareholder return from October 31, 2009 through October 31, 2014 (a five-year period) with the average performance of our industry peer group and the Standard & Poor’s 500 Stock Index, a broad market index (the S&P 500 Index). Our local distribution company (LDC) Peer Group index is comprised of peer group companies that are domiciled in the United States, publicly traded in the U.S. energy industry with a primary focus on natural gas distribution and transmission businesses in multi-state territories and have similar annual revenues and market capitalization to ours. We attempt to have our peer group companies meet a majority of these criteria for inclusion in the group, and we use the same peer group to calculate our relative total shareholder returns, which we use for market benchmarking for our executive compensation plans.

Over the past several years, we have made significant additional investments in transmission pipeline infrastructure. In light of this transmission business and now owning and operating over 2,900 miles of transmission pipeline, our LDC Peer Group was updated to include CenterPoint Energy and Questar Corporation, effective with our performance award under an approved incentive compensation plan covering a three-year performance period that ended October 31, 2014. Our total return of $100 invested as of October 31, 2014 was $198. With the addition of CenterPoint Energy and Questar Corporation, our LDC Peer Group return was $236. Without them, the peer group return would have been $241.

The graph assumes that the value of an investment in Common Stock and in each index was $100 at October 31, 2009 and that all dividends were reinvested. Stock price performances shown on the graph are not indicative of future price performance.

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LDC Peer Group—The following companies are included: AGL Resources, Inc., Atmos Energy Corporation, CenterPoint Energy, New Jersey Resources Corporation, NiSource Inc., Northwest Natural Gas Company, Questar Corporation, South Jersey Industries, Inc., Southwest Gas Corporation, The Laclede Group, Inc., Vectren Corporation and WGL Holdings, Inc. 

	2009		2010		2011		2012		2013		2014
Piedmont	$	100	$	132	$	152	$	154	$	171	$	198
LDC Peer Group	100		129		156		167		201		236
S&P 500 Index	100		117		126		145		185		216

Item 6. Selected Financial Data

The following table provides selected financial data for the years ended October 31, 2010 through 2014.

In thousands, except per share amounts	2014		2013		2012		2011		2010
Operating Revenues	$	1,469,988	$	1,278,229	$	1,122,780	$	1,433,905	$	1,552,295
Margin (operating revenues less cost of gas)	$	690,208	$	621,490	$	575,446	$	573,639	$	552,592
Net Income	$	143,801	$	134,417	$	119,847	$	113,568	$	141,954
Earnings per Share of Common Stock:
Basic	$	1.85	$	1.80	$	1.67	$	1.58	$	1.96
Diluted	$	1.84	$	1.78	$	1.66	$	1.57	$	1.96
Cash Dividends per Share of Common Stock	$	1.27	$	1.23	$	1.19	$	1.15	$	1.11
Total Assets	$	4,784,253	$	4,368,609	$	3,769,939	$	3,242,541	$	3,053,275
Long-Term Debt (less current maturities)	$	1,424,430	$	1,174,857	$	975,000	$	675,000	$	671,922

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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Forward-Looking Statements

This report, as well as other documents we file with the Securities and Exchange Commission (SEC), may contain forward-looking statements. In addition, our senior management and other authorized spokespersons may make forward-looking statements in print or orally to analysts, investors, the media and others. These statements are based on management’s current expectations from information currently available and are believed to be reasonable and are made in good faith. However, the forward-looking statements are subject to risks and uncertainties that could cause actual results to differ materially from those projected in the statements. Factors that may make the actual results differ from anticipated results include, but are not limited to the following, as well as those discussed in Item 1A. Risk Factors:

• Economic conditions in our markets

• Wholesale price of natural gas

• Availability of adequate interstate pipeline transportation capacity and natural gas supply

• Regulatory actions at the state level that impact our ability to earn a reasonable rate of return and fully recover our operating costs on a timely basis

• Competition from other companies that supply energy

• Changes in the regional economies, politics, regulations and weather patterns of the three states in which our operations are concentrated

• Costs of complying or effect of noncompliance with state and federal laws and regulations that are applicable to us

• Effect of climate change, carbon neutral or energy efficiency legislation or regulations on costs and market opportunities

• Changes in local building codes or appliance standards

• Weather conditions

• Operational interruptions to our gas distribution and transmission activities

• Inability to complete necessary or desirable pipeline expansion or infrastructure development projects

• Elevated levels of capital expenditures

• Changes to our credit ratings

• Availability and cost of capital

• Federal and state fiscal, tax and monetary policies

• Ability to generate sufficient cash flows to meet all our cash needs

• Ability to satisfy all of our outstanding debt obligations

• Ability of counterparties to meet their obligations to us

• Costs of providing pension benefits

• Earnings from the joint venture businesses in which we invest

• Ability to attract and retain professional and technical employees

• Cybersecurity breaches or failure of technology systems

• Ability to obtain and maintain sufficient insurance

• Change in number of outstanding shares

Other factors may be described elsewhere in this report. All of these factors are difficult to predict, and many of them are beyond our control. For these reasons, you should not place undue reliance on these forward-looking statements when making investment decisions. When used in our documents or oral presentations, the words “expect,” “believe,” “project,” “anticipate,” “intend,” “may,” “should,” “could,” “assume,” “estimate,” “forecast,” “future,” “indicate,” “outlook,” “plan,” “predict,” “seek,” “target,” “would” and variations of such words and similar expressions are intended to identify forward-looking statements.

Forward-looking statements are based on information available to us as of the date they are made, and we do not undertake any obligation to update publicly any forward-looking statement either as a result of new information, future events or otherwise except as required by applicable laws and regulations. Our reports on Form 10-K, Form 10-Q and Form 8-K and amendments to these reports are available at no cost on our website at www.piedmontng.com as soon as reasonably practicable after the report is filed with or furnished to the SEC.

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Overview

Piedmont Natural Gas Company, Inc., which began operations in 1951, is an energy services company whose principal business is the distribution of natural gas to over one million residential, commercial, industrial and power generation customers in portions of North Carolina, South Carolina and Tennessee, including customers served by municipalities who are our wholesale customers. We are invested in joint venture, energy-related businesses, including unregulated retail natural gas marketing, regulated interstate natural gas transportation and storage and regulated intrastate natural gas transportation businesses.

We operate with three reportable business segments, regulated utility, regulated non-utility activities and unregulated non-utility activities, with the regulated utility segment being the largest. Our utility operations are regulated by the North Carolina Utilities Commission (NCUC), the Public Service Commission of South Carolina and the Tennessee Regulatory Authority (TRA) as to rates, service area, adequacy of service, safety standards, extensions and abandonment of facilities, accounting and depreciation. The NCUC also regulates us as to the issuance of long-term debt and equity securities. Factors critical to the success of the regulated utility segment include operating a safe and reliable natural gas distribution system and the ability to recover the costs and expenses of the business in the rates charged to customers. The regulated non-utility activities segment consists of our equity method investments in joint venture regulated energy-related businesses that are held by our wholly-owned subsidiaries. The unregulated non-utility activities segment consists primarily of our equity method investment in SouthStar Energy Services LLC (SouthStar) that is held by a wholly-owned subsidiary. For further information on equity method investments and business segments, see Note 12 and Note 14, respectively, to the consolidated financial statements in this Form 10-K.

Executive Summary

A summary of our annual results is as follows:

Comprehensive Income Statements Components
							Percent Change
							2014 vs.		2013 vs.
In thousands, except per share amounts	2014		2013		2012		2013		2012
Operating Revenues	$	1,469,988	$	1,278,229	$	1,122,780	15.0	%	13.8	%
Cost of Gas	779,780		656,739		547,334		18.7	%	20.0	%
Margin	690,208		621,490		575,446		11.1	%	8.0	%
Operations and Maintenance	270,877		253,120		242,599		7.0	%	4.3	%
Depreciation	118,996		112,207		103,192		6.1	%	8.7	%
General Taxes	37,294		34,635		34,831		7.7	%	(0.6	)%
Utility Income Taxes	83,176		77,334		69,101		7.6	%	11.9	%
Total Operating Expenses	510,343		477,296		449,723		6.9	%	6.1	%
Operating Income	179,865		144,194		125,723		24.7	%	14.7	%
Other Income (Expense), net of tax	18,622		15,161		14,221		22.8	%	6.6	%
Utility Interest Charges	54,686		24,938		20,097		119.3	%	24.1	%
Net Income	$	143,801	$	134,417	$	119,847	7.0	%	12.2	%
Average Shares of Common Stock:
Basic	77,883		74,884		71,977		4.0	%	4.0	%
Diluted	78,193		75,333		72,278		3.8	%	4.2	%
Earnings per Share of Common Stock:
Basic	$	1.85	$	1.80	$	1.67	2.8	%	7.8	%
Diluted	$	1.84	$	1.78	$	1.66	3.4	%	7.2	%

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Margin by Customer Class
In thousands	2014				2013				2012
Sales and Transportation:
Residential	$	348,782	51	%	$	331,920	54	%	$	321,056	56	%
Commercial	169,442		25	%	155,065		25	%	150,306		26	%
Industrial	50,889		7	%	52,268		8	%	46,993		8	%
Power Generation	77,573		11	%	56,312		9	%	32,289		6	%
For Resale	8,819		1	%	7,477		1	%	7,465		1	%
Total	655,505		95	%	603,042		97	%	558,109		97	%
Secondary Market Sales	25,414		4	%	8,979		1	%	9,681		2	%
Miscellaneous	9,289		1	%	9,469		2	%	7,656		1	%
Total	$	690,208	100	%	$	621,490	100	%	$	575,446	100	%

Gas Deliveries, Customers, Weather Statistics and Number of Employees
							Percent Change
							2014 vs.		2013 vs.
	2014		2013		2012		2013		2012
Deliveries in Dekatherms (in thousands):
Residential	61,782		55,283		43,788		11.8	%	26.3	%
Commercial	44,259		39,602		33,774		11.8	%	17.3	%
Industrial	95,780		95,019		89,234		0.8	%	6.5	%
Power Generation	201,707		190,862		151,675		5.7	%	25.8	%
For Resale	7,174		6,834		5,829		5.0	%	17.2	%
Throughput	410,702		387,600		324,300		6.0	%	19.5	%
Secondary Market Volumes	20,516		41,605		48,373		(50.7	)%	(14.0	)%
Customers Billed (at period end)	992,551		979,909		969,239		1.3	%	1.1	%
Gross Residential, Commercial and Industrial Customer Additions	16,251		14,293		13,274		13.7	%	7.7	%
Degree Days
Actual	3,543		3,336		2,668		6.2	%	25.0	%
Normal	3,265		3,276		3,310		(0.3	)%	(1.0	)%
Percent colder (warmer) than normal	8.5	%	1.8	%	(19.4	)%	n/a		n/a
Number of Employees (at period end)	1,879		1,795		1,752		4.7	%	2.5	%

Financial Performance – Fiscal 2014 Compared with Fiscal 2013

Our 2014 fiscal year was a solid one with a 7% increase in net income. Margin increased 11% due to customer growth, higher volumes delivered to residential and commercial customers in South Carolina and Tennessee due to colder weather, new rates effective January 1, 2014 in North Carolina under a rate case settlement, the Tennessee and North Carolina integrity management rider (IMR) rate adjustments, increased transportation delivery services for power generation customers and higher margin sales from secondary market activity. Operations and maintenance (O&M) expenses and depreciation expense increased 7% and 6%, respectively. The increase in O&M expenses was related to increases in payroll, regulatory, bad debt and contract labor expenses. Depreciation was higher due to increases in plant in service from our capital investment program. General taxes increased 8% primarily due to increased property taxes, franchise taxes and payroll taxes. Other Income (Expense) increased 23% primarily due to an increase in income from equity method investments, primarily from SouthStar and Constitution Pipeline Company, LLC (Constitution), partially offset by a write-off of an investment that had been accounted for under the cost method. Utility interest charges increased 119% from increases in long-term debt outstanding, a decrease in capitalized interest recorded as income and the recording of interest expense on amounts due to customers.

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Business Summary – Fiscal 2014 Compared with Fiscal 2013

Our fiscal 2014 performance reflects execution of our long-term business strategy that focuses on safety and growth in our markets, favorable changes in state regulation with new rates and IMRs, and secondary market activity. As discussed above, financial performance was solid for the year with increased earnings and an increase in our dividend rate per share to our investors.

Financial Strength and Flexibility – In order to prudently fund our investment in growth and our ongoing capital needs, we executed our financing programs to optimize and reduce our cost of capital, preserve our liquidity and strong balance sheet and protect our high quality credit ratings with a goal of maintaining a total debt to capital ratio between 50% and 60%. As reflected in this annual report, we revised this target to include both short- and long-term debt as we believe it provides a more accurate representation of our overall leverage and our financing targets. We continue to rely on our commercial paper (CP) program to meet our short-term liquidity needs. We accomplished the following in fiscal year 2014:

• In November 2013, we entered into an agreement with our revolving credit facility lenders that increased our borrowing capacity to $850 million.

• In December 2013, we repaid the balance of $100 million of our 5% medium-term notes as they became due.

• In December 2013, we issued 1.6 million shares under forward sale agreements (FSAs) entered into in February 2013, receiving proceeds of $47.3 million.

• In September 2014, we issued $250 million of twenty-year, unsecured senior notes, receiving net proceeds of $247.7 million, net of debt issuance costs.

For further information on these transactions, see Note 4, Note 5 and Note 6 to the consolidated financial statements in this Form 10-K and the following discussion of "Cash Flows from Financing Activities."

Managing Gas Supplies and Prices – Our gas supply acquisition strategy is regularly reviewed and adjusted to ensure that we have adequate and reliable supplies of competitively-priced natural gas to meet the needs of our utility customers. In November 2012, in order to provide additional diversification, reliability and gas cost benefits to our customers, we signed long-term capacity and supply contracts to transport more of our gas supplies from the Marcellus shale basin in Pennsylvania for our markets in the Carolinas. This source of supply is scheduled to be available in late 2015 once construction of the Williams – Transco Leidy Southeast expansion project has been completed. In October 2014, we signed a long-term pipeline capacity precedent agreement under the Atlantic Coast Pipeline, LLC (ACP) project to source gas supplies from the Marcellus and Utica shale basins in central West Virginia that are anticipated to be available for the winter 2018 – 2019 season.

Customer Growth – We have added increasing numbers of customers in our service areas each year over our last three fiscal years. Affordable and stable wholesale natural gas costs continued to favorably position natural gas relative to other energy sources. With continued improvement in economic conditions resulting in growth in both the residential and commercial markets and targeted marketing programs on the benefits of natural gas, total new customers increased 13.7% in 2014 compared to 2013.

			Percent
	2014	2013	Change
Residential new home construction	11,659	10,299	13.2	%
Residential conversion	2,814	2,463	14.3	%
Commercial	1,763	1,512	16.6	%
Industrial	15	19	(21.1	)%
Total new customers	16,251	14,293	13.7	%

Overall, total net customers billed increased 1.3% as compared to 2013.

Capital Expenditures – We continued to execute our capital expansion and improvement programs that will provide benefits to our customers through safe and reliable natural gas service while providing our shareholders a fair and reasonable return on invested capital. Our capital expenditures are driven by pipeline integrity, safety and compliance programs, investments for customer growth, and technology and system infrastructure, including a new comprehensive work and asset management system.

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With significant capital costs incurred under our ongoing system integrity programs, we implemented new regulatory mechanisms that will allow us to recover and earn on those investments in a more timely manner. In December 2013, the NCUC approved the settlement of our 2013 general rate case, including the implementation of an IMR to separately track and recover the costs associated with capital expenditures in order to comply with federal pipeline safety and integrity requirements. With the IMR mechanism, we will avoid having to file costly and more frequent future general rate proceedings, consuming both our resources and the resources of the NCUC and its staff. Under the IMR tariff, we will make annual filings each November to capture such costs closed to plant through October with revised rates effective the following February. For the annual period beginning February 1, 2014, the North Carolina IMR will increase our margin revenues by $.8 million with $.6 million recorded through the 2014 fiscal year end. With its approval of the rate case settlement, the NCUC continued to allow regulatory asset treatment of our external pipeline integrity management O&M costs and recovery of these costs through future amortization in rates. Also in December 2013, the TRA approved the settlement of our August 2013 IMR filing in Tennessee to recover the costs of our capital investments associated with federal and state mandated safety and integrity programs. Under the Tennessee IMR, we will file to adjust rates to be effective each January 1 based on capital expenditures incurred through the previous October. For the twelve-month period beginning January 1, 2014, the Tennessee IMR will increase our margin revenues by $13.1 million with $10.1 million recorded through the fourth quarter of 2014.

We completed pipeline expansion projects over our last three fiscal years that provide natural gas delivery service to new power generation facilities in our market area. We currently provide service to 25 power generation customer accounts. See the discussion of our forecasted capital investments in “Cash Flows from Investing Activities” in this Form 10-K .

Business Process and Technology Improvements – We are executing a multi-year, multi-project program designed to bring additional technology and automation to our field operations to enable our employees to more effectively and efficiently manage our pipeline assets. This program is expected to facilitate compliance with pipeline safety and integrity regulations and create operating efficiencies. Implementation began in April 2014. Several phases of the program are expected to be implemented through our fiscal year 2016.

Regulatory and Legislative Activity – We continue our regulatory strategy to implement rate structures that better align and balance the interests of shareholders and customers. As discussed above, with the NCUC approval of the settlement of our 2013 general rate case, we implemented adjustments in our rates and charges, effective January 1, 2014, to provide incremental annual total revenues of $30.7 million, yielding an annual pre-tax income increase of $24.2 million. This revenue increase was a .7% annual rate increase for our customers since our last general rate proceeding in 2008. The new rates are based on a rate base in North Carolina of $1.8 billion as of September 30, 2013, an equity capital structure component of 50.7% and a return on common equity of 10%.

Equity Method Investments – Our investments in complementary energy-related businesses continue to be an attractive way to generate earnings growth and long-term shareholder returns. Our 2014 earnings before taxes from SouthStar increased $5 million with our additional investment of $22.5 million made in September 2013, maintaining our 15% equity ownership. Our partner contributed retail natural gas marketing assets and related customers located in Illinois.

We are a 24% equity member of Constitution, a Federal Energy Regulatory Commission (FERC) regulated interstate natural gas pipeline that is proposed to transport natural gas produced from the Marcellus shale basin in Pennsylvania to northeast markets. The forecasted in-service date of the project is late 2015 or 2016. We expect our total 24% equity contributions will be an estimated $175 million. We contributed $37.6 million and $15.9 million in 2014 and 2013, respectively, for a total of $53.5 million to date.

In September 2014, we became a 10% equity member of ACP, a Delaware limited liability company. ACP intends to construct, operate and maintain a 550 mile natural gas pipeline, with associated compression, from West Virginia through Virginia into eastern North Carolina. The pipeline will provide wholesale natural gas transportation services for Marcellus and Utica gas supplies into southeastern markets. We expect our total 10% equity contributions will be an estimated $450 million to $500 million before any project financing. For further information on equity method investments and business segments, see Note 12 and Note 14, respectively, to the consolidated financial statements and "Cash Flows from Investing Activities" in this Form 10-K.

Strategy and Focus Areas

Our long-term strategic directives shape our annual business objectives and focus on our customers, our communities, our employees and our shareholders. They also reflect what we believe are the inherent advantages of natural gas compared to other types of energy. Our seven foundational strategic priorities are as follows:

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• Promote the benefits of natural gas,

• Expand our core natural gas and complementary energy-related businesses to enhance shareholder value,

• Be the energy service provider of choice,

• Achieve excellence in customer service every time,

• Preserve financial strength and flexibility,

• Execute sustainable business practices, and

• Enhance our healthy, high performance culture.

With a focus on these priorities, we believe we will enhance long-term shareholder value. For a full discussion of our strategy and focus areas, see Item 1. Business in this Form 10-K.

Additional information on operating results for the years ended October 31, 2014, 2013 and 2012 follows.

Results of Operations

Operating Revenues

Changes in operating revenues for 2014 and 2013 compared with the same prior periods are presented below.

Changes in Operating Revenue - Increase (Decrease)
	2014 vs.			2013 vs.
In millions	2013			2012
Residential and commercial customers	$	201.5		$	136.2
Industrial customers	1.4			18.0
Power generation customers	21.8			28.1
Secondary market	5.4			23.8
Margin decoupling mechanism	(39.4		)	(40.8		)
WNA mechanisms	(11.4		)	(10.4		)
IMR mechanisms	10.7			—
Other	1.8			0.5
Total	$	191.8		$	155.4

2014 compared to 2013:

• Residential and commercial customers – the increase is primarily due to higher consumption from colder weather, higher wholesale gas costs passed through to customers and customer growth.

• Industrial customers – the increase is primarily due to higher consumption from colder weather and higher wholesale gas costs passed through to customers, slightly offset by decreased transportation revenues.

• Power generation customers – the increase is primarily due to increased transportation services.

• Secondary market – the increase is due to higher margin sales related to sustained colder-than-normal weather and increased wholesale market volatility. Secondary market transactions consist of off-system sales and capacity release and asset management arrangements and are part of our regulatory gas supply management program with regulatory approved sharing mechanisms between our utility customers and our shareholders.

• Margin decoupling mechanism – the decrease is primarily related to colder weather in North Carolina. As discussed in “Financial Condition and Liquidity,” the margin decoupling mechanism in North Carolina adjusts for variations in residential and commercial use per customer, including those due to weather and conservation.

• Weather normalization adjustment (WNA) mechanisms – the decrease is due to colder weather in South Carolina and Tennessee. As discussed in “Financial Condition and Liquidity,” the WNA mechanisms partially offset the impact of colder- or warmer-than-normal weather on bills rendered.

• IMR mechanisms – the increase is due to the IMR rate adjustments in Tennessee effective January 1, 2014 and North Carolina effective February 1, 2014.

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2013 compared to 2012:

• Residential and commercial customers – the increase is primarily due to colder weather, customer growth and higher wholesale gas costs passed through to customers.

• Industrial customers – the increase is primarily due to colder weather and customer growth.

• Power generation customers – the increase is primarily due to increased transportation services due to new contracts that began in June 2012 and June 2013.

• Secondary market – the increase is primarily due to higher commodity gas costs, partially offset by decreased activity.

• Margin decoupling mechanism – the decrease is due to colder weather in North Carolina.

• WNA mechanisms – the decrease is due to colder weather in South Carolina and Tennessee.

Cost of Gas

Changes in cost of gas for 2014 and 2013 compared with the same prior periods are presented below.

Changes in Cost of Gas - Increase (Decrease)
	2014 vs.			2013 vs.
In millions	2013			2012
Commodity gas costs passed through to sales customers	$	137.5		$	96.8
Commodity gas costs in secondary market transactions	(11.0		)	24.5
Pipeline demand charges	(7.1		)	22.3
Regulatory approved gas cost mechanisms	3.6			(34.2		)
Total	$	123.0		$	109.4

2014 compared to 2013:

• Commodity gas costs passed through to sales customers – the increase is primarily due to higher volumes sold due to colder weather and higher wholesale gas costs passed through to sales customers.

• Commodity gas costs in secondary market transactions – the decrease is primarily due to decreased activity, partially offset by higher average wholesale gas costs.

• Pipeline demand charges – the decrease is due to decreased demand costs and increased capacity release revenues, slightly offset by decreased asset manager payments.

• Regulatory approved gas cost mechanisms – the increase is primarily due to demand cost true-ups, slightly offset by other regulatory mechanisms.

2013 compared to 2012:

• Commodity gas costs passed through to sales customers – the increase is primarily due to higher volumes sold due to colder weather and slightly higher wholesale gas costs passed through to sales customers.

• Commodity gas costs in secondary market transactions – the increase is primarily due to increased average wholesale gas costs, partially offset by decreased activity.

• Pipeline demand charges – the increase is primarily due to increased demand costs, decreased asset manager payments and decreased capacity release revenues.

• Regulatory approved gas cost mechanisms – the decrease is primarily due to commodity gas cost true-ups.

In all three states, we are authorized to recover from customers all prudently incurred gas costs. Charges to cost of gas are based on the amount recoverable under approved rate schedules. The net of any over- or under-recoveries of gas costs are reflected in a regulatory deferred account and are added to or deducted from cost of gas and are in current “Regulatory assets” or current “Regulatory liabilities” in the Consolidated Balance Sheets. For the amounts included in “Amounts due from customers” or “Amounts due to customers,” see “Rate-Regulated Basis of Accounting” in Note 1 to the consolidated financial statements in this Form 10-K.

Margin

Margin, rather than revenues, is used by management to evaluate utility operations due to the regulatory pass through of changes in wholesale commodity gas costs. Our utility margin is defined as natural gas revenues less natural gas

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commodity costs and fixed gas costs for transportation and storage capacity. It is the component of our revenues that is established in general rate cases and is designed to cover our utility operating expenses and our return of and on our utility capital investments and related taxes. Our commodity gas costs accounted for 41% of revenues for the years ended October 31, 2014 and 2013 and 36% for the year ended October 31, 2012. Our pipeline transportation and storage costs accounted for 10%, 12% and 11% for the years ended October 31, 2014, 2013 and 2012 respectively.

In general rate proceedings, state regulatory commissions authorize us to recover our margin in our monthly fixed demand charges and on each unit of gas delivered under our generally applicable sales and transportation tariffs and special service contracts. We negotiate special service contracts with some industrial customers that may include the use of volumetric rates with minimum margin commitments and fixed monthly demand charges. These individually negotiated agreements are subject to review and approval by the applicable state regulatory commission and allow us to make an economic extension or expansion of natural gas service to larger industrial customers.

Our utility margin is also impacted by certain regulatory mechanisms as defined elsewhere in this document. These regulatory mechanisms by jurisdiction are presented below.

Regulatory Mechanism	North Carolina	South Carolina	Tennessee
WNA mechanism*		X	X
Margin decoupling mechanism *	X
Natural gas rate stabilization mechanism		X
Secondary market activity **	X	X	X
Incentive plan for gas supply **			X
IMR mechanism	X		X
Negotiated margin loss treatment	X	X
Uncollectible gas cost recovery	X	X	X
* Residential and commercial customers only.
** In all jurisdictions, we retain 25% of secondary market margins generated through off-system sales and capacity release activity, with 75% credited to customers. Our share of net gains or losses in Tennessee is subject to an annual cap of $1.6 million.

Changes in margin for 2014 and 2013 compared with the same prior periods are presented below.

Changes in Margin - Increase (Decrease)
	2014 vs.			2013 vs.
In millions	2013			2012
Residential and commercial customers	$	31.2		$	15.6
Industrial customers	—			5.3
Power generation customers	21.3			24.0
Secondary market activity	16.4			(0.7		)
Net gas cost adjustments	(0.2		)	1.8
Total	$	68.7		$	46.0

2014 compared to 2013:

• Residential and commercial customers – the increase is primarily due to the general rate increase in North Carolina effective January 1, 2014, the IMR rate adjustments mentioned above, customer growth in all three states and increased volumes delivered in South Carolina and Tennessee due to colder weather.

• Power generation customers – the increase is primarily due to increased transportation services.

• Secondary market activity – the increase is primarily due to higher margin sales related to increased wholesale market volatility and sustained colder-than-normal weather.

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2013 compared to 2012:

• Residential and commercial customers – the increase is primarily due to increased volumes delivered due to colder weather, customer growth in all three states and the general rate increase in Tennessee, effective March 1, 2012.

• Industrial customers – the increase is primarily due to higher consumption in the industrial market from colder weather and customer growth.

• Power generation customers – the increase is primarily due to increased transportation services due to new contracts placed in service in June 2012 and June 2013.

• Secondary market activity – the decrease is primarily due to lower commodity gas price volatility and decreased activity.

Operations and Maintenance Expenses

Changes in O&M expenses for 2014 and 2013 compared with the same prior periods are presented below.

Changes in Operations and Maintenance Expenses - Increase (Decrease)
	2014 vs.			2013 vs.
In millions	2013			2012
Payroll	$	9.6		$	1.8
Regulatory	4.2			1.0
Bad debt	2.1			1.4
Contract labor	1.9			2.4
Employee benefits	(0.3		)	(1.1		)
Other	0.3			5.0
Total	$	17.8		$	10.5

2014 compared to 2013:

• Payroll – the increase is primarily due to additional employees, employee overtime because of colder-than-normal winter weather and incentive plan accruals.

• Regulatory – the increase is primarily due to increased amortization of regulatory assets with approved amortization amounts established in the North Carolina general rate proceeding, effective January 1, 2014, and an increase in the North Carolina regulatory fee due to increased revenues.

• Bad debt – the increase is primarily due to a higher level of net charge-offs from customer receivables due to the colder weather experienced this past winter and increased accruals to reflect higher aging receivables.

• Contract labor – the increase is primarily due to increased call volume and collection efforts for customer receivables resulting from the colder winter, increased process improvement projects and pipeline integrity maintenance and safety programs.

2013 compared to 2012:

• Contract labor – the increase is primarily due to increased process improvement projects and pipeline integrity, maintenance and safety programs.

• Payroll – the increase is due to increases in incentive plan accruals.

• Bad debt – the increase is primarily due to a higher level of projected charge-offs due to higher bills.

• Regulatory – the increase is primarily due to amortization of regulatory assets with new amortization amounts established in the Tennessee general rate proceeding effective in March 2012.

• Employee benefits – the decrease is primarily due to reduced group medical insurance expense from lower claims and a regulatory pension deferral in Tennessee in 2013 related to the funding of the defined benefit plan in November 2012 compared to no plan funding in the prior year, partially offset by an increase in pension expense.

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Depreciation

Depreciation expense increased from $103.2 million to $119 million over the three-year period 2012 to 2014 primarily due to increases in plant in service, particularly related to major utility plant additions to serve new power generation customers, transmission integrity investments and upgrades to our liquefied natural gas facilities.

General Taxes

General taxes increased $2.7 million in 2014 compared with 2013 primarily due to increases in property and franchise taxes as a result of increased property and increases to payroll taxes as a result of higher incentive payouts and an increased payroll base. Changes in general taxes for 2013 compared with the same prior period are insignificant.

Other Income (Expense)

Other Income (Expense) is comprised of income from equity method investments, non-operating income, non-operating expense and income taxes related to these items. Non-operating income includes non-regulated merchandising and service work, home service agreements, subsidiary operations, interest income and other miscellaneous income. Non-operating expense is comprised of charitable contributions and miscellaneous expenses.

Changes in Other Income (Expense) for 2014 and 2013 compared with the same prior period are presented below.

Changes in Other Income (Expense) - Increase (Decrease) to Income
	2014 vs.			2013 vs.
In millions	2013			2012
Income from equity method investments:
SouthStar	$	5.0		$	1.3
Constitution	1.7			1.0
Other	—			(0.1		)
Total	6.7			2.2
Non-operating income	(1.0		)	1.5
Non-operating expense	0.8			(3.3		)
Income Taxes	(3.0		)	0.5
Total	$	3.5		$	0.9

2014 compared with 2013:

• Income from equity method investments from SouthStar – the increase is primarily due to the expansion of the business into Illinois markets beginning in September 2013, and favorable weather and customer usage in Georgia, partially offset by higher general and administrative expenses. For further information on the contribution of the Illinois business to SouthStar and our cash contribution in our equity method investment, see Note 12 to the consolidated financial statements in this Form 10-K.

• Income from equity method investments from Constitution – the increase is primarily due to higher capitalized interest associated with increased capital expenditures on the project.

• Non-operating income – the decrease is primarily due to a $2 million write-off of an investment that we accounted for on the cost basis. This investment was presented in “Other noncurrent assets” in “Noncurrent Assets” in the Condensed Consolidated Balance Sheets.

2013 compared with 2012:

• Income from equity method investments from SouthStar – the increase is primarily due to higher average customer usage from colder weather compared to the prior year, net of weather derivatives, the recording of a lower of cost or market inventory adjustment in the prior year and new margin from the Illinois business that was contributed to the venture with our sharing beginning in September 2013, partially offset by higher gas costs, increased operating expenses and lower retail price spreads.

• Income from equity method investments from Constitution – the increase is primarily due to recording earnings of $1

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million due to the allowance for funds used during construction (AFUDC), partially offset by operating expenses.

• Non-operating income – the increase is primarily due to a $.7 million increase in non-regulated business income plus a gain from a land retirement.

• Non-operating expense – the increase is primarily due to $1.8 million of cumulative amortization of non-land costs related to the allowed deferral of a regulatory asset for certain non-real estate costs, construction of which was suspended in March 2009, as included in the 2013 settlement agreement with the NCUC Public Staff. We had a balance of $6.7 million of capital costs held in “Plant held for future use” comprised of $3.2 million in land costs and $3.5 million in non-land development costs. Under the NCUC approved settlement of the 2013 North Carolina general rate proceeding, we agreed to the amortization and collection of $1.2 million of the non-real estate costs to be amortized over 38 months beginning January 1, 2014, which we recorded as a regulatory asset along with a portion of the costs that we allocated to South Carolina operations. In addition, charitable contributions increased $.8 million primarily due to the funding of our charitable foundation.

Utility Interest Charges

Changes in utility interest charges for 2014 and 2013 compared with the same prior periods are presented below.

Changes in Utility Interest Charges - Increase (Decrease)
	2014 vs.			2013 vs.
In millions	2013			2012
Borrowed AFUDC	$	14.5		$	(5.8	)
Regulatory interest expense, net	8.1			0.1
Interest expense on long-term debt	7.4			12.7
Interest expense on short-term debt	(0.4		)	(1.5		)
Other	0.1			(0.7		)
Total	$	29.7		$	4.8

2014 compared to 2013:

• Borrowed AFUDC – the increase is due to a decrease in capitalized interest on a lower base of construction expenditures in the current period resulting from the timing of projects being placed into service.

• Regulatory interest expense, net – the increase is primarily due to the recording of interest expense on amounts due to customers compared with the recording of interest income in the prior year on amounts due from customers.

• Interest expense on long-term debt – the increase is primarily due to higher amounts of debt outstanding in the current periods.

2013 compared to 2012:

• Interest expense on long-term debt – the increase is primarily due to the issuance of debt in 2013 and a full year of interest expense on the debt issued in 2012.

• Borrowed AFUDC – the decrease is due to an increase in capitalized interest primarily resulting from increased construction expenditures.

• Interest expense on short-term debt – the decrease is primarily due to lower balances outstanding during the current period at interest rates that are 34 basis points lower than the prior year period. We paid down short-term debt as we issued long-term debt and equity securities during our fiscal year.

Financial Condition and Liquidity

Our financial strategy has continued to focus on maintaining a strong balance sheet, ensuring sufficient cash resources and daily liquidity, accessing capital markets at favorable times when needed, managing critical business risks, and maintaining a balanced capital structure through the issuance of equity or long-term debt securities or the repurchase of our equity securities. The need for long-term capital is driven by the level of and timing of capital expenditures and long-term debt maturities. Our issuance of long-term debt and equity securities is subject to regulation by the NCUC. For information on the issuance of long-term debt and equity securities, see Note 4 and Note 6, respectively to the consolidated financial statements in this Form 10-K.

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To meet our capital and liquidity requirements outside of the long-term capital markets, we rely on certain resources, including cash flows from operating activities, cash generated from our investments in joint ventures and short-term debt. Operating activities primarily provides the liquidity to fund our working capital, a portion of our capital expenditures and other cash needs. We rely on short-term debt together with long-term capital markets to provide a significant source of liquidity to meet operating requirements that are not satisfied by internally generated cash flows. Currently, cash flows from operations are not adequate to finance the full cost of planned investments in customer growth, pipeline integrity programs, system infrastructure and contributions to our joint ventures.

The level of short-term debt can vary significantly due to changes in the wholesale cost of natural gas and the level of purchases of natural gas supplies for storage to serve customer demand. We pay our suppliers for natural gas purchases before we collect our costs from customers through their monthly bills. If wholesale gas prices increase, we may incur more short-term debt for natural gas inventory and other operating costs since collections from customers could be slower and some customers may not be able to pay their gas bills on a timely basis.

We believe that the capacity of short-term credit available to us under our revolving syndicated credit facility and our CP program and the issuance of long-term debt and equity securities, together with cash provided by operating activities, will continue to allow us to meet our needs for working capital, capital expenditures, investments in joint ventures, anticipated debt redemptions, dividend payments, employee benefit plan contributions and other cash needs. Our ability to satisfy all of these requirements is dependent upon our future operating performance and other factors, some of which we are not able to control. These factors include prevailing economic conditions, regulatory changes, the price and demand for natural gas and operational risks, among others. Liquidity has been enhanced by reduced tax payments due to the utilization of federal net operating loss (NOL) carryforwards resulting from bonus depreciation, as well as the ability to recover and earn on investments in infrastructure related to our pipeline integrity programs through IMRs in North Carolina and Tennessee. For further information on bonus depreciation, see the following discussion of “Cash Flows from Operating Activities” in this Form 10-K.

Short-Term Debt. We have an $850 million five-year revolving syndicated credit facility that expires in October 2017. We pay an annual fee of $35,000 plus 8.5 basis points for any unused amount. The five-year revolving syndicated credit facility contains normal and customary financial covenants.

We have an $850 million unsecured CP program that is backstopped by the revolving syndicated credit facility. The amounts outstanding under the revolving syndicated credit facility and the CP program, either individually or in the aggregate, cannot exceed $850 million. The notes issued under the CP program may have maturities not to exceed 397 days from the date of issuance. Any borrowings under the CP program rank equally with our other unsecured debt.

We did not have any borrowings under the revolving syndicated credit facility for the year ended October 31, 2014. Highlights for our short-term debt as of October 31, 2014 and 2013 and for the quarter and year ended October 31, 2014 and 2013 are presented below.

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	Credit			Commercial			Total
In thousands	Facility			Paper			Borrowings
2014
End of period (October 31, 2014):
Amount outstanding	$	—		$	355,000		$	355,000
Weighted average interest rate	—		%	.17		%	.17		%
During the period (August 1, 2014 – October 31, 2014):
Average amount outstanding	$	—		$	420,900		$	420,900
Minimum amount outstanding	—			275,000			275,000
Maximum amount outstanding	—			535,000			535,000
Minimum interest rate	—		%	.10		%	.10		%
Maximum interest rate	—		%	.25		%	.25		%
Weighted average interest rate	—		%	.17		%	.17		%
Maximum amount outstanding during the month:
August 2014	$	—		$	525,000		$	525,000
September 2014	—			535,000			535,000
October 2014	—			355,000			355,000
During the year ended October 31, 2014:
Average amount outstanding	$	—		$	441,500		$	441,500
Minimum amount outstanding	—			275,000			275,000
Maximum amount outstanding	—			625,000			625,000
Minimum interest rate	—		%	.10		%	.10		%
Maximum interest rate	—		%	.43		%	.43		%
Weighted average interest rate	—		%	.19		%	.19		%

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	Credit			Commercial			Total
In thousands	Facility			Paper			Borrowings
2013
End of period (October 31, 2013):
Amount outstanding	$	—		$	400,000		$	400,000
Weighted average interest rate	—		%	.36		%	.36		%
During the period (August 1, 2013 – October 31, 2013):
Average amount outstanding	$	—		$	319,700		$	319,700
Minimum amount outstanding	—			220,000			220,000
Maximum amount outstanding	—			475,000			475,000
Minimum interest rate	—		%	.23		%	.23		%
Maximum interest rate	—		%	.43		%	.43		%
Weighted average interest rate	—		%	.28		%	.28		%
Maximum amount outstanding during the month:
August 2013	$	—		$	475,000		$	475,000
September 2013	—			335,000			335,000
October 2013	—			430,000			430,000
During the year ended October 31, 2013:
Average amount outstanding (1)	$	—		$	397,800		$	397,800
Minimum amount outstanding (1)	—			220,000			220,000
Maximum amount outstanding (1)	10,000			555,000			555,000
Minimum interest rate (2)	1.12		%	.23		%	.23		%
Maximum interest rate	1.12		%	.45		%	1.12		%
Weighted average interest rate	1.12		%	.32		%	.32		%
(1) During December 2012, we were borrowing under both the credit facility and CP program for a portion of the month.
(2) This is the minimum rate when we were borrowing under the credit facility and/or CP program.

As of October 31, 2014, we had $10 million available for letters of credit under our revolving syndicated credit facility, of which $1.8 million were issued and outstanding. The letters of credit are used to guarantee claims from self-insurance under our general and automobile liability policies. As of October 31, 2014, unused lines of credit available under our revolving syndicated credit facility, including the issuance of the letters of credit, totaled $493.2 million.

Cash Flows from Operating Activities. The natural gas business is seasonal in nature. Operating cash flows may fluctuate significantly during the year and from year to year due to working capital changes within our utility and non-utility operations. The major factors that affect our working capital are weather, natural gas purchases and prices, natural gas storage activity, collections from customers and deferred gas cost recoveries. We rely on operating cash flows and short-term debt to meet seasonal working capital needs. The level of short-term debt can vary significantly due to changes in the wholesale cost of natural gas and the level of purchases of natural gas supplies for storage to serve customer demand. We pay our suppliers for natural gas purchases before we collect our costs from customers through monthly bills. During our first and second quarters, we generally experience overall positive cash flows from the sale of flowing gas and gas withdrawal from storage and the collection of amounts billed to customers during the November through March winter heating season. Cash requirements generally increase during the third and fourth quarters due to increases in natural gas purchases injected into storage, construction activity and decreases in receipts from customers.

During the winter heating season, our trade accounts payable increase to reflect amounts due to our natural gas suppliers for commodity and pipeline capacity. The cost of the natural gas can vary significantly from period to period due to changes in the price of natural gas, which is a function of market fluctuations in the commodity cost of natural gas, along with our changing requirements for storage volumes. Differences between natural gas costs that we have paid to suppliers and amounts that we have collected from customers are included in regulatory deferred accounts and in amounts due to or from

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customers. These natural gas costs can cause cash flows to vary significantly from period to period along with variations in the timing of collections from customers under our gas cost recovery mechanisms.

Cash flows from operations are impacted by weather, which affects gas purchases and sales. Warmer weather can lead to lower revenues from fewer volumes of natural gas sold or transported. Colder weather can increase volumes sold to weather-sensitive customers but may lead to conservation by customers in order to reduce their heating bills. Regulatory margin stabilizing and cost recovery mechanisms, such as decoupled tariffs and those that allow us to recover the gas cost portion of bad debt expense, mitigate the impact that customer conservation and higher bad debt expense may have on our results of operations. Warmer-than-normal weather can lead to reduced operating cash flows, thereby increasing the need for short-term bank borrowings to meet current cash requirements.

Net cash provided by operating activities was $430.6 million in 2014, $313.2 million in 2013 and $304.5 million in 2012. Net cash provided by operating activities reflects a $9.4 million increase in net income for 2014 compared with 2013 primarily due to increased margin, partially offset by higher operating costs and utility interest charges. The effect of changes in working capital on net cash provided by operating activities is described below:

• Trade accounts receivable and unbilled utility revenues decreased$17.3 million in the current period primarily due to the decrease in unbilled volumes in the month of October and amounts billed to customers. Volumes sold to weather-sensitive residential and commercial customers increased 11.2 million dekatherms as compared with the same prior period primarily due to 6.2%colder weather during the current period. Total throughput increased 23.1 million dekatherms as compared with the same prior period, largely from 10.8 million dekatherms, or 5.7% increased deliveries to power generation customers, as well as increased sales to residential and commercial customers.

• Net amounts due from customers decreased$96.4 million in the current period primarily due to higher margin decoupling, WNA and deferred gas cost amounts due to customers.

• Gas in storage increased$10.2 million in the current period primarily due to an increase in the weighted average cost of gas purchased for injections and increased volumes of gas in storage.

• Prepaid gas costs increased$3.5 million in the current period primarily due to an increase in the weighted average cost of gas purchased for injections. Under some gas supply asset management contracts, prepaid gas costs incurred during the summer months represent purchases of gas that are not available for sale, and therefore not recorded in inventory, until the start of the winter heating season.

• Trade accounts payable decreased$11 million in the current period primarily due to decreased utility capital expenditures and natural gas purchases.

Primarily due to bonus depreciation, we generated a federal NOL in our tax years 2012 and 2013. We filed claims to carryback a portion of the NOLs to prior federal income tax returns. We recorded approximately $27 million in “Income taxes receivable” in “Current Assets” in the Consolidated Balance Sheets for the refundable income taxes from the carryback of these NOLs. Also, we utilized the carryforward of the NOLs to offset $28.6 million of federal income taxes payable in fiscal 2014. We anticipate that we will utilize the remaining portion of the NOL carryforwards prior to the expiration of the loss carryforward period.

The Tax Increase Prevention Act of 2014 (the Act) retroactively extends the 50% bonus depreciation that expired in December 2013 for a year to December 2014. Under this Act, we will be entitled to additional tax depreciation deductions for 2014. These additional deductions will result in generating a federal NOL in 2014. Our federal NOL carryforward position after considering this legislation will increase to approximately $275 million. We anticipate that we will generate future taxable income sufficient to utilize this carryforward prior to the expiration of the loss carryforward period.

Our three state regulatory commissions approve rates that are designed to give us the opportunity to generate revenues to cover our gas costs, fixed and variable non-gas costs and earn a fair return for our shareholders. We have WNA mechanisms in South Carolina and Tennessee that partially offset the impact of colder- or warmer-than-normal weather on bills rendered in November through March for residential and commercial customers in South Carolina and in October through April for residential and commercial customers in Tennessee. The WNA mechanisms in South Carolina and Tennessee generated credits to customers of $8.4 million in 2014 and charges of $3 million and $13.3 million in 2013 and 2012, respectively. In Tennessee, adjustments are made directly to individual customer monthly bills. In South Carolina, the adjustments are calculated at the individual customer level but are recorded in “Amounts due from customers” in “Regulatory Assets” or “Amounts due to customers” in “Regulatory Liabilities,” as presented in Note 1 to the consolidated financial statements in this Form 10-K, for subsequent collection from or refund to all customers in the class. The margin decoupling mechanism in North Carolina provides for the collection of our approved margin from residential and commercial customers independent of weather and consumption patterns. The margin decoupling mechanism reduced margin by $33.4 million in 2014 and increased margin

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by $6 million and $46.8 million in 2013 and 2012, respectively. Our gas costs are recoverable through purchased gas adjustment (PGA) procedures and are not affected by the WNA or the margin decoupling mechanisms.

The financial condition of the natural gas marketers and pipelines that supply and deliver natural gas to our distribution system can increase our exposure to supply and price fluctuations. We believe our risk exposure to the financial condition of the marketers and pipelines is not significant based on our receipt of the products and services prior to payment and the availability of other marketers of natural gas to meet our firm supply needs if necessary. We have regulatory commission approval in North Carolina, South Carolina and Tennessee that places tighter credit requirements on the retail natural gas marketers that schedule gas for transportation service on our system.

The regulated utility competes with other energy products, such as electricity and propane, in the residential and commercial customer markets. The most significant product competition is with electricity for space heating, water heating and cooking. Numerous factors can influence customer demand for natural gas, including price, value, availability, environmental attributes, comfort, convenience, reliability and energy efficiency. Increases in the price of natural gas can negatively impact our competitive position by decreasing the price benefits of natural gas to the consumer. This can impact our cash needs if customer growth slows, resulting in reduced capital expenditures, or if customers conserve, resulting in reduced gas purchases and customer billings.

In the industrial market, many of our customers are capable of burning a fuel other than natural gas, with fuel oil being the most significant competing energy alternative. Our ability to maintain industrial market share is largely dependent on the relative prices of energy. The relationship between supply and demand has the greatest impact on the price of natural gas. The price of oil depends upon a number of factors beyond our control, including the relationship between worldwide supply and demand and the policies of foreign and domestic governments and organizations, as well as the value of the U.S. dollar versus other currencies. Our liquidity could be impacted, either positively or negatively, as a result of alternate fuel decisions made by industrial customers.

In an effort to keep customer rates competitive and to maximize earnings, we continue to implement business process improvement and O&M cost management programs to capture operational efficiencies while improving customer service and maintaining a safe and reliable system.

Cash Flows from Investing Activities. Net cash used in investing activities was $504.4 million in 2014, $663.5 million in 2013 and $549.3 million in 2012. Net cash used in investing activities was primarily for utility capital expenditures. Gross utility capital expenditures were $460.4 million in 2014 as compared to $600 million in 2013 primarily due to lower power generation service delivery project expenditures and lower maintenance expenditures. Gross utility capital expenditures were $600 million in 2013 compared to $529.6 million in 2012 primarily due to increased expenditures for system integrity projects, partially offset by decreased expenditures for the construction of power generation service delivery projects.

We have a substantial capital expansion program for construction of transmission and distribution facilities, purchase of equipment and other general improvements. Our program supports our system infrastructure, the growth in our customer base and large amounts for pipeline integrity, safety and compliance programs, including systems and technology infrastructure to enhance our pipeline system and integrity through a new work and asset management system. Significant utility construction expenditures are expected for growth and system integrity and are part of our long-range forecasts that are prepared at least annually and typically cover a forecast period of five years. We are contractually obligated to expend capital as the work is completed.

Detail of our forecasted 2015 – 2017 capital expenditures, including AFUDC, is presented below. We intend to fund capital expenditures in a manner that maintains our targeted capitalization ratio of 50 – 60% in total debt and 40 – 50% in common equity. A portion of the funding for capital expenditures is derived from operations, including lower federal income tax payments due to accelerated depreciation as well as bonus depreciation benefits.

In millions	2015		2016		2017
Customer growth and other	$	230	$	285	$	295
System integrity	270		245		295
Total forecasted utility capital expenditures	$	500	$	530	$	590

Our estimates for utility capital expenditures associated with system integrity have increased since 2013. These increases are primarily due to costs associated with the development and enhancement of programs and processes designed to mitigate risk on our system to comply with federally mandated pipeline safety and integrity requirements. Such programs

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include retrofitting transmission lines to facilitate internal inspections, transmission line replacements, corrosion control, casing remediation and distribution integrity management.

During fiscal 2012, we placed into service natural gas pipeline and compression facilities to provide natural gas delivery service to a Duke Energy Progress, Inc. (DEP), now a subsidiary of Duke Energy Corporation (Duke Energy), power generation facility located in Wayne County, North Carolina. This project was supported by a long-term service agreement with fixed monthly payments. In connection with this project, we increased our firm capacity entitlement on Cardinal Pipeline Company, L.L.C. (Cardinal) pipeline to serve the DEP Wayne County site, requiring Cardinal to invest in a new compressor station and expanded meter stations in order to increase the capacity of its system for us and another customer. As an equity venture partner of Cardinal, we made capital contributions of $9.8 million related to this system expansion and received $5.4 million as a partial return of our capital investment with Cardinal's issuance of $45 million of long-term debt. Cardinal's expansion service for the project and our natural gas delivery service for DEP's Wayne County site were placed into service in June 2012.

During fiscal 2013, we placed into service natural gas pipeline and compression facilities to provide natural gas delivery service to a DEP power generation facility at their Sutton site near Wilmington, North Carolina. Our investment in the pipeline and compression facilities was supported by a long-term service agreement with fixed monthly payments.

Our Sutton project facilities created cost effective expansion capacity that we will also use to help serve the growing natural gas requirements of our customers in the eastern part of North Carolina. The approval of our 2013 NCUC rate settlement provided for the inclusion of this project in rate base in North Carolina. Beginning in 2015, a special contracts credit, representing a portion of margin on our power generation contracts, will reduce the IMR revenue requirement under the IMR mechanism.

In July 2013, we acquired an additional 5% membership interest in Pine Needle LNG Company, L.L.C. from Hess Corporation for $2.9 million, which increased our membership interest from 40% to 45%.

In September 2013, we made an additional $22.5 million capital contribution to our existing SouthStar investment associated with our partner contributing retail natural gas marketing assets and related customer accounts located in Illinois. For further information regarding this transaction, see Note 12 to the consolidated financial statements in this Form 10-K.

In November 2012, we became a 24% equity member of Constitution, a Delaware limited liability company. The purpose of the joint venture is to construct, own and operate approximately 120 miles of interstate natural gas pipeline and related facilities connecting shale natural gas supplies and gathering systems in Susquehanna County, Pennsylvania, to the Iroquois Gas Transmission and Tennessee Gas Pipeline systems in New York. We have committed to fund an amount in proportion to our ownership interest for the development and construction of the new pipeline. Our contributions for the year ended October 31, 2014 were $37.6 million with our total equity contribution for the project totaling $53.5 million as of October 31, 2014. On December 2, 2014, the FERC issued a certificate of public convenience and necessity approving construction of the Constitution pipeline. The forecasted in-service date of the project is late 2015 or 2016. We expect our equity contributions will be an estimated $86 million and $35.4 million in our fiscal years 2015 and 2016, respectively, for total equity contributions of $175 million. In November 2014, we contributed $1.9 million to the project. For further information regarding this agreement, see Note 12 to the consolidated financial statements in this Form 10-K.

In June 2014, we executed an agreement to construct approximately 1.5 miles of natural gas transmission pipeline and associated compression to serve Duke Energy’s W.S. Lee power generation facility near Anderson, South Carolina. Our total investment is estimated to be $38 million, with $8 million and $30 million in our fiscal years 2015 and 2016, respectively, and is included in the table above in the line “Customer growth and other.” This agreement is supported by a long-term natural gas service agreement with fixed monthly charges.

In September 2014, Piedmont, Duke Energy, Dominion Resources, Inc. (Dominion), and AGL Resources, Inc. (AGL) announced the formation of ACP, a Delaware limited liability company. ACP intends to construct, operate and maintain a 550 mile natural gas pipeline, with associated compression, from West Virginia through Virginia into eastern North Carolina. The pipeline is proposed to provide wholesale natural gas transportation services for Marcellus and Utica gas supplies into southeastern markets. ACP, which is regulated by the FERC, will be designed with an initial capacity of 1.5 billion cubic feet per day with a target in-service date of late 2018. The capacity of ACP is substantially subscribed by utilities and related companies, including us, under twenty-year contracts.

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We entered into an agreement through a wholly-owned subsidiary to become a 10% equity member of ACP. The other members are subsidiaries of Duke Energy, Dominion and AGL. A Dominion subsidiary will be the operator of the pipeline. The cost for the development and construction of the pipeline is expected to be between $4.5 billion to $5 billion, excluding financing costs. Members anticipate obtaining project financing for 70% of the total costs during the construction period. As of October 31, 2014, we have made no contributions to ACP. In November 2014, we contributed $.9 million to the project.

In connection with the ACP project, we plan to make additional utility capital investments in our natural gas delivery system of approximately $190 million in order to redeliver ACP gas supplies to local North Carolina markets we serve, predominately in fiscal 2017 and 2018. Of that amount, approximately $170 million will be supported by third-party contracts.

Cash Flows from Financing Activities. Net cash provided by financing activities was $75.4 million in 2014, $356.3 million in 2013 and $240 million in 2012. Funds are primarily provided from long-term debt securities, short-term borrowings and the issuance of common stock through our dividend reinvestment and stock purchase plan (DRIP) and our employee stock purchase plan (ESPP). We may sell common stock and long-term debt when market and other conditions favor such long-term financing to maintain our target capital structure of 40 – 50% equity to total capital. In recent years, bonus depreciation has been a source of funds in that it has decreased our federal income tax payments. Funds are primarily used to finance capital expenditures, retire long-term debt maturities, pay down outstanding short-term debt, repurchase common stock under the common stock repurchase program, pay quarterly dividends on our common stock and general corporate purposes.

Outstanding debt under our CP program decreased from $400 million as of October 31, 2013 to $355 million as of October 31, 2014 primarily due to net proceeds received from the issuance of long-term debt and our common stock, reduced utility capital expenditures and cash flow stemming from colder-than normal weather, partially offset by natural gas purchases, repayment of our long-term debt and investments in one of our equity method investments. On November 1, 2013, we entered into an agreement with the lenders under our five-year revolving syndicated credit facility to increase the aggregate commitment from $650 million to $850 million with an expiration date of October 1, 2017. Our unsecured CP program is backstopped by this credit facility. For further information on short-term debt, see Note 5 to the consolidated financial statements in this Form 10-K and the previous discussion of “Short-Term Debt” in “Financial Condition and Liquidity.”

On June 6, 2014, we filed with the SEC a combined debt and equity shelf registration statement that became effective on the same date. Unless otherwise specified at the time such securities are offered for sale, the net proceeds from the sale of the securities will be used to finance capital expenditures, to repay outstanding short-term notes under our unsecured CP program, to refinance other indebtedness, to repurchase our common stock, to pay dividends and for general corporate purposes. Pending such use, we may temporarily invest any net proceeds that are not applied to the purposes mentioned above in investment-grade securities. We plan to issue new long-term debt and equity capital in our fiscal years 2015 and 2016, at such amounts to support our capital investment program and maintain our target capital structure of 50 – 60% in total debt and 40 – 50% in common equity. In addition to issuing common stock under our DRIP and ESPP as described above, we expect to establish in the first quarter of 2015 an at-the-market equity sales program that may also include sales with a forward component. We anticipate that sales under this program would not exceed an aggregate of $170 million, as market conditions permit, and would be completed by the end of fiscal 2016. Any such shares of our common stock would be offered and sold under our shelf registration statement and related prospectuses.

On January 29, 2013, we entered into an underwriting agreement under our open combined debt and equity shelf registration statement to sell up to 4.6 million shares of our common stock of which 3 million direct shares were issued and settled on February 4, 2013 with net proceeds of $92.6 million received. The shares were purchased by the underwriters at the net price of $30.88, the offering price to the public of $32 per share per the prospectus less an underwriting discount of $1.12 per share.

Under this same underwriting agreement, we had two FSAs totaling 1.6 million shares that had to be settled no later than mid-December 2013. Under the terms of the FSAs, at our election, we could physically settle in shares, cash or net share settle for all or a portion of our obligations under the agreements. In December 2013, we physically settled the FSAs by issuing 1.6 million shares of our common stock to the forward counterparty and received net proceeds of $47.3 million based on the net settlement price of $30.88 per share, the original offering price, less certain adjustments.

We used the net proceeds from the equity transactions discussed above to finance capital expenditures, repay outstanding notes under the unsecured CP program and for general corporate purposes. For further information on our common stock and for more details on these equity issuance transactions, see Note 6 to the consolidated financial statements in this Form 10-K.

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We continually monitor customer growth trends and investment opportunities in our markets and the timing of any infrastructure investments that would require the need for additional long-term debt. The table below presents the activity of our long-term debt during the three-year period ended October 31, 2014. For further information on our long-term debt instruments, see Note 4 to the consolidated financial statements in this Form 10-K.

In millions	Issued (Redeemed)			Date Issued/Redeemed	Cash Impact
Senior Notes:
3.47%, due July 16, 2027 (1) (2)	$	100		July 2012	$	100.0
3.57%, due July 16, 2027 (1) (2)	200			October 2012	200.0
4.65%, due August 1, 2043 (3)	300			August 2013	299.9
4.10%, due September 18, 2034 (1)	250			September 2014	249.6
Medium-Term Notes:
5.00%, due December 19, 2013	(100		)	December 2013	(100		)
(1) The net proceeds were used to finance capital expenditures, to repay outstanding short-term notes under our unsecured CP program and for general corporate purposes.
(2) In March 2012, we entered into an agreement to issue $300 million of notes in a private placement with a blended rate of 3.54%.
(3) The net proceeds were used to finance capital expenditures, to repay the balance of $100 million of our 5% Medium-Term Notes listed below, to repay outstanding short-term notes under our unsecured CP program and for general corporate purposes.

From time to time, we have repurchased shares of common stock under our Common Stock Open Market Purchase Program as described in Note 6 to the consolidated financial statements in this Form 10-K. During 2014 and 2013, we did not repurchase any of our common stock. Under our Common Stock Open Market Purchase Program, we repurchased and retired .8 million shares for $26.5 million during 2012. We do not anticipate repurchasing our common stock in our fiscal year 2015.

During 2014, we issued $25.6 million of common stock through DRIP and ESPP. During 2013 and 2012, we issued $24.6 million and $22.1 million, respectively, through these plans.

We have paid quarterly dividends on our common stock since 1956. We increased our common stock dividend on an annualized basis by $.04 per share over the past three fiscal years. Dividends of $99.2 million, $92.1 million and $85.7 million in 2014, 2013 and 2012, respectively, were paid on common stock. Provisions contained in certain note agreements under which certain long-term debt was issued restrict the amount of cash dividends that may be paid. As of October 31, 2014, our ability to pay dividends was not restricted. On December 12, 2014, the Board of Directors declared a quarterly dividend on common stock of $.32 per share, payable January 15, 2015 to shareholders of record at the close of business on December 24, 2014. For further information, see Note 4 to the consolidated financial statements in this Form 10-K.

Our targeted capitalization ratio is 50 – 60% in total debt and 40 – 50% in common equity. The components of our total debt outstanding (short-term and long-term) to our total capitalization as of October 31, 2014 and 2013 are summarized in the table below.

	October 31				October 31
In thousands	2014		Percentage		2013		Percentage
Short-term debt	$	355,000	12	%	$	400,000	14	%
Current portion of long-term debt	—		—	%	100,000		3	%
Long-term debt	1,424,430		46	%	1,174,857		41	%
Total debt	1,779,430		58	%	1,674,857		58	%
Common stockholders’ equity	1,308,602		42	%	1,188,596		42	%
Total capitalization (including short-term debt)	$	3,088,032	100	%	$	2,863,453	100	%

Credit ratings impact our ability to obtain short-term and long-term financing and the cost of such financings. The borrowing costs under our revolving syndicated credit facility and our unsecured CP program are based on our credit ratings, and consequently, any decrease in our credit ratings would increase our borrowing costs. We believe our credit ratings will allow us to continue to have access to the capital markets, as and when needed, at a reasonable cost of funds.

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The lenders under our revolving syndicated credit facility and our unsecured CP program are major financial institutions, all of which have investment grade credit ratings as of October 31, 2014. It is possible that one or more lending commitments could be unavailable to us if the lender defaulted due to lack of funds or insolvency. However, based on our current assessment of our lenders’ creditworthiness, we believe the risk of lender default is minimal.

As of October 31, 2014, all of our long-term debt was unsecured. Our long-term debt is rated “A” by Standard & Poor’s Ratings Services (S&P) and “A2” by Moody’s Investors Service (Moody’s). Currently, with respect to our long-term debt, the credit agencies maintain their stable outlook. S&P and Moody’s have issued credit ratings on our unsecured CP program at “A1” and “P1”, respectively. Credit ratings and outlooks are opinions of the rating agencies and are subject to their ongoing review. A significant decline in our operating performance, a significant negative change in our capital structure, a change from the constructive regulatory environments in which we operate, a significant reduction in our liquidity or a methodological change at the rating agencies themselves could trigger a negative change in our ratings outlook or even a reduction in our credit ratings by the rating agencies. This would mean more limited access to the private and public credit markets and an increase in the costs of such borrowings. There is no guarantee that a rating will remain in effect for any given period of time or that a rating will not be lowered or withdrawn by a rating agency if, in its judgment, circumstances warrant a change.

We are subject to default provisions related to our long-term debt and short-term borrowings. Failure to satisfy any of the default provisions may result in total outstanding issues of debt becoming due. There are cross-default provisions in all of our debt agreements. As of October 31, 2014, there has been no event of default giving rise to acceleration of our debt.

The default provisions of some or all of our senior debt include:

• Failure to make principal or interest payments,

• Bankruptcy, liquidation or insolvency,

• Final judgment against us in excess of $1 million that after 60 days is not discharged, satisfied or stayed pending appeal,

• Specified events under the Employee Retirement Income Security Act of 1974,

• Change in control, and

• Failure to observe or perform covenants, including:

• Interest coverage of at least 1.75 times. Interest coverage was 4.29 times as of October 31, 2014;

• Funded debt cannot exceed 70% of total capitalization. Funded debt was 58% of total capitalization as of October 31, 2014;

• Funded debt of all subsidiaries in the aggregate cannot exceed 15% of total capitalization. There is no funded debt of our subsidiaries as of October 31, 2014;

• Restrictions on permitted liens;

• Restrictions on paying dividends, on or repurchasing our stock or making investments in subsidiaries; and

• Restrictions on burdensome agreements.

Contractual Obligations and Commitments

We have incurred various contractual obligations and commitments in the normal course of business. As of October 31, 2014, our estimated recorded and unrecorded contractual obligations are as follows. We have conditional asset retirement obligations for underground mains and services of $14.6 million that are not included in the table because we cannot reasonably estimate payments by periods.

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	Payments Due by Period
	Less than		1-3		3-5		More than
In thousands	1 year		Years		Years		5 Years		Total
Recorded contractual obligations:
Long-term debt (1)	$	—	$	75,000	$	—	$	1,350,000	$	1,425,000
Short-term debt (2)	355,000		—		—		—		355,000
Total recorded contractual obligations	355,000		75,000		—		1,350,000		1,780,000
Unrecorded contractual obligations and
commitments: (3)
Pipeline and storage capacity (4)	158,984		437,424		246,091		513,697		1,356,196
Gas supply reservation fees (5)	8,657		272		—		—		8,929
Interest on long-term debt (6)	69,609		204,949		131,811		736,555		1,142,924
Capital contributions to joint ventures (7)	106,734		159,847		88,612		—		355,193
Telecommunications and information
technology (8)	14,601		5,648		80		—		20,329
Qualified and nonqualified pension plan
funding (9)	11,821		36,571		2,590		—		50,982
Postretirement benefits plan funding (9)	1,500		4,000		1,300		—		6,800
Operating leases (10)	4,600		13,013		8,362		23,134		49,109
Other purchase obligations (11)	41,008		—		—		—		41,008
Surety bonds (10)	4,782		—		—		—		4,782
Letters of credit (2)	1,797		—		—		—		1,797
Total unrecorded contractual obligations
and commitments	424,093		861,724		478,846		1,273,386		3,038,049
Total contractual obligations and
commitments	$	779,093	$	936,724	$	478,846	$	2,623,386	$	4,818,049

(1) See Note 4 to the consolidated financial statements in this Form 10-K.

(2) See Note 5 to the consolidated financial statements in this Form 10-K.

(3) In accordance with generally acceptable accounting principles in the United States (GAAP), these items are not reflected in the Consolidated Balance Sheets.

(4) Recoverable through PGA procedures.

(5) Reservation fees are fixed payments and are recoverable through PGA procedures.

(6) Includes accrued interest of $20.8 million as of October 31, 2014.

(7) See Note 12 to the consolidated financial statements in this Form 10-K.

(8) Consists primarily of maintenance fees for hardware and software applications, usage fees, local and long-distance data costs, frame relay, and cell phone and pager usage fees.

(9) Estimated funding beyond five years is not available. See Note 9 to the consolidated financial statements in this Form 10-K.

(10) See Note 8 to the consolidated financial statements in this Form 10-K. Operating lease payments do not include payment for common area maintenance, utilities or tax payments.

(11) Consists primarily of pipeline products, vehicles, contractors and merchandise.

Off-balance Sheet Arrangements

We have no off-balance sheet arrangements other than letters of credit, surety bonds and operating leases. The letters of credit are discussed in Note 5 to the consolidated financial statements in this Form 10-K. The surety bonds and operating leases are discussed in Note 8 to the consolidated financial statements in this Form 10-K.

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Critical Accounting Estimates

We prepare the consolidated financial statements in conformity with accounting principles generally accepted in the United States of America. We make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the periods reported. Actual results may differ significantly from these estimates and assumptions. We base our estimates on historical experience, where applicable, and other relevant factors that we believe are reasonable under the circumstances. On an ongoing basis, we evaluate estimates and assumptions and make adjustments in subsequent periods to reflect more current information if we determine that modifications in assumptions and estimates are warranted.

Management considers an accounting estimate to be critical if it requires assumptions to be made that were uncertain at the time the estimate was made, and changes in the estimate or a different estimate that could have been used would have had a material impact on our financial condition or results of operations. We consider regulatory accounting, revenue recognition, and pension and postretirement benefits to be our critical accounting estimates. Management is responsible for the selection of these critical accounting estimates. Management has discussed these critical accounting estimates presented below with the Audit Committee of the Board of Directors.

Revenue Recognition. Utility sales and transportation revenues are based on rates approved by state regulatory commissions. Base rates charged to customers may not be changed without formal approval by the regulatory commission in that jurisdiction; however, the wholesale cost of gas component of rates may be adjusted periodically under PGA procedures. In South Carolina and Tennessee, we have WNA mechanisms that are designed to protect a portion of our residential and commercial customer revenues against warmer-than-normal weather as deviations from normal weather can affect our financial performance and liquidity. The mechanisms also serve to offset the impact of colder-than-normal weather by reducing the amounts we can charge our customers. In North Carolina, a margin decoupling mechanism provides for the recovery of our approved margin from residential and commercial customers independent of weather and consumption patterns. The margin earned monthly under the margin decoupling mechanism results in semi-annual rate adjustments to refund any over-collection or recover any under-collection. The gas cost portion of our costs is recoverable through PGA procedures and is not affected by the WNA or the margin decoupling mechanisms. Without the WNA and margin decoupling mechanisms, our operating revenues and margin would have been higher by $41.8 million in 2014 and lower by $9 million and by $60.1 million in 2013 and 2012, respectively.

New in 2014 is the IMR that was implemented in North Carolina and Tennessee to separately track and recover costs associated with capital expenditures in order to comply with pipeline safety and integrity requirements on an annual basis outside general rate cases. Under the North Carolina IMR tariff, we make annual filings each November to capture such costs closed to plant through October with revised rates effective the following February. Under the Tennessee IMR, we file to adjust rates to be effective each January 1 based on capital expenditures incurred through the previous October. Without the IMR in North Carolina, our operating revenues and margin would have been lower by $.6 million for the period February 1, 2014 through October 31, 2014. Without the IMR in Tennessee, our operating revenues and margin would have been lower by $10.1 million for the period January 1, 2014 through October 31, 2014.

Revenues are recognized monthly on the accrual basis, which includes estimated amounts for gas delivered to customers but not yet billed under the cycle-billing method from the last meter reading date to month end. Meters are read throughout the month based on an approximate 30-day usage cycle; therefore, at any point in time, volumes are delivered to customers that have not been metered and billed. The unbilled revenue estimate reflects factors requiring judgment related to estimated usage by customer class, customer mix, changes in weather during the period and the impact of the WNA or margin decoupling mechanisms, as applicable. Secondary market revenues are recognized when the physical sales are delivered based on contract or market prices.

Regulatory Accounting. Our regulated utility segment is subject to regulation by certain state and federal authorities. Our accounting policies conform to the accounting regulations required by rate-regulated operations and are in accordance with accounting requirements and ratemaking practices prescribed by the regulatory authorities. The application of these accounting policies allows us to defer expenses and revenues on the balance sheet as regulatory assets and liabilities when those expenses and revenues will be allowed in the ratemaking process in a period different from the period in which they would have been reflected in the income statement by an unregulated company. We then recognize these deferred regulatory assets and liabilities through the income statement in the period in which the same amounts are reflected in rates. If we, for any reason, cease to meet the criteria for application of regulatory accounting treatment for all or part of our operations, we would eliminate from the balance sheet the regulatory assets and liabilities related to those portions ceasing to meet such criteria and include them as an adjustment to net income or accumulated other comprehensive income for the period in which the discontinuance of regulatory accounting treatment occurs. Such an event could have a material effect on our results of operations in the period this action was recorded.

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Management continually assesses whether the regulatory assets are probable of future recovery by considering factors such as applicable regulatory environment changes, historical regulatory treatment of similar costs in our jurisdictions, recent rate orders to other regulated entities and the status of any pending or potential legislation that would affect the regulatory environment. Based on our assessment that reflects the current political and regulatory climate at the state and federal levels, we believe that all of our regulatory assets are recoverable in current rates or future rate proceedings. However, this assessment is subject to change in the future.

Regulatory assets as of October 31, 2014 and 2013 totaled $213.9 million and $246.3 million, respectively. Regulatory liabilities as of October 31, 2014 and 2013 totaled $604.8 million and $541.9 million, respectively. The detail of these regulatory assets and liabilities is presented in “Rate-Regulated Basis of Accounting” in Note 1 to the consolidated financial statements in this Form 10-K.

Pension and Postretirement Benefits. We have a traditional defined benefit pension plan (qualified pension plan) covering eligible employees. We also provide certain other postretirement health care and life insurance benefits to eligible employees. For further information and our reported costs of providing these benefits, see Note 9 to the consolidated financial statements in this Form 10-K. We recognize the funded status of our benefit plans as an asset or liability with any changes in the funded status recorded as a regulatory asset or liability as allowed by our state regulatory commissions.

The costs of providing these benefits are impacted by numerous factors, including the provisions of the plans, changing employee demographics and various actuarial calculations, assumptions and accounting mechanisms. Because of the complexity of these calculations, the long-term nature of these obligations and the importance of the assumptions used, our estimate of these costs is a critical accounting estimate.

Several statistical and other factors, which attempt to anticipate future events, are used in calculating the expenses and liabilities related to the plans. These factors include assumptions about the discount rate used in determining future benefit obligations, projected health care cost trend rates, expected long-term return on plan assets and rate of future compensation increases, within certain guidelines. In addition, we also use subjective factors such as withdrawal and mortality rates to estimate projected benefit obligations. The actuarial assumptions used may differ materially from actual results due to changing market and economic conditions, higher or lower withdrawal rates or longer or shorter life spans of participants. These differences may result in a significant impact on the amount of pension expense or other postretirement benefit costs recorded in future periods, and we cannot predict with certainty what these factors will be in the future.

The discount rate has been separately determined for each plan by projecting the plan’s cash flows and developing a zero-coupon spot rate yield curve using non-arbitrage pricing and non-callable bonds rated AA or better by either Moody’s or S&P that have a yield higher than the regression mean yield curve. Based on this approach, the weighted average discount rate used in the measurement of the benefit obligation for the qualified pension plan changed from 4.55% in 2013 to 4.13% in 2014. For the nonqualified pension plans, the weighted average discount rate used in the measurement of the benefit obligation changed from 3.98% in 2013 to 3.69% in 2014. Similarly, the weighted average discount rate for postretirement benefits changed from 4.44% in 2013 to 4.03% in 2014. The lower discount rates discussed above reflect the lower yields found in the AA corporate bond market where the bond price has increased. Based on our review of actual cost trend rates and projected future trends in establishing health care cost trend rates, the initial health care cost trend rate was assumed to be 7.40% in 2014 declining gradually to 5% by 2027.

In determining our expected long-term rate of return on plan assets, we review past long-term performance, asset allocations and long-term inflation assumptions. We target our asset allocations for qualified pension plan assets and other postretirement benefit assets to be approximately 55% equity securities and 45% fixed income securities. To the extent that the actual rate of return on assets realized during the fiscal year is greater or less than the assumed rate, that year’s qualified pension plan and postretirement benefits plan costs are not affected; instead, this gain or loss reduces or increases the future costs of the plans over the average remaining service period for active employees. The expected long-term rate of return on plan assets was 8% in 2012 and 2013. The expected long-term rate of return was reduced to 7.75% for 2014. Based on a fairly constant inflation trend, our age-related assumed rate of increase in future compensation levels was 3.78% in 2012, decreasing to 3.76% in 2013, and further decreasing to 3.72% in 2014 due to changes in the demographics of the participants.

Our market-related value of plan assets represents the fair market value of the plan’s assets as adjusted by the portion of the prior five years’ asset gains and losses that has not yet been recognized. The use of this calculation delays the impact of current market fluctuations on benefit costs for the fiscal year.

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During 2014, we recorded costs of $6.4 million related to our qualified pension plan and postretirement benefits plan. We estimate 2015 expenses for these two plans to be in the range of $7 to $8 million representing an increase of $.6 to $1.6 million from 2014. These estimates reflect the lower discount rates and a 7.50% assumed rate of return on the plan assets.

The following reflects the sensitivity of pension cost to changes in certain actuarial assumptions for our qualified pension plan, assuming that the other components of the calculation are constant.

	Change in		Impact on 2014		Impact on Projected
Actuarial Assumption	Assumption		Benefit Cost		Benefit Obligation
			Increase (Decrease) In thousands
Discount rate	(0.25)%	$	594	$	7,566
Rate of return on plan assets	(0.25)%		727		N/A
Rate of increase in compensation	0.25%		741		4,209

The following reflects the sensitivity of postretirement benefit cost to changes in certain actuarial assumptions, assuming that the other components of the calculation are constant.

			Impact on 2014		Impact on Accumulated
	Change in		Postretirement		Postretirement Benefit
Actuarial Assumption	Assumption		Benefit Cost		Obligation
			Increase (Decrease)
			In thousands
Discount rate	(0.25)%	$	—	$	995
Rate of return on plan assets	(0.25)%		14		N/A
Health care cost trend rate	0.25%		8		210

We utilize accounting methods consistently applied that are allowed under GAAP which reduce the volatility of reported pension costs. Differences between actuarial assumptions and actual plan results are deferred and amortized into cost when the accumulated differences exceed 10% of the greater of the projected benefit obligation or the market-related value of the plan assets. If necessary, the excess is amortized over the average remaining service period of active employees.

Gas Supply and Regulatory Proceedings

The source of our gas supply that we distribute to our customers is contracted from a diverse portfolio of major and independent producers and marketers and interstate and intrastate pipeline and storage operators. In November 2012, we continued to diversify our supply portfolio by contracting to bring abundant and low cost natural gas supplies from the Marcellus supply basin to our natural gas markets in the Carolinas. We signed a long-term contract with Cabot Oil & Gas to purchase firm, price-competitive Marcellus gas supplies. We also signed a long-term firm capacity contract with Williams – Transco under its Leidy Southeast expansion project to transport the Marcellus based Cabot gas supplies to our markets. In December 2012, we also signed a long-term firm capacity contract with Williams – Transco under its Virginia Southside expansion project that will also allow us to further diversify our supply portfolio with Marcellus based natural gas. These new supply arrangements are scheduled to begin in late 2015. Also, in October 2014, we contracted for long-term pipeline capacity from the Marcellus and Utica shale basins in central West Virginia under the ACP project that is proposed to be effective for the winter 2018 – 2019 season. We believe that these new natural gas supplies will provide diversification, reliability and gas cost benefits to Piedmont’s customers across the Carolinas.

Natural gas demand is continuing to grow in our service area as discussed in the preceding section of “Cash Flows from Investing Activities” in this Form 10-K. For further information on our equity ventures with ACP to serve our expanding markets, see Note 12 to the consolidated financial statements in this Form 10-K.

As approved by our state regulatory commissions, secondary market transactions permit us to market gas supplies and transportation services by contract with wholesale or off-system customers. These sales contribute smaller per-unit margins to earnings; however, the programs allow us to act as a wholesale marketer of natural gas and transportation capacity when market conditions permit and when the supply and capacity are not required to serve our retail distribution system. For further information on secondary market transactions, see Note 2 to the consolidated financial statements in this Form 10-K.

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We continue to work with our regulatory commissions to earn a fair rate of return on invested capital for our shareholders and provide safe, reliable natural gas distribution service to our customers. For further information about regulatory proceedings and other regulatory information, see Note 2 to the consolidated financial statements in this Form 10-K.

Equity Method Investments

For information about our equity method investments, see Note 12 to the consolidated financial statements in this Form 10-K.

Environmental Matters

We have developed an environmental self-assessment plan to examine our facilities and program areas for compliance with federal, state and local environmental regulations and to correct any deficiencies identified. As a member of the North Carolina MGP Initiative Group, we, along with other responsible parties, work directly with the North Carolina Department of Environment and Natural Resources to set priorities for manufactured gas plant (MGP) site remediation. For additional information on environmental matters, see Note 8 to the consolidated financial statements in this Form 10-K.

Accounting Guidance

For further information regarding recently issued accounting guidance, see Note 1 to the consolidated financial statements in this Form 10-K.

Item 7A. Quantitative and Qualitative Disclosures about Market Risk

We are exposed to various forms of market risk, including the credit risk of our suppliers and our customers, interest rate risk, commodity price risk and weather risk. We seek to identify, assess, monitor and manage all of these risks in accordance with defined policies and procedures under the direction of the Treasurer and Chief Risk Officer and our Enterprise Risk Management (ERM) program, including our Energy Price Risk Management Committee. Risk management is guided by senior management with Board of Directors oversight, and senior management takes an active role in the development of policies and procedures.

During our current fiscal year, the Board of Directors delegated oversight of our ERM program to the Finance and Enterprise Risk (FER) Committee. All other committees of our Board of Directors have enhanced monitoring of those risks relating to areas where they have oversight responsibility. The Board of Directors approved risk tolerances for major areas of risk exposure and will receive quarterly reports from the FER Committee and annual reports from management.

We hold all financial instruments discussed below for purposes other than trading.

Credit Risk

We enter into contracts with third parties to buy and sell natural gas. Our policy requires counterparties to have an investment-grade credit rating at the time of the contract, or in situations where counterparties do not have investment-grade or functionally equivalent credit ratings, our policy requires credit enhancements that include letters of credit or parental guaranties. In either circumstance, the policy specifies limits on the contract amount and duration based on the counterparty’s credit rating and/or credit support. In order to minimize our exposure, we continually re-evaluate third-party creditworthiness and market conditions and modify our requirements accordingly.

We also enter into contracts with third parties to manage some of our supply and capacity assets for the purpose of maximizing their value. These arrangements include a counterparty credit evaluation according to our policy described above prior to contract execution and typically have durations of one year or less. In the event that a party is unable to perform under these arrangements, we have exposure to satisfy our underlying supply or demand contractual obligations that were incurred while under the management of this third party.

We have mitigated our exposure to the risk of non-payment of utility bills by our customers. In all three states, gas costs related to uncollectible accounts are recovered through PGA procedures. To manage the non-gas cost customer credit risk, we evaluate credit quality and payment history and may require cash deposits from our high risk customers that do not satisfy our predetermined credit standards until a satisfactory payment history has been established. Significant increases in the price of natural gas or colder-than-normal weather can slow our collection efforts as customers experience increased difficulty in paying their gas bills, leading to higher than normal accounts receivable.

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Interest Rate Risk

We are exposed to interest rate risk as a result of changes in interest rates on short-term debt. As of October 31, 2014, all of our long-term debt was issued at fixed rates, and therefore not subject to interest rate risk.

We have short-term borrowing arrangements to provide working capital and general corporate liquidity. The level of borrowings under such arrangements varies from period to period depending upon many factors, including the cost of wholesale natural gas and our gas supply hedging programs, our investments in capital projects, the level and expense of our storage inventory and the collection of receivables. Future short-term interest expense and payments will be impacted by both short-term interest rates and borrowing levels.

As of October 31, 2014, we had $355 million of short-term debt outstanding as commercial paper at an interest rate of .17%. The carrying amount of our short-term debt approximates fair value. A change of 100 basis points in the underlying average interest rate for our short-term debt would have caused a change in interest expense of approximately $4.4 million during 2014.

As of October 31, 2014, information about our long-term debt is presented below.

																						Fair Value as
	Expected Maturity Date																					of October 31,
In millions	2015			2016			2017			2018			2019			Thereafter			Total			2014
Fixed Rate Long-term Debt	$	—		$	40		$	35		$	—		$	—		$	1,350		$	1,425		$	1,617.5
Average Interest Rate	—		%	2.92		%	8.51		%	—		%	—		%	4.88		%	4.92		%

Commodity Price Risk

We have mitigated the cash flow risk resulting from commodity purchase contracts under our regulatory gas cost recovery mechanisms that permit the recovery of these costs in a timely manner. However, we face regulatory recovery risk associated with these costs. With regulatory commission approval, we revise rates periodically without formal rate proceedings to reflect changes in the wholesale cost of gas, including costs associated with our hedging programs under the recovery mechanism allowed by each of our state regulators. Under our PGA procedures, differences between gas costs incurred and gas costs billed to customers are deferred and any under-recoveries are included in “Amounts due from customers” in “Regulatory Assets” or any over-recoveries are included in “Amounts due to customers” in “Regulatory Liabilities” as presented in Note 1 to the consolidated financial statements in this Form 10-K, for collection or refund over subsequent periods. When we have “Amounts due from customers,” we earn a carrying charge that mitigates any incremental short-term borrowing costs. When we have “Amounts due to customers,” we incur a carrying charge that we must refund to our customers.

We manage our gas supply costs through a portfolio of short- and long-term procurement and storage contracts with various suppliers. We actively manage our supply portfolio to balance sales and delivery obligations. We inject natural gas into storage during the summer months and withdraw the gas during the winter heating season. In the normal course of business, we utilize New York Mercantile Exchange (NYMEX) exchange traded instruments of various durations to hedge price volatility on a portion of our natural gas requirements, subject to regulatory review and approval.

We purchase firm gas from a diverse portfolio of suppliers at liquid exchange points. For term suppliers whose performance is greater than one month, we evaluate and monitor their creditworthiness and maintain the ability to require additional financial assurances, including deposits, letters of credit or surety bonds, in case a supplier defaults. Since most of our commodity supply contracts are at market index prices tied to liquid exchange points and with our significant storage flexibility, we believe that it is unlikely that a supplier default would have a material effect on our financial position, results of operations or cash flows.

Our gas purchasing practices are subject to regulatory reviews in all three states in which we operate. We are responsible for following competitive and reasonable practices in purchasing gas for our customers. Costs have never been disallowed on the basis of prudence in any jurisdiction.

45

Weather Risk

We are exposed to weather risk in our regulated utility segment in South Carolina and Tennessee where revenues are collected from volumetric rates without a margin decoupling mechanism. Our rates are designed based on an assumption of normal weather. This risk is mitigated by a WNA mechanism designed to offset the impact of colder-than-normal or warmer-than-normal weather in our residential and commercial markets during the months of November through March in South Carolina and October through April in Tennessee. The WNA formulas do not ensure full recovery of approved margin during periods when customer consumption patterns vary from those used to establish the WNA factors. In North Carolina, we manage our weather risk through a year round margin decoupling mechanism that allows us to recover our approved margin from residential and commercial customers independent of volumes sold. We are exposed to weather risks in our industrial markets to the extent our margin is collected through volumetric rates in all of our jurisdictions.

Additional information concerning market risk is set forth in “Financial Condition and Liquidity” in Item 7 of this Form 10-K in Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Item 8. Financial Statements and Supplementary Data

Consolidated financial statements required by this item are listed in Item 15 (a) 1 in Part IV of this Form 10-K.

46

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of

Piedmont Natural Gas Company, Inc.

Charlotte, North Carolina

We have audited the accompanying consolidated balance sheets of Piedmont Natural Gas Company, Inc. and subsidiaries (the “Company”) as of October 31, 2014 and 2013, and the related consolidated statements of comprehensive income, stockholders’ equity, and cash flows for each of the three years in the period ended October 31, 2014. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements based on our 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 audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Piedmont Natural Gas Company, Inc. and subsidiaries at October 31, 2014 and 2013, and the results of their operations and their cash flows for each of the three years in the period ended October 31, 2014, in conformity with accounting principles generally accepted in the United States of America.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of October 31, 2014, based on the criteria established in Internal Control—Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated December 23, 2014 expressed an unqualified opinion on the Company’s internal control over financial reporting.

/s/ Deloitte & Touche LLP

Charlotte, North Carolina

December 23, 2014

47

Consolidated Balance Sheets

October 31, 2014 and 2013

ASSETS

In thousands	2014		2013
Utility Plant:
Utility plant in service	$	5,011,497	$	4,421,937
Less accumulated depreciation	1,166,922		1,088,331
Utility plant in service, net	3,844,575		3,333,606
Construction work in progress	141,693		297,717
Plant held for future use	3,155		3,155
Total utility plant, net	3,989,423		3,634,478
Other Physical Property, at cost (net of accumulated depreciation of $904 in 2014 and $876 in 2013)	355		382
Current Assets:
Cash and cash equivalents	9,643		8,063
Trade accounts receivable (less allowance for doubtful accounts of $2,152 in 2014 and $1,604 in 2013)	65,260		79,210
Income taxes receivable	36,100		31,065
Other receivables	3,361		1,988
Unbilled utility revenues	21,093		24,967
Inventories:
Gas in storage	84,081		73,929
Materials, supplies and merchandise	1,652		1,725
Gas purchase derivative assets, at fair value	4,898		1,834
Regulatory assets	29,088		77,204
Prepayments	39,030		35,038
Deferred income taxes	53,418		12,695
Other current assets	326		338
Total current assets	347,950		348,056
Noncurrent Assets:
Equity method investments in non-utility activities	170,171		128,469
Goodwill	48,852		48,852
Regulatory assets	184,779		169,102
Marketable securities, at fair value	3,727		2,995
Overfunded postretirement asset	33,757		28,258
Other noncurrent assets	5,239		8,017
Total noncurrent assets	446,525		385,693
Total	$	4,784,253	$	4,368,609

See notes to consolidated financial statements.

48

Consolidated Balance Sheets

October 31, 2014 and 2013

CAPITALIZATION AND LIABILITIES

In thousands	2014			2013
Capitalization:
Stockholders’ equity:
Cumulative preferred stock - no par value - 175 shares authorized	$	—		$	—
Common stock – no par value – shares authorized: 200,000; shares outstanding: 78,531 in 2014 and 76,099 in 2013	636,835			561,644
Retained earnings	672,004			627,236
Accumulated other comprehensive loss	(237		)	(284		)
Total stockholders’ equity	1,308,602			1,188,596
Long-term debt	1,424,430			1,174,857
Total capitalization	2,733,032			2,363,453
Current Liabilities:
Current maturities of long-term debt	—			100,000
Short-term debt	355,000			400,000
Trade accounts payable	85,299			96,281
Other accounts payable	54,349			43,855
Accrued interest	27,982			28,205
Customers’ deposits	19,994			19,831
General taxes accrued	23,828			21,454
Regulatory liabilities	46,231			—
Other current liabilities	9,303			7,024
Total current liabilities	621,986			716,650
Noncurrent Liabilities:
Deferred income taxes	809,467			681,369
Unamortized federal investment tax credits	1,193			1,402
Accumulated provision for postretirement benefits	15,471			12,042
Regulatory liabilities	558,598			541,897
Conditional cost of removal obligations	14,647			27,016
Other noncurrent liabilities	29,859			24,780
Total noncurrent liabilities	1,429,235			1,288,506
Commitments and Contingencies (Note 8)
Total	$	4,784,253		$	4,368,609

See notes to consolidated financial statements.

49

Consolidated Statements of Comprehensive Income

For the Years Ended October 31, 2014, 2013 and 2012

In thousands, except per share amounts	2014			2013			2012
Operating Revenues	$	1,469,988		$	1,278,229		$	1,122,780
Cost of Gas	779,780			656,739			547,334
Margin	690,208			621,490			575,446
Operating Expenses:
Operations and maintenance	270,877			253,120			242,599
Depreciation	118,996			112,207			103,192
General taxes	37,294			34,635			34,831
Utility income taxes	83,176			77,334			69,101
Total operating expenses	510,343			477,296			449,723
Operating Income	179,865			144,194			125,723
Other Income (Expense):
Income from equity method investments	32,753			26,056			23,904
Non-operating income	1,842			2,839			1,288
Non-operating expense	(4,331		)	(5,122		)	(1,855		)
Income taxes	(11,642		)	(8,612		)	(9,116		)
Total other income (expense)	18,622			15,161			14,221
Utility Interest Charges:
Interest on long-term debt	61,562			54,158			41,412
Allowance for borrowed funds used during construction	(16,427		)	(30,975		)	(25,211		)
Other	9,551			1,755			3,896
Total utility interest charges	54,686			24,938			20,097
Net Income	143,801			134,417			119,847
Other Comprehensive Income (Loss), net of tax:
Unrealized gain (loss) from hedging activities of equity method investments, net of tax of $225, ($69) and ($530) for the years ended October 31, 2014, 2013 and 2012, respectively	355			(109		)	(826		)
Reclassification adjustment of realized gain (loss) from hedging activities of equity method investments included in net income, net of tax of ($177), $85 and $621 for the years ended October 31, 2014, 2013 and 2012, respectively	(284		)	130			973
Net current period benefit activities of equity method investments, net of tax of ($16) for the year ended October 31, 2014	(24		)
Total other comprehensive income	47			21			147
Comprehensive Income	$	143,848		$	134,438		$	119,994
Average Shares of Common Stock:
Basic	77,883			74,884			71,977
Diluted	78,193			75,333			72,278
Earnings Per Share of Common Stock:
Basic	$	1.85		$	1.80		$	1.67
Diluted	$	1.84		$	1.78		$	1.66

See notes to consolidated financial statements.

50

Consolidated Statements of Cash Flows

For the Years Ended October 31, 2014, 2013 and 2012

In thousands	2014			2013			2012
Cash Flows from Operating Activities:
Net income	$	143,801		$	134,417		$	119,847
Adjustments to reconcile net income to net cash provided by
operating activities:
Depreciation and amortization	129,343			120,797			109,230
Allowance for doubtful accounts	548			25			232
Impairment loss on investment	2,000			—			—
Net gain on sale of property	(817		)	(349		)	—
Income from equity method investments	(32,753		)	(26,056		)	(23,904		)
Distributions of earnings from equity method investments	24,843			22,139			19,590
Deferred income taxes, net	87,136			57,637			99,159
Changes in assets and liabilities:
Gas purchase derivatives, at fair value	(3,064		)	1,319			(381		)
Receivables	16,196			(23,327		)	5,403
Inventories	(10,079		)	(2,059		)	18,897
Settlement of legal asset retirement obligations	(3,575		)	(2,389		)	(2,038		)
Regulatory assets	20,297			43,338			(93,268		)
Other assets	(2,829		)	4,629			(2,314		)
Accounts payable	18			2,381			4,283
Provision for postretirement benefits, net	(2,070		)	(53,515		)	45,507
Regulatory liabilities	49,468			23,429			(2,990		)
Other liabilities	12,149			10,831			7,262
Net cash provided by operating activities	430,612			313,247			304,515
Cash Flows from Investing Activities:
Utility capital expenditures	(460,444		)	(599,999		)	(529,576		)
Allowance for borrowed funds used during construction	(16,427		)	(30,975		)	(25,211		)
Contributions to equity method investments	(37,642		)	(41,348		)	(3,566		)
Distributions of capital from equity method investments	3,929			4,700			5,372
Proceeds from sale of property	1,883			1,951			1,250
Investments in marketable securities	(454		)	(414		)	(606		)
Other	4,708			2,609			3,044
Net cash used in investing activities	(504,447		)	(663,476		)	(549,293		)

51

Consolidated Statements of Cash Flows

For the Years Ended October 31, 2014, 2013 and 2012

In thousands	2014			2013			2012
Cash Flows from Financing Activities:
Borrowings under credit facility	—			10,000			350,000
Repayments under credit facility	—			(10,000		)	(681,000		)
Net (repayments) borrowings - commercial paper	(45,000		)	35,000			365,000
Proceeds from issuance of long-term debt, net of discount	249,565			299,856			300,000
Repayment of long-term debt	(100,000		)	—			—
Expenses related to issuance of debt	(2,871		)	(3,250		)	(3,908		)
Proceeds from issuance of common stock, net of expenses	47,290			92,271			—
Issuance of common stock through dividend reinvestment and
employee stock plans	25,556			24,610			22,123
Repurchases of common stock	—			—			(26,528		)
Dividends paid	(99,151		)	(92,146		)	(85,693		)
Other	26			(8		)	(34		)
Net cash provided by financing activities	75,415			356,333			239,960
Net Increase (Decrease) in Cash and Cash Equivalents	1,580			6,104			(4,818		)
Cash and Cash Equivalents at Beginning of Year	8,063			1,959			6,777
Cash and Cash Equivalents at End of Year	$	9,643		$	8,063		$	1,959
Cash Paid During the Year for:
Interest	$	64,276		$	50,275		$	44,571
Income Taxes:
Income taxes paid	$	10,840		$	5,760		$	4,770
Income taxes refunded	30			169			8,437
Income taxes, net	$	10,810		$	5,591		$	(3,667	)
Noncash Investing and Financing Activities:
Accrued construction expenditures	$	38,869		$	39,389		$	43,643

See notes to consolidated financial statements.

52

Consolidated Statements of Stockholders’ Equity

For the Years Ended October 31, 2014, 2013 and 2012

In thousands, except per share amounts	Common Stock			Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total
Balance, October 31, 2011	$	446,791		$	550,584		$	(452	)	$	996,923
Comprehensive Income:
Net income				119,847						119,847
Other comprehensive income							147			147
Total comprehensive income										119,994
Common Stock Issued	22,198									22,198
Common Stock Repurchased	(26,528		)							(26,528		)
Tax Benefit from Dividends Paid on ESOP Shares				110						110
Dividends Declared ($1.19 per share)				(85,693		)				(85,693		)
Balance, October 31, 2012	442,461			584,848			(305		)	1,027,004
Comprehensive Income:
Net income				134,417						134,417
Other comprehensive income							21			21
Total comprehensive income										134,438
Common Stock Issued	119,552									119,552
Expenses from Issuance of Common Stock	(369		)							(369		)
Tax Benefit from Dividends Paid on ESOP Shares				117						117
Dividends Declared ($1.23 per share)				(92,146		)				(92,146		)
Balance, October 31, 2013	561,644			627,236			(284		)	1,188,596
Comprehensive Income:
Net income				143,801						143,801
Other comprehensive income							47			47
Total comprehensive income										143,848
Common Stock Issued	75,203									75,203
Expenses from Issuance of Common Stock	(12		)							(12		)
Tax Benefit from Dividends Paid on ESOP Shares				118						118
Dividends Declared ($1.27 per share)				(99,151		)				(99,151		)
Balance, October 31, 2014	$	636,835		$	672,004		$	(237	)	$	1,308,602

The components of accumulated other comprehensive income (loss) (OCIL) as of October 31, 2014 and 2013 are as follows.

In thousands	2014			2013
Hedging activities of equity method investments	$	(213	)	$	(284	)
Benefit activities of equity method investments	(24		)

See notes to consolidated financial statements.

53

Notes to Consolidated Financial Statements

1. Summary of Significant Accounting Policies

Nature of Operations and Basis of Consolidation

Piedmont Natural Gas Company, Inc. is an energy services company primarily engaged in the distribution of natural gas to residential, commercial, industrial and power generation customers in portions of North Carolina, South Carolina and Tennessee. We are invested in joint venture, energy-related businesses, including unregulated retail natural gas marketing, regulated interstate natural gas transportation and storage and regulated intrastate natural gas transportation. Our utility operations are regulated by three state regulatory commissions. Unless the context requires otherwise, references to “we,” “us,” “our,” “the Company” or “Piedmont” means consolidated Piedmont Natural Gas Company, Inc. and its subsidiaries. For further information on regulatory matters, see Note 2 to the consolidated financial statements.

The consolidated financial statements reflect the accounts of Piedmont and its wholly-owned subsidiaries whose financial statements are prepared for the same reporting period as Piedmont using consistent accounting policies. Investments in non-utility activities, or joint ventures, are accounted for under the equity method as we do not have controlling voting interests or otherwise exercise control over the management of such companies. Our ownership interest in each entity is recorded in “Equity method investments in non-utility activities” in “Noncurrent Assets” in the Consolidated Balance Sheets at cost plus post-acquisition contributions and earnings based on our share in each of the joint ventures less any distributions received from the joint venture, and if applicable, less any impairment in value of the investment. Earnings or losses from equity method investments are recorded in “Income from equity method investments” in “Other Income (Expense)” in the Consolidated Statements of Comprehensive Income. Revenues and expenses of all other non-utility activities are included in “Non-operating income” in “Other Income (Expense)” in the Consolidated Statements of Comprehensive Income. Inter-company transactions have been eliminated in consolidation where appropriate; however, we have not eliminated inter-company profit on sales to affiliates and costs from affiliates in accordance with accounting regulations prescribed under rate-based regulation. For further information on equity method investments and related party transactions, see Note 12 to the consolidated financial statements.

We monitor significant events occurring after the balance sheet date and prior to the issuance of the financial statements to determine the impacts, if any, of events on the financial statements to be issued. All subsequent events of which we are aware were evaluated. There are no subsequent events that had a material impact on our financial position, results of operations or cash flows. For further information, see Note 15 to the consolidated financial statements.

Use of Estimates

The consolidated financial statements of Piedmont have been prepared in conformity with generally accepted accounting principles in the United States of America (GAAP) and under the rules of the Securities and Exchange Commission (SEC). In accordance with GAAP, we make certain estimates and assumptions regarding reported amounts of assets, liabilities, revenues and expenses and the related disclosures, using historical experience and other assumptions that we believe are reasonable at the time. Our estimates may involve complex situations requiring a high degree of judgment in the application and interpretation of existing literature or in the development of estimates that impact our financial statements. These estimates and assumptions affect the reported amounts of assets and liabilities as of the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from these estimates and assumptions, which are evaluated on a continual basis.

Segment Reporting

Our segments are based on the components of the Company for which we produce separate financial information internally that is used regularly by the chief operating decision maker in deciding how to allocate resources and in assessing performance. Our chief operating decision maker is the executive management team comprised of senior level management. Our segments are identified based on products and services, regulatory environments and our current corporate organization and business decision-making activities. We evaluate the performance of the regulated utility segment based on margin, operations and maintenance (O&M) expenses and operating income. We evaluate the performance of the regulated non-utility activities segment and the unregulated non-utility activities segment based on earnings from and our cash flows in the ventures.

Beginning with the fourth quarter of 2014, we have three reportable business segments, regulated utility, regulated non-utility activities and unregulated non-utility activities. The regulated utility segment is the gas distribution business, where

54

we include the operations of merchandising and its related service work and home service agreements, with activities conducted by the utility. Operations of our regulated non-utility activities segment are comprised of our equity method investments in joint ventures with regulated activities that are held by our wholly-owned subsidiaries. Operations of our unregulated non-utility activities segment are comprised primarily of our equity method investment in a joint venture with unregulated activities that is held by a wholly-owned subsidiary; activities of our other minor subsidiaries are also included. See Note 14 to the consolidated financial statements for further discussion of segments.

Rate-Regulated Basis of Accounting

Our utility operations are subject to regulation with respect to rates, service area, accounting and various other matters by the regulatory commissions in the states in which we operate. The accounting regulations provide that rate-regulated public utilities account for and report assets and liabilities consistent with the economic effect of the manner in which independent third-party regulators establish rates. In applying these regulations, we capitalize certain costs and benefits as regulatory assets and liabilities, respectively, in order to provide for recovery from or refund to utility customers in future periods. Generally, regulatory assets are amortized to expense and regulatory liabilities are amortized to income over the period authorized by our regulators.

Our regulatory assets are recoverable through either base rates or rate riders specifically authorized by a state regulatory commission. Base rates are designed to provide both a recovery of cost and a return on investment during the period the rates are in effect. As such, all of our regulatory assets are subject to review by the respective state regulatory commissions during any future rate proceedings. In the event that accounting for the effects of regulation were no longer applicable, we would recognize a write-off of the regulatory assets and regulatory liabilities that would result in an adjustment to net income or accumulated other comprehensive income (OCI). Our utility operations continue to recover their costs through cost-based rates established by the state regulatory commissions. As a result, we believe that the accounting prescribed under rate-based regulation remains appropriate. It is our opinion that all regulatory assets are recoverable in current rates or in future rate proceedings.

55

Regulatory assets and liabilities in the Consolidated Balance Sheets as of October 31, 2014 and 2013 are as follows.

In thousands	2014		2013
Regulatory Assets:
Current:
Unamortized debt expense	$	1,490	$	1,274
Amounts due from customers	16,108		66,321
Environmental costs	1,568		1,480
Deferred operations and maintenance expenses	916		739
Deferred pipeline integrity expenses	3,470		3,149
Deferred pension and other retirement benefits costs	2,769		2,768
Robeson liquefied natural gas (LNG) development costs	917		382
Other	1,850		1,091
Total current	29,088		77,204
Noncurrent:
Unamortized debt expense	15,402		14,149
Environmental costs	6,470		7,936
Deferred operations and maintenance expenses	4,721		5,637
Deferred pipeline integrity expenses	24,694		16,300
Deferred pension and other retirement benefits costs	18,799		17,968
Amounts not yet recognized as a component of pension and other retirement benefit costs	94,265		80,604
Regulatory cost of removal asset	18,275		22,974
Robeson LNG development costs	509		1,426
Other	1,644		2,108
Total noncurrent	184,779		169,102
Total	$	213,867	$	246,306

Regulatory Liabilities:
Current:
Amounts due to customers	$	46,231	$	—
Noncurrent:
Regulatory cost of removal obligations	506,574		493,111
Deferred income taxes	51,930		48,647
Amounts not yet recognized as a component of pension and other retirement costs	94		139
Total noncurrent	558,598		541,897
Total	$	604,829	$	541,897

As of October 31, 2014, we have $18.3 million of asset retirement obligations (AROs) and $98.1 million of other regulatory assets on which we do not earn a return. Included in deferred pension and other retirement costs are amounts related to pension funding for our Tennessee jurisdiction. The recovery of these amounts is authorized by the Tennessee Regulatory Authority (TRA) on a deferred cash basis.

56

Utility Plant and Depreciation

Utility plant is stated at original cost, including direct labor and materials, contractor costs, allocable overhead charges, such as engineering, supervision, corporate office salaries and expenses, pensions and insurance, and an allowance for funds used during construction (AFUDC) that is calculated under a formula prescribed by our state regulators. We apply the group method of accounting, where the costs of homogeneous assets are aggregated and depreciated by applying a rate based on the average expected useful life of the assets. Major expenditures that last longer than a year and improve or lengthen the expected useful life of the overall property from original expectations that are recoverable in regulatory rate base are capitalized while expenditures not meeting these criteria are expensed as incurred. The costs of property retired or otherwise disposed of are removed from utility plant and charged to accumulated depreciation for recovery or refund through future rates. On certain assets, like land, that are nondepreciable, we record a gain or loss upon the disposal of the property that is recorded in “Non-operating income” in “Other Income (Expense)” in the Consolidated Statements of Comprehensive Income.

The classification of total utility plant, net, for the years ended October 31, 2014 and 2013 is presented below.

In thousands	2014			2013
Intangible plant	$	3,374		$	3,374
Other storage plant	180,058			171,349
Transmission plant	1,787,990			1,403,829
Distribution plant	2,623,560			2,505,160
General plant	421,763			335,847
Asset retirement cost	11			7,565
Contributions in aid of construction	(5,259		)	(5,187		)
Total utility plant in service	5,011,497			4,421,937
Less accumulated depreciation	(1,166,922		)	(1,088,331		)
Total utility plant in service, net	3,844,575			3,333,606
Construction work in progress	141,693			297,717
Plant held for future use	3,155			3,155
Total utility plant, net	$	3,989,423		$	3,634,478

Contributions in aid of construction represent nonrefundable donations or contributions received from third-parties for partial or full reimbursement for construction expenditures for utility plant in service.

AFUDC represents the estimated costs of funds from both debt and equity sources used to finance the construction of major projects and is capitalized for ratemaking purposes when the completed projects are placed in service. The portion of AFUDC attributable to borrowed funds is shown as a reduction of “Utility Interest Charges” in the Consolidated Statements of Comprehensive Income. Any portion of AFUDC attributable to equity funds would be included in “Other Income (Expense)” in the Consolidated Statements of Comprehensive Income. For the three years ended October 31, 2014, 2013 and 2012, all of our AFUDC was attributable to borrowed funds.

AFUDC for the years ended October 31, 2014, 2013 and 2012 is presented below.

In thousands	2014		2013		2012
AFUDC	$	16,427	$	30,975	$	25,211

In accordance with utility accounting practice, we classified real estate and development costs associated with a LNG peak storage facility in the eastern part of North Carolina as “Plant held for future use” in the Consolidated Balance Sheets, due to construction being suspended in March 2009. As of 2012, approximately $3.2 million of the “Plant held for future use” related to land costs and approximately $3.5 million related to non-real estate costs. In May 2013, we filed a general rate application with the North Carolina Utilities Commission (NCUC) requesting rate recovery of the non-real estate costs. Under the settlement of the 2013 North Carolina general rate proceeding approved by the NCUC in December 2013, we agreed to the amortization and collection of $1.2 million of non-real estate costs that is recorded as a regulatory asset to be amortized over 38 months beginning January 1, 2014 through February 2017. Under the settlement of our June 2014 rate stabilization adjustment (RSA) filing with the Public Service Commission of South Carolina (PSCSC) that was approved in October 2014, we agreed to the amortization and collection of $.5 million of non-real estate costs that is recorded as a regulatory asset to be amortized over 12 months beginning November 1, 2014. We recorded cumulative amortization of $1.8 million of non-real

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estate costs in fiscal year 2013 that is included in the Consolidated Statements of Comprehensive Income in “Other Income (Expense)” in “Non-operating expense.” For further information on the 2013 general rate proceeding settlement of these costs for North Carolina or the 2014 RSA filing for South Carolina, see Note 2 to the consolidated financial statements.

We compute depreciation expense using the straight-line method over periods ranging from 5 to 80 years. The composite weighted-average depreciation rates were 2.54% for 2014, 2.77% for 2013 and 2.94% for 2012.

Depreciation rates for utility plant are approved by our regulatory commissions. In North Carolina, we are required to conduct a depreciation study every five years and file the results with the regulatory commission. No such five-year requirement exists in South Carolina or Tennessee; however, we periodically propose revised rates in those states based on depreciation studies. Our last system-wide depreciation study based on fiscal year 2009 data was completed in 2011 and filed with the appropriate regulatory commission in all jurisdictions. New depreciation rates were approved effective November 1, 2011 for South Carolina, March 1, 2012 for Tennessee and January 1, 2014 for North Carolina.

As authorized by our regulatory commissions, the estimated costs of removal on certain regulated properties are collected through depreciation expense through rates with a corresponding credit to accumulated depreciation. Our approved depreciation rates are comprised of two components, one based on average service life and one based on cost of removal for certain regulated properties. Therefore, through depreciation expense, we collect and record estimated non-legal costs of removal on any depreciable asset that includes cost of removal in its depreciation rate. Because the estimated removal costs are a non-legal obligation, we account for them as a regulatory liability and present the accumulated removal costs in “Regulatory Liabilities” in “Rate-Regulated Basis of Accounting” in this Note 1. For further discussion of this regulatory liability, see “Asset Retirement Obligations” in this Note 1.

Cash and Cash Equivalents

We consider instruments purchased with an original maturity at date of purchase of three months or less to be cash equivalents, particularly affecting the Consolidated Statements of Cash Flows. We have no restrictions on our cash balances that would impact the payment of dividends as of October 31, 2014 and 2013.

Trade Accounts Receivable and Allowance for Doubtful Accounts

Trade accounts receivable consist of natural gas sales and transportation services, merchandise sales and service work. We bill customers monthly with payment due within 30 days. We maintain an allowance for doubtful accounts, which we adjust periodically, based on the aging of receivables and our historical and projected charge-off activity. Our estimate of recoverability could differ from actual experience based on customer credit issues, the level of natural gas prices and general economic conditions. We write off our customers’ accounts when they are deemed to be uncollectible. Pursuant to orders issued by the NCUC, the PSCSC and the TRA, we are authorized to recover all uncollected gas costs through the purchased gas adjustment (PGA). As a result, only the portion of accounts written off relating to the non-gas costs, or margin, is included in base rates and, accordingly, only this portion is included in the provision for uncollectibles expense. Non-regulated merchandise and service work receivables due beyond one year are included in “Other noncurrent assets” in “Noncurrent Assets” in the Consolidated Balance Sheets.

We are exposed to credit risk when we enter into contracts with third parties to buy and sell natural gas. We also enter into short-term contracts with third parties to manage some of our supply and capacity assets for the purpose of maximizing their value. Our policy requires counterparties to have an investment-grade credit rating at the time of the contract. In situations where counterparties do not have investment grade or functionally equivalent credit ratings, our policy requires credit enhancements that include letters of credit or parental guaranties. In either circumstance, the policy specifies limits on the contract amount and duration based on the counterparty’s credit rating and/or credit support. In order to minimize our exposure, we continually re-evaluate third-party credit worthiness and market conditions and modify our requirements accordingly.

Our principal business activity is the distribution of natural gas. We believe that we have provided an adequate allowance for any receivables which may not be ultimately collected. As of October 31, 2014 and 2013, our trade accounts receivable consisted of the following.

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In thousands	2014			2013
Gas receivables	$	64,400		$	78,540
Non-regulated merchandise and service work receivables	3,012			2,274
Allowance for doubtful accounts	(2,152		)	(1,604		)
Trade accounts receivable	$	65,260		$	79,210

A reconciliation of the changes in the allowance for doubtful accounts for the years ended October 31, 2014, 2013 and 2012 is presented below.

In thousands	2014			2013			2012
Balance at beginning of year	$	1,604		$	1,579		$	1,347
Additions charged to uncollectibles expense	6,959			5,314			4,584
Accounts written off, net of recoveries	(6,411		)	(5,289		)	(4,352		)
Balance at end of year	$	2,152		$	1,604		$	1,579

Inventories

We maintain gas inventories on the basis of average cost. Injections into storage are priced at the purchase cost at the time of injection, and withdrawals from storage are priced at the weighted average purchase price in storage. The cost of gas in storage is recoverable under rate schedules approved by state regulatory commissions. Inventory activity is subject to regulatory review on an annual basis in gas cost recovery proceedings.

We enter into service contracts, or asset management arrangements (AMAs), with counterparties to efficiently manage portions of our gas supply, transportation capacity and storage capacity to serve our customers. These AMAs are structured in compliance with Federal Energy Regulatory Commission (FERC) Order 712. Generally, under an AMA, we receive a fixed monthly payment which is set at inception of the arrangement, and in return, we may assign the gas supply and/or storage inventory and release the transportation capacity and storage capacity to the asset manager for the term of the agreement. The inventory is assigned at no cost, and the same quantities are required to be returned at the expiration of the agreements. One agreement allows us to call on inventory during the summer months to satisfy operational requirements, if needed. The inventory that is assigned to the asset manager is available for our use during the winter heating season, November through March. We account for these amounts on the Consolidated Balance Sheets as a current asset in the inventories section as “Gas in storage.” From the period of April through October, the inventory that is not available for our use is reclassified on the Consolidated Balance Sheets as a current asset in “Prepayments,” and the inventory that is available for our use remains in “Gas in storage.”

At October 31, 2014 and 2013, such counterparties held natural gas storage assets as recorded in “Prepayments,” with a value of $35 million and $31.5 million, respectively, through such asset management relationships. Under the terms of the agreements, we receive asset management fees, which are recorded as secondary market transactions and shared between our utility customers and our shareholders. The AMAs expire at various times through March 31, 2017. For further information on the revenue sharing of secondary market transactions, see Note 2 to the consolidated financial statements.

Materials, supplies and merchandise inventories are valued at the lower of average cost or market and removed from such inventory at average cost.

Fair Value Measurements

We have financial and nonfinancial assets and liabilities subject to fair value measurement. The financial assets and liabilities measured and carried at fair value in the Consolidated Balance Sheets are cash and cash equivalents, marketable securities held in rabbi trusts established for our deferred compensation plans and derivative assets and liabilities, if any, that are held for our utility operations. The carrying values of receivables, short-term debt, accounts payable, accrued interest and other current assets and liabilities approximate fair value as all amounts reported are to be collected or paid within one year. Our nonfinancial assets and liabilities include our qualified pension and postretirement plan assets and liabilities that are recorded at fair value in the Consolidated Balance Sheets in accordance with employers’ accounting and related disclosures of postretirement plans.

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Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date, or exit date. We utilize market data or assumptions that market participants would use in valuing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. We primarily apply the market approach for fair value measurements and endeavor to utilize the best available information. Accordingly, we use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The fair value of our financial assets and liabilities are subject to potentially significant volatility based on changes in market prices, the portfolio valuation of our contracts, as well as the maturity and settlement of those contracts, and subsequent newly originated transactions, each of which directly affects the estimated fair value of our financial instruments. We are able to classify fair value balances based on the observance of those inputs at the lowest level that is significant to the fair value measurement, in its entirety, in the following fair value hierarchy levels as set forth in the fair value guidance.

Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities as of the reporting date. Active markets have sufficient frequency and volume to provide pricing information for the asset or liability on an ongoing basis. Our Level 1 items consist of financial instruments of exchange-traded derivatives, investments in marketable securities and benefit plan assets held in registered investment companies and individual stocks.

Level 2 inputs are inputs other than quoted prices in active markets included in Level 1 and are either directly or indirectly corroborated or observable as of the reporting date, generally using valuation methodologies. These methodologies are primarily industry-standard methodologies that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. We obtain market price data from multiple sources in order to value some of our Level 2 transactions and this data is representative of transactions that occurred in the marketplace. Our Level 2 items include non-exchange-traded derivative instruments, such as some qualified pension plan assets held in hedge fund of funds, commodities fund of funds, common trust funds, collateralized mortgage obligations, swaps, futures, currency forwards, corporate bonds and government and agency obligations that are valued at the closing price reported in the active market for similar assets in which the individual securities are traded or based on yields currently available on comparable securities of issuers with similar credit ratings or based on the most recent available financial information for the respective funds and securities. For some qualified pension plan assets, the determination of Level 2 assets was completed through a process of reviewing each individual security while consulting research and other metrics provided by investment managers, including a pricing matrix detailing the pricing source and security type, annual audited financial statements and a review of valuation policies and procedures used by the investment managers as well as our investment advisor.

Level 3 inputs include significant pricing inputs that are generally less observable from objective sources and may be used with internally developed methodologies that result in management’s best estimate of fair value. Our Level 3 inputs include cost estimates for removal (contract fees or manpower/equipment estimates), inflation factors, risk premiums, the remaining life of long-lived assets, the credit adjusted risk free rate to discount for the time value of money over an appropriate time span, and the most recent available financial information of an investment in a diversified private equity fund of funds for some of our qualified pension plan assets. We do not have any other assets or liabilities classified as Level 3.

In determining whether to categorize the fair value measurement of an instrument as Level 2 or Level 3, we must use judgment to assess whether we have the ability as of the measurement date to redeem an investment at its net asset value per share (NAV) in the near term. We consider when we might have the ability to redeem the investment by reviewing contractual restrictions in effect as of the investment date as well as any potential restrictions that the investee may impose. Regarding our benefit plans’ investments, “near term” is the ability to redeem an investment in no more than 180 days.

Transfers between different levels of the fair value hierarchy may occur based on the level of observable inputs used to value the instruments for the period. These transfers represent existing assets or liabilities previously categorized as Level 1 or Level 2 for which the inputs to the estimate became less observable or assets and liabilities previously classified as Level 2 or Level 3 for which the lowest significant input became more observable during the period. Transfers into and out of each level are measured at the actual date of the event or change in circumstances causing the transfer.

For the fair value measurements of our derivatives and marketable securities, see Note 7 to the consolidated financial statements. For the fair value measurements of our benefit plan assets, see Note 9 to the consolidated financial statements.

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Goodwill, Equity Method Investments and Long-Lived Assets

Goodwill is the excess of the purchase price over the fair value of identifiable net assets acquired in a business combination. We annually evaluate goodwill for impairment as of October 31, or more frequently if impairment indicators arise during the year. These indicators include, but are not limited to, a significant change in operating performance, the business climate, legal or regulatory factors, or a planned sale or disposition of a significant portion of the business. We test goodwill using a fair value approach at a reporting unit level, generally equivalent to our operating segments as discussed in Note 14 to the consolidated financial statements. An impairment charge would be recognized if the carrying value of the reporting unit, including goodwill, exceeded its fair value. All of our goodwill is attributable to the regulated utility segment.

Our annual goodwill impairment assessment was performed as of October 31, 2014, and we determined that there was no impairment to the carrying value of our goodwill. No impairment was recognized during the years ended October 31, 2014, 2013 and 2012. The fair value of our regulated utility reporting unit substantially exceeds the carrying value, including goodwill.

We review our equity method investments and long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable. In April 2014, we recorded a $2 million write-off for an investment that was accounted for on the cost basis. The write-off was recorded to "Non-operating expense" in the Consolidated Statements of Comprehensive Income. There were no events or circumstances during the years ended October 31, 2013 and 2012 that resulted in any impairment charges. For further information on equity method investments, see Note 12 to the consolidated financial statements.

Marketable Securities

We have marketable securities that are invested in money market and mutual funds that are liquid and actively traded on the exchanges. These securities are assets that are held in rabbi trusts established for our deferred compensation plans. For further information on the deferred compensation plans, see Note 9 to the consolidated financial statements.

We have classified these marketable securities as trading securities since their inception as the assets are held in rabbi trusts. Trading securities are recorded at fair value on the Consolidated Balance Sheets with any gains or losses recognized currently in earnings. We do not intend to engage in active trading of the securities, and participants in the deferred compensation plans may redirect their deemed investments at any time. We have matched the current portion of the deferred compensation liability with the current asset and noncurrent deferred compensation liability with the noncurrent asset; the current portion has been included in “Other current assets” in “Current Assets” in the Consolidated Balance Sheets.

The money market investments in the trusts approximate fair value due to the short period of time to maturity. The fair values of the equity securities are based on quoted market prices as traded on the exchanges. The composition of these securities as of October 31, 2014 and 2013 is as follows.

	2014				2013
In thousands	Cost		Fair Value		Cost		Fair Value
Current trading securities:
Money markets	$	22	$	22	$	—	$	—
Mutual funds	106		192		134		199
Total current trading securities	128		214		134		199
Noncurrent trading securities:
Money markets	447		447		380		380
Mutual funds	2,598		3,280		1,995		2,615
Total noncurrent trading securities	3,045		3,727		2,375		2,995
Total trading securities	$	3,173	$	3,941	$	2,509	$	3,194

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Unamortized Debt Expense

Unamortized debt expense consists of costs, such as underwriting and broker dealer fees, discounts and commissions, legal fees, accountant fees, registration fees and rating agency fees, related to issuing long-term debt and the short-term syndicated revolving credit facility. We amortize long-term debt expense on a straight-line basis, which approximates the effective interest method, over the life of the related debt with lives ranging from 5 to 30 years. We amortize bank debt expense over the life of the syndicated revolving credit facility, which is five years.

Should we reacquire long-term debt prior to its term date and simultaneously issue new debt, we defer the gain or loss resulting from the transaction, essentially the remaining unamortized debt expense, and amortize it over the life of the new debt in accordance with established regulatory practice. Where the refunding of the debt is not simultaneous, we defer the gain or loss resulting from the reacquisition of the debt and amortize it over the remaining life of the redeemed debt in accordance with established regulatory practice. For income tax purposes, any gain or loss would be recognized as incurred.

Issuances and Repurchases of Common Stock

As discussed in Note 6 to the consolidated financial statements, from time to time we may repurchase shares on the open market and such shares are then canceled and become authorized but unissued shares. It is our policy to issue new shares for share-based employee awards and shareholder and employee investment plans. We present net shares issued under these awards and plans in “Common Stock Issued” in the Consolidated Statements of Stockholders’ Equity. Shares withheld by us to satisfy tax withholding obligations related to the vesting of shares awarded under the Incentive Compensation Plan have been immaterial to date.

Asset Retirement Obligations

The accounting guidance for AROs addresses the financial accounting and reporting for AROs associated with the retirement of long-lived assets that result from the acquisition, construction, development and operation of the assets. The accounting guidance requires the recognition of the fair value of a liability for AROs in the period in which the liability is incurred if a reasonable estimate of fair value can be made. We have determined that conditional AROs exist for our underground mains and services.

We have costs of removal that are non-legal obligations as defined by the accounting guidance. The costs of removal are a component of our depreciation rates in accordance with long-standing regulatory treatment. Because these estimated removal costs meet the requirements of rate-regulated accounting guidance, we have accounted for these non-legal AROs in “Regulatory Liabilities” as presented in “Rate-Regulated Basis of Accounting” in this Note 1. In the rate setting process, the liability for non-legal costs of removal is treated as a reduction to the net rate base upon which the regulated utility has the opportunity to earn its allowed rate of return. For further discussion of these costs of removal as a component of depreciation, see “Utility Plant and Depreciation” in this Note 1.

We apply the accounting guidance for conditional AROs that requires recognition of a liability for the fair value of conditional AROs when incurred if the liability can be reasonably estimated. The NCUC, the PSCSC and the TRA have approved placing these ARO costs in deferred accounts to preserve the regulatory treatment of these costs; therefore, accretion is not reflected in the Consolidated Statements of Comprehensive Income as the regulatory treatment provides for deferral of the accretion as a regulatory asset with a corresponding deferral of the accretion recorded as a regulatory liability. AROs are capitalized concurrently by increasing the carrying amount of the related asset by the same amount as the regulatory liability. In periods subsequent to the initial measurement, any changes in the liability resulting from the passage of time (accretion) or due to the revisions of either timing or the amount of the originally estimated cash flows to settle conditional AROs must be recognized. The estimated cash flows to settle conditional AROs are discounted using the credit adjusted risk-free rate, which ranged from 4.40% to 5.15% with a weighted average of 5.09% for the twelve months ended October 31, 2014. The estimate was calculated using a time value weighted average credit adjusted risk-free rate. We have recorded a liability on our distribution and transmission mains and services.

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The cost of removal obligations recorded in the Consolidated Balance Sheets as of October 31, 2014 and 2013 are presented below.

In thousands	2014		2013
Regulatory non-legal AROs	$	506,574	$	493,111
Conditional AROs	14,647		27,016
Total cost of removal obligations	$	521,221	$	520,127

A reconciliation of the changes in conditional AROs for the year ended October 31, 2014 and 2013 is presented below.

In thousands	2014			2013
Beginning of period	$	27,016		$	28,629
Liabilities incurred during the period	2,108			2,052
Liabilities settled during the period	(3,576		)	(2,389		)
Accretion	1,548			1,641
Adjustment to estimated cash flows	(12,449		)	(2,917		)
End of period	$	14,647		$	27,016

Revenue Recognition

We record revenues when services are provided to our distribution service customers. Utility sales and transportation revenues are based on rates approved by state regulatory commissions. Base rates charged to jurisdictional customers may not be changed without approval by the regulatory commission in that jurisdiction; however, the wholesale cost of gas component of rates may be adjusted periodically under PGA provisions. In North Carolina, a margin decoupling mechanism provides for the recovery of our approved margin from residential and commercial customers on an annual basis independent of weather and consumption patterns. The margin decoupling mechanism provides for semi-annual rate adjustments to refund any over-collection of margin or to recover any under-collection of margin. In South Carolina, a RSA tariff mechanism achieves the objectives of margin decoupling for residential and commercial customers with a one year lag. Under the RSA tariff mechanism, we reset our rates in South Carolina based on updated costs and revenues on an annual basis. In South Carolina and Tennessee, a weather normalization adjustment (WNA) is calculated for residential and commercial customers during the winter heating season November through March, and in Tennessee, the months of April and October. The WNA mechanisms are designed to partially offset the impact that warmer-than-normal or colder-than-normal weather has on customer billings during the winter heating season. The WNA formulas do not ensure full recovery of approved margin during periods when customer consumption patterns vary from those used to establish the WNA factors. In all states, the gas cost portion of our costs is recoverable through PGA procedures and is not affected by the margin decoupling mechanism or the WNA mechanism.

We have integrity management riders (IMRs) in our tariffs in North Carolina, effective February 1, 2014, and in Tennessee effective January 1, 2014, related to our ongoing system integrity programs. These IMRs provide for rate adjustments to allow us to recover and earn on those investments without the necessity of filing general rate cases. The North Carolina IMR was approved in December 2013 in the settlement of our 2013 general rate case. Under the North Carolina IMR tariff, we will make annual filings by November 30 of each year for costs closed to plant through October with revised rates effective the following February 1. The Tennessee IMR tariff was approved in December 2013 with the settlement of our August 2013 IMR filing. Under the Tennessee IMR, we will file to adjust rates to be effective each January 1 based on capital expenditures related to mandated safety and integrity programs that were incurred by the previous October 31. For further discussion of the IMRs, see Note 2 to the consolidated financial statements.

Revenues are recognized monthly on the accrual basis, which includes estimated amounts for gas delivered to customers but not yet billed under the cycle-billing method from the last meter reading date to month end. The unbilled revenue estimate reflects factors requiring judgment related to estimated usage by customer class, customer mix, changes in weather during the period and the impact of the WNA or margin decoupling mechanisms, as applicable.

Secondary market revenues associated with the commodity are recognized when the physical sales are delivered based on contract or market prices. Asset management fees for storage and transportation remitted on a monthly basis are recognized as earned given the monthly capacity costs associated with the contracts involved. Asset management fees remitted

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in a lump sum are deferred and amortized ratably into income over the period in which they are earned, which is typically the contract term. See Note 2 to the consolidated financial statements regarding revenue sharing of secondary market transactions.

Utility sales, transportation and secondary market revenues are reported net of excise taxes, sales taxes and franchise fees. For further information regarding taxes, see “Taxes” in this Note 1.

Non-regulated merchandise and service work includes the sale, installation and/or maintenance of natural gas appliances and gas piping beyond the meter. Revenue is recognized when the sale is made or the work is performed. If the customer is eligible for and elects financing through us, the finance fee income is recognized on a monthly basis based on principal, rate and term.

Cost of Gas and Deferred Purchased Gas Adjustments

We charge our utility customers for natural gas consumed using natural gas cost recovery mechanisms as set by the regulatory commissions in states in which we operate. Rate schedules for utility sales and transportation customers include PGA provisions that provide for the recovery of prudently incurred gas costs. With regulatory commission approval, we revise rates periodically without formal rate proceedings to reflect changes in the wholesale cost of gas. We charge our secondary market customers for natural gas based on negotiated contract terms. Under PGA provisions, charges to cost of gas are based on the amount recoverable under approved rate schedules. Within our cost of gas, we include amounts for lost and unaccounted for gas and adjustments to reflect the gains and losses associated with gas price hedging derivatives. By jurisdiction, differences between gas costs incurred and gas costs billed to customers, such that no operating margin is recognized related to these costs, are deferred and included in “Amounts due from customers” in “Regulatory Assets” or “Amounts due to customers” in “Regulatory Liabilities” as presented in “Rate-Regulated Basis of Accounting” in this Note 1. We review gas costs and deferral activity periodically (including deferrals under the margin decoupling and WNA mechanisms) and, with regulatory commission approval, increase rates to collect under-recoveries or decrease rates to refund over-recoveries over a subsequent period.

Taxes

We have two categories of income taxes in the Consolidated Statements of Comprehensive Income: current and deferred. Current income tax expense consists of federal and state income taxes less applicable tax credits related to the current year. Deferred income tax expense generally is equal to the changes in the deferred income tax liability and regulatory tax liability during the year. Deferred taxes are primarily attributable to utility plant, deferred gas costs, revenues and cost of gas, equity method investments, benefit of loss carryforwards and employee benefits and compensation. The determination of our provision for income taxes requires judgment, the use of estimates, and the interpretation and application of complex tax laws. Judgment is required in assessing the timing and amounts of deductible and taxable items.

Deferred income taxes are determined based on the estimated future tax effects of differences between the book and tax basis of assets and liabilities. We have provided valuation allowances to reduce the carrying amount of deferred tax assets to amounts that are more likely than not to be realized. To the extent that the establishment of deferred income taxes is different from the recovery of taxes through the ratemaking process, the differences are deferred in accordance with rate-regulated accounting provisions, and a regulatory asset or liability is recognized for the impact of tax expenses or benefits that will be collected from or refunded to customers in different periods pursuant to rate orders.

Deferred investment tax credits, including energy credits, associated with our utility operations are presented in the Consolidated Balance Sheets. We amortize these deferred investment and energy tax credits to income over the estimated useful lives of the property to which the credits relate.

We recognize accrued interest and penalties, if any, related to uncertain tax positions as operating expenses in the Consolidated Statements of Comprehensive Income. This is consistent with the recognition of these items in prior reporting periods.

Excise taxes, sales taxes and franchises fees separately stated on customer bills are recorded on a net basis as liabilities payable to the applicable jurisdictions. All other taxes other than income taxes are recorded as general taxes. General taxes consist of property taxes, payroll taxes, Tennessee gross receipt taxes, franchise taxes, tax on company use and other miscellaneous taxes.

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Consolidated Statements of Cash Flows

With respect to cash overdrafts, book overdrafts are included within operating cash flows while any bank overdrafts are included with financing cash flows.

Recently Issued Accounting Guidance

In July 2013, the Financial Accounting Standards Board (FASB) issued accounting guidance on presenting an unrecognized tax benefit when net operating loss (NOL) carryforwards exist. The guidance was issued in an effort to eliminate diversity in practice resulting from a lack of guidance on this topic in current US GAAP. The update provides that an unrecognized tax benefit, or a portion of an unrecognized tax benefit, should be presented in the financial statements as a reduction to a deferred tax asset for a NOL carryforward, a similar tax loss, or a tax credit carryforward, except under certain circumstances outlined in the update. The amendments in the update are effective for annual periods, and interim periods within those periods, beginning after December 15, 2013, with early adoption permitted. The adoption of this disclosure guidance will have no impact on our financial position, results of operations or cash flows.

In May 2014, the FASB and the International Accounting Standards Board issued converged accounting guidance on the recognition of revenue from contracts with customers. Under the new standard, entities will recognize revenue to depict the transfer of goods and services to customers in amounts that reflect the payment to which the entity expects to be entitled in exchange for those goods or services. The disclosure requirements will provide information about the nature, amount, timing and uncertainty of revenue and cash flows from an entity’s contracts with customers. The new guidance is effective for annual periods beginning after December 15, 2016, and interim periods within those periods, which for us is our fiscal year 2018.

An accounting utility subgroup has identified five issues (scope for cost-of-service-tariff sales, contract modifications, variable consideration, multiple element arrangements and sales of real estate) that are not clear within the standard and require revenue implementation guidance. The revenue implementation guide is expected to be published prior to the standard becoming effective in 2017; however, no date has been set.

We are currently evaluating the effect on our financial position, results of operations and cash flows. The evaluation includes identifying revenues streams by like contracts to allow for ease of implementation once the utility sub-group has issued the revenue implementation guide.

In June 2014, the FASB amended accounting guidance to eliminate certain financial reporting requirements for development stage entities, including an amendment to variable interest entity (VIE) guidance. The modification to the guidance may change the consolidation analysis, consolidation decision and disclosure requirements for a reporting entity that has an interest in an entity in the development stage. The amendments in the update are effective for annual periods, and interim periods within those periods, beginning after December 15, 2015, with early adoption permitted. We will consider this guidance regarding our current joint venture investments where the investment infrastructure is under development and any future investments that are development stage projects, particularly any disclosures about risks and uncertainties of the development of the project and our equity method investment.

In August 2014, the FASB issued accounting guidance on determining when and how reporting entities must disclose going concern uncertainties in their financial statements. The new standard requires management to perform interim and annual assessments of an entity's ability to continue as a going concern within one year of the date of issuance of the entity's financial statements. An entity must provide certain disclosures if there is a "substantial doubt about the entity's ability to continue as a going concern." The standard is effective for annual periods ending after December 15, 2016, and interim periods thereafter; early adoption is permitted. The adoption of this assessment will have no impact on our financial position, results of operations or cash flows.

Reclassifications and Changes in Presentation

Reclassifications have been made to certain prior year financial statements to conform with the current year presentation. Within “Cash Flows From Operating Activities” in the Consolidated Statements of Cash Flows, we have changed the presentation of cash flows from regulatory assets and liabilities, previously included within the line items “Other assets” and “Other liabilities,” respectively, to provide additional detail and to present such information within separate line items, “Regulatory assets” and “Regulatory liabilities.”  The 2013 and 2012 presentation has been changed to conform to the current year presentation. The reclassifications had no effect on previously reported amounts for net cash flows from operating, investing or financing activities.

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2. Regulatory Matters

Our utility operations are regulated by the NCUC, PSCSC and TRA as to rates, service area, adequacy of service, safety standards, extensions and abandonment of facilities, accounting and depreciation. We are also regulated by the NCUC as to the issuance of long-term debt and equity securities.

The NCUC and the PSCSC regulate our gas purchasing practices under a standard of prudence and audit our gas cost accounting practices. The TRA regulates our gas purchasing practices under a gas supply incentive program which compares our actual costs to market pricing benchmarks. As part of this jurisdictional oversight, all three regulatory commissions address our gas supply hedging activities. Additionally, all three regulatory commissions allow for recovery of uncollectible gas costs through the PGA. The portion of uncollectibles related to gas costs is recovered through the deferred account and only the non-gas costs, or margin, portion of uncollectibles is included in base rates and uncollectibles expense.

North Carolina

The North Carolina General Assembly enacted the Clean Water and Natural Gas Critical Needs Act of 1998 which provided for the issuance of $200 million of general obligation bonds of the state for the purpose of providing grants, loans or other financing for the cost of constructing natural gas facilities in unserved areas of North Carolina. In 2000, the NCUC issued an order awarding Eastern North Carolina Natural Gas Company (EasternNC) an exclusive franchise to provide natural gas service to 14 counties in the eastern-most part of North Carolina that had not been able to obtain gas service because of the relatively small population of those counties and the resulting economic infeasibility of providing service and granted $38.7 million in state bond funding. In 2001, the NCUC issued an order granting EasternNC an additional $149.6 million, for a total of $188.3 million. With the 2003 acquisition and subsequent merger of EasternNC into our regulated utility segment, we are required to provide an accounting of the operational feasibility of this area to the NCUC every two years. Should this operational area become economically feasible and generate a profit, which we believe is unlikely, we would begin to repay the state bond funding.

The NCUC had allowed EasternNC to defer its O&M expenses during the first eight years of operation or until the first rate case order, whichever occurred first, with the deferred amounts accruing interest per annum. In December 2003, the NCUC confirmed that these deferred expenses should be treated as a regulatory asset for future recovery from customers to the extent they are deemed prudent and proper. Under the settlement of the 2008 general rate proceeding, the unamortized balance of the EasternNC deferred O&M expenses of $9 million at October 31, 2008 was to be amortized over a twelve year period beginning November 1, 2008, with interest accruing at 7.84% per annum. Under the settlement of the 2013 general rate proceeding discussed below, the unamortized balance of the EasternNC deferred O&M expenses was $6.3 million as of December 31, 2013. This balance is accruing interest at a rate of 6.55% per annum with amortization beginning January 1, 2014over an 82-month period ending October 31, 2020. As of October 31, 2014 and 2013, we had unamortized balances, including accrued interest, of $5.6 million and $6.4 million, respectively.

We incur certain pipeline integrity management costs in compliance with the Pipeline Safety Improvement Act of 1992 and certain regulations of the United States Department of Transportation. The NCUC approved deferral treatment of the O&M costs applicable to certain incremental pipeline integrity external expenditures beginning November 1, 2004. The approved balance for recovery of actual pipeline integrity management O&M costs incurred between July 1, 2008 through August 31, 2013 as established in the settlement of the 2013 general rate proceeding discussed below was $17.3 million to be amortized over a five-year period from January 1, 2014 through December 31, 2018. As of October 31, 2014 and 2013, we had unamortized regulatory asset balances for deferred pipeline integrity expenses of $28.2 million and $19.4 million, respectively. The existing regulatory asset treatment for ongoing pipeline integrity management costs will continue until another recovery mechanism is established in a future rate proceeding.

With the approval of the settlement of the 2013 NCUC general rate proceeding discussed below, future capital expenditures that are incurred to comply with federal pipeline safety and integrity requirements will be separately tracked and recovered on an annual basis through an IMR. The settlement also approved recovery of $6.3 million of deferred North Carolina environmental costs over a five-year period from January 2014 through December 2018.

In North Carolina, our recovery of gas costs is subject to annual gas cost proceedings to determine the prudence of our gas purchases. Our gas costs have never been disallowed on the basis of prudence.

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In January 2012, the NCUC approved our accounting of gas costs for the twelve months ended May 31, 2011, with adjustments agreed to by us as a result of the NCUC Public Staff’s audit of the 2011 gas cost review period. We were deemed prudent on our gas purchasing policies and practices during this review period and allowed 100% recovery.

In November 2012, the NCUC approved our accounting of gas costs for the twelve months ended May 31, 2012. We were deemed prudent on our gas purchasing policies and practices during this review period and allowed 100% recovery.

In November 2013, the NCUC approved our accounting of gas costs for the twelve months ended May 31, 2013. We were deemed prudent on our gas purchasing policies and practices during this review period and allowed 100% recovery.

In November 2014, the NCUC approved our accounting of gas costs for the twelve months ended May 31, 2014. We were deemed prudent on our gas purchasing policies and practices during this review period and allowed 100% recovery.

Our gas cost hedging plan for North Carolina is designed to provide a level of protection against significant price increases, targets a percentage range of 22.5% to 45% of annual normalized sales volumes for North Carolina and operates using historical pricing indices that are tied to future projected gas prices as traded on a national exchange. Unlike South Carolina as discussed below, recovery of costs associated with the North Carolina hedging plan is not pre-approved by the NCUC, and the costs are treated as gas costs subject to the annual gas cost prudence review. Any gain or loss recognition under the hedging program is a reduction in or an addition to gas costs, respectively, which, along with any hedging expenses, are flowed through to North Carolina customers in rates. The gas cost review orders issued January 2012, November 2012, November 2013 and November 2014 found our hedging activities during the review periods to be reasonable and prudent.

In October 2012, we filed a petition with the NCUC seeking authority to transfer the total balance of $6.7 million of capital costs held in “Plant held for future use” in “Utility Plant” in the Consolidated Balance Sheets to a deferred regulatory asset account, effective November 1, 2012. This balance in “Plant held for future use” was comprised of real estate and non-real estate costs and related to the development of a LNG facility in Robeson County, North Carolina, construction of which was suspended by Piedmont in March 2009. In April 2013, we withdrew the petition, citing our intent to address the matter in a general rate application. The appropriate treatment of the Robeson County LNG costs was addressed in the general rate settlement discussed below.

In May 2013, we filed a general rate application with the NCUC requesting an increase in rates and charges. In December 2013, the NCUC approved our general rate case settlement agreement with the NCUC Public Staff with new rates effective January 2014. In its order, the NCUC approved the following:

• Updated and increased rates and charges based on an overall rate base of $1.8 billion, an equity capital structure component of 50.7% and a return on common equity of 10% and an overall rate of return of 7.51%.

• Increased total annual revenues of $30.7 million, a 3.58% increase in total revenues, or .7% annual increase, including $16.8 million related to gas utility margin and $13.8 million related to increased fixed gas costs, and annual pre-tax income of $24.2 million after taking into account revised depreciation rates and changes to regulatory asset amortizations.

• Implementation of a new IMR designed to separately track and recover annually outside of general rate cases the costs associated with capital expenditures incurred to comply with federal pipeline safety and integrity requirements.

• Implementation of lower depreciation rates that provide increased annual pre-tax income of $10.9 million. These new lower rates reflect the most recent study conducted in 2009, as discussed in Note 1 to the consolidated financial statements.

• Amortization and collection of $1.2 million of certain non-real estate costs associated with the initial development of the Robeson County LNG facility as discussed above.

• Amortization and collection of certain environmental expenses and pipeline safety and integrity compliance expenses through August 31, 2013 that had been deferred since our last general rate case in 2008.

• Provision for ongoing increased annual contributions to fund pipeline safety and integrity research.

• Future adjustments to rates to recognize the lower state corporate income taxes from North Carolina legislation for fiscal years beginning November 1, 2014 and November 1, 2015.

In January 2014, we filed a petition with the NCUC seeking authority to adjust rates effective February 1, 2014 under the IMR mechanism approved in the general rate case settlement agreement in December 2013 discussed above. The IMR provides for annual adjustments to our rates every February 1 for capital investments in integrity and safety projects as of October 31 of the preceding year. On February 5, 2014, the NCUC approved as filed the initial IMR adjustment totaling $.8 million in annual margin revenues that we reflected in our rates to customers beginning that month. In December 2014, we filed a petition with the NCUC seeking authority to adjust rates to collect an additional $26.6 million in annual IMR margin

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revenues effective February 1, 2015 based on $241.9 million of capital investments in integrity and safety projects over the twelve-month period ending October 31, 2014. We are waiting on a ruling from the NCUC at this time.

In April 2014, we filed a petition with the NCUC for a limited waiver of certain billing provisions of our tariff related to emergency service and unauthorized gas taken by customers in January 2014. In August 2014, we and the NCUC Public Staff filed a joint stipulation of settlement. The terms of the settlement included the granting of a waiver of the commodity index pricing mechanism for January 2014, that we should not be penalized for our conduct in varying from the tariff in this instance as that conduct was solely for the benefit of our customers, and that we and the Public Staff would work together to develop mutually agreeable revisions to our tariff to address the situation that led to this petition. In October 2014, the NCUC issued an order rejecting the joint stipulation of settlement, finding that we must bill our customers for the higher commodity cost of gas pursuant to tariffs and assessing a $65,000 penalty against us for failure to bill and collect according to the commission-approved tariffs. The order further requires us to engage in discussions with each customer served under an interruptible rate schedule to explain the service and obligation under that rate schedule and to conduct an investigation to determine if customers are receiving service under the appropriate tariff.

In April 2014, the NCUC issued an order granting us the authority to issue up to $1 billion in the aggregate of senior or subordinated debt securities or equity securities under our open shelf registration statement. This request was made by us to allow flexibility to access the capital markets as needed for business purposes, including for capital investments and to fund the operations of our subsidiaries. For further information on this shelf registration statement, see Note 4 to the consolidated financial statements.

South Carolina

We currently operate under the Natural Gas Rate Stabilization Act of 2005 in South Carolina. If a utility elects to operate under this act, the annual cost and revenue filing will provide that the utility’s rate of return on equity will remain within a 50-basis point band above or below the last approved allowed rate of return on equity.

In June 2012, we filed with the PSCSC a quarterly monitoring report for the twelve months ended March 31, 2012 and a cost and revenue study as permitted by the RSA requesting a change in rates from those approved by the PSCSC in the October 2011 order. In October 2012, the PSCSC issued an order approving a settlement agreement between the Office of Regulatory Staff (ORS) and us that resulted in a $1.1 million annual decrease in margin based on a return on equity of 11.3%, effective November 1, 2012.

In June 2013, we filed with the PSCSC a quarterly monitoring report for the twelve months ended March 31, 2013 and a cost and revenue study as permitted by the RSA requesting a change in rates from those approved by the PSCSC in the October 2012 order. In October 2013, the PSCSC issued an order approving a settlement agreement between the ORS and us that resulted in a $.1 million annual decrease in margin based on a return on equity of 11.3%, effective November 1, 2013. The PSCSC also approved the recovery of $.2 million of our deferred South Carolina environmental costs over a one-year period beginning November 2013 and ending October 2014.

In June 2014, we filed with the PSCSC a quarterly monitoring report for the twelve months ended March 31, 2014 and a cost and revenue study under the RSA requesting a change in rates from those approved by the PSCSC in the October 2013 order. In October 2014, the PSCSC issued an order approving a settlement agreement between the ORS and us that resulted in a $2.9 million annual decrease in margin based on a stipulated allowed return on equity of 10.2%, effective November 1, 2014. Also in this proceeding, the PSCSC approved the recovery of $.1 million of our deferred South Carolina environmental costs and $.5 million of certain non-real estate costs associated with the initial development of the Robeson County LNG facility located in North Carolina as discussed above, both with amortization periods of one year beginning November 2014 and ending October 2015.

In South Carolina, our recovery of gas costs is subject to annual gas cost proceedings to determine the prudence of our gas purchases. Costs have never been disallowed on the basis of prudence.

The PSCSC has approved a gas cost hedging plan for the purpose of cost stabilization for South Carolina customers. The plan targets a percentage range of 22.5% to 45% of annual normalized sales volumes for South Carolina and operates using historical pricing indices tied to future projected gas prices as traded on a national exchange. All properly accounted for costs incurred in accordance with the plan are deemed to be prudently incurred and recovered in rates as gas costs. Any gain or loss recognized under the hedging program is a reduction in or an addition to gas costs, respectively, and flows through to South Carolina customers in rates. In an August 2011 order, the PSCSC approved a stipulation that our hedging program should no longer have a required minimum volume of hedging.

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In August 2012, the PSCSC approved our PGAs and found our gas purchasing policies to be prudent for the twelve months ended March 31, 2012.

In August 2013, the PSCSC approved our PGAs and found our gas purchasing policies to be prudent for the twelve months ended March 31, 2013.

In August 2014, the PSCSC approved our PGAs and found our gas purchasing policies to be prudent for the twelve months ended March 31, 2014.

In July 2014, we filed a petition with the PSCSC requesting a limited waiver of certain billing provisions of our tariff related to emergency service for customers in January 2014. In August 2014, the PSCSC granted our request and ordered us to continue to collaborate with the ORS to revise our tariff to address the situation that led to this petition.

Tennessee

In February 2010, we filed a petition with the TRA to adjust the applicable rate for the collection of the Nashville franchise fee from certain customers. The proposed rate adjustment was calculated to recover the net $2.9 million of under-collected Nashville franchise fee payments as of May 31, 2009. In April 2010, the TRA passed a motion approving a new Nashville franchise fee rate designed to recover only the net under-collections that have accrued since June 1, 2005, which would have denied recovery of $1.5 million. In October 2011, the TRA issued an order denying us the recovery of $1.5 million of franchise fees consistent with its April 2010 motion, and we recorded $1.5 million in “Operating Expenses” as “Operations and maintenance” in the Consolidated Statements of Comprehensive Income. In November 2011, we filed for reconsideration, which was granted that month. In February 2012, a hearing on this matter was held before the TRA. In May 2012, the TRA approved the recovery of an additional $.5 million in under-collected Nashville franchise fees covering years 2002 through May 2005, which we recorded as a reduction in O&M expenses. The written order was issued by the TRA in June 2012.

In Tennessee, the Tennessee Incentive Plan (TIP) replaced annual prudence reviews under the Actual Cost Adjustment (ACA) mechanism in 1996 by benchmarking gas costs against amounts determined by published market indices and by sharing secondary market (capacity release and off-system sales) activity performance. In 2007, the TRA modified our TIP to clarify and simplify the calculation of allocating secondary marketing gains and losses to ratepayers and shareholders by adopting a uniform 75/25 sharing ratio. The TRA also maintained the $1.6 million annual incentive cap for us on gains and losses, improved the transparency of plan operations by an agreed to request for proposal procedures for asset management transactions and provided for a triennial review of TIP operations by an independent consultant.

In August 2011, we filed an annual report with the TRA reflecting the shared gas cost savings from gains and losses derived from gas purchase benchmarking and secondary market transactions for the twelve months ended June 30, 2011 under the TIP. In March 2012, the TRA approved our TIP account balance. The TRA issued its written order approving the deferred gas cost balances in April 2012.

In September 2011, we filed an annual report for the twelve months ended June 30, 2011 with the TRA that reflected the transactions in the deferred gas cost account for the ACA mechanism. In March 2012, the TRA approved the deferred gas cost account balances. The TRA issued its written order approving the deferred gas cost balances in April 2012.

In August 2012, we filed an annual report with the TRA reflecting the shared gas cost savings from gains and losses derived from gas purchase benchmarking and secondary market transactions for the twelve months ended June 30, 2012 under the TIP. In February 2013, the TRA approved the TIP account balances. The TRA issued its written order approving our TIP account balances in March 2013.

In September 2012, we filed an annual report for the twelve months ended June 30, 2012 with the TRA that reflected the transactions in the deferred gas cost account for the ACA mechanism. In February 2013, the TRA approved the deferred gas cost account balances. The TRA issued its written order approving the deferred gas cost balances in March 2013.

In December 2014, we filed an annual report for the twelve months ended June 30, 2013 with the TRA that reflected the transactions in the deferred gas cost account for the ACA mechanism. We are waiting on a ruling from the TRA at this time.

In August 2013, we filed an annual report with the TRA reflecting the shared gas cost savings from gains and losses derived from gas purchase benchmarking and secondary market transactions for the twelve months ended June 30, 2013 under

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the TIP. In February 2014, the TRA Utilities Division Audit Staff (Audit Staff) submitted their report with which we concurred. In March 2014, the TRA approved and adopted the Audit Staff’s report. The TRA’s written order was issued in April 2014.

In August 2014, we filed an annual report with the TRA reflecting the shared gas cost savings from gains and losses derived from gas purchase benchmarking and secondary market transactions for the twelve months ended June 30, 2014 under the TIP. We are waiting on a ruling from the TRA at this time.

In August 2013, we filed an ACA petition with the TRA to authorize us to make an adjustment to the deferred gas cost account reporting for prior periods in the amount of a $3.7 million under collection. In November 2014, we filed a joint settlement agreement with the TRA staff and the Tennessee Attorney General's Consumer Advocate and Protection Division (CAD) in which the parties agreed that we may include in our next ACA filing prior period adjustments totaling $2 million in lieu of the $3.7 million as originally petitioned. In September 2014, we recorded as expense $1.7 million in the Consolidated Statements of Comprehensive Income. In December 2014, the TRA approved the settlement agreement, and we included the stipulated $2 million of prior period adjustments in the ACA annual report filed in December 2014 for the twelve-month period ended June 30, 2013, as described above.

In September 2011, we filed a general rate application with the TRA requesting authority for an increase to rates and charges, proposed to be effective March 1, 2012. In addition, the petition also requested modifications of the cost allocation and rate designs underlying our existing rates, including shifting more of our cost recovery to our fixed charges and expanding the period of the WNA to October through April. We also sought approval to implement a school-based energy education program with appropriate cost recovery mechanisms, amortization of certain regulatory assets and deferred accounts, revised depreciation rates for plant and changes to the existing service regulations and tariffs. In December 2011, we and the CAD reached a stipulation and settlement agreement resolving all issues in this proceeding, including an increase in rates and charges to all customers effective March 1, 2012 designed to produce overall incremental revenues of $11.9 million annually, or 6.3% above the current annual revenue, based upon an approved rate of return on equity of 10.2%. The new cost allocation and rate designs shifted recovery of fixed charges from 29% to 37% with a resulting decrease of volumetric charges from 71% to 63%. The stipulation and settlement agreement did not include a cost recovery mechanism for a school-based energy education program. In January 2012, a hearing on this matter was held by the TRA. The TRA approved the settlement agreement at the January 2012 hearing. The TRA’s written order was issued in April 2012.

As a part of the rate case settlement mentioned above, the TRA approved the recovery of $1 million incurred as a result of our response to severe flooding in Nashville in May 2010. These direct incremental expenses had been approved for deferred accounting treatment in October 2010. These deferred expenses are being amortized over eight years beginning March 1, 2012 through February 2020.

In August 2013, we filed a petition with the TRA seeking authority to implement an IMR to recover the costs of our capital investments that are made in compliance with federal and state safety and integrity management laws or regulations. We proposed that the rider be effective October 1, 2013 with an initial adjustment on January 1, 2014 of $13.1 million in annual margin revenue from tariff customers based on capital expenditures incurred through October 2013 and for rates to be updated annually outside of general rate cases for the return of and on these capital investments. In September 2013, the TRA issued an order suspending this proposed tariff through December 30, 2013. In November 2013, we and the CAD filed an IMR settlement with the TRA. A hearing on this matter was held in December 2013, and the TRA approved the IMR settlement as filed for $13.1 million with the IMR rate adjustments beginning January 2014. A written order was issued in May 2014. In December 2014, we filed a petition with the TRA seeking authority to collect an additional $6.5 million in annual IMR margin revenues effective January 2015 based on $54 million of capital investments in integrity and safety projects over the twelve-month period ending October 31, 2014. We are waiting on a ruling from the TRA at this time.

In February 2014, we filed a petition with the TRA to authorize us to amortize and refund $4.7 million to customers for recorded excess deferred taxes. We proposed to refund this amount to customers over three years. We are waiting on a ruling from the TRA at this time.

In September 2014, we filed a petition with the TRA seeking authority to implement a compressed natural gas infrastructure rider to recover the costs of our capital investments in infrastructure and equipment associated with this alternative motor vehicle transportation fuel. We proposed that the tariff rider be effective October 1, 2014 with an initial rate adjustment on November 1, 2014 based on capital expenditures incurred through June 2014 and for rates to be updated annually outside of general rate cases for the return of and on these capital investments. In November 2014, the TRA consolidated this docket with a separate petition we filed seeking modifications to our tariff regarding service to customers using natural gas as a motor fuel. The TRA suspended the proposed tariffs through February 9, 2015. A hearing on this matter has been scheduled for January 12, 2015.

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All States

Due to the seasonal nature of our business, we contract with customers in the secondary market to sell supply and capacity assets when market conditions permit. In North Carolina and South Carolina, we operate under sharing mechanisms approved by the NCUC and the PSCSC for secondary market transactions where 75% of the net margins are flowed through to jurisdictional customers in rates and 25% is retained by us. In Tennessee, we operate under the amended TIP where gas purchase benchmarking gains and losses are combined with secondary market transaction gains and losses and shared 75% by customers and 25% by us. Our share of net gains or losses in Tennessee is subject to an overall annual cap of $1.6 million. In all three jurisdictions for the twelve months ended October 31, 2014, we generated $97.6 million of margin from secondary market activity, $72.2 million of which is allocated to customers as gas cost reductions and $25.4 million as margin allocated to us. In all three jurisdictions for the twelve months ended October 31, 2013, we generated $35.9 million of margin from secondary market activity, $26.9 million of which is allocated to customers as gas cost reductions and $9 million as margin allocated to us. In all three jurisdictions for the twelve months ended October 31, 2012, we generated $38.7 million of margin from secondary market activity, $29 million of which is allocated to customers as gas cost reductions and $9.7 million as margin allocated to us.

We currently have commission approval in all three states that place tighter credit requirements on the retail natural gas marketers that schedule gas for transportation service on our system in order to mitigate the risk exposure to the financial condition of the marketers.

3. Earnings Per Share

We compute basic earnings per share (EPS) using the daily weighted average number of shares of common stock outstanding during each period. In the calculation of fully diluted EPS, shares of common stock to be issued under approved incentive compensation plans are contingently issuable shares, as determined by applying the treasury stock method, and are added to average common shares outstanding, resulting in a potential reduction in diluted EPS.

A reconciliation of basic and diluted EPS, which includes contingently issuable shares that could affect EPS if performance units ultimately vest or stock agreements settle, for the years ended October 31, 2014, 2013 and 2012 is presented below.

In thousands, except per share amounts	2014		2013		2012
Net Income	$	143,801	$	134,417	$	119,847
Average shares of common stock outstanding for basic earnings per share	77,883		74,884		71,977
Contingently issuable shares under incentive compensation plans	310		289		301
Contingently issuable shares under forward sale agreements	—		160		—
Average shares of dilutive stock	78,193		75,333		72,278
Earnings Per Share of Common Stock:
Basic	$	1.85	$	1.80	$	1.67
Diluted	$	1.84	$	1.78	$	1.66

4. Long-Term Debt

Our long-term debt consists of privately placed senior notes issued under note purchase agreements, as well as publicly issued medium-term and senior notes issued under an indenture. All of our long-term debt is unsecured and is issued at fixed rates. Long-term debt as of October 31, 2014 and 2013 is as follows.

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In thousands	2014		2013
Senior Notes:
2.92%, due June 6, 2016	$	40,000	$	40,000
8.51%, due September 30, 2017	35,000		35,000
4.24%, due June 6, 2021	160,000		160,000
3.47%, due July 16, 2027	100,000		100,000
3.57%, due July 16, 2027	200,000		200,000
4.10%, due September 18, 2034	250,000		—
4.65%, due August 1, 2043	300,000		300,000
Medium-Term Notes:
5.00%, due December 19, 2013	—		100,000
6.87%, due October 6, 2023	45,000		45,000
8.45%, due September 19, 2024	40,000		40,000
7.40%, due October 3, 2025	55,000		55,000
7.50%, due October 9, 2026	40,000		40,000
7.95%, due September 14, 2029	60,000		60,000
6.00%, due December 19, 2033	100,000		100,000
Total	1,425,000		1,275,000
Less current maturities	—		100,000
Less discount on issuance of notes *	570		143
Total	$	1,424,430	$	1,174,857

* The discount on the 4.65% senior notes was $138 and $143 at October 31, 2014 and 2013, respectively. The discount on the 4.10% senior notes was $432 at October 31, 2014.

Current maturities for the next five years ending October 31 and thereafter are as follows.

In thousands
2015	$	—
2016	40,000
2017	35,000
2018	—
2019	—
Thereafter	1,350,000
Total	$	1,425,000

We had an open combined debt and equity shelf registration statement filed with the SEC in July 2011 that was available for future use until its expiration date of July 6, 2014. In February 2013, we sold shares of common stock under this registration statement. For further information on this transaction, see Note 6 to the consolidated financial statements.

On August 1, 2013, we issued $300 million of thirty-year, unsecured senior notes with an interest rate of 4.65% and at a discount of .048% or $144,000, which we began to amortize ratably over the expected life of the notes, under the registration statement in effect noted above. We have the option to redeem all or part of the notes before the stated maturity prior to February 1, 2043, at a redemption price equal to the greater of a) 100% of the principal amount plus any accrued and unpaid interest to the date of redemption, or b) the sum of the present values of the remaining scheduled payments of principal and interest on the notes to be redeemed, discounted to the date of redemption on a semi-annual basis at the Treasury Rate as defined in the indenture, plus 15 basis points and any accrued and unpaid interest to the date of redemption. We have the option to redeem all or part of the notes before the stated maturity on or after February 1, 2043, at 100% of the principal amount plus any accrued and unpaid interest to the date of redemption. We used the net proceeds of $297.2 million from this issuance to finance capital expenditures, to repay $100 million of our 5% medium-term notes due December 19, 2013 at maturity, to repay outstanding short-term notes under our unsecured commercial paper (CP) program and for general corporate purposes.

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In June 2014, we filed with the SEC a combined debt and equity shelf registration statement that became effective on June 6, 2014. The NCUC has approved debt and equity issuances under this shelf registration statement up to $1 billion during its three-year life. Unless otherwise specified at the time such securities are offered for sale, the net proceeds from the sale of the securities will be used to finance capital expenditures, to repay outstanding short-term, unsecured notes under our CP program, to refinance other indebtedness, to repurchase our common stock, to pay dividends and for general corporate purposes.

On September 18, 2014, we issued $250 million of twenty-year, unsecured senior notes with an interest rate of 4.10% and at a discount of .174% or $435,000, which we began to amortize ratably over the expected life of the notes, under the registration statement in effect noted above. We have the option to redeem all or part of the notes before the stated maturity prior to March 18, 2034, at a redemption price equal to the greater of a) 100% of the principal amount plus any accrued and unpaid interest to the date of redemption, or b) the sum of the present values of the remaining scheduled payments of principal and interest on the notes to be redeemed, discounted to the date of redemption on a semi-annual basis at the Treasury Rate as defined in the indenture, plus 15 basis points and any accrued and unpaid interest to the date of redemption. We have the option to redeem all or part of the notes before the stated maturity on or after March 18, 2034, at 100% of the principal amount plus any accrued and unpaid interest to the date of redemption. We used the net proceeds of $247.7 million from this issuance to finance capital expenditures, to repay outstanding short-term, unsecured notes under our CP program and for general corporate purposes.

The amount of cash dividends that may be paid on common stock is restricted by provisions contained in certain note agreements under which long-term debt was issued, with those for the senior notes being the most restrictive. We cannot pay or declare any dividends or make any other distribution on any class of stock or make any investments in subsidiaries or permit any subsidiary to do any of the above (all of the foregoing being “restricted payments”), except out of net earnings available for restricted payments. As of October 31, 2014, our net earnings available for restricted payments were $1.1 billion.

We are subject to default provisions related to our long-term debt and short-term borrowings. Failure to satisfy any of the default provisions may result in total outstanding issues of debt becoming due. There are cross default provisions in all of our debt agreements. As of October 31, 2014, we are in compliance with all default provisions.

The default provisions of some or all of our senior debt include:

• Failure to make principal or interest payments,

• Bankruptcy, liquidation or insolvency,

• Final judgment against us in excess of $1 million that after 60 days is not discharged, satisfied or stayed pending appeal,

• Specified events under the Employee Retirement Income Security Act of 1974,

• Change in control, and

• Failure to observe or perform covenants, including:

• Interest coverage of at least 1.75 times. Interest coverage was 4.29 times as of October 31, 2014;

• Funded debt cannot exceed 70% of total capitalization. Funded debt was 58% of total capitalization as of October 31, 2014;

• Funded debt of all subsidiaries in the aggregate cannot exceed 15% of total capitalization. There is no funded debt of our subsidiaries as of October 31, 2014;

• Restrictions on permitted liens;

• Restrictions on paying dividends, on or repurchasing our stock or making investments in subsidiaries; and

• Restrictions on burdensome agreements.

5. Short-Term Debt Instruments

We have an $850 million five-year revolving syndicated credit facility that expires on October 1, 2017. We pay an annual fee of $35,000 plus 8.5 basis points for any unused amount. The facility provides a line of credit for letters of credit of $10 million, of which $1.8 million and $2.1 million were issued and outstanding at October 31, 2014 and 2013, respectively. These letters of credit are used to guarantee claims from self-insurance under our general and automobile liability policies. The credit facility bears interest based on the 30-day London Interbank Offered Rate (LIBOR) plus from 75 to 125 basis points, based on our credit ratings. Amounts borrowed are continuously renewable until the expiration of the facility in 2017 provided that we are in compliance with all terms of the agreement. See Note 4 to the consolidated financial statements for discussion of default provisions, including cross default provisions, in all of our debt agreements.

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We have an $850 million unsecured CP program that is backstopped by the revolving syndicated credit facility. The amounts outstanding under the revolving syndicated credit facility and the CP program, either individually or in the aggregate, cannot exceed $850 million. The notes issued under the CP program may have maturities not to exceed 397 days from the date of issuance and bear interest based on, among other things, the size and maturity date of the note, the frequency of the issuance and our credit ratings, plus a spread of 5 basis points. Any borrowings under the CP program rank equally with our other unsecured debt. The notes under the CP program are not registered and are offered and issued pursuant to an exemption from registration. Due to the seasonal nature of our business, amounts borrowed can vary significantly during the year.

As of October 31, 2014, we had $355 million of notes outstanding under the CP program, as included in “Short-term debt” in “Current Liabilities” in the Consolidated Balance Sheets, with original maturities ranging from 4 to 28 days from their dates of issuance at a weighted average interest rate of .17%. As of October 31, 2013, our outstanding notes under the CP program, included in the Consolidated Balance Sheets as stated above, were $400 million at a weighted average interest rate of .36%.

We did not have any borrowings under the revolving syndicated credit facility for the twelve months ended October 31, 2014. A summary of the short-term debt activity under our CP program for the twelve months ended October 31, 2014 is as follows

In thousands
Minimum amount outstanding	$	275,000
Maximum amount outstanding	$	625,000
Minimum interest rate	.10		%
Maximum interest rate	.43		%
Weighted average interest rate	.19		%

Our five-year revolving syndicated credit facility’s financial covenants require us to maintain a ratio of total debt to total capitalization of no greater than 70%, and our actual ratio was 58% at October 31, 2014.

6. Stockholders’ Equity

Capital Stock

Changes in common stock for the years ended October 31, 2014, 2013 and 2011 are as follows.

In thousands	Shares		Amount
Balance, October 31, 2011	72,318		$	446,791
Issued to participants in the Employee Stock Purchase Plan (ESPP)	30		894
Issued to the Dividend Reinvestment and Stock Purchase Plan (DRIP)	677		20,508
Issued to participants in the Incentive Compensation Plan (ICP)	25		796
Shares repurchased under Accelerated Share Repurchase (ASR) agreement	(800	)	(26,528		)
Balance, October 31, 2012	72,250		442,461
Issued to ESPP	33		1,056
Issued to DRIP	720		22,791
Issued to ICP	96		3,065
Issuance of common stock through public share offering, net of underwriting fees	3,000		92,640
Costs from issuance of common stock	—		(369		)
Balance, October 31, 2013	76,099		561,644
Issued to ESPP	34		1,143
Issued to DRIP	698		23,443
Issued to ICP	100		3,315
Issuance of common stock through forward sale agreements, net of expenses	1,600		47,290
Balance, October 31, 2014	78,531		$	636,835

In June 2004, the Board of Directors approved a Common Stock Open Market Purchase Program that authorized the repurchase of up to three million shares of currently outstanding shares of common stock. We implemented the program in

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September 2004. We utilize a broker to repurchase the shares on the open market, and such shares are canceled and become authorized but unissued shares available for issuance under the ESPP, DRIP and ICP.

On December 16, 2005, the Board of Directors approved an increase in the number of shares in this program from three million to six million to reflect the two-for-one stock split in 2004. The Board also approved at that time an amendment of the Common Stock Open Market Purchase Program to provide for the repurchase of up to four million additional shares of common stock to maintain our debt-to-equity capitalization ratios at target levels. These combined actions increased the total authorized share repurchases from three million to ten million shares. The additional four million shares were referred to as our ASR program. On March 6, 2009, the Board of Directors authorized the repurchase of up to an additional four million shares under the Common Stock Open Market Purchase Program and the ASR program, which were consolidated.

On January 29, 2013, we entered into an underwriting agreement under our open combined debt and equity shelf registration statement to sell up to 4.6 million shares of our common stock of which 3 million direct shares were issued and settled on February 4, 2013 with proceeds of $92.6 million received. The shares were purchased by the underwriters at the net price of $30.88 per share, the offering price to the public of $32 per share per the prospectus less an underwriting discount of $1.12 per share.

The remaining 1.6 million shares under this same underwriting agreement were under forward sale agreements (FSAs) with 1 million shares borrowed by a forward counterparty and sold to the underwriters for resale to the public on February 4, 2013 at the same price as the direct shares; the remaining .6 million shares were subject to a 30-day option by the underwriters to purchase these additional shares at the same price as the direct shares and would be, at our option, either issued at the time of purchase and delivered directly to the underwriters or borrowed and delivered to the underwriters by the forward counterparty. On February 19, 2013, the underwriters exercised their option to purchase the full additional .6 million shares of our common stock where the shares were borrowed from third parties and sold to the underwriters by the forward counterparty. Both of the FSAs had to be settled no later than mid-December 2013. Under the terms of these FSAs, at our election, we could physically settle in shares, cash or net share settle for all or a portion of our obligation under the agreements.

On December 16, 2013, we physically settled the FSAs by issuing 1.6 million shares of our common stock to the forward counterparty and received net proceeds of $47.3 million based on the net settlement price of $30.88 per share, the original offering price, less certain adjustments. We recorded this amount in "Stockholders' equity" as an addition to "Common stock" in the Consolidated Balance Sheets. Upon settlement, we used the net proceeds from these FSA transactions to finance capital expenditures, repay outstanding short-term, unsecured notes under our CP program and for general corporate purposes.

In accordance with ASC 815-40, Derivatives and Hedging - Contracts in Entity’s Own Equity, we classified the FSAs as equity transactions because the forward sale transactions were indexed to our own stock and physical settlement was within our control. As a result of this classification, no amounts were recorded in the consolidated financial statements until settlement of each FSA.

Upon physical settlement of the FSAs, delivery of our shares resulted in dilution to our EPS at the date of the settlement. In quarters prior to the settlement date, any dilutive effect of the FSAs on our EPS occurred during periods when the average market price per share of our common stock was above the per share adjusted forward sale price described above. See Note 3 to the consolidated financial statements for the dilutive effect of the FSAs on our EPS at October 31, 2013 with the inclusion of incremental shares in our average shares of dilutive stock as calculated under the treasury stock method.

On January 4, 2012, we entered into an ASR agreement where we purchased 800,000 shares of our common stock from an investment bank at the closing price that day of $33.77 per share. The settlement and retirement of those shares occurred on January 5, 2012. Total consideration paid to purchase the shares of $27 million was recorded in “Stockholders’ equity” as a reduction in “Common stock” in the Consolidated Balance Sheets.

As part of the ASR, we simultaneously entered into a forward sale contract with the investment bank that was expected to mature in 52 trading days, or March 21, 2012. Under the terms of the forward sale contract, the investment bank was required to purchase, in the open market, 800,000 shares of our common stock during the term of the contract to fulfill its obligation related to the shares it borrowed from third parties and sold to us. At settlement, we, at our option, were required to either pay cash or issue shares of our common stock to the investment bank if the investment bank’s weighted average purchase price, less a $.09 per share discount, was higher than the January 4, 2012 closing price. The investment bank was required to pay us either cash or shares of our common stock, at our option, if the investment bank’s weighted average price, less a $.09 per share discount, for the shares purchased was lower than the initial purchase closing price. At settlement on February 28, 2012, we received $.5 million from the investment bank and recorded this amount in “Stockholders’ equity” as an addition to “Common stock” in the Consolidated Balance Sheets. The $.5 million was the difference between the investment bank’s

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weighted average purchase price of $33.25 per share less a discount of $.09 per share for a settlement price of $33.16 per share and the initial purchase closing price of $33.77 per share multiplied by 800,000 shares. We had an ASR transaction in 2011 as presented in the table above with a similar structure with the investment bank, which was accounted for in the same manner.

As of October 31, 2014, our shares of common stock were reserved for issuance as follows.

In thousands
ESPP	176
DRIP	840
ICP	950
Total	1,966

Other Comprehensive Income (Loss)

Our OCIL is a part of our accumulated OCIL and is comprised of hedging activities from our equity method investments. For further information on these hedging activities by our equity method investments, see Note 12 to the consolidated financial statements. Beginning in 2014, another component of our accumulated OCIL is the allocation of retirement benefits to SouthStar Energy Services, LLC (SouthStar) by its majority member. Changes in each component of accumulated OCIL are presented below for the years ended October 31, 2014 and 2013.

Changes in Accumulated OCIL (1)
In thousands	2014			2013
Accumulated OCIL beginning balance, net of tax	$	(284	)	$	(305	)
Hedging activities of equity method investments:
OCIL before reclassifications, net of tax	355			(109		)
Amounts reclassified from accumulated OCIL, net of tax	(284		)	130
Total current period activity of hedging activities of equity method investments, net of tax	71			21
Net current period benefit activities of equity method investments, net of tax	(24		)
Accumulated OCIL ending balance, net of tax	$	(237	)	$	(284	)

⁽¹⁾ Amounts in parentheses indicate debits to accumulated OCIL.

A reconciliation of the effect on certain line items of net income on amounts reclassified out of each component of accumulated OCIL is presented below for the years ended October 31, 2014 and 2013.

	Reclassification Out of Accumulated OCIL (1)
	Years Ended
	October 31						Affected Line Items on Statement of  Comprehensive Income
In thousands	2014			2013
Hedging activities of equity method investments	$	(461	)	$	215		Income from equity method investments
Income tax expense	177			(85		)	Income taxes
Hedging activities of equity method investments	(284		)	$	130
Net benefit activities of equity method investments	(40		)				Income from equity method investments
Income tax expense	16						Income taxes
Net benefit activities of equity method investments	(24		)
Total reclassification for the period, net of tax	$	(308	)	$	130

⁽¹⁾ Amounts in parentheses indicate debits to accumulated OCIL.

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7. Financial Instruments and Related Fair Value

Derivative Assets and Liabilities under Master Netting Arrangements

We maintain brokerage accounts to facilitate transactions that support our gas cost hedging plans. The accounting guidance related to derivatives and hedging requires that we use a gross presentation, based on our election, for the fair value amounts of our derivative instruments. We use long position gas purchase options to provide some level of protection for our customers in the event of significant commodity price increases. As of October 31, 2014 and 2013, we had long gas purchase options providing total coverage of 29.2 million dekatherms and 25.4 million dekatherms, respectively. The long gas purchase options held at October 31, 2014 are for the period from December 2014 through November 2015.

Fair Value Measurements

We use financial instruments that are not designated as hedges for accounting purposes to mitigate commodity price risk for our customers. We also have marketable securities that are held in rabbi trusts established for certain of our deferred compensation plans. In developing our fair value measurements of these financial instruments, we utilize market data or assumptions about risk and the risks inherent in the inputs to the valuation technique. Fair value refers to the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants in the market in which the entity transacts. We classify fair value balances based on the observance of those inputs into the fair value hierarchy levels as set forth in the fair value accounting guidance and fully described in “Fair Value Measurements” in Note 1 to the consolidated financial statements.

The following table sets forth, by level of the fair value hierarchy, our financial assets that were accounted for at fair value on a recurring basis as of October 31, 2014 and 2013. Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their consideration within the fair value hierarchy levels. We have had no transfers between any level during the years ended October 31, 2014 and 2013. We present our derivative positions at fair value on a gross basis and have only asset positions for all periods presented for the fair value of purchased call options held for our utility operations. There are no derivative contracts in a liability position, and we have posted no cash collateral nor received any cash collateral under our master netting arrangements. Therefore, we have no offsetting disclosures for financial assets or liabilities for our derivatives held for utility operations. Our derivatives held for utility operations are held with one broker as our counterparty.

Recurring Fair Value Measurements as of October 31, 2014
			Significant				Effects of
	Quoted Prices		Other		Significant		Netting and
	in Active		Observable		Unobservable		Cash Collateral		Total
	Markets		Inputs		Inputs		Receivables/		Carrying
In thousands	(Level 1)		(Level 2)		(Level 3)		Payables		Value
Assets:
Derivatives held for distribution operations	$	4,898	$	—	$	—	$	—	$	4,898
Debt and equity securities held as trading securities:
Money markets	469		—		—		—		469
Mutual funds	3,472		—		—		—		3,472
Total fair value assets	$	8,839	$	—	$	—	$	—	$	8,839

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Recurring Fair Value Measurements as of October 31, 2013
			Significant				Effects of
	Quoted Prices		Other		Significant		Netting and
	in Active		Observable		Unobservable		Cash Collateral		Total
	Markets		Inputs		Inputs		Receivables/		Carrying
In thousands	(Level 1)		(Level 2)		(Level 3)		Payables		Value
Assets:
Derivatives held for distribution operations	$	1,834	$	—	$	—	$	—	$	1,834
Debt and equity securities held as trading securities:
Money markets	380		—		—		—		380
Mutual funds	2,814		—		—		—		2,814
Total fair value assets	$	5,028	$	—	$	—	$	—	$	5,028

Our regulated utility segment derivative instruments are used in accordance with programs filed with or approved by the NCUC, the PSCSC and the TRA to hedge the impact of market fluctuations in natural gas prices. These derivative instruments are accounted for at fair value each reporting period. In accordance with regulatory requirements, the net gains and losses related to these derivatives are reflected in purchased gas costs and ultimately passed through to customers through our PGA procedures. In accordance with accounting provisions for rate-regulated activities, the unrecovered amounts related to these instruments are reflected as a regulatory asset or liability, as appropriate, in “Amounts due from customers” or “Amounts due to customers” in Note 1 to the consolidated financial statements. These derivative instruments are exchange-traded derivative contracts. Exchange-traded contracts are generally based on unadjusted quoted prices in active markets and are classified within Level 1.

Trading securities include assets in rabbi trusts established for our deferred compensation plans and are included in “Marketable securities, at fair value” in “Noncurrent Assets” in the Consolidated Balance Sheets. Securities classified within Level 1 include funds held in money market and mutual funds which are highly liquid and are actively traded on the exchanges.

Our long-term debt is recorded at unamortized cost. In developing the fair value of our long-term debt, we use a discounted cash flow technique, consistently applied, that incorporates a developed discount rate using long-term debt similarly rated by credit rating agencies combined with the U.S. Treasury benchmark with consideration given to maturities, redemption terms and credit ratings similar to our debt issuances. The carrying amount and fair value of our long-term debt, including the current portion, which is classified within Level 2, are shown below.

	Carrying
In thousands	Amount *		Fair Value
As of October 31, 2014	$	1,425,000	$	1,617,453
As of October 31, 2013	1,275,000		1,409,892

* Excludes discount on issuance of notes of $570 and $143 as of October 31, 2014 and 2013, respectively.

Quantitative and Qualitative Disclosures

The costs of our financial price hedging options for natural gas and all other costs related to hedging activities of our regulated gas costs are recorded in accordance with our regulatory tariffs approved by our state regulatory commissions, and thus are not accounted for as designated hedging instruments under derivative accounting standards. As required by the accounting guidance, the fair value of our financial options is presented on a gross basis with only asset positions for all periods presented. There are no derivative contracts in a liability position, and we have posted no cash collateral nor received any cash collateral under our master netting arrangements; therefore, we have no offsetting disclosures for financial assets or liabilities for our financial option derivatives.

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The following table presents the fair value and balance sheet classification of our financial options for natural gas as of October 31, 2014 and 2013.

Fair Value of Derivative Instruments
In thousands	2014		2013
Derivatives Not Designated as Hedging Instruments under Derivative Accounting Standards:
Asset Financial Instruments:
Current Assets - Gas purchase derivative assets (December 2014 - November 2015)	$	4,898
Current Assets - Gas purchase derivative assets (December 2013 - October 2014)			$	1,834

We purchase natural gas for our regulated operations for resale under tariffs approved by state regulatory commissions. We recover the cost of gas purchased for regulated operations through PGA procedures. Our risk management policies allow us to use financial instruments to hedge commodity price risks, but not for speculative trading. The strategy and objective of our hedging programs is to use these financial instruments to reduce gas cost volatility for our customers. Accordingly, the operation of the hedging programs on the regulated utility segment as a result of the use of these financial derivatives is initially deferred as amounts due from customers included as “Regulatory Assets” or amounts due to customers included as “Regulatory Liabilities” in Note 1 to the consolidated financial statements and recognized in the Consolidated Statements of Comprehensive Income as a component of “Cost of Gas” when the related costs are recovered through our rates.

The following table presents the impact that financial instruments not designated as hedging instruments under derivative accounting standards would have had on the Consolidated Statements of Comprehensive Income for the twelve months ended October 31, 2014 and 2013, absent the regulatory treatment under our approved PGA procedures.

	Amount of					Amount of					Location of Gain (Loss)
	Gain (Loss) Recognized					Gain (Loss) Deferred					Recognized through
	on Derivative Instruments					Under PGA Procedures					PGA Procedures
	Twelve Months Ended					Twelve Months Ended
	October 31					October 31
In thousands	2014		2013			2014		2013
Gas purchase options	$	6,162	$	(6,303	)	$	6,162	$	(6,303	)	Cost of Gas

In Tennessee, the cost of gas purchase options and all other costs related to hedging activities up to 1% of total annual gas costs are approved for recovery under the terms and conditions of our TIP approved by the TRA. In South Carolina, the costs of gas purchase options are subject to and are approved for recovery under the terms and conditions of our gas hedging plan approved by the PSCSC. In North Carolina, the costs associated with our hedging program are treated as gas costs subject to an annual cost review proceeding by the NCUC.

Credit and Counterparty Risk

We are exposed to credit risk as a result of transactions for the purchase and sale of natural gas and related products and services and management agreements of our transportation capacity, storage capacity and supply contracts with major companies in the energy industry and within our utility operations serving industrial, commercial, power generation, residential and municipal energy consumers. These transactions principally occur in the eastern, gulf coast and mid-west regions of the United States. We believe that this geographic concentration does not contribute significantly to our overall exposure to credit risk. Credit risk associated with trade accounts receivable for the natural gas distribution segment is mitigated by the large number of individual customers and diversity in our customer base.

We enter into contracts with third parties to buy and sell natural gas. A significant portion of these transactions are with, or are associated with, energy producers, utility companies, off-system municipalities and natural gas marketers. The amount included in “Trade accounts receivable” in “Current Assets” in the Consolidated Balance Sheets attributable to these entities amounted to $3.5 million, or approximately 5% of our gross trade accounts receivable at October 31, 2014. Our policy requires counterparties to have an investment-grade credit rating at the time of the contract, or in situations where counterparties do not have investment-grade or functionally equivalent credit ratings, our policy requires credit enhancements that include letters of credit or parental guaranties. In either circumstance, our policy specifies limits on the contract amount and duration based on the counterparty’s credit rating and/or credit support. In order to minimize our exposure, we continually re-evaluate third-party creditworthiness and market conditions and modify our requirements accordingly.

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We also enter into contracts with third parties to manage some of our supply and capacity assets for the purpose of maximizing their value. These arrangements include a counterparty credit evaluation according to our policy described above prior to contract execution and typically have durations of one year or less. In the event that a party is unable to perform under these arrangements, we have exposure to satisfy our underlying supply or demand contractual obligations that were incurred while under the management of this third party. We believe, based on our credit policies as of October 31, 2014, that our financial position, results of operations and cash flows will not be materially affected as a result of nonperformance by any single counterparty.

Natural gas distribution operating revenues and related trade accounts receivable are generated from state-regulated utility natural gas sales and transportation to over one million residential, commercial and industrial customers, including power generation and municipal customers, located in North Carolina, South Carolina and Tennessee. A change in economic conditions may affect the ability of customers to meet their obligations. We have mitigated our exposure to the risk of non-payment of utility bills by our customers. Gas costs related to uncollectible accounts are recovered through PGA procedures in all jurisdictions. To manage the non-gas cost customer credit risk, we evaluate credit quality and payment history and may require cash deposits from our high risk customers that do not satisfy our predetermined credit standards until a satisfactory payment history has been established. Significant increases in the price of natural gas and colder-than-normal weather can slow our collection efforts as customers experience increased difficulty in paying their gas bills, leading to higher than normal trade accounts receivable; however, we believe that our provision for possible losses on uncollectible trade accounts receivable is adequate for our credit loss exposure.

Risk Management

Our financial derivative instruments do not contain material credit-risk-related or other contingent features that could require us to make accelerated payments.

We seek to identify, assess, monitor and manage risk in accordance with defined policies and procedures under the direction of the Treasurer and Chief Risk Officer and our Enterprise Risk Management (ERM) program, including our Energy Price Risk Management Committee. Risk management is guided by senior management with Board of Directors oversight, and senior management takes an active role in the development of policies and procedures.

8. Commitments and Contingent Liabilities

Leases

We lease certain buildings, land and equipment for use in our operations under noncancelable operating leases. We account for these leases by recognizing the future minimum lease payments as expense on a straight-line basis over the respective minimum lease terms under current accounting guidance.

Operating lease payments for the years ended October 31, 2014, 2013 and 2012 are as follows.

In thousands	2014		2013		2012
Operating lease payments (1)	$	4,701	$	4,729	$	3,712

⁽¹⁾ Operating lease payments do not include payments for common area maintenance, utilities or tax payments.

Future minimum lease obligations for the next five years ending October 31 and thereafter are as follows.

In thousands
2015	$	4,600
2016	4,491
2017	4,297
2018	4,225
2019	4,137
Thereafter	27,359
Total	$	49,109

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Long-term contracts

We routinely enter into long-term gas supply commodity and capacity commitments and other agreements that commit future cash flows to acquire services we need in our business. These commitments include pipeline and storage capacity contracts and gas supply contracts to provide service to our customers and telecommunication and information technology contracts and other purchase obligations. Costs arising from the gas supply commodity and capacity commitments, while significant, are pass-through costs to our customers and are generally fully recoverable through our PGA procedures and prudence reviews in North Carolina and South Carolina and under the TIP in Tennessee. The time periods for fixed payments under pipeline and storage capacity contracts are up to twenty-one years. The time periods for fixed payments under gas supply contracts are up to three years. The time periods for the telecommunications and technology outsourcing contracts, maintenance fees for hardware and software applications, usage fees, local and long-distance costs and wireless service are up to five years. Other purchase obligations consist primarily of commitments for pipeline products, vehicles, equipment and contractors.

Certain storage and pipeline capacity contracts require the payment of demand charges that are based on rates approved by the FERC in order to maintain our right to access the natural gas storage or the pipeline capacity on a firm basis during the contract term. The demand charges that are incurred in each period are recognized in the Consolidated Statements of Comprehensive Income as part of gas purchases and included in “Cost of Gas.”

As of October 31, 2014, future unconditional purchase obligations for the next five years ending October 31 and thereafter are as follows.

	Pipeline		Gas Supply		Telecommunications
	Storage		Reservation		and Information
In thousands	Capacity		Fees		Technology		Other		Total
2015	$	158,984	$	8,657	$	14,601	$	41,008	$	223,250
2016	149,412		137		4,786		—		154,335
2017	145,579		135		736		—		146,450
2018	142,433		—		126		—		142,559
2019	132,186		—		80		—		132,266
Thereafter	627,602		—		—		—		627,602
Total	$	1,356,196	$	8,929	$	20,329	$	41,008	$	1,426,462

Legal

We have only routine litigation in the normal course of business. We do not expect any of these routine litigation matters to have a material effect, either individually or in the aggregate, on our financial position, results of operations or cash flows.

Letters of Credit

We use letters of credit to guarantee claims from self-insurance under our general and automobile liability policies. We had $1.8 million in letters of credit that were issued and outstanding at October 31, 2014. Additional information concerning letters of credit is included in Note 5 to the consolidated financial statements.

Surety Bonds

In the normal course of business, we are occasionally required to provide financial commitments in the form of surety bonds to third parties as a guarantee of our performance on commercial obligations. We have agreements that indemnify certain issuers of surety bonds against losses that they may incur as a result of executing surety bonds on our behalf. If we were to fail to perform according to the terms of the underlying contract, any draws upon surety bonds issued on our behalf would then trigger our payment obligation to the surety bond issuer. As of October 31, 2014, we had open surety bonds with a total contingent obligation of $4.8 million.

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Environmental Matters

Our three regulatory commissions have authorized us to utilize deferral accounting in connection with environmental costs. Accordingly, we have established regulatory assets for actual environmental costs incurred and for estimated environmental liabilities recorded for manufactured gas plant (MGP) sites, LNG facilities and underground storage tanks (USTs).

In 1997, we entered into a settlement with a third-party with respect to nine MGP sites that we have owned, leased or operated that released us from any investigation and remediation liability. Although no such claims are pending or, to our knowledge, threatened, the settlement did not cover any third-party claims for personal injury, death, property damage and diminution of property value or natural resources.

In connection with the 2003 North Carolina Natural Gas Corporation (NCNG) acquisition, several MGP sites owned by NCNG were transferred to a wholly-owned subsidiary of Progress Energy, Inc. (Progress), now a subsidiary of Duke Energy Corporation (Duke Energy), prior to closing. Progress has complete responsibility for performing all of NCNG’s remediation obligations to conduct testing and clean-up at these sites, including both the costs of such testing and clean-up and the implementation of any affirmative remediation obligations that NCNG has related to the sites. Progress’ responsibility does not include any third-party claims for personal injury, death, property damage, and diminution of property value or natural resources. We know of no such pending or threatened claims.

The following table summarizes information regarding our environmental sites as of October 31, 2014.

			Costs		Undiscounted
	Site		Incurred		Environmental
In thousands	Type	Site Status	to Date		Liability *
Anderson, SC	MGP	Site Investigation Work Plan submitted to the South Carolina Department of Health and Environmental Control.	$	7	$	890
Hickory, NC	MGP	Remediation complete. Land use restrictions in progress.	1,494		18
Reidsville, NC	MGP	Remediation complete. Land use restrictions filed.	641		199
Huntersville, NC	LNG	Soil remediation complete. Quarterly and semi-annual groundwater sampling in progress. Lead-based paint remediation complete.	4,738		81
Charlotte, NC	UST	USTs removed. Tank closure process in progress with the North Carolina Department of Environment and Natural Resources.	32		33
Clemmons, NC	UST	Potential responsible party for propane tank	—		38
Totals			$	6,912	$	1,259
* Estimated based on assumptions using actual costs incurred, the timing of future payments and inflation factors, among others.

We continue to expand our sampling of our pipelines for coatings containing asbestos. Additionally, we continue to educate our employees on the hazards of asbestos and implemented procedures for removing these coatings from our pipelines when we must excavate and expose portions of the pipeline.

As of October 31, 2014, our regulatory assets for unamortized environmental costs in our three-state territory totaled $8 million. We received approval from the TRA to recover $2 million of our deferred Tennessee environmental costs over an eight-year period beginning March 2012, pursuant to the 2012 general rate case proceeding in Tennessee. We will seek recovery of the remaining Tennessee balance in future rate proceedings. The approval by the NCUC in December 2013 of the settlement of the general rate proceeding allowed recovery of $6.3 million of our deferred North Carolina environmental costs over a five-year period beginning January 2014. We received approval from the PSCSC to recover $.1 million of our deferred South Carolina environmental costs over a one-year period beginning November 2014, pursuant to the annual rate stabilization order issued in October 2014.

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Further evaluation of the MGP, LNG and UST sites could significantly affect recorded amounts; however, we believe that the ultimate resolution of these matters will not have a material effect on our financial position, results of operations or cash flows.

9. Employee Benefit Plans

Under accounting guidance, we are required to recognize all obligations related to defined benefit pension and other postretirement employee benefits (OPEB) plans and quantify the plans’ funded status as an asset or liability on the Consolidated Balance Sheets. In accordance with accounting guidance, we measure the plans’ assets and obligations that determine our funded status as of the end of our fiscal year, October 31. We are required to recognize as a component of OCI the changes in the funded status that occurred during the year that are not recognized as part of net periodic benefit cost; however, in 2006, we obtained regulatory treatment from the NCUC, the PSCSC and the TRA to record the amount that would have been recorded in accumulated OCI as a regulatory asset or liability as the future recovery of pension and OPEB costs is probable. To date, our regulators have allowed future recovery of our pension and OPEB costs. For the impact of this regulatory treatment, see the following table of actuarial plan information that specifies the amounts not yet recognized as a component of cost and recognized as a regulatory asset or liability. Our plans’ assets are required to be accounted for at fair value.

Pension Benefits

We have a noncontributory, tax-qualified defined benefit pension plan (qualified pension plan) for our eligible employees. A defined benefit plan specifies the amount of benefit that an eligible participant eventually will receive upon retirement using information about that participant. An employee became eligible on the January 1 or July 1 following either the date on which he or she attained age 30 or attained age 21 and completed 1,000 hours of service during the 12-month period commencing on the employment date. Plan benefits are generally based on credited years of service and the level of compensation during the five consecutive years of the last ten years prior to retirement or termination during which the participant received the highest compensation. Our policy is to fund the plan in an amount not in excess of the amount that is deductible for income tax purposes. The qualified pension plan is closed to employees hired after December 31, 2007. Employees hired prior to January 1, 2008 continue to participate in the qualified pension plan. Employees are vested after five years of service and can be credited with up to a total of 35 years of service. When a vested employee leaves the company, his benefit payment will be calculated as the greater of the accrued benefit as of December 31, 2007 under a specific formula plus the accrued benefit calculated under a second formula for years of service after December 31, 2007, or the benefit for all years of service up to 35 years under the second formula.

The investment objectives of the qualified pension plan are oriented to meet both the current ongoing and future commitments to the participants and designed to grow at an acceptable rate of return for the risks permitted under the investment policy guidelines. Assets are structured to provide for both short-term and long-term needs and to meet the objectives of the qualified pension plan as specified by the Benefits Committee of the Board of Directors.

Our primary investment objective of the qualified pension plan is to generate sufficient assets to meet plan liabilities. The plan’s assets will therefore be invested to maximize long-term returns in a manner that is consistent with the plan’s liabilities, cash flow requirements and risk tolerance. The plan’s liabilities are defined in terms of participant salaries. Given the nature of these liabilities and recognizing the long-term benefits of investing in return-generating assets, the qualified pension plan seeks to invest in a diversified portfolio to:

• Achieve full funding over the longer term, and

• Control year-to-year fluctuations in pension expense that is created by asset and liability volatility.

We consider the historical long-term return experience of our assets, the current and targeted allocation of our plan assets and the expected long-term rates of return. Investment advisors assist us in deriving expected long-term rates of return. These rates are generally based on a 20-year horizon for various asset classes, our expected investments of plan assets and active asset management instead of a passive investment strategy of an index fund.

The investment philosophy of the qualified pension plan is to maintain a balanced portfolio which is diversified across asset classes. The portfolio is primarily composed of equity and fixed income investments in order to provide diversification as to issuers, economic sectors, markets and investment instruments. Risk and quality are viewed in the context of the diversification requirements of the aggregate portfolio. We measure and monitor investment risk on an ongoing basis through quarterly investment portfolio reviews, annual liability measurements and periodic asset/liability studies. We do not have a concentration of assets in a single entity, industry, country, commodity or class of investment fund.

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The qualified pension plan maintains a 45% target allocation to fixed income securities, including U.S. treasuries, corporate bonds, high yield debt, asset-backed securities and derivatives. The derivatives in the fixed income portfolio are fully collateralized. The investment guidelines limit liabilities created with derivatives in the fixed income portfolio to cash equivalents plus 10% of the portfolio’s market value. The aggregate risk exposure of the plan can be no greater than that which could be achieved without using derivatives. The qualified pension plan maintains a 35% target allocation to equities, including exposure to large cap growth, large cap value and small cap domestic equity securities, as well as exposure to international equity. There is a 5% target allocation to real estate in a diversified global real estate investment trust (REIT) fund. The remaining 15% target allocation is for investments in other types of funds, including commodities, hedge funds and private equity funds that follow several diversified strategies.

Employees hired or rehired after December 31, 2007 cannot participate in the qualified pension plan but are participants in the Money Purchase Pension (MPP) plan, a defined contribution pension plan that allows the employee to direct the investments and assume the risk of investment returns. A defined contribution plan specifies the amount of the employer’s annual contribution to individual participant accounts established for the retirement benefit. Eligible employees who have completed 30 days of continuous service and have attained age 18 are eligible to participate. Under the MPP plan, we annually deposit a percentage of each participant’s pay into an account of the MPP plan. This contribution equals 4% of the participant’s compensation plus an additional 4% of compensation above the social security wage base up to the Internal Revenue Service (IRS) compensation limit. The participant is vested in this plan after three years of service. During the year ended October 31, 2014, we contributed $.9 million to the MPP plan.

OPEB Plan

We provide certain postretirement health care and life insurance benefits to eligible retirees. The liability associated with such benefits is funded in irrevocable trust funds that can only be used to pay the benefits. Employees are first eligible to retire and receive these benefits at age 55 with ten or more years of service after the age of 45. Employees who met this requirement in 1993 or who retired prior to 1993 are in a “grandfathered” group for whom we pay the full cost of the retiree’s coverage. Retirees not in the grandfathered group have a portion of the cost of retiree coverage paid by us, subject to certain annual contribution limits. Retirees are responsible for the full cost of dependent coverage. Effective January 1, 2008, new employees have to complete ten years of service after age 50 to be eligible for benefits, and no benefits are provided to those employees after age 65 when they are automatically eligible for Medicare benefits to cover health costs. Our OPEB plan includes a defined dollar benefit to pay the premiums for Medicare Part D. Employees who meet the eligibility requirements to retire also receive a life insurance benefit. For employees who retire after July 1, 2005, this benefit is $15,000. The life insurance amount for employees who retired prior to this date was calculated as a percentage of their basic life insurance prior to retirement.

OPEB plan assets are comprised of mutual funds within a 401(h) and Voluntary Employees’ Beneficiary Association trusts. The investment philosophy is similar to the qualified pension plan as discussed above. We target an OPEB allocation of 45% to fixed income securities, including U.S. treasuries, corporate bonds, high yield bonds and asset-backed securities. The OPEB plan maintains a 47% target allocation to equities, which includes exposure to large cap growth, large cap value and small cap domestic equity, as well as exposure to international equity. The OPEB plan maintains a 5% target allocation to real estate in a diversified global REIT fund and a 3% target allocation to cash. We do not have a concentration of assets in a single entity, industry, country, commodity or class of investment fund.

Supplemental Executive Retirement Plans

We have pension liabilities related to supplemental executive retirement plans (SERPs) for certain former employees, non-employee directors or surviving spouses. There are no assets related to these SERPs, and no additional benefits accrue to the participants. Payments to the participants are made from operating funds during the year. Actuarial information for these nonqualified plans is presented below.

We have a non-qualified defined contribution restoration plan (DCR plan) for all officers at the vice president level and above where benefits payable under the plan are informally funded annually through a rabbi trust with a bank as the trustee. We contribute 13% of the total cash compensation (base salary, short-term incentive and MVP incentive) that exceeds the IRS compensation limit to the DCR plan account of each covered executive. Participants may not contribute to the DCR plan. Vesting under the DCR plan is five-year cliff vesting, including service prior to adoption of the plan on January 1, 2009, of annual company contributions, and prospective five-year cliff vesting for the one-time opening balances of four Vice Presidents to compensate them for the loss of future benefits under this DCR plan as compared with a terminated SERP.

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Participants in the DCR plan may provide instructions to us for the deemed investment of their plan accounts. Distribution will occur upon separation of service or death of the participant.

We have a voluntary deferred compensation plan for the benefit of all director-level employees and officers, where we make no contributions to this plan. Benefits under this plan, known as the Voluntary Deferral Plan, are also informally funded monthly through a rabbi trust with a bank as the trustee. Participants may defer up to 50% of base salary with elections made by December 31 prior to the upcoming calendar year, and up to 95% of annual incentive pay with elections made by April 30. Vesting is immediate and deferrals are held in the rabbi trust. Participants may provide instructions to us for the deemed investment of their plan accounts. Distributions can be made from the Voluntary Deferral Plan on a specified date that is at least two years from the date of deferral, on separation of service or upon death.

The funding to the DCR plan accounts for the years ended October 31, 2014 and 2013, and the amounts recorded as liabilities for these deferred compensation plans as of October 31, 2014 and 2013 are presented below.

In thousands	2014		2013
Funding	$	524	$	434
Liability:
Current	214		199
Noncurrent	4,248		3,328

We provide term life insurance policies for certain officers at the vice president level and above who were former participants in a terminated SERP; the level of the insurance benefit is dependent upon the level of the benefit provided under the terminated SERP. These life insurance policies are owned exclusively by each officer. Premiums on these policies are paid and expensed. We also provide a term life insurance benefit equal to $200,000 to all officers and director-level employees for which we bear the cost of the policies. The cost of these premiums is presented below.

In thousands	2014		2013		2012
Term life policies of certain officers at the vice president level and above	$	30	$	27	$	43
Officers and director-level employees	32		28		25

Actuarial Plan Information

A reconciliation of changes in the plans’ benefit obligations and fair value of assets for the years ended October 31, 2014 and 2013, and a statement of the funded status and the amounts reflected in the Consolidated Balance Sheets for the years ended October 31, 2014 and 2013 are presented below.

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	Qualified Pension						Nonqualified Pension						Other Benefits
In thousands	2014			2013			2014			2013			2014			2013
Accumulated benefit obligation at year end	$	252,706		$	230,175		$	5,925		$	4,736		N/A			N/A
Change in projected benefit obligation:
Obligation at beginning of year	$	272,403		$	293,327		$	4,736		$	5,569		$	33,678		$	34,830
Service cost	10,865			12,005			—			—			1,109			1,327
Interest cost	11,781			9,946			200			157			1,448			1,130
Plan amendments	—			—			485			—			—			—
Actuarial (gain) loss	23,646			(24,859		)	956			(540		)	3,734			(1,094		)
Participant contributions	—			—			—			—			805			641
Administrative expenses	(465		)	(534		)	—			—			—			—
Benefit payments	(15,544		)	(17,482		)	(452		)	(450		)	(2,957		)	(3,156		)
Obligation at end of year	302,686			272,403			5,925			4,736			37,817			33,678
Change in fair value of plan assets:
Fair value at beginning of year	300,661			272,337			—			—			25,961			23,663
Actual return on plan assets	31,791			26,340			—			—			1,874			2,848
Employer contributions	20,000			20,000			452			450			2,064			1,965
Participant contributions	—			—			—			—			805			641
Administrative expenses	(465		)	(534		)	—			—			—			—
Benefit payments	(15,544		)	(17,482		)	(452		)	(450		)	(2,957		)	(3,156		)
Fair value at end of year	336,443			300,661			—			—			27,747			25,961
Funded status at year end - over (under)	$	33,757		$	28,258		$	(5,925	)	$	(4,736	)	$	(10,070	)	$	(7,717	)
Noncurrent assets	$	33,757		$	28,258		$	—		$	—		$	—		$	—
Current liabilities	—			—			(521		)	(445		)	—			—
Noncurrent liabilities	—			—			(5,404		)	(4,291		)	(10,070		)	(7,717		)
Net amount recognized	$	33,757		$	28,258		$	(5,925	)	$	(4,736	)	$	(10,070	)	$	(7,717	)
Amounts Not Yet Recognized as a Component
of Cost and Recognized in a Deferred
Regulatory Account:
Unrecognized transition obligation	$	—		$	—		$	—		$	—		$	—		$	—
Unrecognized prior service credit (cost)	15,046			17,243			(439		)	(196		)	—			—
Unrecognized actuarial loss	(103,038		)	(96,338		)	(1,745		)	(820		)	(3,995		)	(354		)
Regulatory asset	(87,992		)	(79,095		)	(2,184		)	(1,016		)	(3,995		)	(354		)
Cumulative employer contributions in
excess of cost	121,749			107,353			(3,741		)	(3,720		)	(6,075		)	(7,363		)
Net amount recognized	$	33,757		$	28,258		$	(5,925	)	$	(4,736	)	$	(10,070	)	$	(7,717	)

In 2006 with the implementation of accounting guidance for employers’ accounting for defined benefit pension and other postretirement plans, the NCUC, the PSCSC and the TRA approved our request to place certain defined benefit postretirement obligations in a deferred regulatory account instead of OCIL as presented above. The regulators have allowed future recovery of our pension and OPEB costs to this date.

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Net periodic benefit cost for the years ended October 31, 2014, 2013 and 2012 includes the following components.

	Qualified Pension									Nonqualified Pension									Other Benefits
In thousands	2014			2013			2012			2014			2013			2012			2014			2013			2012
Service cost	$	10,865		$	12,005		$	9,573		$	—		$	—		$	39		$	1,109		$	1,327		$	1,387
Interest cost	11,781			9,946			10,640			200			157			203			1,448			1,130			1,347
Expected return on plan assets	(22,530		)	(21,105		)	(20,289		)	—			—			—			(1,782		)	(1,663		)	(1,551		)
Amortization of transition obligation	—			—			—			—			—			—			—			667			667
Amortization of prior service cost
(credit)	(2,198		)	(2,198		)	(2,198		)	243			81			81			—			—			—
Amortization of net loss	7,685			11,202			5,966			31			161			49			—			—			—
Net periodic benefit cost	5,603			9,850			3,692			474			399			372			775			1,461			1,850
Other changes in plan assets and benefit
obligation recognized through
regulatory asset or liability:
Prior service cost	—			—			—			485			—			—			—			—			—
Net loss (gain)	14,385			(30,094		)	43,945			956			(540		)	629			3,641			(2,278		)	2,209
Amounts recognized as a component of
net periodic benefit cost:
Transition obligation	—			—			—			—			—			—			—			(667		)	(667		)
Amortization of net loss	(7,685		)	(11,202		)	(5,966		)	(31		)	(161		)	(49		)	—			—			—
Prior service (cost) credit	2,198			2,198			2,198			(243		)	(81		)	(81		)	—			—			—
Total recognized in regulatory asset
(liability)	8,898			(39,098		)	40,177			1,167			(782		)	499			3,641			(2,945		)	1,542
Total recognized in net periodic benefit
and regulatory asset (liability)	$	14,501		$	(29,248	)	$	43,869		$	1,641		$	(383	)	$	871		$	4,416		$	(1,484	)	$	3,392

The 2015 estimated amortization of the following items for our plans, which are recorded as a regulatory asset or liability instead of accumulated OCIL discussed above, are as follows.

	Qualified			Nonqualified		Other
In thousands	Pension			Pension		Benefits
Amortization of unrecognized prior service (credit) cost	$	(2,198	)	$	231	$	—
Amortization of unrecognized actuarial loss	8,121			85		29

The discount rate has been separately determined for each plan by projecting the plan’s cash flows and developing a zero-coupon spot rate yield curve using non-arbitrage pricing and non-callable bonds rated AA or better by either Moody’s Investors Service’s or Standard & Poor’s Ratings Services that have a yield higher than the regression mean yield curve. The discount rate can vary from plan year to plan year. As of October 31, 2014, the benchmark by plan was as follows.

Pension plan	4.13	%
NCNG SERP	3.64	%
Directors’ SERP	3.74	%
Piedmont SERP	3.10	%
OPEB	4.03	%

Equity market performance has a significant effect on our market-related value of plan assets. In determining the market-related value of plan assets, we use the following methodology: The asset gain or loss is determined each year by comparing the fund’s actual return to the expected return, based on the disclosed expected return on investment assumption. Such asset gain or loss is then recognized ratably over a five-year period. Thus, the market-related value of assets as of year end is determined by adjusting the market value of assets by the portion of the prior five years’ gains or losses that has not yet been recognized, meaning that 20% of the prior five years’ asset gains and losses are recognized each year. This method has been applied consistently in all years presented in the consolidated financial statements.

We amortize unrecognized prior-service cost over the average remaining service period for active employees. We amortize the unrecognized transition obligation over the average remaining service period for active employees expected to receive benefits under the plan as of the date of transition. We amortize gains and losses in excess of 10% of the greater of the benefit obligation and the market-related value of assets over the average remaining service period for active employees. The amortization period used for the purposes mentioned above for the NCNG SERP and the Piedmont SERP is an expected future lifetime as there are no active members in these plans. The method of amortization in all cases is straight-line.

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The weighted average assumptions used in the measurement of the benefit obligation as of October 31, 2014 and 2013 are presented below.

	Qualified Pension				Nonqualified Pension				Other Benefits
	2014		2013		2014		2013		2014		2013
Discount rate	4.13	%	4.55	%	3.69	%	3.98	%	4.03	%	4.44	%
Rate of compensation increase	3.68	%	3.72	%	N/A		N/A		N/A		N/A

In addition to the assumptions in the above table, we also use subjective factors such as withdrawal and mortality rates in determining benefit obligations for all of our benefit plans. As of October 31, 2014, we updated our assumed mortality rates to incorporate the new set of mortality tables issued by the Society of Actuaries in October 2014.

The weighted average assumptions used to determine the net periodic benefit cost as of October 31, 2014, 2013 and 2012 are presented below.

	Qualified Pension						Nonqualified Pension
	2014		2013		2012		2014		2013		2012
Discount rate	4.55	%	3.51	%	4.67	%	3.98	%	2.95	%	4.10	%
Expected long-term rate of return on plan assets	7.75	%	8.00	%	8.00	%	N/A		N/A		N/A
Rate of compensation increase	3.72	%	3.76	%	3.78	%	N/A		N/A		N/A
	Other Benefits
	2014		2013		2012
Discount rate	4.44	%	3.34	%	4.36	%
Expected long-term rate of return on plan assets	7.75	%	8.00	%	8.00	%
Rate of compensation increase	N/A		N/A		N/A

We anticipate that we will contribute the following amounts to our plans in 2015.

In thousands
Qualified pension plan *	$	10,000
Nonqualified pension plans	521
MPP plan	1,300
OPEB plan	1,500

* Funded in November 2014.

The Pension Protection Act of 2006 (PPA) specified funding requirements for single employer defined benefit pension plans. The PPA established a 100% funding target for plan years beginning after December 31, 2007, and we are in compliance.

Benefit payments, which reflect expected future service, as appropriate, are expected to be paid for the next ten years ending October 31 as follows.

	Qualified		Nonqualified		Other
In thousands	Pension		Pension		Benefits
2015	$	29,946	$	521	$	2,409
2016	16,794		507		2,449
2017	16,332		491		2,527
2018	19,197		472		2,606
2019	20,685		490		2,682
2020 - 2024	110,459		2,149		14,179

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The assumed health care cost trend rates used in measuring the accumulated OPEB obligation for the medical plans for all participants as of October 31, 2014 and 2013 are presented below.

	2014		2013
Health care cost trend rate assumed for next year	7.40	%	7.40	%
Rate to which the cost trend is assumed to decline (the ultimate trend rate)	5.00	%	5.00	%
Year that the rate reaches the ultimate trend rate	2027		2027

The health care cost trend rate assumptions could have a significant effect on the amounts reported. A change of 1% would have the following effects.

In thousands	1% Increase		1% Decrease
Effect on total of service and interest cost components of net periodic
postretirement health care benefit cost for the year ended October 31, 2014	$	31	$	(32	)
Effect on the health care cost component of the accumulated postretirement
benefit obligation as of October 31, 2014	829		(841		)

Fair Value Measurements

Mutual funds are valued at the quoted NAV per share, which is computed as of the close of business on our balance sheet date. Mutual funds with a publicly quoted NAV per share are classified as Level 1; mutual funds with a NAV per share that is not publicly available are classified as Level 2.

Following is a description of the valuation methodologies used for assets measured at fair value in our qualified pension plan.

Cash and cash equivalents – These are Level 1 assets valued at face value as they are primarily cash or cash equivalents. The assets that are Level 2 assets have been valued at the market value of the shares held by the plan at the valuation date for a money market mutual fund.

U.S. treasuries – These are Level 2 assets whose values are based on observable market information including quotes from a quotation reporting system, established market makers or pricing services. This asset class includes long duration fixed income investments.

Long duration bonds – These are Level 2 assets in an actively managed private series long duration fixed income fund valued using pricing models that consider various observable inputs, such as benchmark yields, reported trades, broker quotes and issuer spreads.

Corporate bonds, collateralized mortgage obligations, municipals – These are Level 2 assets valued based on primarily observable market information or broker quotes on a non-active market. This class includes long duration fixed income investments.

High yield bonds – These are Level 1 assets valued at the quoted NAV of high yield fixed income mutual fund shares.

Derivatives – The Level 1 assets were valued using a compilation of observable market information on an active market. The Level 2 assets were valued using broker quotes on a non-active market.

Large cap core index – These are Level 1 assets valued at the quoted NAV of the low-cost equity index mutual fund that tracks the Standard & Poor’s 500 Stock Index (S&P 500 Index).

Large cap value and small cap value – These are Level 1 assets valued at the market price of the active market on which the individual security is traded.

Large cap growth and global REIT – These are Level 1 assets valued at the quoted NAV of mutual fund shares in managed equity funds.

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Common trust funds – International growth and bank loans (and for 2013, international value) – These are Level 2 assets held in common trust funds in which we own interests that are valued at the NAV of the funds as traded on international exchanges. Currently there are no restrictions on redemptions for the funds.

Hedge fund of funds – This is a Level 2 asset with the value of our investment based on the estimated fair value of the underlying holdings in the portfolio at a NAV. These investments are across a variety of markets through investment funds or managed accounts that invest in equities, equity-related instruments, fixed income and other debt-related instruments. Currently there are no restrictions on redemptions for the fund.

Private equity fund of funds – This is a Level 3 asset invested in hedge fund of funds valued based on a quarterly compilation of the financial statements from the underlying partnerships in which the fund invests. There are currently redemption restrictions for this fund. The target allocation for this investment is 3.5% but is still being funded through capital calls; $5.4 million of the original $12 million subscription remains unfunded. Until a 3.5% allocation can be achieved, the balance of the 3.5% allocation is invested in a low-cost equity index fund that tracks the S&P 500 Index. Our investment is in various funds that invests in North American companies; allocate capital to private equity funds; invest in venture capital partnerships; and private equity partnerships in emerging markets.

Commodities fund of funds – This is a Level 2 asset with the value of our investment based on the estimated fair value of the various holdings in the portfolio as reported in the financial statements at a NAV. Currently there are no restrictions on redemptions for the fund. These investments are in commodities fund of funds that are actively managed through a well-diversified group of underlying managers.

As stated above, some of our investments for the qualified pension plan have redemption limitations, restrictions and notice requirements which are further explained below.

			Redemptions
	Redemption		Notice
Investment	Frequency	Other Redemption Restrictions	Period
Common trust fund - International growth	Monthly	None	30 days
Hedge fund of funds	Quarterly	Redeemed in whole or part but not less than the minimum redemption amount for each currency. Redemption within one year of purchase is subject to 1.5% redemption fee. Redeemed on “first in first out” basis. None of our investment is subject to the redemption fee. Fund’s Board of Directors may limit or suspend share redemptions until a further notification ending suspension. No such notification has been received as of October 31, 2014.	65 days
Private equity fund of funds	Limited	Investors have only very limited withdrawal rights for specific legal or regulatory reasons. Any transfer of interest will be subject to approval.	(1)
Commodities fund of funds	Monthly	Redemption within one year of purchase is subject to 1% redemption fee. None of our investment is subject to the redemption fee. If 95% or more of the balance is requested, 95% of the balance will be paid within 30 days. Any outstanding balance or interest owed will be paid after the annual audit is complete.	35 days
Bank loans	Daily	None	30 days

(1) The investment cannot be redeemed. We receive distributions only through the liquidation of the underlying assets. The assets are expected to be liquidated over the next 10 to 12 years.

The qualified pension plan’s asset allocations by level within the fair value hierarchy at October 31, 2014 and 2013 are presented below. Our assessment of the significance of a particular input to the fair value measurement requires judgment

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and may affect the valuation of fair value assets and their consideration within the fair value hierarchy levels. For further information on a description of the fair value hierarchy, see “Fair Value Measurements” in Note 1 to the consolidated financial statements.

	Qualified Pension Plan as of October 31, 2014
				Significant Other Observable Inputs(Level 2)
	Quoted Prices In Active Markets (Level 1)						Significant Unobservable Inputs (Level 3)
										Total Carrying Value			% of Total
In thousands
Cash and cash equivalents	$	27,932		$	435		$	—		$	28,367		8	%
Fixed Income Securities:													45	%
U.S. treasuries	—			27,224			—			27,224			8	%
Long duration bonds	—			48,049			—			48,049			14	%
Corporate bonds	—			49,816			—			49,816			15	%
High yield bonds	8,100			—			—			8,100			3	%
Common trust fund - Bank loans	—			16,187			—			16,187			5	%
Collateralized mortgage
obligations	—			1,035			—			1,035			—	%
Derivatives	48			(49		)	—			(1		)	—	%
Equity Securities:													31	%
Large cap core index	9,982			—			—			9,982			3	%
Large cap value	19,937			—			—			19,937			6	%
Large cap growth	19,745			—			—			19,745			6	%
Small cap value	31,329			—			—			31,329			9	%
Common trust fund - International
growth	—			22,877			—			22,877			7	%
Real Estate:													5	%
Global REIT	16,675			—			—			16,675			5	%
Other Investments:													11	%
Hedge fund of funds	—			19,829			—			19,829			6	%
Private equity fund of funds	—			—			7,158			7,158			2	%
Commodities fund of funds	—			10,134			—			10,134			3	%
Total assets at fair value	$	133,748		$	195,537		$	7,158		$	336,443		100	%
Percent of fair value hierarchy	40		%	58		%	2		%	100		%

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	Qualified Pension Plan as of October 31, 2013
				Significant Other Observable Inputs(Level 2)
	Quoted Prices In Active Markets (Level 1)						Significant Unobservable Inputs (Level 3)
										Total Carrying Value			% of Total
In thousands
Cash and cash equivalents	$	5,566		$	156		$	—		$	5,722		2	%
Fixed Income Securities:													38	%
U.S. treasuries	—			24,078			—			24,078			8	%
Long duration bonds	—			34,041			—			34,041			11	%
Corporate bonds	—			42,701			—			42,701			14	%
High yield bonds	14,680			—			—			14,680			5	%
Collateralized mortgage
obligations	—			1,098			—			1,098			—	%
Derivatives	6			(17		)	—			(11		)	—	%
Equity Securities:													43	%
Large cap core index	12,023			—			—			12,023			4	%
Large cap value	16,908			—			—			16,908			6	%
Large cap growth	17,823			—			—			17,823			6	%
Small cap value	30,831			—			—			30,831			10	%
Common trust fund - International
value	—			24,460			—			24,460			8	%
Common trust fund - International
growth	—			27,270			—			27,270			9	%
Real Estate:													5	%
Global REIT	15,042			—			—			15,042			5	%
Other Investments:													12	%
Hedge fund of funds	—			18,571			—			18,571			6	%
Private equity fund of funds	—			—			4,659			4,659			2	%
Commodities fund of funds	—			10,765			—			10,765			4	%
Total assets at fair value	$	112,879		$	183,123		$	4,659		$	300,661		100	%
Percent of fair value hierarchy	37		%	61		%	2		%	100		%

The following is a reconciliation of the assets in the qualified pension plan that are classified as Level 3 in the fair value hierarchy.

	Private
	Equity Fund
In thousands	of Funds
Balance, October 31, 2012	$	3,522
Actual return on plan assets:
Relating to assets still held at the reporting date	116
Relating to assets sold during the period	61
Purchases, sales and settlements (net)	960
Transfer in/out of Level 3	—
Balance, October 31, 2013	4,659
Actual return on plan assets:
Relating to assets still held at the reporting date	1,031
Relating to assets sold during the period	113
Purchases, sales and settlements (net)	1,355
Transfer in/out of Level 3	—
Balance, October 31, 2014	$	7,158

During the year, the qualified pension plan raises cash from various plan assets in order to fund periodic and lump sum benefit payments. Cash is raised as needed primarily from investments that have exceeded their target allocation and is dependent upon the number of retirees seeking lump sum distributions.

There are significant unobservable inputs used in the fair value measurements of our investment in the private equity fund of funds’ limited partnerships. We are subject to the business risks inherent in the markets in which the partnerships are invested. The success or failure of the underlying businesses of the various partnerships that have been funded would result in a higher or lower fair value measurement.

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Following is a description of the valuation methodologies used for assets measured at fair value in our OPEB plan with all of the OPEB plan’s assets invested in mutual funds.

Cash and cash equivalents – These are Level 1 assets having maturities of three months or less when purchased and are considered to be cash equivalents.

U.S. treasuries – These are Level 1 assets in an actively managed mutual fund measured at NAV.

Corporate bonds/Other fixed income securities – These are Level 1 assets valued at the quoted NAV of mutual fund investments that are primarily invested in investment grade securities that mature within ten years. The OPEB plan maintains a 5% target allocation to high yield fixed income.

Large cap value, large cap growth, small cap growth, small cap value – These are Level 1 assets valued at the quoted NAV as invested in mutual funds that invest by a specific style.

Large cap index – These are Level 1 assets valued at the NAV as invested in a low-cost equity index mutual fund that tracks the S&P 500 Index.

International blend – These are Level 1 assets valued at the quoted NAV of mutual fund shares in managed global equity funds outside of the United States whose styles include both growth and value investments.

Global REIT – These are Level 1 assets valued at the quoted NAV of mutual fund shares in a managed equity fund that invests globally but primarily in the United States.

The OPEB plan’s asset allocations by level within the fair value hierarchy at October 31, 2014 and 2013 are presented below. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and their placement within the fair value hierarchy levels. For further information on a description of the fair value hierarchy, see “Fair Value Measurements” in Note 1 to the consolidated financial statements.

	Other Benefits as of October 31, 2014
				Significant Other Observable Inputs(Level 2)
	Quoted Prices In Active Markets (Level 1)						Significant Unobservable Inputs (Level 3)
										Total Carrying Value			% of Total
In thousands
Cash and cash equivalents	$	2,590		$	—		$	—		$	2,590		9	%
Fixed Income Securities:													44	%
U.S. treasuries	2,013			—			—			2,013			7	%
Corporate bonds / Other fixed income
securities	10,187			—			—			10,187			37	%
Equity Securities:													42	%
Large cap value	1,269			—			—			1,269			4	%
Large cap growth	1,310			—			—			1,310			5	%
Small cap value	1,336			—			—			1,336			5	%
Small cap growth	1,319			—			—			1,319			5	%
Large cap index	2,532			—			—			2,532			9	%
International blend	3,846			—			—			3,846			14	%
Real Estate:													5	%
Global REIT	1,345			—			—			1,345			5	%
Total assets at fair value	$	27,747		$	—		$	—		$	27,747		100	%
Percent of fair value hierarchy	100		%	—		%	—		%	100		%

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	Other Benefits as of October 31, 2013
				Significant Other Observable Inputs(Level 2)
	Quoted Prices In Active Markets (Level 1)						Significant Unobservable Inputs (Level 3)
										Total Carrying Value			% of Total
In thousands
Cash and cash equivalents	$	982		$	—		$	—		$	982		4	%
Fixed Income Securities:													46	%
U.S. treasuries	2,582			—			—			2,582			10	%
Corporate bonds / Other fixed income
securities	9,232			—			—			9,232			36	%
Equity Securities:													45	%
Large cap value	1,327			—			—			1,327			5	%
Large cap growth	1,352			—			—			1,352			5	%
Small cap value	1,331			—			—			1,331			5	%
Small cap growth	1,313			—			—			1,313			5	%
Large cap index	2,384			—			—			2,384			9	%
International blend	4,206			—			—			4,206			16	%
Real Estate:													5	%
Global REIT	1,252			—			—			1,252			5	%
Total assets at fair value	$	25,961		$	—		$	—		$	25,961		100	%
Percent of fair value hierarchy	100		%	—		%	—		%	100		%

401(k) Plan

We maintain a 401(k) plan that is a profit-sharing plan under Section 401(a) of the Internal Revenue Code of 1986, as amended (the Tax Code), which includes qualified cash or deferred arrangements under Tax Code Section 401(k). The 401(k) plan is subject to the provisions of the Employee Retirement Income Security Act. Eligible employees who have completed 30 days of continuous service and have attained age 18 are eligible to participate. Participants may defer a portion of their base salary and cash incentive payments to the plan, and we match a portion of their contributions. Employee contributions vest immediately, and company contributions vest after six months of service.

Employees receive a company match of 100% up to the first 5% of eligible pay contributed. Employees may contribute up to 50% of eligible pay to the 401(k) on a pre-tax basis, up to the Tax Code annual contribution and compensation limits. We automatically enroll all eligible non-participating employees in the 401(k) plan at a 2% contribution rate unless the employee chooses not to participate by notifying our record keeper. For employees who are automatically enrolled in the 401(k) plan, we automatically increase their contributions by 1% each year to a maximum of 5% unless the employee chooses to opt out of the automatic increase by contacting our record keeper. If the employee does not make an investment election, employee contributions and matches are automatically invested in a diversified portfolio of stocks and bonds. Participants may direct up to 20% of their contributions and company matching contributions as an investment in the Piedmont Stock Fund. Employees may change their contribution rate and investments at any time. For the years ended October 31, 2014, 2013 and 2012, we made matching contributions to participant accounts as follows.

In thousands	2014		2013		2012
401(k) matching contributions	$	6,134	$	5,688	$	5,400

As a result of a plan merger effective in 2001, participants’ accounts in our employee stock ownership plan (ESOP) were transferred into the participants’ 401(k) accounts. Former ESOP participants may remain invested in Piedmont common stock in their 401(k) plan or may sell the common stock at any time and reinvest the proceeds in other available investment options. The tax benefit of any dividends paid on ESOP shares still in participants’ accounts is reflected in the Consolidated Statement of Stockholders’ Equity as an increase in retained earnings.

10. Employee Share-Based Plans

Under our shareholder approved ICP, eligible officers and other participants are awarded units that pay out depending upon the level of performance achieved by Piedmont during three-year incentive plan performance periods. Distribution of those awards may be made in the form of shares of common stock and withholdings for payment of applicable taxes on the compensation. These plans require that a minimum threshold performance level be achieved in order for any award to be distributed. For the years ended October 31, 2014, 2013 and 2012, we recorded compensation expense, and as of October 31, 2014 and 2013, we accrued a liability for these awards based on the fair market value of our stock at the end of each quarter. The liability is re-measured to market value at the settlement date.

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We have granted three series of awards under approved incentive compensation plans, each with a three-year performance period (ending October 31, 2014, October 31, 2015 and October 31, 2016). For each of these performance periods, awards will be based on achievement relative to a target annual compounded increase in basic EPS and the achievement of total shareholder returns relative to a group of peer companies that are domiciled in the United States, publicly traded in the U.S. energy industry with a primary focus on natural gas distribution and transmission businesses in multi-state territories and have similar annual revenues and market capitalization to ours, with each measure being weighted at 50%. The plans with performance periods ending October 31, 2015 (2015 plan) and October 31, 2016 (2016 plan) have an additional performance measure of actual average return on equity compared to the weighted average return on equity allowed by our regulatory commissions. The weighting of the units awarded under the 2015 plan and the 2016 plan is based on EPS at 37.5%, total shareholder return at 37.5% and return on equity at 25% of the total units awarded.

In December 2010, a long-term retention stock unit award under the ICP (where a stock unit equals one share of our common stock upon vesting) was approved for eligible officers and other participants to support our succession planning and retention strategies. This retention stock unit award vested for participants who met the retention requirements at the end of the three-year period ending in December 2013 and settled in the same month with payment in the form of shares of common stock and withholdings for payment of applicable taxes on the compensation. The Compensation Committee of our Board of Directors had the discretion to accelerate the vesting of all or a portion of a participant’s units. For the twelve months ended October 31, 2013 and 2012, we recorded compensation expense and a liability as of October 31, 2013 with compensation expense recorded in fiscal 2014 until December 2013 when the award was settled. The liability, which we accrued for this award based on the fair market value of our stock at the end of each quarter, was re-measured to market value in December 2013, the settlement date.

Also under our approved ICP, 64,700 unvested retention stock units were granted to our President and Chief Executive Officer in December 2011. During the five-year vesting period, any dividend equivalents will accrue on these stock units and be converted into additional units at the same rate and based on the closing price on the same payment date as dividends on our common stock. The stock units will vest, payable in the form of shares of common stock and withholdings for payment of applicable taxes on the compensation, over a five-year period only if he is an employee on each vesting date. In accordance with the vesting schedule, 20% of the units vested on December 15, 2014, 30% of the units vest on December 15, 2015 and 50% of the units vest on December 15, 2016. For the twelve months ended October 31, 2014, 2013 and 2012,we recorded compensation expense, and as of October 31, 2014 and 2013, we accrued a liability for this award based on the fair market value of our stock at the end of each quarter. The liability is re-measured to market value at the settlement date.

The award which vested on December 15, 2014 covered 20% of the grant, including accrued dividends, for a total of 14,461 shares of common stock. After the withholding of $.3 million for federal and state income taxes, our President and Chief Executive Officer received 7,231 shares at the New York Stock Exchange composite closing price on December 12, 2014 of $37.89 per share.

At the time of distribution of awards under the ICP, the number of shares issuable is reduced by the withholdings for payment of applicable income taxes for each participant. The participant may elect income tax withholdings at or above the minimum statutory withholding requirements. The maximum withholdings allowed is 50%. To date, shares withheld for payment of applicable income taxes have been immaterial. We present these net shares issued in the Consolidated Statements of Stockholders’ Equity and in Note 6 to the consolidated financial statements.

The compensation expense related to the incentive compensation plans for the years ended October 31, 2014, 2013 and 2012, and the amounts recorded as liabilities in "Other noncurrent liabilities" in "Noncurrent Liabilities" with the current portion recorded in "Other current liabilities" in "Current Liabilities" in the Consolidated Balance Sheets as of October 31, 2014 and 2013 are presented below.

In thousands	2014		2013		2012
Compensation expense	$	8,496	$	4,526	$	5,730
Tax benefit	2,476		1,538		2,080
Liability	15,130		11,098

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Based on current accrual assumptions as of October 31, 2014, the expected payout for the approved incentive compensation awards at target will occur in the following fiscal years.

In thousands	2015		2016		2017
Amount of payout	$	7,204	$	4,980	$	2,946

On a quarterly basis, we issue shares of common stock under the ESPP and account for the issuance as an equity transaction. The exercise price is calculated as 95% of the fair market value on the purchase date of each quarter where fair market value is determined by calculating the mean average of the high and low trading prices on the purchase date.

11. Income Taxes

The components of income tax expense for the years ended October 31, 2014, 2013 and 2012 are presented below.

	2014					2013						2012
In thousands	Federal			State		Federal			State			Federal			State
Charged (Credited) to operating
income:
Current (1)	$	(1,653	)	$	950	$	(3,032	)	$	919		$	(29,062	)	$	1,857
Deferred (1)	70,654			13,434		67,885			11,829			86,496			10,144
Tax Credits:
Amortization	(209		)	—		(267		)	—			(334		)	—
Total	68,792			14,384		64,586			12,748			57,100			12,001
Charged (Credited) to other income
(expense):
Current	4,233			870		6,049			984			5,636			1,027
Deferred	5,811			728		2,225			(646		)	2,214			239
Total	10,044			1,598		8,274			338			7,850			1,266
Total	$	78,836		$	15,982	$	72,860		$	13,086		$	64,950		$	13,267

⁽¹⁾ Includes utilization of federal NOL carryforward benefit of $28.6 million for the year ended October 31, 2014 and the generation of a NOL carryforward benefit of $62.3 million for the year ended October 31, 2013.

A reconciliation of income tax expense at the federal statutory rate to recorded income tax expense for the years ended October 31, 2014, 2013 and 2012 is presented below.

In thousands	2014			2013			2012
Federal taxes at 35%	$	83,517		$	77,127		$	69,322
State income taxes, net of federal benefit	10,389			8,506			8,624
Amortization of investment tax credits	(209		)	(267		)	(334		)
Other, net	1,121			580			605
Total	$	94,818		$	85,946		$	78,217

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As of October 31, 2014 and 2013, deferred income taxes consisted of the following temporary differences.

In thousands	2014			2013
Deferred tax assets:
Benefit of loss carryforwards	$	39,532		$	66,087
Revenues and cost of gas	4,960			—
Employee benefits and compensation	16,547			13,834
Revenue requirement	20,320			19,062
Utility plant	5,631			10,386
Other	12,869			12,796
Total deferred tax assets	99,859			122,165
Valuation allowance	(505		)	(505		)
Total deferred tax assets, net	99,354			121,660
Deferred tax liabilities:
Utility plant	724,172			652,822
Revenues and cost of gas	4,340			21,257
Equity method investments	42,998			38,710
Deferred costs	65,828			59,221
Other	18,065			18,324
Total deferred tax liabilities	855,403			790,334
Net deferred income tax liabilities	$	756,049		$	668,674

As of October 31, 2014 and 2013, total net deferred income tax assets were net of a valuation allowance to reduce amounts to the amounts that we believe will be more likely than not realized. We and our wholly-owned subsidiaries file a consolidated federal income tax return and various state income tax returns. As of October 31, 2014 and 2013, we have federal NOL carryforwards of $97 million and $178.1 million, respectively, which expire in 2033. We also have $5.9 million of federal NOL carryforwards as of October 31, 2014 and 2013 that expire in 2021 through 2025 and are subject to an annual limitation of $.3 million. As of October 31, 2014, we have a $2.4 million alternative minimum tax credit carryforward.

As of October 31, 2014 and 2013, we have state NOL carryforwards of $7.2 million and $6.4 million, respectively, that expire from 2020 through 2028. We may use the carryforwards to offset taxable income.

We are no longer subject to federal income tax examinations for tax years ending before and including October 31, 2009, and with few exceptions, state income tax examinations by tax authorities for years ended before and including October 31, 2009. The IRS is currently auditing the federal income tax returns for years ended October 31, 2010, 2011 and 2012.

A reconciliation of changes in the deferred tax valuation allowance for the years ended October 31, 2014, 2013 and 2012 is presented below.

In thousands	2014		2013		2012
Balance at beginning of year	$	505	$	505	$	505
Credited to income tax expense	—		—		—
Balance at end of year	$	505	$	505	$	505

There were no unrecognized tax benefits for the years ended October 31, 2014 and 2013.

In July 2013, legislation was passed in North Carolina affecting corporate taxation. The legislation reduced the corporate income tax rate from 6.9% to 6% for tax years beginning after January 1, 2014 and to 5% for tax years beginning after January 1, 2015. It also provided for two additional 1% rate reductions if the state’s tax collections exceed certain thresholds. We record deferred income taxes on temporary tax differences using the income tax rate in effect when the temporary difference is expected to reverse. As a result of the rate reductions, we adjusted our noncurrent deferred income tax balances at October 31, 2013 by approximately $25 million for temporary differences expected to reverse at a lower rate than

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under the prior law and recognized a tax benefit of approximately $1 million in net income, the majority of which relates to our regulated non-utility activities segment, with the balance of approximately $24 million recorded in deferred income taxes in “Regulatory Liabilities” as presented in Note 1 to the consolidated financial statements, reflecting a future benefit to our customers. During fiscal 2014, we recorded an additional $3 million for the difference in the tax rate included in our customers' rates and the rate at which the deferred taxes are expected to reverse. This increased our deferred income taxes recorded in “Regulatory Liabilities” to approximately $27 million. Our state regulatory commissions will determine the refund period of this regulatory liability in future proceedings.

12. Equity Method Investments

The consolidated financial statements include the accounts of wholly-owned subsidiaries whose investments in joint venture, energy-related businesses are accounted for under the equity method. Our ownership interest in each entity is included in “Equity method investments in non-utility activities” in “Noncurrent Assets” in the Consolidated Balance Sheets. Earnings or losses from equity method investments are included in “Income from equity method investments” in “Other Income (Expense)” in the Consolidated Statements of Comprehensive Income.

As of October 31, 2014, there were no amounts that represented undistributed earnings of our 50% or less owned equity method investments in our retained earnings.

Cardinal Pipeline Company, L.L.C.

We own 21.49% of the membership interests in Cardinal Pipeline Company, L.L.C. (Cardinal), a North Carolina limited liability company. The other members are subsidiaries of The Williams Companies, Inc., and SCANA Corporation. Cardinal owns and operates an intrastate natural gas pipeline in North Carolina and is regulated by the NCUC. Cardinal has firm, long-term service agreements with local distribution companies for 100% of the firm transportation capacity on the pipeline, of which Piedmont subscribes to approximately 53%. Cardinal is dependent on the Williams – Transco pipeline system to deliver gas into its system for service to its customers.

Cardinal enters into interest-rate swap agreements to modify the interest expense characteristics of its unsecured long-term debt. Our share of movements in the market value of these agreements are recorded as a hedge in “Accumulated other comprehensive loss” in “Stockholders’ equity” in the Consolidated Balance Sheets; the detail of our share of the market value of the swap agreements is combined with our other equity method investments and presented in “Other Comprehensive Income (Loss), net of tax” in the Consolidated Statements of Comprehensive Income. Cardinal’s long-term debt is nonrecourse to the members.

We have related party transactions as a transportation customer of Cardinal, and we record the transportation costs charged by Cardinal in “Cost of Gas” in the Consolidated Statements of Comprehensive Income. For each of the years ended October 31, 2014, 2013 and 2012, these transportation costs and the amounts we owed Cardinal as of October 31, 2014 and 2013 are as follows.

In thousands	2014		2013		2012
Transportation costs	$	8,825	$	8,775	$	6,613
Trade accounts payable	747		755

Summarized financial information provided to us by Cardinal for 100% of Cardinal as of September 30, 2014 and 2013, and for the twelve months ended September 30, 2014, 2013 and 2012 is presented below.

In thousands	2014		2013		2012
Current assets	$	8,856	$	15,179
Noncurrent assets	111,881		116,414
Current liabilities	1,468		2,637
Noncurrent liabilities	45,402		45,273
Revenues	16,705		17,649		$	16,165
Gross profit	16,705		17,649		16,165
Income before income taxes	8,042		9,361		10,433

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Pine Needle LNG Company, L.L.C.

We own 45% of the membership interests in Pine Needle LNG Company, L.L.C. (Pine Needle), a North Carolina limited liability company that owns an interstate LNG storage facility in North Carolina regulated by the FERC. Pine Needle has firm, long-term service agreements for 100% of the storage capacity of the facility, of which Piedmont subscribes to approximately 64%. Effective July 1, 2013, we acquired Hess Corporation’s 5% membership interest in Pine Needle for $2.9 million,which increased our membership interest from 40% to 45%. The other members are the Municipal Gas Authority of Georgia and subsidiaries of The Williams Companies, Inc. and SCANA Corporation.

Pine Needle enters into interest-rate swap agreements to modify the interest expense characteristics of its long-term debt. Our share of movements in the market value of these agreements are recorded as a hedge in “Accumulated other comprehensive loss” in “Stockholders’ equity” in the Consolidated Balance Sheets; the detail of our share of the market value of the swap agreements is combined with our other equity method investments and presented in “Other Comprehensive Income (Loss), net of tax” in the Consolidated Statements of Comprehensive Income. Pine Needle’s long-term debt is nonrecourse to the members.

We have related party transactions as a customer of Pine Needle, and we record the storage costs charged by Pine Needle in “Cost of Gas” in the Consolidated Statements of Comprehensive Income. For the years ended October 31, 2014, 2013 and 2012, these gas storage costs and the amounts we owed Pine Needle as of October 31, 2014 and 2013 are as follows.

In thousands	2014		2013		2012
Gas storage costs	$	11,364	$	11,098	$	10,410
Trade accounts payable	989		940

Summarized financial information provided to us by Pine Needle for 100% of Pine Needle as of September 30, 2014 and 2013, and for the twelve months ended September 30, 2014, 2013 and 2012 is presented below.

In thousands	2014		2013		2012
Current assets	$	8,812	$	9,225
Noncurrent assets	70,837		74,710
Current liabilities	38,029		3,531
Noncurrent liabilities	—		35,391
Revenues	18,025		16,810		$	16,390
Gross profit	18,025		16,810		16,390
Income before income taxes	6,011		5,804		5,832

SouthStar Energy Services LLC

We own 15% of the membership interests in SouthStar, a Delaware limited liability company. The other member is Georgia Natural Gas Company (GNGC), a wholly-owned subsidiary of AGL Resources, Inc. (AGL). SouthStar primarily sells natural gas in the unregulated retail gas market to residential, commercial and industrial customers in the eastern United States, primarily in Georgia and Illinois. We account for our investment in SouthStar using the equity method, as we have board representation with equal voting rights on significant governance matters and policy decisions, and thus, exercise significant influence over the operations of SouthStar.

In September 2013, GNGC contributed its retail natural gas marketing assets and customer accounts located in Illinois. AGL acquired these retail assets and customers from Nicor Inc. in December 2011 and additional retail natural gas assets and customer accounts in a separate transaction in June 2013. We made an additional $22.5 million capital contribution to SouthStar, maintaining our 15% equity ownership, related to this transaction.

SouthStar’s business is seasonal in nature as variations in weather conditions generally result in greater revenue and earnings during the winter months when weather is colder and natural gas consumption is higher. Also, because SouthStar is not a rate-regulated company, the timing of its earnings can be affected by changes in the wholesale price of natural gas. While SouthStar uses financial contracts to moderate the effect of price and weather changes on the timing of its earnings, wholesale price and weather volatility can cause variations in the timing of the recognition of earnings.

99

These financial contracts, in the form of futures, options and swaps, are considered to be derivatives and fair value is based on selected market indices. Beginning in 2014, retirement benefits were allocated to SouthStar by its majority member with the activity of prescribed benefit expense items reflected in accumulated OCIL. Our share of movements in the market value of these derivative contracts are recorded as a hedge and the activity of the retirement benefit items are reflected in “Accumulated other comprehensive loss” in “Stockholders’ equity” in the Consolidated Balance Sheets; the detail of our share of the market value of these contracts and the retirement benefits are combined with our other equity method investments and presented in “Other Comprehensive Income (Loss), net of tax” in the Consolidated Statements of Comprehensive Income.

We have related party transactions as we sell wholesale gas supplies to SouthStar, and we record the amounts billed to SouthStar in “Operating Revenues” in the Consolidated Statements of Comprehensive Income. For the years ended October 31, 2014, 2013 and 2012, our operating revenues from these sales and the amounts SouthStar owed us as of October 31, 2014 and 2013 are as follows.

In thousands	2014		2013		2012
Operating revenues	$	3,541	$	3,291	$	2,442
Trade accounts receivable	460		441

Summarized financial information provided to us by SouthStar for 100% of SouthStar as of September 30, 2014 and 2013, and for the twelve months ended September 30, 2014, 2013 and 2012 is presented below.

In thousands	2014		2013*		2012
Current assets	$	196,286	$	199,425
Noncurrent assets	143,420		147,571
Current liabilities	51,435		76,346
Noncurrent liabilities	83		31
Revenues	845,695		639,426		$	585,291
Gross profit	234,581		174,993		161,122
Income before income taxes	136,569		102,805		94,631

* Amounts have been changed to reflect restatement of AGL's Form 10-K for the year ended December 31, 2013. The restatement had an immaterial impact on SouthStar's results.

Hardy Storage Company, LLC

We own 50% of the membership interests in Hardy Storage Company, LLC (Hardy Storage), a West Virginia limited liability company. The other owner is a subsidiary of Columbia Gas Transmission Corporation, a subsidiary of NiSource Inc. Hardy Storage owns and operates an underground interstate natural gas storage facility located in Hardy and Hampshire Counties, West Virginia, that is regulated by the FERC. Hardy Storage has firm, long-term service agreements for 100% of the storage capacity of the facility, of which Piedmont subscribes to approximately 40%.

We have related party transactions as a customer of Hardy Storage, and we record the storage costs charged by Hardy Storage in “Cost of Gas” in the Consolidated Statements of Comprehensive Income. For the years ended October 31, 2014, 2013 and 2012, these gas storage costs and the amounts we owed Hardy Storage as of October 31, 2014 and 2013 are as follows.

In thousands	2014		2013		2012
Gas storage costs	$	9,461	$	9,702	$	9,702
Trade accounts payable	774		808

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Summarized financial information provided to us by Hardy Storage for 100% of Hardy Storage as of October 31, 2014 and 2013, and for the twelve months ended October 31, 2014, 2013 and 2012 is presented below.

In thousands	2014		2013		2012
Current assets	$	12,644	$	7,641
Noncurrent assets	157,861		161,282
Current liabilities	17,316		12,378
Noncurrent liabilities	78,830		87,184
Revenues	23,804		24,375		$	24,359
Gross profit	23,804		24,375		24,359
Income before income taxes	10,497		10,582		9,939

Constitution Pipeline Company, LLC

We own 24% of the membership interests of Constitution Pipeline Company, LLC (Constitution), a Delaware limited liability company. The other members are subsidiaries of The Williams Companies, Inc., Cabot Oil & Gas Corporation and WGL Holdings, Inc. A subsidiary of The Williams Companies is the operator of the project. The purpose of the joint venture is to develop, construct, own and operate approximately 120 miles of interstate natural gas pipeline and related facilities connecting shale natural gas supplies and gathering systems in Susquehanna County, Pennsylvania, to the Iroquois Gas Transmission and Tennessee Gas Pipeline systems in New York. We have committed to fund an amount in proportion to our ownership interest for the development and construction of the new pipeline, which is expected to cost approximately $730 million at the project level. As of October 31, 2014, our fiscal year contributions were $37.6 million, with our total equity contributions for the project totaling $53.5 million to date. On December 2, 2014, the FERC issued a certificate of public convenience and necessity approving construction of the Constitution pipeline. The target in-service date of the project is late 2015 or 2016. The capacity of the pipeline is 100% subscribed under fifteen year service agreements with two Marcellus producer-shippers with a negotiated rate structure.

Summarized financial information provided to us by Constitution for 100% of Constitution as of September 30, 2014 and 2013, and for the twelve months ended September 30, 2014 and 2013 is presented below.

In thousands	2014		2013 (1)
Current assets	$	11,273	$	10,944
Noncurrent assets	219,208		62,438
Current liabilities	7,667		7,960
Noncurrent liabilities	—		—
Revenues	—		—
Gross profit	—		—
Income before income taxes	10,091		3,459
(1) Presented in the period in which we have a membership interest in Constitution, and not prior periods when we had no membership interest in Constitution. Our membership in Constitution began in November 2012.

Atlantic Coast Pipeline, LLC

On September 2, 2014, Piedmont, Duke Energy, Dominion Resources, Inc. (Dominion), and AGL announced the formation of Atlantic Coast Pipeline, LLC (ACP), a Delaware limited liability company. ACP intends to construct, operate and maintain a 550 mile natural gas pipeline, with associated compression, from West Virginia through Virginia into eastern North Carolina. The pipeline is proposed to provide interstate natural gas transportation services for Marcellus and Utica gas supplies into southeastern markets. ACP, which is regulated by the FERC, will be designed with an initial capacity of 1.5 billion cubic feet per day with a target in-service date of late 2018. The capacity of ACP is substantially subscribed by the members of ACP, other utilities and related companies under twenty-year contracts.

We entered into an agreement through a wholly-owned subsidiary to become a 10% equity member of ACP. The other members are subsidiaries of Duke Energy, Dominion and AGL. A Dominion subsidiary will be the operator of the pipeline. The cost for the development and construction of the pipeline is expected to be between $4.5 billion to $5 billion,

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excluding financing costs. Members anticipate obtaining project financing for 70% of the total costs during the construction period. As of October 31, 2014, we have made no contributions to ACP.

In October 2014, ACP requested approval from the FERC to utilize the pre-filing process under which environmental review for the natural gas pipeline will commence. ACP expects to file its FERC application in the third quarter of 2015, receive the FERC certificate in the summer of 2016 and begin construction thereafter. The project is subject to FERC, state and other federal approvals.

13. Variable Interest Entities

Under accounting guidance, a VIE is a legal entity that conducts a business or holds property whose equity, by design, has any of the following characteristics: an insufficient amount of equity at risk to finance its activities, equity owners who do not have the power to direct the significant activities of the entity (or have voting rights that are disproportionate to their ownership interest), or where equity owners do not receive expected losses or returns. An entity may have an interest in a VIE through ownership or other contractual rights or obligations and that interest changes as the entity’s net assets change. The consolidating investor, or the primary beneficiary, is the entity that has the power to direct the activities of a VIE that most significantly impact the VIE’s economic performance, the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE.

On a quarterly basis, we reassess whether we have a controlling financial interest in and are the primary beneficiary of a VIE. The quarterly reassessment process considers whether we have acquired or divested the power to direct the activities of the VIE through changes in governing documents or other circumstances. The reassessment also considers whether we have acquired or disposed of a financial interest that could be significant to the VIE, or whether an interest in the VIE has become significant or is no longer significant. The consolidation status of the VIEs with which we are involved may change as a result of such reassessments. Changes in consolidation status are applied prospectively, with assets and liabilities of a newly consolidated VIE initially recorded at fair value. A gain or loss may be recognized upon deconsolidation of a VIE depending on the carrying values of deconsolidated assets and liabilities compared to the fair value of retained interests and ongoing contractual arrangements.

As of October 31, 2014, we have determined that we are not the primary beneficiary under VIE accounting guidance in any of our equity method investments, as discussed in Note 12 to the consolidated financial statements. Based on our involvement in these investments, we do not have the power to direct the activities of these investments that most significantly impact the VIE’s economic performance. As we are not the consolidating investor, we will continue to apply equity method accounting to these investments, as discussed in Note 12 to the consolidated financial statements. Our maximum loss exposure related to these equity method investments is limited to our equity investment in each entity. As of October 31, 2014 and 2013, our investment balances are as follows.

	October 31,		October 31,
In thousands	2014		2013
Cardinal	$	16,073	$	18,207
Pine Needle	18,689		20,270
SouthStar	40,965		38,372
Hardy Storage	37,179		34,681
Constitution	57,255		16,939
ACP	10
Total equity method investments in non-utility activities	$	170,171	$	128,469

We have also reviewed various lease arrangements, contracts to purchase, sell or deliver natural gas and other agreements in which we hold a variable interest. In these cases, we have determined that we are not the primary beneficiary of the related VIE because we do not have the power to direct the activities of the VIE that most significantly impact the VIE’s economic performance, or the obligation to absorb losses of the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE.

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14. Business Segments

We have three reportable business segments, regulated utility, regulated non-utility activities and unregulated non-utility activities. Our segments are identified based on products and services, regulatory environments and our current corporate organization and business decision-making activities. The regulated utility segment is the gas distribution business, where we include the operations of merchandising and its related service work and home service agreements, with activities conducted by the parent company. Although the operations of our regulated utility segment are located in three states under the jurisdiction of individual state regulatory commissions, the operations are managed as one unit having similar economic and risk characteristics within one company.

Prior to this fiscal year ended October 31, 2014, we aggregated the regulated non-utility activities and unregulated non-utility activities into one segment, the non-utility activities segment. These activities shared a majority of characteristics that permitted aggregation under relevant accounting guidance. Based on this accounting guidance, the unaggregated operating activities individually have never met the quantitative thresholds for separate disclosure. In September 2014 with the formation of ACP and our equity membership in the venture, our current and future commitment to fund construction of regulated pipelines through our equity method investments became more significant and, as a result, we have changed our segment presentation to separately disclose our non-utility activities into regulated non-utility and unregulated non-utility activities. The effect on our company's risk profile of regulation versus non-regulation of our equity method investments and management’s view that this segmentation will provide disclosures that will help users of our financial statements to better understand how management assesses organizational performance and makes decisions about the allocation of resources were key factors in our decision to modify our reportable segments. We anticipate significant growth in our regulated non-utility activities as compared to our unregulated non-utility activities. This is especially so given our equity ownership in Constitution and ACP, both FERC regulated pipelines. Once these pipelines are in operation, the earnings contribution is expected to increase for this segment.

Operations of our regulated non-utility activities segment are comprised of our equity method investments in joint ventures with regulated activities that are held by our wholly-owned subsidiaries. Operations of our unregulated non-utility activities segment are comprised primarily of our equity method investment in a joint venture with unregulated activities that is held by a wholly-owned subsidiary; activities of our other minor subsidiaries are also included.

Operations of the regulated utility segment are reflected in “Operating Income” in the Consolidated Statements of Comprehensive Income. Operations of the regulated non-utility activities and unregulated non-utility activities segments are included in the Consolidated Statements of Comprehensive Income in “Other Income (Expense)” in “Income from equity method investments” and “Non-operating income.” All of our operations are within the United States. No single customer accounts for more than 10% of our consolidated revenues.

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Operations by segment for the years ended October 31, 2014, 2013 and 2012, and as of October 31, 2014, 2013 and 2012 are presented below. The information provided for fiscal years 2013 and 2012 have been restated to align with management's view of the non-utility activities.

			Regulated			Unregulated
	Regulated		Non-Utility			Non-Utility
In thousands	Utility		Activities			Activities			Total
2014
Revenues from external customers	$	1,469,988	$	—		$	—		$	1,469,988
Margin	690,208		—			—			690,208
Operations and maintenance expenses	270,877		132			92			271,101
Depreciation	118,996		—			18			119,014
Operating income (loss) before income taxes	263,041		(183		)	(203		)	262,655
Income from equity method investments	—		12,318			20,435			32,753
Interest expense	54,686		—			—			54,686
Income before income taxes	206,253		12,135			20,231			238,619
Total assets	4,442,185		129,206			41,309			4,612,700
Equity method investments in non-utility activities	—		129,206			40,965			170,171
Construction expenditures	460,444		—			—			460,444
			Regulated			Unregulated
	Regulated		Non-Utility			Non-Utility
In thousands	Utility		Activities			Activities			Total
2013
Revenues from external customers	$	1,278,229	$	—		$	—		$	1,278,229
Margin	621,490		—			—			621,490
Operations and maintenance expenses	253,120		103			78			253,301
Depreciation	112,207		—			18			112,225
Operating income (loss) before income taxes	221,528		(150		)	(202		)	221,176
Income from equity method investments	—		10,584			15,472			26,056
Interest expense	24,938		—			—			24,938
Income before income taxes	194,659		10,434			15,270			220,363
Total assets	4,053,591		90,097			38,735			4,182,423
Equity method investments in non-utility activities	—		90,097			38,372			128,469
Construction expenditures	599,999		—			—			599,999
			Regulated			Unregulated
	Regulated		Non-Utility			Non-Utility
In thousands	Utility		Activities			Activities			Total
2012
Revenues from external customers	$	1,122,780	$	—		$	—		$	1,122,780
Margin	575,446		—			—			575,446
Operations and maintenance expenses	242,599		31			71			242,701
Depreciation	103,192		—			18			103,210
Operating income (loss) before income taxes	194,824		(78		)	(186		)	194,560
Income from equity method investments	—		9,709			14,195			23,904
Interest expense	20,097		—			—			20,097
Income before income taxes	174,424		9,631			14,009			198,064
Total assets	3,475,640		69,749			18,498			3,563,887
Equity method investments in non-utility activities	—		69,749			18,118			87,867
Construction expenditures	529,576		—			—			529,576

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Reconciliations to the consolidated financial statements for the years ended October 31, 2014, 2013 and 2012, and as of October 31, 2014 and 2013 are as follows.

In thousands	2014			2013			2012
Operating Income:
Segment operating income before income taxes	$	262,655		$	221,176		$	194,560
Utility income taxes	(83,176		)	(77,334		)	(69,101		)
Regulated non-utility activities operating loss before income taxes	183			150			78
Unregulated non-utility activities operating loss before income taxes	203			202			186
Total	$	179,865		$	144,194		$	125,723
Net Income:
Income before income taxes for reportable segments	$	238,619		$	220,363		$	198,064
Income taxes	(94,818		)	(85,946		)	(78,217		)
Total	$	143,801		$	134,417		$	119,847

In thousands	2014		2013
Consolidated Assets:
Total assets for reportable segments	$	4,612,700	$	4,182,423
Eliminations/Adjustments	171,553		186,186
Total	$	4,784,253	$	4,368,609

15. Subsequent Events

We monitor significant events occurring after the balance sheet date and prior to the issuance of the financial statements to determine the impacts, if any, of events on the financial statements to be issued. All subsequent events of which we are aware were evaluated. For information on subsequent event disclosure items related to regulatory matters and employee share-based plans, see Note 2 and Note 10, respectively, to the consolidated financial statements.

16. Selected Quarterly Financial Data (In thousands except per share amounts) (Unaudited)

										Earnings (Loss)
							Net			Per Share of
	Operating				Operating		Income			Common Stock
	Revenues		Margin		Income		(Loss)			Basic			Diluted
Fiscal Year 2014
January 31	$	657,733	$	261,512	$	102,319	$	97,572		$	1.27		$	1.26
April 30	462,247		211,523		67,299		62,540			0.80			0.80
July 31	164,187		104,847		3,254		(7,344		)	(0.09		)	(0.09		)
October 31	185,821		112,326		6,993		(8,967		)	(0.11		)	(0.11		)
Fiscal Year 2013
January 31	$	515,875	$	231,623	$	86,213	$	85,923		$	1.19		$	1.18
April 30	399,411		183,856		51,504		55,790			0.74			0.74
July 31	162,943		97,000		591		(2,293		)	(0.03		)	(0.03		)
October 31	200,000		109,011		5,886		(5,003		)	(0.07		)	(0.07		)

The pattern of quarterly earnings is the result of the highly seasonal nature of the business as variations in weather conditions and our regulated utility rate designs generally result in greater earnings during the winter months. Basic earnings

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per share are calculated using the weighted average number of shares outstanding during the quarter. The annual amount may differ from the total of the quarterly amounts due to changes in the number of shares outstanding during the year.

Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

None.

Item 9A. Controls and Procedures

Management’s Evaluation of Disclosure Controls and Procedures

Our management, including the President and Chief Executive Officer and the Senior Vice President and Chief Financial Officer, has evaluated the effectiveness of our disclosure controls and procedures as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act as of the end of the period covered by this Form 10-K. Such disclosure controls and procedures are designed to provide reasonable assurance that the information we are required to disclose in the reports we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods required by the United States Securities and Exchange Commission’s rules and forms and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. Based on such evaluation, the President and Chief Executive Officer and the Senior Vice President and Chief Financial Officer concluded that, as of the end of the period covered by this Form 10-K, our disclosure controls and procedures were effective at the reasonable assurance level.

We routinely review our internal control over financial reporting and from time to time make changes intended to enhance the effectiveness of our internal control over financial reporting. There were no changes to our internal control over financial reporting as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act during the fourth quarter of fiscal 2014 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

December 23, 2014

Our management is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting as that term is defined in Rules 13a-15(f) under the Securities Exchange Act of 1934 is 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. The Company’s internal control over financial reporting is supported by a program of internal audits and appropriate reviews by management, written policies and guidelines, careful selection and training of qualified personnel and a written Code of Ethics and Business Conduct adopted by the Company’s Board of Directors and applicable to all Company Directors, officers and employees.

Because of the inherent limitations, any system of internal control over financial reporting, no matter how well designed, may not prevent or detect misstatements due to the possibility that a control can be circumvented or overridden or that misstatements due to error or fraud may occur that are not detected. Also, projections of the effectiveness to future periods are subject to the risk that the internal controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies and procedures included in such controls may deteriorate.

We have conducted an evaluation of the effectiveness of our internal control over financial reporting based upon the framework in “Internal Control—Integrated Framework” (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based upon such evaluation, our management concluded that as of October 31, 2014, our internal control over financial reporting was effective.

The Company’s independent registered public accounting firm, Deloitte & Touche LLP, has issued its report on the effectiveness of the Company’s internal control over financial reporting as of October 31, 2014.

Piedmont Natural Gas Company, Inc.
	/s/ Thomas E. Skains
	Thomas E. Skains Chairman, President and Chief Executive Officer
	/s/ Karl W. Newlin
	Karl W. Newlin Senior Vice President and Chief Financial Officer
	/s/ Jose M. Simon
	Jose M. Simon Vice President and Controller

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of

Piedmont Natural Gas Company, Inc.

Charlotte, North Carolina

We have audited the internal control over financial reporting of Piedmont Natural Gas Company, Inc. and subsidiaries (the “Company”) as of October 31, 2014, based on criteria established in Internal Control—Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel 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 (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) 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 (3) 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 the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of October 31, 2014, based on the criteria established in Internal Control—Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended October 31, 2014 of the Company and our report dated December 23, 2014 expressed an unqualified opinion on those financial statements.

/s/ Deloitte & Touche LLP

Charlotte, North Carolina

December 23, 2014

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Item 9B. Other Information

None.

PART III

Item 10. Directors, Executive Officers and Corporate Governance

Information concerning our executive officers and directors is set forth in the sections entitled “Board of Directors” and “Executive Officers” in our Proxy Statement for the 2015 Annual Meeting of Shareholders (2015 Proxy Statement), which sections are incorporated in this annual report on Form 10-K by reference. Information concerning compliance with Section 16(a) of the Securities Exchange Act of 1934, as amended, is set forth in the section entitled “Section 16(a) Beneficial Ownership Reporting Compliance” in our 2015 Proxy Statement, which section is incorporated in this annual report on Form 10-K by reference.

Information concerning our Audit Committee and our Audit Committee financial experts is set forth in the section entitled “Committees of the Board” in our 2015 Proxy Statement, which section is incorporated in this annual report on Form 10-K by reference.

We have adopted a Code of Ethics and Business Conduct that is applicable to all our directors, officers and employees, including our principal executive officer, principal financial officer and principal accounting officer, which serves as the code of ethics applicable to our principal executive officer, principal financial officer, principal accounting officer and persons performing similar functions under Item 406(b) of Regulation S-K. The Code of Ethics and Business Conduct is available on the “For Investors-Corporate Governance” section of our website at www.piedmontng.com. If we amend or grant a waiver, including an implicit waiver, from the Code of Ethics and Business Conduct that apply to the principal executive officer, principal financial officer and principal accounting officer or persons performing similar functions and that relate to any element of the code enumerated in Item 406(b) of Regulation S-K, we will disclose the amendment or waiver on the “For Investors-Corporate Governance” section of our website within four business days of such amendment or waiver.

Item 11. Executive Compensation

Information for this item is set forth in the sections entitled “Executive Compensation,” “Director Compensation,” “Compensation Committee Interlocks and Insider Participation,” and “Compensation Committee Report” in our 2015 Proxy Statement, which sections are incorporated in this annual report on Form 10-K by reference.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

Information for this item is set forth in the section entitled “Security Ownership of Management and Certain Beneficial Owners” in our 2015 Proxy Statement, which section is incorporated in this annual report on Form 10-K by reference.

Information concerning securities authorized for issuance under our equity compensation plans is set forth in the section entitled “Equity Compensation Plan Information” in our 2015 Proxy Statement, which section is incorporated in this annual report on Form 10-K by reference.

Item 13. Certain Relationships and Related Transactions, and Director Independence

Information for this item is set forth in the section entitled “Director Independence and Related Person Transactions” in our 2015 Proxy Statement, which section is incorporated in this annual report on Form 10-K by reference.

Item 14. Principal Accounting Fees and Services

Information for this item is set forth in “Proposal 2 – Ratification of the Appointment of Deloitte & Touche LLP As Independent Registered Public Accounting Firm For Fiscal Year 2015” in our 2015 Proxy Statement, which section is incorporated in this annual report on Form 10-K by reference.

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PART IV

Item 15. Exhibits, Financial Statement Schedules

(a)	1.	Financial Statements
The following consolidated financial statements for the year ended October 31, 2014, are included in Item 8 of this report as follows:
Consolidated Balance Sheets – October 31, 2014 and 2013 Consolidated Statements of Comprehensive Income – Years Ended October 31, 2014, 2013 and 2012 Consolidated Statements of Cash Flows – Years Ended October 31, 2014, 2013 and 2012 Consolidated Statements of Stockholders’ Equity – Years Ended October 31, 2014, 2013 and 2012 Notes to Consolidated Financial Statements Report of Independent Registered Public Accounting Firm
(a)	2.	Supplemental Consolidated Financial Statement Schedules
None Schedules and certain other information are omitted for the reason that they are not required or are not applicable, or the required information is shown in the consolidated financial statements or notes thereto.
(a)	3.	Exhibits
		Where an exhibit is filed by incorporation by reference to a previously filed registration statement or report, such registration statement or report is identified in parentheses. Upon written request of a shareholder, we will provide a copy of the exhibit at a nominal charge.
		The exhibits numbered 10.1 through 10.18 are management contracts or compensatory plans or arrangements.
	3.1	Restated Articles of Incorporation of Piedmont Natural Gas Company, Inc., dated as of March 2009 (incorporated by reference to Exhibit 3.1, Form 10-Q for the quarter ended July 31, 2009).
	3.2	Bylaws of Piedmont Natural Gas Company, Inc., as Amended and Restated Effective September 8, 2011 (incorporated by reference to Exhibit 3.1, Form 8-K dated September 13, 2011).
	4.1	Note Agreement, dated as of September 21, 1992, between Piedmont and Provident Life and Accident Insurance Company (incorporated by reference to Exhibit 4.30, Form 10-K for the fiscal year ended October 31, 1992).
	4.2	Amendment to September 1992 Note Agreement, dated as of September 16, 2005, by and between Piedmont and Provident Life and Accident Insurance Company (incorporated by reference to Exhibit 4.2, Form 10-K for the fiscal year ended October 31, 2007).
	4.3	Indenture, dated as of April 1, 1993, between Piedmont and The Bank of New York Mellon Trust Company, N.A. (as successor to Citibank, N.A.), Trustee (incorporated by reference to Exhibit 4.1, Form S-3 Registration Statement No. 33-59369).
	4.4	Medium-Term Note, Series A, dated as of October 6, 1993 (incorporated by reference to Exhibit 4.8, Form 10-K for the fiscal year ended October 31, 1993).

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4.5	First Supplemental Indenture, dated as of February 25, 1994, between PNG Acquisition Company, Piedmont Natural Gas Company, Inc., and Citibank, N.A., Trustee (incorporated by reference to Exhibit 4.2, Form S-3 Registration Statement No. 33-59369).
4.6	Medium-Term Note, Series A, dated as of September 19, 1994 (incorporated by reference to Exhibit 4.9, Form 10-K for the fiscal year ended October 31, 1994).
4.7	Form of Master Global Note (incorporated by reference to Exhibit 4.4, Form S-3 Registration Statement No. 33-59369).
4.8	Pricing Supplement of Medium-Term Notes, Series B, dated October 3, 1995 (incorporated by reference to Exhibit 4.10, Form 10-K for the fiscal year ended October 31, 1995).
4.9	Pricing Supplement of Medium-Term Notes, Series B, dated October 4, 1996 (incorporated by reference to Exhibit 4.11, Form 10-K for the fiscal year ended October 31, 1996).
4.10	Form of Master Global Note (incorporated by reference to Exhibit 4.4, Form S-3 Registration Statement No. 333-26161).
4.11	Pricing Supplement of Medium-Term Notes, Series C, dated September 15, 1999 (incorporated by reference to Rule 424(b)(3) Pricing Supplement to Form S-3 Registration Statement Nos. 33-59369 and 333-26161).
4.12	Second Supplemental Indenture, dated as of June 15, 2003, between Piedmont and Citibank, N.A., Trustee (incorporated by reference to Exhibit 4.3, Form S-3 Registration Statement No. 333-106268).
4.13	Form of 6% Medium-Term Note, Series E, dated as of December 19, 2003 (incorporated by reference to Exhibit 99.2, Form 8-K, dated December 23, 2003).
4.14	Third Supplemental Indenture, dated as of June 20, 2006, between Piedmont Natural Gas Company, Inc. and Citibank, N.A., as trustee (incorporated by reference to Exhibit 4.1, Form 8-K dated June 20, 2006).
4.15	Agreement of Resignation, Appointment and Acceptance dated as of March 29, 2007, by and among Piedmont Natural Gas Company, Inc., Citibank, N.A., and The Bank of New York Trust Company, N.A. (incorporated by reference to Exhibit 4.1, Form 10-Q for quarter ended April 30, 2007).
4.16	Note Purchase Agreement, dated as of May 6, 2011, among Piedmont Natural Gas Company, Inc. and the Purchasers party thereto (incorporated by reference to Exhibit 10, Form 8-K, dated May 12, 2011).
4.17	Form of 2.92% Series A Senior Notes due June 6, 2016 (incorporated by reference to Exhibit 4.1, Form 8-K dated May 12, 2011).
4.18	Form of 4.24% Series B Senior Notes due June 6, 2021 (incorporated by reference to Exhibit 4.2, Form 8-K dated May 12, 2011).
4.19	Fourth Supplemental Indenture, dated as of May 6, 2011, between Piedmont Natural Gas Company, Inc. and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated by reference to Exhibit 4.2, Form S-3-ASR Registration Statement No. 333-175386).

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4.20	Amendment to September 1992 Note Agreement dated as of April 15, 2011 by and between Piedmont Natural Gas Company, Inc., and Provident Life and Accident Insurance Company (incorporated by reference to Exhibit 10.3, Form 10-Q for the quarter ended April 30, 2011).
4.21	Note Purchase Agreement, dated as of March 27, 2012, among Piedmont Natural Gas Company, Inc. and the Purchasers party thereto (incorporated by reference to Exhibit 10.1, Form 8-K dated March 29, 2012).
4.22	Form of 3.47% Series A Senior Notes due July 16, 2027 (incorporated by reference to Exhibit 4.1, Form 8-K dated March 29, 2012).
4.23	Form of 3.57% Series B Senior Notes due July 16, 2027 (incorporated by reference to Exhibit 4.2, Form 8-K dated March 29, 2012).
4.24	Corporate Commercial Paper Master Note dated March 1, 2012 between U.S. Bank National Association as Paying Agent and Piedmont Natural Gas Company, Inc. as Issuer (incorporated by reference to Exhibit 4.1, Form 10-Q for the quarter ended April 30, 2012).
4.25	Fifth Supplemental Indenture, dated August 1, 2013, between the Company and The Bank of New York Mellon Trust Company, N.A. (incorporated by reference to Exhibit 4.1, Form 8-K dated August 1, 2013).
4.26	Form of 4.65% Senior Notes due 2043 (incorporated by reference to Exhibit 4.2, Form 8-K dated August 1, 2013).
4.27	Sixth Supplemental Indenture, dated September 18, 2014, between the Company and The Bank of New York Mellon Trust Company, N.A. (incorporated by reference to Exhibit 4.1, Form 8-K dated September 18, 2014).
4.28	Form of 4.10% Senior Notes due 2034 (incorporated by reference to Exhibit 4.2, Form 8-K dated September 18, 2014).
4.29	Third Amendment to September 1992 Note Agreement, dated as of October 15, 2014, between the Company and Provident Life and Accident Insurance Company.
	Compensatory Contracts:
10.1	Form of Director Retirement Benefits Agreement with outside directors, dated September 1, 1999 (incorporated by reference to Exhibit 10.54, Form 10-K for the fiscal year ended October 31, 1999).
10.2	Severance Agreement with Thomas E. Skains, dated September 4, 2007 (substantially identical agreements have been entered into as of the same date with Franklin H. Yoho, Kevin M. O’Hara and Jane R. Lewis-Raymond) (incorporated by reference to Exhibit 10.2, Form 10-Q for the quarter ended July 31, 2007).
10.3	Schedule of Severance Agreements with Executives (incorporated by reference to Exhibit 10.2a, Form 10-Q for the quarter ended July 31, 2007).
10.4	Piedmont Natural Gas Company, Inc. Incentive Compensation Plan as Amended and Restated Effective December 15, 2010 (incorporated by reference to Appendix A, Form DEF14A dated January 14, 2011).

112

10.5	Form of Performance Unit Award Agreement (incorporated by reference to Exhibit 10.1, Form 10-Q for the quarter ended January 31, 2011).
10.6	Resolution of Board of Directors, June 7, 2013, establishing compensation for non-management directors (incorporated by reference to Exhibit 10.1, Form 10-Q for the quarter ended July 31, 2013).
10.7	Piedmont Natural Gas Company, Inc. Voluntary Deferral Plan, dated as of December 8, 2008, effective November 1, 2008 (incorporated by reference to Exhibit 10.1, Form 10-Q for the quarter ended January 31, 2009).
10.8	Piedmont Natural Gas Company, Inc. Defined Contribution Restoration Plan, dated as of December 8, 2008, effective January 1, 2009 (incorporated by reference to Exhibit 10.2, Form 10-Q for the quarter ended January 31, 2009).
10.9	Piedmont Natural Gas Company Employee Stock Purchase Plan, amended and restated as of April 1, 2009 (incorporated by reference to Exhibit 4.1, Form 8-K dated April 3, 2009).
10.10	Amendment No. 1 to Director Retirement Benefits Agreements with outside directors, dated as of December 31, 2008 (incorporated by reference to Exhibit 10.1, Form 10-Q for the quarter ended July 31, 2009).
10.11	Severance Agreement between Piedmont Natural Gas Company, Inc. and Karl W. Newlin, dated as of June 4, 2010 (incorporated by reference to Exhibit 10.3, Form 10-Q for the quarter ended July 31, 2010).
10.12	Instrument of Amendment for Piedmont Natural Gas Company, Inc. Defined Contribution Restoration Plan dated as of January 23, 2012, by Piedmont Natural Gas Company, Inc. (incorporated by reference to Exhibit 10.1, Form 10-Q for the quarter ended January 31, 2012).
10.13	2011 Retention Award Agreement dated December 15, 2011 between Piedmont Natural Gas Company, Inc. and Thomas E. Skains (incorporated by reference to Exhibit 10.2, Form 10-Q for the quarter ended January 31, 2012).
10.14	Severance Agreement, dated February 1, 2012, between Piedmont Natural Gas Company, Inc. and Victor M. Gaglio (incorporated by reference to Exhibit 10.2, Form 10-Q for the quarter ended April 30, 2012).
10.15	Amended and Restated Employment Agreement dated May 25, 2012 between Piedmont Natural Gas Company, Inc. and Thomas E. Skains (substantially identical agreements have been entered into with Victor M. Gaglio, Jane R. Lewis-Raymond, Karl W. Newlin, Kevin M. O’Hara and Franklin H. Yoho) (incorporated by reference to Exhibit 10.1, Form 10-Q for the quarter ended July 31, 2012).
10.16	Schedule of Amended and Restated Employment Agreements with Executives (incorporated by reference to Exhibit 10.2, Form 10-Q for the quarter ended July 31, 2012).
10.17	Amendment to the Piedmont Natural Gas Company Employee Stock Purchase Plan dated September 18, 2012, by Piedmont Natural Gas Company, Inc. (incorporated by reference to Exhibit 10.21, Form 10-K for the fiscal year ended October 31, 2012).
10.18	Resolution of Board of Directors, June 6, 2014, establishing compensation for non-management directors (incorporated by reference to Exhibit 10.1, Form 10-Q for the quarter ended July 31, 2014).

113

	Other Contracts:
10.19	Amended and Restated Limited Liability Company Agreement of SouthStar Energy Services LLC, effective January 1, 2004, between Piedmont Energy Company and Georgia Natural Gas Company (incorporated by reference to Exhibit 10.1, Form 10-Q for the quarter ended April 30, 2004).
10.20	First Amendment to Amended and Restated Limited Liability Company Agreement of SouthStar Energy Services LLC, dated as of July 31, 2006, between Piedmont Energy Company and Georgia Natural Gas Company (incorporated by reference to Exhibit 10.28, Form 10-K for the fiscal year ended October 31, 2006).
10.21	Amendment by Written Consent to Amended and Restated Limited Liability Company Agreement of SouthStar Energy Services LLC, dated as of August 28, 2006, between Piedmont Energy Company and Georgia Natural Gas Company (incorporated by reference to Exhibit 10.29, Form 10-K for the fiscal year ended October 31, 2006).
10.22	Amendment by Written Consent to Amended and Restated Limited Liability Company Agreement of SouthStar Energy Services LLC, dated as of September 20, 2006, between Piedmont Energy Company and Georgia Natural Gas Company (incorporated by reference to Exhibit 10.30, Form 10-K for the fiscal year ended October 31, 2006).
10.23	Second Amendment to Amended and Restated Limited Liability Company Agreement of SouthStar Energy Services LLC by and between Georgia Natural Gas Company and Piedmont Energy Company, dated July 2, 2009 (incorporated by reference to Exhibit 10.2, Form 10-Q for the quarter ended July 31, 2009).
10.24	Settlement Agreement by and between Georgia Natural Gas Company and Piedmont Energy Company, dated July 29, 2009 (incorporated by reference to Exhibit 10.1, Form 8-K dated August 4, 2009).
10.25	Third Amendment to Amended and Restated Limited Liability Company Agreement of SouthStar Energy Services LLC by and between Georgia Natural Gas Company and Piedmont Energy Company, dated July 29, 2009 (incorporated by reference to Exhibit 10.2, Form 8-K dated August 4, 2009).
10.26	Form of Commercial Paper Dealer Agreement between Piedmont Natural Gas Company, Inc. and Dealers party thereto (incorporated by reference to Exhibit 10.3, Form 10-Q for the quarter ended April 30, 2012).
10.27	Amended and Restated Credit Agreement dated as of October 1, 2012 among Piedmont Natural Gas Company, Inc., Wells Fargo Bank, National Association, as Administrative Agent, Swing Line Lender, L/C Issuer and a Lender, and Branch Banking and Trust Company, Bank of America, N.A., JPMorgan Chase Bank, N.A., PNC Bank, National Association, U.S. Bank National Association and Royal Bank of Canada, each a Lender (incorporated by reference to Exhibit 10.34, Form 10-K for the fiscal year ended October 31, 2012).
10.28	Amended and Restated Limited Liability Company Agreement of Constitution Pipeline Company, LLC dated April 9, 2012, by and among Williams Partners Operating LLC and Cabot Pipeline Holdings LLC (incorporated by reference to Exhibit 10.1, Form 10-Q for the quarter ended January 31, 2013).
10.29	First Amendment to Amended and Restated Limited Liability Company Agreement of Constitution Pipeline Company, LLC, dated as of November 9, 2012, by and among Constitution Pipeline Company, LLC, Williams Partners Operating LLC, Cabot Pipeline Holdings LLC, and Piedmont Constitution Pipeline Company, LLC (incorporated by reference to Exhibit 10.2, Form 10-Q for the quarter ended January 31, 2013).

114

10.30	Confirmation of Forward Sale Transaction dated January 29, 2013, between the Company and Morgan Stanley & Co. LLC, in its capacity as the forward counterparty (incorporated by reference to Exhibit 99.1, Form 8-K filed February 4, 2013).
10.31	Confirmation of Forward Sale Transaction dated February 19, 2013, between Piedmont Natural Gas Company, Inc., and Morgan Stanley & Co. LLC, in its capacity as the forward counterparty (incorporated by reference to Exhibit 99.1, Form 8-K filed February 25, 2013).
10.32	Second Amendment to Amended and Restated Limited Liability Company Agreement of Constitution Pipeline Company, LLC, dated as of May 29, 2013, by and among Constitution Pipeline Company, LLC, Williams Partners Operating LLC, Cabot Pipeline Holdings LLC, Piedmont Constitution Pipeline Company, LLC, and Capitol Energy Ventures Corp. (incorporated by reference to Exhibit 99.1, Form 8-K filed September 4, 2013).
10.33	Second Amended and Restated Limited Liability Company Agreement of SouthStar Energy Services LLC, dated as of September 1, 2013, by and between Georgia Natural Gas Company and Piedmont Energy Company (incorporated by reference to Exhibit 10.39, Form 10-K for the fiscal year ended October 31, 2013).
10.34	Increasing Lender Agreement dated as of November 1, 2013 among Wells Fargo Bank, National Association, Bank of America, N.A., Branch Banking and Trust Company, JPMorgan Chase Bank, N.A., PNC Bank, National Association, U.S. Bank National Association and Royal Bank of Canada, each as a Lender (incorporated by reference to Exhibit 10.1, Form 8-K dated November 4, 2013).
10.35 *	Limited Liability Company Agreement of Atlantic Coast Pipeline, LLC, dated as of September 2, 2014, by and between Dominion Atlantic Coast Pipeline, LLC, Duke Energy ACP, LLC, Piedmont ACP Company, LLC, and Maple Enterprise Holdings, Inc.
12	Computation of Ratio of Earnings to Fixed Charges.
21	List of Subsidiaries.
23.1	Consent of Independent Registered Public Accounting Firm.
31.1	Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of the Chief Executive Officer.
31.2	Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of the Chief Financial Officer.
32.1	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 of the Chief Executive Officer.
32.2	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 of the Chief Financial Officer.

115

101.INS	XBRL Instance Document
101.SCH	XBRL Taxonomy Extension Schema
101.CAL	XBRL Taxonomy Calculation Linkbase
101.DEF	XBRL Taxonomy Definition Linkbase
101.LAB	XBRL Taxonomy Extension Label Linkbase
101.PRE	XBRL Taxonomy Extension Presentation Linkbase
*	Certain portions of this Exhibit have been omitted pursuant to a request for confidential treatment. The non-public information has been filed separately with the SEC pursuant to Rule 24b-2 under the Securities Exchange Act of 1934, as amended.
Attached as Exhibit 101 to this Annual Report are the following documents formatted in extensible business reporting language (XBRL): (1) Document and Entity Information; (2) Consolidated Balance Sheets at October 31, 2014 and 2013; (3) Consolidated Statements of Comprehensive Income for the years ended October 31, 2014, 2013 and 2012; (4) Consolidated Statements of Cash Flows for the years ended October 31, 2014, 2013 and 2012; (5) Consolidated Statements of Stockholders’ Equity for the years ended October 31, 2014, 2013 and 2012; and Notes to Consolidated Financial Statements.

116

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Piedmont Natural Gas Company, Inc.
	(Registrant)
By:	/s/ Thomas E. Skains
	Thomas E. Skains
	Chairman of the Board, President
	and Chief Executive Officer
Date:	December 23, 2014

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature	Title
/s/ Thomas E. Skains	Chairman of the Board, President and
Thomas E. Skains	Chief Executive Officer
	(Principal Executive Officer)
Date: December 23, 2014
/s/ Karl W. Newlin	Senior Vice President and
Karl W. Newlin	Chief Financial Officer
	(Principal Financial Officer)
Date: December 23, 2014
/s/ Jose M. Simon	Vice President and Controller
Jose M. Simon	(Principal Accounting Officer)
Date: December 23, 2014

117

Signature	Title
/s/ E. James Burton	Director
E. James Burton
/s/ Malcolm E. Everett III	Director
Malcolm E. Everett III
/s/ Aubrey B. Harwell, Jr.	Director
Aubrey B. Harwell, Jr.
/s/ Frank B. Holding, Jr.	Director
Frank B. Holding, Jr.
/s/ Frankie T. Jones, Sr.	Director
Frankie T. Jones, Sr.
/s/ Vicki McElreath	Director
Vicki McElreath
/s/ Minor M. Shaw	Director
Minor M. Shaw
/s/ Jo Anne Sanford	Director
Jo Anne Sanford
/s/ David E. Shi	Director
David E. Shi
/s/ Michael C. Tarwater	Director
Michael C. Tarwater
/s/ Phillip D. Wright	Director
Phillip D. Wright

118

	Piedmont Natural Gas Company, Inc.
	Form 10-K
	For the Fiscal Year Ended October 31, 2014
	Exhibits
4.29	Third Amendment to September 1992 Note Agreement, dated as of October 15, 2014, between the Company and Provident Life and Accident Insurance Company
10.35 *	Limited Liability Company Agreement of Atlantic Coast Pipeline, LLC, dated as of September 2, 2014, by and between Dominion Atlantic Coast Pipeline, LLC, Duke Energy ACP, LLC, Piedmont ACP Company, LLC, and Maple Enterprise Holdings, Inc.
12	Computation of Ratio of Earnings to Fixed Charges
21	List of Subsidiaries
23.1	Consent of Independent Registered Public Accounting Firm
31.1	Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of the Chief Executive Officer
31.2	Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of the Chief Financial Officer
32.1	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 of the Chief Executive Officer
32.2	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 of the Chief Financial Officer
*	Certain portions of this Exhibit have been omitted pursuant to a request for confidential treatment. The non-public information has been filed separately with the SEC pursuant to Rule 24b-2 under the Securities Exchange Act of 1934, as amended.

119

EX-4.29

Exhibit 4.29

THIRD AMENDMENT TO SEPTEMBER 1992 NOTE AGREEMENT

THIS THIRD AMENDMENT TO SEPTEMBER 1992 NOTE AGREEMENT (this “Amendment”) is entered into this 15th day of October, 2014, by and between Piedmont Natural Gas Company, Inc., a North Carolina corporation (the “Company”) and the undersigned holder of all of the senior promissory notes issued pursuant to that certain Note Agreement dated as of September 21, 1992 (as amended, modified, extended, supplemented, restated and/or replaced from time to time, the “Note Agreement”), between the Company and Provident Life and Accident Insurance Company (“Provident”).

Capitalized terms used herein and not otherwise defined herein shall have the meanings ascribed to such terms in the Note Agreement or the Amendment.

WITNESSETH:

WHEREAS, the Company is exploring opportunities to enter into energy services projects that may involve non-recourse third-party financing that may involve the non-recourse assignment, sale or other transfer of receivables and contract rights by the Company, the filing of financing statements under the applicable Uniform Commercial Code, or other actions or documents that may constitute a “Lien” under the Note Agreement; and

WHEREAS, the Company desires to amend the Note Agreement to permit Liens that are deemed to exist as a result of such arrangements.

NOW, THEREFORE, for good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto, intending to be legally bound hereby, do agree as follows:

SECTION 1.

AMENDMENT TO THE NOTE AGREEMENT

The Note Agreement shall be and hereby is amended as follows:

1.1. Section 6B(1) is amended by:

(a) replacing the “.” at the end of subsection 6B(1)(xi) with “; and”; and

(b) adding the following as new subsection 6B(1)(xii):

“(xii)    Liens created or deemed to exist as a result of (i) a non-recourse assignment, sale or other transfer of receivables in connection with one or more third-party financings (or Guarantee of such financing) of energy projects developed by the Company (or any subcontractor of the Company) and (ii) Liens on such energy projects in favor of one or more providers of such third-party financing (including, without limitation, with respect to each of the foregoing clauses (i) and (ii), projects developed for agencies, departments and instrumentalities of the United States government, any state, county, municipal government or other political subdivision, any university or any college through utility energy services contracts).”

1.2. Section 10 is amended by inserting, immediately after the word “jurisdiction“ at the end of the definition of “Lien”, the following: “that is filed to secure an obligation for which the Company is responsible for payment or performance”.

SECTION 2.

WARRANTIES AND REPRESENTATIONS

To induce Provident to enter into this Amendment and to consent to the modifications to the Note Agreement set forth herein, the Company warrants and represents, on the date of this Amendment, as follows (it being agreed, however, that nothing in this Section 2 shall affect any of the warranties and representations previously made by the Company in or pursuant to the Note Agreement, and that all of such other warranties and representations, as well as the warranties and representations in this Section 2, shall survive the effectiveness of this Amendment and the modifications to the Note Agreement as forth herein):

2.1. Organization; Power and Authority. The Company is a public company duly incorporated and validly existing under the laws of the State of North Carolina and is duly qualified as a corporation and is in good standing in each other jurisdiction in which such qualifications are required by law, other than those jurisdictions as to which the failure to be so qualified or in good standing would not, individually or in the aggregate, reasonably be expected to have a material adverse effect. The Company has the corporate power and authority to own its properties and to conduct its business and to execute and deliver this Amendment.

2.2. Authorization, Etc. This Amendment has been duly authorized by all necessary corporate action on the part of the Company.

SECTION 3.

MISCELLANEOUS

3.1 Except as hereinabove specifically amended, all other provisions of the Note Agreement shall remain in full force and effect.

3.2 THIS AMENDMENT SHALL BE CONSTRUED AND ENFORCED IN ACCORDANCE WITH, AND THE RIGHTS OF THE PARTIES SHALL BE GOVERNED BY, THE LAW OF THE STATE OF NORTH CAROLINA.

3.3 This Amendment and all of the provisions hereof shall be binding upon and inure to the benefit of the parties hereto and their respective permitted successors and assigns.

3.4 This Amendment may be executed in one or more counterparts, each of which shall be deemed an original and all of which taken together shall be deemed to constitute one and the same instrument, and it shall not be necessary in making proof of this Amendment to produce or account for more than one of such counterparts.

IN WITNESS WHEREOF, the parties hereto have caused this Amendment to be signed and delivered on the day and year first written above.

PIEDMONT NATURAL GAS COMPANY, INC., a North Carolina corporation
By:	/s/ Robert O. Pritchard
	Name:	Robert O. Pritchard
	Title:	V.P., Treasurer & Chief Risk Officer
PROVIDENT LIFE AND ACCIDENT INSURANCE COMPANY
By:	/s/ Ben Vance
	Name:	Ben Vance
	Title:	Senior Managing Director

EX-10.35

Exhibit 10.35

Note: Registrant has requested that portions of this document denoted [***] be accorded confidential treatment pursuant to Rule 24b-2 promulgated under the Securities Exchange Act of 1934, as amended.

LIMITED LIABILITY COMPANY AGREEMENT

OF

ATLANTIC COAST PIPELINE, LLC

a Delaware Limited Liability Company

Dated as of September 2, 2014

THE SECURITIES REFERENCED IN THIS LIMITED LIABILITY COMPANY AGREEMENT (THIS “AGREEMENT”) HAVE NOT BEEN REGISTERED UNDER THE UNITED STATES SECURITIES ACT OF 1933, AS AMENDED, OR REGISTERED OR QUALIFIED UNDER ANY OTHER STATE OR FEDERAL SECURITIES LAWS. SUCH SECURITIES MAY NOT BE OFFERED, SOLD, ASSIGNED, PLEDGED OR OTHERWISE DISPOSED OF AT ANY TIME WITHOUT AN EFFECTIVE REGISTRATION STATEMENT OR QUALIFICATION UNDER SUCH ACT AND LAWS OR AN EXEMPTION THEREFROM, AND COMPLIANCE WITH THE OTHER SUBSTANTIAL RESTRICTIONS ON TRANSFERABILITY SET FORTH HEREIN. THEREFORE, MEMBERS MAY NOT BE ABLE TO READILY LIQUIDATE THEIR INVESTMENTS. THERE IS NO TRADING MARKET FOR THE SECURITIES REFERENCED IN THIS AGREEMENT, AND IT IS NOT ANTICIPATED THAT ONE WILL DEVELOP.

THE SECURITIES REFERENCED IN THIS LIMITED LIABILITY COMPANY AGREEMENT ARE SUBJECT TO CONDITIONS AND RESTRICTIONS ON TRANSFER SET FORTH HEREIN AND CERTAIN RESTRICTIONS ON VOTING RIGHTS.

TABLE OF CONTENTS

Page

Article 1 ORGANIZATIONAL MATTERS    1

1.1. Formation and Continuation    1

1.2. Name    1

1.3. Purpose    2

1.4. Registered Office and Registered Agent; Principal Place of Business    2

1.5. Foreign Qualification    2

1.6. Term    2

1.7. Expense    3

1.8. No State Law Partnership    3

1.9. Mergers and Exchanges    3

Article 2 DEFINITIONS AND REFERENCES    3

2.1. Definitions    3

Article 3 MEMBERS    19

3.1. Members    19

3.2. Membership Interests    20

3.3. Voting.    20

3.4. Additional Members and Membership Interests    20

3.5. Liability to Third Parties    21

3.6. Withdrawal    21

3.7. Members Have No Agency Authority    21

3.8. Priority and Return of Capital    21

3.9. Limitation on Liens    21

Article 4 CAPITAL CONTRIBUTIONS; DEFAULT    21

4.1. Capital Contributions    21

4.2. Additional Capital Contributions    22

4.3. Dilution    25

4.4. Pre-Effective Expenditures    26

4.5. Events of Default    27

4.6. Interest on and Return of Capital Contributions    29

4.7. Financing    29

Article 5 ALLOCATIONS AND DISTRIBUTIONS    30

5.1. Allocations of Profits and Losses    30

5.2. Special Allocations    30

5.3. Allocation and Other Rules    32

5.4. Allocations for Tax Purposes    33

5.5. Distributions    34

5.6. Acknowledgement of Allocation Rules    34

5.7. Tax Withholding    34

i

Article 6 MANAGEMENT AND GOVERNANCE    35

6.1. Board    35

6.2. Certain Agreements    35

6.3. Designation of Managers    36

6.4. Removal of Managers    37

6.5. Vacancies    37

6.6. Meetings of Board    37

6.7. Restricted Action Requiring Board Approval    39

6.8. FERC Certificate Approval    42

6.9. Officers    44

6.10. Duties of Managers    44

6.11. Commercially Sensitive Information    45

6.12. Employees    46

Article 7 BUDGETS; ACCOUNTING, TAX AND BANKING MATTERS    46

7.1. Facilities Budgets    46

7.2. Annual Budgets    47

7.3. Books and Records; Reports    47

7.4. Fiscal Year    50

7.5. Bank Accounts    50

7.6. Capital Accounts    50

7.7. Tax Partnership    51

7.8. Tax Elections.    51

7.9. Tax Matters Member    51

7.10. Tax Returns and Reports    52

7.11. Audit Rights    52

Article 8 INDEMNIFICATION    52

8.1. Right to Indemnification    52

8.2. Indemnification of Employees and Agents    53

8.3. Advance Payment    53

8.4. Appearance as a Witness    54

8.5. Nonexclusivity of Rights    54

8.6. Insurance    54

8.7. Certain Definitions    54

8.8. Severability    55

Article 9 COMMITTED FACILITIES; OTHER ACTIVITIES    55

9.1. Development of Committed Facilities    55

9.2. Development of Approved Facilities Projects    55

9.3. Proposed Facilities Projects    56

9.4. Development of Business Opportunities    57

9.5. Certain Opportunities    57

9.6. Insurance    57

Article 10 DISPOSITION    58

ii

10.1. Dispositions; Exception to Application of this Article 10    58

10.2. Other Restrictions on Dispositions    59

10.3. [RESERVED].    60

10.4. Preemptive Right    60

10.5. Dominion ROFR    61

Article 11 DISSOLUTION, LIQUIDATION, AND TERMINATION    62

11.1. Dissolution    62

11.2. Liquidation and Termination    62

11.3. Deficit Capital Accounts    64

11.4. Certificate of Cancellation    64

Article 12 REPRESENTATIONS AND WARRANTIES    64

12.1. Representations and Warranties of the Members    64

Article 13 EFFECTIVENESS    65

13.1. Effectiveness    65

Article 14 GENERAL PROVISIONS    65

14.1. Notices    65

14.2. Amendment or Modification    66

14.3. Entire Agreement    66

14.4. Extensions; Waivers    66

14.5. Assignment; Binding Effect    67

14.6. Governing Law    67

14.7. Dispute Resolution    67

14.8. Waiver of Jury Trial    67

14.9. Affiliate Contracts    68

14.10. No Consequential Damages    68

14.11. Severability    68

14.12. Further Assurances    69

14.13. Title to Company Property    69

14.14. Intellectual Property    69

14.15. Press Releases and Public Announcements    69

14.16. No Third Party Beneficiaries    69

14.17. Confidentiality    70

14.18. Headings    70

14.19. Construction    70

14.20. Fair Market Value Determination    71

14.21. Counterparts; Effectiveness    71

14.22. Adjustment for Inflation    72

14.23. Legal Representation    72

iii

INDEX TO ANNEXES

Annex A    Transferee Representations

Annex B    Accession Agreement

Annex C    Form of Capital Call Notice

INDEX TO EXHIBITS

Exhibit 2.1    Initial Precedent Agreements

Exhibit 3.1    Member Addresses, Capital Contributions and Percentage Interests

Exhibit 4.4    Pre-Effective Expenditures

Exhibit 6.3(a)    Designated Managers

Exhibit 6.9(c)    Officers

Exhibit 14.9    Affiliate Contracts

INDEX TO SCHEDULES

Schedule A    Initial Facilities

Schedule B    Minimum Insurance Coverage

iv

LIMITED LIABILITY COMPANY AGREEMENT
OF
ATLANTIC COAST PIPELINE, LLC

THIS LIMITED LIABILITY COMPANY AGREEMENT of ATLANTIC COAST PIPELINE, LLC, a Delaware limited liability company (the “Company”), dated as of September 2, 2014 (the “Effective Date”), is adopted, executed and agreed to by DOMINION ATLANTIC COAST PIPELINE, LLC, a Delaware limited liability company (“Dominion”), DUKE ENERGY ACP, LLC, a Delaware limited liability company (“Duke”), PIEDMONT ACP COMPANY, LLC, a North Carolina limited liability company (“Piedmont”), and MAPLE ENTERPRISE HOLDINGS, INC., a Georgia corporation (“AGL”). Capitalized terms used herein shall have the meanings set forth in Article 2 unless otherwise defined herein.

WHEREAS, the Company was formed on August 27, 2014 by the filing of a Certificate of Formation (the “Certificate”) with the Secretary of State of the State of Delaware; and

WHEREAS, the Members desire to enter into this Agreement for purposes of evidencing the various rights, privileges, duties and obligations of the Members.

NOW, THEREFORE, for good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto intending to be legally bound hereby enter into this Agreement.

ARTICLE 1

ORGANIZATIONAL MATTERS

1.1.Formation and Continuation

The Company was formed upon the filing of the Certificate with the Secretary of State of the State of Delaware on August 27, 2014 under and pursuant to the Act. The Members desire to continue the Company for the purposes and upon the terms and conditions hereinafter set forth. The Members hereby agree that during the term of the Company, the rights and obligations of the Members with respect to the Company will be determined in accordance with the terms and provisions of this Agreement and the Act (except where the Act provides that such rights and obligations specified in the Act shall apply “unless otherwise provided in a limited liability company agreement” or words of similar effect and such rights and obligations are set forth in this Agreement). Notwithstanding anything herein to the contrary, the Members shall not have the rights described in Section 18-210 of the Act (entitled “Contractual Appraisal Rights”), which shall not apply to this Agreement or to the Company.

1.2.    Name

The Company’s name is “Atlantic Coast Pipeline, LLC.” The Company’s business shall be conducted in the Company’s name or in any other name approved by the Board. If the law of a jurisdiction where the Company does business requires the Company to do business under a different name, the Company’s business in such jurisdiction may be conducted under such other name or names as the Board may select.

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1.3.    Purpose

Subject to the terms of this Agreement, the purpose of the Company shall be to engage in the Business and to engage in any lawful act or activity for which limited liability companies may engage under the Act and other applicable laws in furtherance of, ancillary to or in connection with the Business. The Company shall have all powers and privileges granted by the Act, any other law or this Agreement, including incidental powers thereto, to the extent that such powers and privileges are necessary, customary, convenient or incidental to engaging in the Business.

1.4.    Registered Office and Registered Agent; Principal Place of Business

(a)The Company’s registered office required by the Act to be maintained in the State of Delaware shall be the initial registered office named in the Certificate or such other office (which need not be a place of business of the Company) as the Board may designate from time to time in the manner provided by law. The Company’s registered agent in the State of Delaware shall be the initial registered agent named in the Certificate or such other Person or Persons as the Board may designate from time to time.

(b)The principal place of business of the Company shall be in Richmond, VA. The Board, at any time and from time to time, may change the location of the Company’s principal place of business and may establish such additional place or places of business of the Company as the Board shall determine to be necessary or desirable.

1.5.    Foreign Qualification

Prior to the Company conducting business in any jurisdiction other than Delaware, the Company shall comply, to the extent procedures are reasonably available, with all requirements necessary to qualify the Company as a foreign limited liability company in such jurisdiction. At the request of the Board or an officer of the Company upon proper authorization, each Member agrees to execute, acknowledge, swear to, and deliver all certificates and other instruments conforming with this Agreement that are necessary or appropriate to qualify, continue, and terminate the Company as a foreign limited liability company in such jurisdiction; provided that no Member shall be required to file any general consent to service of process or to qualify as a foreign corporation, limited liability company, partnership or other entity in any jurisdiction in which it is not already so qualified.

1.6.    Term

The existence of the Company commenced on the date the Certificate was filed with the Secretary of State of the State of Delaware and shall continue in existence until it is dissolved and the Certificate is cancelled in accordance with the terms hereof and the Act.

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1.7.    Expense

Each Member and each of their respective Affiliates shall be responsible for and bear their own costs and expenses incurred in connection with the consideration of their investment in the Company, their due diligence review of the Company, and the negotiation, preparation and execution of the Transaction Documents.

1.8.No State Law Partnership

The Members intend that: (a) the Company shall not be treated as a common law partnership or joint venture; and (b) this Agreement shall not create any agency or other relationship creating fiduciary or quasi-fiduciary duties owed by any Member to the Company or to any other Member or Manager, and this Agreement may not be construed to suggest otherwise, except for the implied covenant of good faith and fair dealing. To the extent that, at law or in equity, a Member owes any fiduciary or other duty to the Company or any Manager pursuant to this Agreement, such duty is hereby eliminated pursuant to Section 18-1101(c) of the Act, except for the implied covenant of good faith and fair dealing. This Agreement shall not subject the Members to joint and several or vicarious liability for the obligations of the Company or any other Member or impose any duty, obligation or liability on any Member that would arise therefrom with respect to any or all of the Members or the Company. Notwithstanding anything in this Agreement to the contrary, nothing in this Agreement is intended to change or in any way modify or reduce the fiduciary or other duties which may be agreed to by a Member in its capacity as a party to a Transaction Document or other contract with the Company or any Subsidiary of the Company other than this Agreement.

1.9.Mergers and Exchanges

Except as otherwise provided in this Agreement, the Company may be a party to any merger, equity exchange, consolidation, acquisition or other type of reorganization upon proper authorization taken pursuant to the terms hereof.

ARTICLE 2

DEFINITIONS AND REFERENCES

2.1.    Definitions

When used in this Agreement, the following terms shall have the respective meanings assigned to them in this Section 2.1 or in the sections or other subdivisions referred to below:

“AccessionAgreement” means the agreement substantially in the form attached hereto as Annex B.

“Act” means the Delaware Limited Liability Company Act or any successor statute, as amended from time to time.

“ActingMember” means, with respect to any Affiliate Contract, each Member that is not itself, nor is any of its Affiliates, a party to such Affiliate Contract.

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“AdditionalCapitalContribution” means, with respect to any Member, any Capital Contribution allowed or required to be made by such Member from time to time in accordance with the terms of Article 4.

“AdjustedCapitalAccount” means the Capital Account maintained for each Member as provided in Section 7.6, (a) increased by an amount equal to the amount such Member is deemed obligated to restore under the penultimate sentences of Treasury Regulations Section 1.704-2(g)(1) and 1.704-2(i)(5) as computed on the last Day of such Fiscal Year in accordance with the applicable Treasury Regulations, and (b) decreased by the adjustments provided for in Treasury Regulations Section 1.704-1(b)(2)(ii)(d)(4)-(6).

“Affected Member” is defined in Section 14.20(b).

“Affiliate” means, when used with respect to any Person, any Person directly or indirectly Controlling, Controlled by, or under common Control with such Person, and the term “Affiliate” includes, with respect to any Member, (a) a limited partnership or a Person Controlled by a limited partnership if the general partner of such limited partnership is Controlled by such Member’s Parent, or (b) a limited liability company or a Person controlled by a limited liability company if the managing member of the limited liability company is Controlled by such Member’s Parent. For purposes of this Agreement, neither the Company nor any of its Subsidiaries is an Affiliate of any of the Members or any of their respective Affiliates. For the purposes of Article X, the term “Affiliate” includes, in the case of Dominion, Dominion Midstream Partners, LP (“Dominion MLP”).

“Affiliate Contract” means a contract, agreement, document or other instrument between the Company or a Subsidiary thereof on one hand and a Member or an Affiliate of a Member on the other hand.

“AFP Budget” is defined in Section 7.1(c).

“Aggregate Budget Cap” means, with respect to any Committed Facilities, an amount equal to the aggregate of the Budget Caps of all Members for such Committed Facilities.

“AGL” is defined in the recitals.

“AGL Manager(s)” is defined in Section 6.3(a).

“Agreement” means this Limited Liability Company Agreement, as hereafter amended, modified or changed from time to time in accordance with the terms hereof.

“AllocationPeriod” means (a) the period commencing on the Effective Date and ending on December 31, 2014, (b) any subsequent 12-month period commencing on January 1, and ending on December 31, (c) any portion of the periods described in clauses (a) or (b) for which the Company is required to allocate Profits, Losses and other items of Company income, gain, loss or deduction under Article 5 or (d) the period commencing on the immediately preceding January 1, and ending on the date on which all Properties of the Company are distributed to the Members under Article 11; provided, however, if such period is not permissible for tax purposes, the Tax Matters Member shall select another period that is permissible for tax purposes.

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“AlternateManager” is defined in Section 6.3(b).

“Annual Budget” means the annual budget of the Company, comprised of the Annual Capital Budget and, with respect to any year (or portion thereof) following the In-Service Date, the Annual Operating Budget.

“Annual Capital Budget” is defined in Section 7.2(a).

“Annual Operating Budget” is defined in Section 7.2(a).

“Appraiser” is defined in Section 14.20(b).

“Approved Facilities Project” means any Facilities Project to be undertaken by the Company that the Board approves pursuant to Section 6.7(b)(iii).

“Available Cash” means, with respect to any period, the following, without duplication: (a) all revenues and other cash and cash equivalents collected or received by the Company from any and all sources (other than Capital Contributions) as of the end of such period less (b) as of the end of such period, reserves reasonably established by the Board to provide for the proper conduct of the business of the Company, including any reserves to comply with applicable law or any instrument of indebtedness or obligation to which the Company is a party or by which it is bound or its assets are subject; provided, however, that Available Cash shall not be reduced by depreciation, amortization, cost recovery deductions or similar non-cash expenses or allowances, and shall be increased by any reductions of cash reserves previously established pursuant to the first clause of this definition. Available Cash generated from Capital Contributions pursuant to Sections 4.1 and 4.2 shall not be considered “Available Cash” for distribution purposes.

“BankruptMember” means any Member:

(a)that (i) makes a general assignment for the benefit of creditors; (ii) files a voluntary bankruptcy petition; (iii) becomes the subject of an order for relief or is declared insolvent in any federal or state bankruptcy or insolvency proceeding; (iv) files a petition or answer in a court of competent jurisdiction seeking for such Member a reorganization, arrangement, composition, readjustment, liquidation, dissolution, or similar relief under any applicable law; (v) files an answer or other pleading admitting or failing to contest the material allegations of a petition filed against such Member in a proceeding of the type described in subclauses (i) through (iv) of this clause (a); or (vi) seeks, consents, or acquiesces to the appointment of a trustee, receiver, or liquidator of such Member or of all or any substantial part of such Member’s assets or properties; or

(b)against which a proceeding seeking reorganization, arrangement, composition, readjustment, liquidation, dissolution, or similar relief under any law has been commenced and ninety (90) Days have expired without dismissal thereof or with respect to which, without such Member’s consent or acquiescence, a trustee, receiver, or liquidator of such Member or of all or any substantial part of such Member’s properties has been appointed and sixty (60) Days have expired without such

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appointments having been vacated or stayed, or sixty (60) Days have expired after the date of expiration of a stay, if the appointment has not previously been vacated.

“Base Facilities Project” means any project that involves (i) constructing or installing any pipeline that would loop (as such term is commonly used in the natural gas pipeline industry) the Facilities, (ii) installing or upgrading any compression with respect to the Facilities, (iii) increasing the transportation capacity of the Facilities through the installation of greater capacity pipe, looping or similar improvements, and/or (iv) any extension to the Trunkline, in each case excluding any project upstream of the Marts Junction receipt point in Lewis County, West Virginia.

“Base Facilities Project Notice” is defined in Section 9.3(a).

“Board” is defined in Section 6.1.

“Budget Cap” means, for each Member (a) with respect to the Initial Facilities, the amount in U.S. dollars set forth opposite such Member’s name in the Initial Facilities Budget, (b) with respect to the PA Required Expansion Facilities, the amount in U.S. dollars set forth opposite such Member’s name in Attachment D to the Initial Resolution, in each case as such amount may be increased from time to time in accordance with Section 4.2(f).

“Budget Overrun” is defined in Section 6.7(b)(iii)(14).

“Business” means the business of acquiring, planning, designing, financing, constructing, operating, owning, improving, marketing, maintaining and expanding the Facilities, engaging in the transmission of natural gas through the Facilities, procuring or leasing gas transportation capacity on any other pipeline facilities and engaging in the transmission of natural gas through such pipeline facilities, and performing other activities or services related or ancillary thereto and such other related business as approved by the Board.

“BusinessDay” means a Day, other than a Saturday or a Sunday, on which commercial banks in the Unites States of America are open for business with the public.

“CapitalAccount” is defined in Section 7.6(a).

“Capital Call Notice” is defined in Section 4.2(a).

“CapitalContribution” means, for any Member at the particular time in question, the aggregate of the dollar amounts of any cash contributed to the Company’s capital and/or the Gross Asset Value of any property or asset contributed (or deemed contributed pursuant to this Agreement) by such Member to the Company’s capital.

“CapitalExpenditures” shall mean costs and expenses associated with the acquisition, development or redevelopment of Company Properties or any other fixed or capital assets of the Company or any of its Subsidiaries which are capitalized pursuant to GAAP and subject to depletion, depreciation or amortization.

“Certificate” is defined in the recitals.

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“Chairman” is defined in Section 6.6(f).

“ChangeinControl” means, with respect to any Member, any transaction or series of transactions that causes such Member’s Parent to be Controlled by a Person (or group of Persons that have agreed to act in concert) that does not Control (or is not Controlled by) such Parent as of the date that such Member first executed this Agreement.

“CollectionCosts” is defined in Section 4.5(a).

“Committed Facilities” means the Initial Facilities and the PA Required Expansion Facilities, collectively.

“Company” is defined in the preamble to this Agreement.

“CompanyNonrecourseLiabilities” means nonrecourse liabilities (or portions thereof) of the Company as defined in Treasury Regulations Section 1.752-1(a)(2) or Treasury Regulations Section 1.752-7 liabilities (as defined in Treasury Regulations Section 1.752-7(b)(3)(i)) assumed by the Company from a Member.

“CompanyProperty” or “CompanyProperties” or “Properties of the Company” means any right, title or interest of the Company or any Subsidiary in or to property or assets of any kind whatsoever, whether real, personal or mixed and whether tangible or intangible and including equity interests or other ownership interests in any Person and whether now in existence or owned or hereafter acquired or constructed.

“Competitive Facilities Project” means (i) any project that involves the addition of any lateral or other pipeline that connects directly to the Facilities and that would transport natural gas for: (1) the ultimate delivery to an end-use facility or (2) further downstream transportation after such natural gas has been transported through any of the Facilities, or (ii) any pipeline project delivering natural gas directly into the Facilities, in each case excluding (x) any project upstream of the Marts Junction receipt point in Lewis County, West Virginia and (y) any extension to the Trunkline.

“Competitive Facilities Project Notice” is defined in Section 9.3(a).

“Contribution Default” is defined in Section 4.2(d)(ii).

“Contribution DefaultNotice” is defined in Section 4.2(d)(ii).

“Control” and its derivatives mean, with respect to any Person, the possession, directly or indirectly, through one or more intermediaries, of the power to direct or cause the direction of management or policies (whether through ownership of securities, by contract or otherwise) of a Person. For the purposes of the preceding sentence but without limiting the generality thereof, Control is deemed to exist when a Person (or group of Persons who have agreed to act in concert) possesses, directly or indirectly, (i) the ability to elect or cause the election of a majority of the board of directors, board of managers or other governing authority of the applicable Person, (ii) in the case of a corporation, 50% or more of all classes and series of issued and outstanding capital stock entitled to vote for the election of the board of directors, (iii) in the case

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of a limited liability company, partnership, limited partnership or joint venture, the right to 50% or more of the distributions therefrom (including liquidating distributions), (iv) in the case of a limited liability company, 50% or more of the outstanding securities of all classes and series of securities entitled to vote in the election of the board of managers, management committee or other governing authority thereof, (v) in the case of a limited partnership (including any master or publically traded limited partnership), a general partner interest therein or the right to vote or designate or cause the voting or designation of a general partner thereof or (vi) in the case of any Person, 50% or more of the economic or beneficial interest therein or the right to receive 50% or more of the profits or income of such Person.

“CPI” is defined in Section 14.22.

“Day(s)” means any calendar day.

“DefaultingMember” means any Member for which an Event of Default has occurred.

“Deficiency” is defined in Section 4.2(d)(i).

“Deficiency Interest Expense” has the meaning set forth in the definition of “Interest.”

“Deficiency Interest Income” has the meaning set forth in the definition of “Interest.”

“Depreciation” means for each taxable period, an amount equal to the depreciation, amortization, or other cost recovery deduction allowable with respect to an asset for such period for federal income tax purposes, except that (a) with respect to any asset the Gross Asset Value of which differs from its adjusted tax basis for federal income tax purposes and which difference is being eliminated by use of the remedial allocation method pursuant to Treasury Regulations Section 1.704-3(d), Depreciation for such period shall be the amount of book basis recovered for such period under the rules prescribed by Treasury Regulations Section 1.704-3(d)(2) and (b) with respect to any other asset the Gross Asset Value of which differs from its adjusted tax basis at the beginning of such period, Depreciation shall be an amount that bears the same ratio to such beginning Gross Asset Value as the federal income tax depreciation, amortization, or other cost recovery deduction for such period bears to such beginning adjusted tax basis, provided, however, that if the adjusted tax basis of an asset at the beginning of such period is zero, Depreciation shall be determined with reference to such beginning Gross Asset Value using any reasonable method selected by the Board.

“Diluting Member” is defined in Section 4.3(c).

“Dilution Election” is defined in Section 4.3(a).

“Dilution Funding Member” is defined in Section 4.3(d).

“Dilution Shortfall” is defined in Section 4.3(c).

“Disagreeing Member” is defined in Section 6.8(b).

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“Dispose” (including the correlative terms “Disposed” or “Disposition”) means any direct or indirect sale, assignment, transfer, conveyance, gift, distribution or any other disposition, whether voluntary, involuntary or by operation of law or otherwise, including by merger or consolidation or upon liquidation or dissolution, of any rights, interests or obligations with respect to all or any portion of any Membership Interest, Company Properties or other assets; provided, however, that the foregoing expressly excludes (i) a Change in Control and (ii) any pledge of a Member’s Membership Interest or grant of a lien or security interest in a Member’s Membership Interest pursuant to Section 10.1(a).

“Disposition Default” is defined in Section 10.1(a).

“Dominion” is defined in the recitals.

“Dominion Manager(s)” is defined in Section 6.3(a).

“Dominion MLP” is defined in the definition of “Affiliate.”

“Duke” is defined in the recitals.

“DukeManager(s)” is defined in Section 6.3(a).

“EffectiveDate” is defined in the preamble to this Agreement.

“ElectiveContribution” is defined in Section 4.2(e)(i).

“Elective FundingMember” means each Member that elects to fund an Elective Contribution in accordance with Section 4.2(e)(i).

“ElectiveNotice” is defined in Section 4.2(e)(i).

“Emergency Services” is defined in the Operations Agreement.

“EventofDefault” means in respect of a Member (a) a Contribution Default, (b) a Performance Default, (c) a Disposition Default or (d) the occurrence of a Fundamental Event.

“Exercising Member” is defined in Section 10.4(b).

“Facilities” means the Initial Facilities, the PA Required Expansion Facilities and any Approved Facilities Project.

“Facilities Budget” means the Initial Facilities Budget, the PA Required Expansion Facilities Budget and any AFP Budget.

“Facilities Project” means a Base Facilities Project or a Competitive Facilities Project, as applicable.

“Facilities Project Notice” is defined in Section 9.3(b).

“Facilities Project Proposal” is defined in Section 9.3(b).

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“FairMarketValue” means, (i) with respect to any property (including Company Property) or assets, the fair market value of such property or assets as determined in good faith by the Board; and (ii) with respect to a Member’s Membership Interest, the fair market value of such Membership Interest as determined pursuant to the terms of Section 14.20. If any party disputes the Fair Market Value of any property or assets determined in accordance with the foregoing sentence, the Fair Market Value of the property or assets in question shall also be determined pursuant to the procedures set forth in Section 14.20.

“FERC” means the Federal Energy Regulatory Commission or any Governmental Authority succeeding to the powers of such commission.

“FERC Application” means the document, including any amendments, modifications, alterations, revisions or changes thereto, pursuant to which the application for a certificate(s) of public convenience and necessity is made under Section 7 of the Natural Gas Act of 1938, as amended, to the FERC by the Company for authority to construct, own, acquire and operate, and provide service on the Facilities.

“FERC Certificate” means the certificate(s) of public convenience and necessity issued by the FERC pursuant to any FERC Application.

“FERC Certificate Non-Accepting Member” is defined in Section 6.8(c)(i).

“Financing Commitment” means any definitive agreements between one or more Financing Entities and the Company pursuant to which such Financing Entities agree, subject to the conditions set forth therein, to lend money to, or purchase securities of, the Company, the proceeds of which shall be used to finance all or a portion of the Facilities.

“Financing Commitment Assurance” is defined in Section 4.7(b).

“Financing Entity” means a corporation, limited liability company, trust, financial institution, lender or other entity or Person that may be organized for the purpose of lending money or issuing or purchasing securities, the net proceeds of which are to be advanced directly or indirectly to the Company and used to finance the construction of all or a portion of the Facilities.

“FiscalQuarter” means (a) any three-month period commencing on each of January 1, April 1, July 1 and October 1 of a calendar year, and ending on the last date before the next such date and (b) the period commencing on the immediately preceding January 1, April 1, July 1, or October 1, as the case may be, and ending on the date on which all Properties of the Company are distributed to the Members pursuant to Article 11.

“FiscalYear” means (a) any twelve-month period commencing on January 1 and ending on December 31 of a calendar year and (b) the period commencing on the immediately preceding January 1, and ending on the date on which all Properties of the Company are distributed to the Members under Article 11; provided, however, if such period is not permissible for tax purposes, the Board shall select another period as the Company’s “Fiscal Year” that is permissible for tax purposes.

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“FMV Notice” is defined in Section 14.20(b).

“FMV Report” is defined in Section 14.20(b).

“FundamentalEvent” means in respect of a Member (a) that Member or such Member’s equity owner approves of the winding up, dissolution and/or termination of the Member (unless such event occurs after the In-Service Date and the sole distributee of the Member’s Membership Interest is a Permitted Transferee) and such winding up, dissolution and/or termination is not withdrawn or cured by such Member or such Member’s equity owner within 30 Days thereafter or (b) the Member becomes a Bankrupt Member.

“FundingDeadline” is defined in Section 4.2(d)(i).

“GAAP” means generally accepted accounting principles in effect in the United States of America from time to time consistently applied throughout the applicable period.

“Governmental Authority” means any federal, state or local government of the United States or any state thereof, any political subdivision thereof, whether state or local, and any agency, authority, commission, instrumentality, regulatory body, court, central bank or other entity exercising executive, legislative, judicial, taxing, regulatory or administrative powers or functions of government.

“GrossAssetValue” means, with respect to any asset, the asset’s adjusted basis for federal income tax purposes, except as follows:

(1)The initial Gross Asset Value of any asset contributed by a Member to the Company shall be the Fair Market Value;

(2)The Gross Asset Values of all Company Properties shall be adjusted to equal their respective gross fair market values (taking Internal Revenue Code Section 7701(g) into account on the date determined), as reasonably determined by the Board as of the following times: (A) the acquisition of an additional Membership Interest by any new or existing Member in exchange for more than a de minimis Capital Contribution; (B) the acquisition of an interest in the Company (other than a de minimis interest) as consideration for the provision of services to or for the benefit of the Company; (C) the distribution by the Company to a Member of more than a de minimis amount of property as consideration for a Membership Interest; and (D) the liquidation of the Company within the meaning of Treasury Regulations Section 1.704-1(b)(2)(ii)(g); provided that any or all adjustments described in clauses (A), (B) and (C) of this paragraph shall be made only if the Board reasonably determines that such adjustment is necessary to reflect the relative economic interests of the Members in the Company, and provided, further, that, consistent with Section 4.2(e)(iii), the adjustment described in clause (A) of this paragraph shall not be made in connection with any Contribution Default by a Non-Funding Member if no Elective Contributions are made by Non-Defaulting Members and the Non-Funding Member’s Membership Interest is not purchased pursuant to Section 4.5(d);

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(3)The Gross Asset Value of any item of Company Properties distributed to any Member shall be adjusted to equal the Fair Market Value (taking Internal Revenue Code Section 7701(g) into account) of such asset on the date of distribution as reasonably determined by the Board; and

(4)The Gross Asset Values of Company Properties shall be increased (or decreased) to reflect any adjustments to the adjusted basis of such Company Properties under Internal Revenue Code Sections 734(b) or 743(b), but only to the extent that such adjustments are taken into account in determining Capital Accounts under Treasury Regulations Section 1.704-1(b)(2)(iv)(m) and subparagraph (6) of the definition of “Profits” and “Losses”; provided, however, that Gross Asset Values shall not be adjusted under this subparagraph (4) to the extent that an adjustment under subparagraph (2) is required in connection with a transaction that would otherwise result in an adjustment under this subparagraph (4).

If the Gross Asset Value of a Company Property has been determined or adjusted under subparagraphs (2) or (4) above, such Gross Asset Value shall thereafter be adjusted by the Depreciation taken into account with respect to such Company Property for purposes of computing Profits and Losses.

“Initial Facilities” means an approximately 550-mile natural gas pipeline running generally between Lewis County, West Virginia and Chesapeake, Virginia and Robeson County, North Carolina, together with certain gas-fired compression stations and associated meter and regulation stations, all as more fully described and identified in the FERC Application for such Facilities (as amended or modified) and as further described on Schedule A hereto.

“Initial Facilities Budget” means the multi-year budget for the development and construction of the Initial Facilities attached to and approved pursuant to the Initial Resolution.

“Initial Notice” is defined in Section 10.4(b).

“Initial Percentage Interest” means the initial Percentage Interest of each Member set forth on Exhibit 3.1 attached hereto.

“Initial Precedent Agreements” means the Precedent Agreements listed on Exhibit 2.1.

“Initial Resolution” means the initial written consent of all of the Managers dated as of the Effective Date.

“In-Service Date” means the initial date of the placing of the Initial Facilities in service, as notified by the Operator to the Company pursuant to the Operations Agreement.

“Intellectual Property Rights” means (i) patents, trademarks, service marks, rights in designs, trade names, domain names, copyrights, know-how, rights in confidential information and all other intellectual property rights and similar property rights of whatever nature, in each case whether registered or not; (ii) applications and rights to apply for registrations of any of the foregoing and (iii) all forms of protection of a similar nature or having equivalent or similar effect to any of them which may subsist anywhere in the world.

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“Interest” means, with respect to any Contribution Default, (i) if the Company incurred indebtedness to fund the amount of such Contribution Default, any interest incurred by the Company on such Indebtedness (“Deficiency Interest Expense”), or (ii) otherwise, interest on the amount of the Deficiency with respect to such Contribution Default at the Interest Rate, accruing from the Funding Deadline with respect to such Deficiency until the date that the Total Amount in Default is satisfied pursuant to Section 4.2(e)(iii); provided that interest shall accrue only on the amount of the Deficiency that has not been satisfied with retained distributions pursuant to Section 4.2(e)(iii) (“Deficiency Interest Income”).

“InterestRate” means, on the applicable date of determination, the Prime Rate (as published in the “Money Rates” table of The Wall Street Journal).

“InternalRevenueCode” means the Internal Revenue Code of 1986, as amended.

“IP Rights” is defined in Section 14.14.

“Lender” is defined in Section 10.1(a).

“Lien” means any of the following: mortgage; lien (statutory or other); other security agreement, arrangement or interest; hypothecation, pledge or other deposit arrangement; assignment; charge; levy; executory seizure; attachment; garnishment; encumbrance (including any easement, exception, reservation or limitation, right of way, and the like); conditional sale, title retention, voting agreement or other similar agreement, arrangement, device or restriction; preemptive or similar right; the filing of any financing statement under the Uniform Commercial Code or comparable law of any jurisdiction; restriction on Disposition; or any option, equity, claim or right of or obligation to any other Person of whatever kind and character; provided, however, that the term “Lien” excludes any of the foregoing to the extent created by or as permitted under this Agreement.

“MAE” is defined in Section 6.8(a).

“Manager” and “Managers” are defined in Section 6.1 and shall include any Person then serving as a Manager but shall not include any removed Manager.

“Material Contract” means any of the following contracts or agreements to which the Company is or becomes a party after the Effective Date: (i) engineering, procurement and construction contracts, contracts for the construction of the Facilities, and contracts for the procurement of pipe, compression and associated equipment, (ii) any contracts or agreements that require expenditures by the Company in excess of $5,000,000 in the aggregate or provide revenues to the Company in excess of $5,000,000 in the aggregate, (iii) any service agreements for the transmission of natural gas through the Facilities and any other pipeline facilities on which the Company maintains gas transmission capacity, and (iv) any contracts or agreements for the leasing or procurement of any gas transmission capacity on any pipeline facilities not owned by the Company.

“Member” is defined in Section 3.1, but such term excludes any Person who has ceased to be a member.

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“MemberNonrecourseDebt” has the same meaning as the term “partner nonrecourse debt” set forth in Section 1.704-2(b)(4) of the Treasury Regulations.

“MemberNonrecourseDebtMinimumGain” has the same meaning as “partner nonrecourse debt minimum gain” set forth in Treasury Regulations Section 1.704-2(i)(2).

“MemberNonrecourseDeductions” means the amount of deductions, losses and expenses equal to the net increase during the year in minimum gain attributable to a Member Nonrecourse Debt, reduced (but not below zero) by proceeds of such Member Nonrecourse Debt distributed during the year to the Members who bear the economic risk of loss for such debt, as determined in accordance with applicable Treasury Regulations.

“Members Holding a Majority of the Percentage Interests” means Members, subject to the provisions of Section 4.5(b), holding at least fifty-five percent (55%) of the Percentage Interests.

“MembershipInterest” means the interest of a Member in the Company, including the right of such Member to receive distributions (liquidating or otherwise), to be allocated income, gain, loss, deduction, credit, or similar items, to receive information, vote, grant consents or approvals, and all other rights, benefits and privileges enjoyed by or incidental to being a Member, and all liabilities and obligations imposed upon a Member under the Act, the Certificate, this Agreement or otherwise in its capacity as a Member.

“MinimumGain” means with respect to Company Nonrecourse Liabilities, the amount of gain that would be realized by the Company if it Disposed of (in a taxable transaction) all Company Properties that are subject to Company Nonrecourse Liabilities in full satisfaction of such liabilities, computed in accordance with Treasury Regulations Section 1.704-2(d).

“Moody’s” means Moody’s Investors Service, Inc.

“Non-DefaultingMembers” is defined in Section 4.2(e)(i).

“Non-FundingMember” is defined in Section 4.2(d)(ii).

“Nonrecourse Deductions” means, for each Allocation Period or other period, the Company allocations that are characterized as “nonrecourse deductions” under Treasury Regulations Section 1.704-2(b)(1).

“Offered Interest” is defined in Section 10.5(a).

“Officer” is defined in Section 6.9(a).

“OperationsAgreement” means that certain Construction, Operation and Maintenance Agreement to be entered into by and between the Company and Operator on the Effective Date in substantially the form attached to the Initial Resolution.

“Operator” means, initially, Dominion Transmission, Inc.

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“PA Execution Date” means the date on which the last of the Initial Precedent Agreements is executed and delivered by the Company and the other party thereto.

“PA Required Expansion Facilities” means the facilities described in the relevant attachment to the Initial Resolution.

“PA Required Expansion Facilities Budget” is defined in Section 7.1(b).

“Parent” means the Person that Controls a Member as of the date that such Member executed this Agreement, and that is not itself Controlled by any other Person. The Parents of the Members as of the Effective Date are: (i) with respect to Dominion, Dominion Resources, Inc., (ii) with respect to Duke, Duke Energy Corporation, (iii) with respect to Piedmont, Piedmont Natural Gas Company, Inc., and (iv) with respect to AGL, AGL Resources, Inc. Upon any change to the identity of a Member’s Parent, such Member shall immediately notify all other Members.

“ParticipationElectionPeriod” is defined in Section 4.2(e)(i).

“Participation Notice” is defined in Section 4.2(e)(i).

“Percentage Interest” means, as of any date of determination, the ratio (expressed as a percentage) that (a) such Member’s aggregate Capital Contributions as of such date bears to (b) the aggregate Capital Contributions of all Members as of such date; provided that amounts treated as Capital Contributions pursuant to (i) Section 4.2(e)(iii) and applied to the payment of Deficiency Interest Expense or Collection Costs and (ii) Section 4.5(a) shall not be included in Capital Contributions for purposes of this definition of “Percentage Interest.” Notwithstanding the foregoing, the Initial Percentage Interests of the Members shall not be adjusted for any amounts contributed pursuant to Section 4.1 or Section 4.4. In addition, if there are no Elective Contributions in respect of any Contribution Default by a Non-Funding Member and such Non-Funding Member’s Membership Interest is not purchased pursuant to Section 4.5(d), then for purposes of this definition of “Percentage Interest” the Non-Funding Member will be treated as having made a Capital Contribution of the Deficiency with respect to such Contribution Default but will not be treated as having made a further Capital Contribution when Retained Distributions of the Non-Funding Member are applied to the payment of such Deficiency pursuant to Section 4.2(e)(iii).

“Performance Default” means any material breach or material default (other than a Contribution Default) by a Member in the performance of, or any material failure by a Member to comply with, any agreement, obligation, covenant, or undertaking of such Member under this Agreement which has not been remedied on or prior to (i) the expiration of the cure period, if any, set forth herein or (ii) if no cure period is set forth herein, thirty (30) Days after such Member’s receipt of such written notice of such breach, default or failure from the Company or any other Member, or if such breach, default or failure cannot reasonably be remedied within such thirty (30) Day period, sixty (60) days after such Member’s receipt of such written notice (provided that such Member has and continues to diligently pursue such remedy).

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“PermittedLiens” means any of the following matters:

(i)    any (a) undetermined or inchoate liens or charges constituting or securing the payment of expenses which were incurred incidental to maintenance or operation of the Company’s Properties and (b) materialman’s, mechanics’, repairman’s, employees’, contractors’, operators’ or other similar liens, security interests or charges for liquidated amounts arising in the ordinary course of business incidental to construction, maintenance or operation of the Company’s Properties that are not due and payable and that will be paid in the ordinary course of business;

(ii)    any liens for taxes, assessments, or other government charges that are not yet due and payable; and

(iii)    rights reserved to or vested in any Governmental Authority to control or regulate any of the Company’s Properties and all applicable laws.

“PermittedTransfer” means (a) with respect to any Member, (i) a Disposition by such Member of all or any portion of its Membership Interests, to one or more Permitted Transferees, or (ii) a Change in Control of such Member and (b) with respect to Dominion and AGL, a one-time Disposition by Dominion to AGL of a portion of Dominion’s Membership Interest equal to two percent (2%) of the Membership Interests of the Company.

“PermittedTransferee” means any Affiliate of the transferring Member.

“Person” is defined in Section 18-101(12) of the Act.

“Piedmont” is defined in the recitals.

“PiedmontManager(s)” is defined in Section 6.3(a).

“Pledged Interest” is defined in Section 10.1(a).

“Pre-Effective Expenditures” means (a) expenditures made and costs incurred by any Member or any of its Affiliates prior to the Effective Date, as set forth on Exhibit 4.4, or (b) expenditures and costs incurred by any Member or any of its Affiliates prior to the PA Execution Date that are approved by the Board pursuant to Section 4.4, in either case, in the course of planning and designing the Initial Facilities, including expenditures made and costs incurred in preparing materials necessary for the FERC Application for the Initial Facilities and determining the route(s), acquiring survey and land rights and commencing public outreach efforts for the Initial Facilities, except for any costs or expenses described in Section 1.7.

“Precedent Agreement” means an agreement between the Company and a prospective shipper of natural gas through the Facilities, including any Facilities Project, that involves the commitment by such shipper, upon satisfaction of one or more conditions precedent, to execute a service agreement with Company obligating such shipper to pay demand charges in return for a firm transportation obligation on the part of the Company.

“Proceeding” is defined in Section 8.1.

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“Profits” and “Losses” mean, for each Allocation Period, an amount equal to the Company’s taxable income or loss for such Allocation Period, determined in accordance with Internal Revenue Code Section 703(a) (for purposes of such determination, all items of income, gain, loss or deduction required to be stated separately under Internal Revenue Code Section 703(a)(1) shall be included in taxable income or loss), with the following adjustments (without duplication):

(5)Any income of the Company exempt from federal income tax and not otherwise taken into account in computing Profits or Losses under this definition of “Profits” and “Losses” shall be added to such taxable income or loss;

(6)Any expenditures of the Company described in Internal Revenue Code Section 705(a)(2)(B) or treated as Internal Revenue Code Section 705(a)(2)(B) expenditures under Treasury Regulations Section 1.704-1(b)(2)(iv)(i) and not otherwise taken into account in computing Profits or Losses under this definition of “Profits” and “Losses” shall be subtracted from such taxable income or loss;

(7)If the Gross Asset Value of any Company asset is adjusted under clauses (ii) or (iii) of the definition of Gross Asset Value, the amount of such adjustment shall be treated as an item of gain (if the adjustment increases the Gross Asset Value of the asset) or an item of loss (if the adjustment decreases the Gross Asset Value of the asset) from the disposition of such asset and shall be taken into account for purposes of computing Profits or Losses;

(8)Gain or loss resulting from any Disposition of property of the Company with respect to which gain or loss is recognized for federal income tax purposes shall be computed by reference to the Gross Asset Value of the property Disposed of, notwithstanding that the adjusted tax basis of such property differs from its Gross Asset Value;

(9)In lieu of the depreciation, amortization and other cost recovery deductions taken into account in computing such taxable income or loss, there shall be taken into account Depreciation for such Allocation Period, computed in accordance with the definition of Depreciation;

(10)To the extent an adjustment to the adjusted tax basis of any Company asset under Internal Revenue Code Section 734(b) is required, under Treasury Regulations Section 1.704-1(b)(2)(iv)(m)(4), to be taken into account in determining Capital Accounts as a result of a distribution other than in liquidation of a Member’s Membership Interest, the amount of such adjustment shall be treated as an item of gain (if the adjustment increases the basis of the asset) or loss (if the adjustment decreases such basis) from the Disposition of such asset and shall be taken into account for purposes of computing Profits or Losses; and

(11)Notwithstanding any other provision of this definition, any items which are specially allocated under Section 5.2 shall not be taken into account in computing Profits or Losses.

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The amounts of the items of Company income, gain, loss or deduction available to be specially allocated under Section 5.2 shall be determined by applying rules analogous to those set forth in subparagraphs (1) through (6).

“Proposing Member” is defined in Section 10.5(a).

“Purchase Notice” is defined in Section 10.5(a).

“Purchased Interest” is defined in Section 10.5(a).

“Qualified Transferee” means a corporation, limited liability company or partnership organized and existing under the laws of the United States, any state thereof or the District of Columbia that either (a) both before and after giving effect to the relevant Disposition, has a Sufficient Credit Rating, or is Affiliated with a Person having a Sufficient Credit Rating that has agreed in writing to irrevocably and unconditionally guarantee all of such transferee’s obligations under this Agreement or (b) has the requisite financial capability to assume the responsibilities and obligations as a Member as reasonably determined, in writing, by Members holding at least 70% of the Percentage Interests.

“RegulatoryAllocations” is defined in Section 5.2(k).

“Reimbursed Expenditures” is defined in Section 4.1(d).

“Retained Distributions” is defined in Section 4.2(e)(iii).

“ROFR Expiration Date” is defined in Section 10.5(a).

“ROFR Interest” is defined in Section 10.5(a).

“ROFR Notice” is defined in Section 10.5(a).

“S&P” means Standard and Poor’s Rating Group.

“Securities Act” means the Securities Act of 1933, as amended.

“SeniorExecutives” means the employees of the Members who have the authority to settle disputes among the Members.

“Subsequent Notice” is defined in Section 10.4(c).

“Subsequent Purchase” is defined in Section 10.4(c).

“Subsidiary” means (i) any corporation or other entity a majority of the common stock (or similar equity securities) of which having ordinary voting power to elect a majority of the board of directors or other Persons performing similar functions is at the time owned, directly or indirectly, with power to vote, by the Company or any direct or indirect Subsidiary of the Company or (ii) a partnership in which the Company or any direct or indirect Subsidiary is a general partner.

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“Sufficient Credit Rating” means a credit rating for a Person’s long-term, senior, unsecured debt not supported by third party credit enhancements (or if such Person has no long-term, senior unsecured debt, then such party’s long-term issuer rating) of Baa2 or higher from Moody’s and BBB or higher from S&P (in the event such Person is rated differently by S&P and Moody’s, the lower of which shall apply).

“TaxMattersMember” is defined in Section 7.9.

“TotalAmountinDefault” means, as of any time with respect to any Non-Funding Member, an amount equal to: (a) the outstanding amount of such Non-Funding Member’s Deficiency, plus any associated Interest and Collection Costs, reduced by (b) distributions otherwise payable to the Non-Funding Member which are retained by the Company pursuant to Article 4.

“TransactionDocuments” means, collectively, (a) this Agreement, (b) the Certificate, and (c) the Operations Agreement.

“TreasuryRegulations” (or any abbreviation thereof used herein) means temporary or final regulations promulgated under the Internal Revenue Code.

“Trunkline” means the principal natural gas transmission pipeline component(s) of the Facilities.

“Unfunded Default Amount” means, as of any date of determination with respect to a Member, an amount equal to the sum of (i) the excess, if any, of (x) the cumulative amount of items of deductions and loss for Deficiency Interest Expense or attributable to Collection Costs allocated to such Member pursuant to Section 5.2(h) or Section 5.2(j), as applicable, over (y) the cumulative amount of Retained Distributions of such Member that are applied to the payment of such Deficiency Interest Expense or Collection Costs pursuant to Section 4.2(e)(iii) and the amount of payments made by such Member to the Company with respect to such Collection Costs pursuant to Section 4.5(a)plus (ii) the excess, if any, of (x) any Deficiency of such Member that is subject to the provisions of Section 4.2(e)(iii), over (y) the amount of Retained Distributions applied to the payment of such Deficiency pursuant to Section 4.2(e)(iii).

“Undistributed Deficiency Interest Income” means, as of any date of determination with respect to a Member, an amount equal to cumulative amount of items of income or gain for Deficiency Interest Income allocated to such Member pursuant to Section 5.2(i).

ARTICLE 3

MEMBERS

3.1.    Members

The names and addresses of the members of the Company are set forth in Exhibit 3.1 (the “Members”).

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3.2.    Membership Interests

The Company shall have one class of Membership Interests which shall be expressed as a percentage and may be issued in whole or fractional percentages. The Membership Interests shall have the rights, preferences, privileges, restrictions and obligations set forth in this Agreement. The creation of any new series or class of Membership Interests by designation, resolution, amendment or otherwise shall be deemed to be an amendment, modification or restatement of this Agreement requiring compliance with Section 14.2. The Membership Interests shall not be certificated. Each of the Members was admitted as a Member of the Company in accordance with this Agreement. Subject to each Member making its initial Capital Contribution as provided in Sections 4.1(a) and (b), each Member’s Capital Contributions and Percentage Interest shall be as set forth opposite such Member’s name on Exhibit 3.1 hereto. Without the consent of the Members, the Board may amend Exhibit 3.1 to reflect any changes thereto resulting from any additional Capital Contributions by a Member, Permitted Transfers or other Dispositions of Membership Interests, admissions of new Members and dilutions or upward adjustments to a Member’s Percentage Interest effected in accordance with this Agreement.

3.3.    Voting.

(a)In order for the Company to determine the Members entitled to (i) vote at any meeting of Members or any adjournment thereof, (ii) express consent to action in writing without a meeting, (iii) receive payment of any distribution and (iv) exercise any rights hereunder and in order to determine the allocation of votes or rights based on the Membership Interests held by the Members, the Board may fix a record date, which shall not precede the date upon which the resolution fixing the record date is adopted by the Board, and which record date shall not be more than sixty (60) Days nor less than five (5) Days before the date of such meeting or other action.

(b)Except as otherwise provided in this Agreement, to the extent that the vote of Members may be required hereunder or under applicable law, the affirmative vote of the Members Holding a Majority of the Percentage Interests shall constitute an act of the Members.

3.4.    Additional Members and Membership Interests

The Company may issue additional Membership Interests at such price and on such terms as may be agreed upon by the Board with the consent of the Members holding at least 96% of the Percentage Interests from time to time; provided that, pursuant to Section 10.4, all Members (other than a Defaulting Member or a Diluting Member) will have pro rata preemptive rights in the issuance by the Company of any such additional Membership Interests to the extent necessary to maintain their respective Percentage Interests in the Company, as adjusted, prior to such additional Membership Interest issuance. Additional Persons may only be admitted to the Company as Members as expressly provided in Section 10.1(c).

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3.5.    Liability to Third Parties

Except as otherwise required by the Act, no Manager and no Member or any Affiliate, officer, director, manager, partner, employee or other agent of such Member, solely by reason of being a Member or a Manager, shall be liable for the debts, obligations or liabilities of the Company or any other Member.

3.6.Withdrawal

A Member has no power or right to voluntarily withdraw, resign or retire from the Company, and each Member irrevocably waives any and all rights of a resigning or withdrawing member under Section 18-604 of the Act. Any attempted withdrawal by any Member from the Company before any dissolution of the Company will be deemed a Performance Default and result in such Member being treated as a Defaulting Member, and such Member shall be liable to the Company for any damages arising directly or indirectly from such purported withdrawal and shall not be entitled to any distribution from the Company by reason of such purported withdrawal.

3.7.Members Have No Agency Authority

Except as expressly provided in this Agreement, no Member (in its capacity as a member of the Company) has any agency authority on behalf of the Company.

3.8.Priority and Return of Capital

No Membership Interest shall have any priority over any other Membership Interest, either as to the return of Capital Contributions or as to the allocation of Profits, Losses or in any distributions.

3.9.    Limitation on Liens

Except for (i) Liens described in Section 10.1(a) (ii) a right of first offer granted by Dominion or its Affiliate in favor of Dominion MLP in respect of the direct or indirect ownership of Dominion’s Membership Interest and (iii) Liens granted to a Financing Entity (or any agent or trustee thereof) in connection with any approved Financing Commitment, no Member shall pledge, grant a security interest in or otherwise permit or suffer to exist any Lien on its Membership Interest without the prior written approval of the other Members.

ARTICLE 4

CAPITAL CONTRIBUTIONS; DEFAULT

4.1.Capital Contributions

(a)Effective Date Capital Contributions. Simultaneous with the execution of this Agreement, each Member hereby agrees to contribute all of its right, title and interest, if any, in the assets acquired by means of the Pre-Effective Expenditures, free and clear of any encumbrances, liens or mortgages, and agrees to execute and deliver any and all assignments and conveyances as may be necessary or appropriate to evidence

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such contribution. The amount of each such Member’s initial Capital Contribution shall be the amount of the Pre-Effective Expenditures set forth opposite such Member’s name on Exhibit 4.4 attached hereto.

(b)PA Execution Date Capital Contributions. Subject to the last sentence of this Section 4.1(b), within two (2) Business Days after the PA Execution Date, each Member hereby agrees to make a cash Capital Contribution in the amount set forth opposite such Member’s name on Exhibit 3.1 attached hereto under the column titled “Capital Contributions” as part of its initial Capital Contribution in order to equalize the Members’ Capital Contributions in proportion to their respective Percentage Interests (so that all Members’ Capital Contributions made pursuant to Section 4.1(a) and this Section 4.1(b), after giving effect to the distribution of such cash described in the next sentence, are pro rata in proportion to their Initial Percentage Interests). The Members acknowledge and agree that such cash Capital Contributions shall, subject to the last sentence of this Section 4.1(b), immediately be distributed pursuant to Section 5.5(d) to the Members that have Pre-Effective Expenditures set forth on Exhibit 4.4 such that the amount of Pre-Effective Expenditures of a Member set forth on Exhibit 4.4less the cash distribution to such Member equals such Member’s pro rata portion (in accordance with its Initial Percentage Interest set forth on Exhibit 3.1) of all such Pre-Effective Expenditures. Notwithstanding the foregoing, in the event that prior to the PA Execution Date, Duke or Piedmont makes Capital Contributions to the Company pursuant to Section 4.1(d), the amount of such Capital Contributions shall reduce the amount otherwise required to be contributed by such Member(s) (and distributed to the Members that have Pre-Effective Expenditures set forth on Exhibit 4.4) pursuant to this Section 4.1(b); provided, further, [^***].

(c)Further Capital Contributions. Except as specifically set forth in this Article 4 or otherwise agreed to in writing by all of the Members, no Member will be required or permitted to make any Capital Contributions.

(d)    Reimbursement. The Members acknowledge that Dominion and/or its Affiliates have incurred or committed to incur on behalf of the Company, and prior to the PA Execution Date will continue to incur or commit to incur on behalf of the Company, all of the Pre-Effective Expenditures. [^***]

4.2.    Additional Capital Contributions

______________________

^*** Confidential information has been omitted and filed separately with the Securities and Exchange Commission. Confidential treatment has been requested with respect to this omitted information.

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(a)Capital Call. From and after the PA Execution Date, the Board shall make a capital call for Additional Capital Contributions from the Members by issuing a written notice to the Members in the form set forth as Annex C (a “Capital Call Notice”) at any time the Operator determines in good faith that the Company requires capital to fund (i) expenditures contemplated in and substantially consistent with the current Annual Budget for the purposes set forth therein and, if with respect to expenditures contemplated by the Initial Budget or the PA Required Expansion Facilities Budget, up to an amount not to exceed, in the aggregate, the applicable Aggregate Budget Cap or (ii) Emergency Services. Except as provided in Sections 4.2(f) and 4.3, all Capital Contributions described in any Capital Call Notice issued in accordance with Section 4.2(b) are mandatory, and each Member hereby agrees to make such Capital Contributions to the Company, by wire transfer in immediately available funds, at the time and in such amount as is specified in each Capital Call Notice.

(b)Capital Call Notice. Each Capital Call Notice will specify: (i) the aggregate amount of Capital Contributions to be made consistent with the current Annual Budget; (ii) the date on which such funds are to be contributed (which date will not be less than twenty (20) Days after the date the Capital Call Notice is issued by the Board); (iii) the amount of the Capital Contribution to be made by each Member (calculated as the product of such aggregate amount of Capital Contributions described in clause (i) multiplied by such Member’s Percentage Interest); (iv) the bank account of the Company to which such Capital Contributions should be transferred; and (v) the purpose(s) for which the additional capital will be utilized (including a reference to the applicable item(s) in the Annual Budget or Facilities Budget against which such capital will be applied). In no event shall a Capital Call Notice be issued for the purpose of funding cash distributions to the Members. Each Capital Call Notice issued by the Board shall, absent manifest error, be conclusive and binding for all purposes on the Members.

(c)Upon the making of any Capital Contribution, the Members’ respective Capital Account balances shall be adjusted to reflect such Capital Contributions.

(d)Failure to Contribute.

(i)Notice. If a Member fails to contribute all or any portion of a Capital Contribution required to be made by it hereunder by the date required in the relevant Capital Call Notice, then a Manager on behalf of the Board will, and any Member may, promptly provide written notice of such failure to such Member, and such Member will have ten (10) Days from receipt of such written notice (the “Funding Deadline”) to contribute such Capital Contribution in full (such amount, the “Deficiency”).

(ii)Failure to Make a Capital Contribution. If a Member fails to contribute (or satisfy through Financing Commitment Assurance, if any, that may be in existence for the benefit of the Company pursuant to Section 4.7(b)) the Deficiency in full by the Funding Deadline (such Member, a “Non-Funding

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Member”), then such Member shall be in default of its obligations hereunder in respect of such Capital Contribution (referred to as a “Contribution Default”). The Board will, or any Member may, promptly provide written notice of such Contribution Default to each Member, which notice will indicate the amount of such Deficiency (a “Contribution Default Notice”); provided that the failure to provide such notice shall have no effect on the existence of such Contribution Default.

(e)Elective Contributions.

(i)Funding by Non-Defaulting Members. After the Funding Deadline, each Member (other than the Non-Funding Member(s) and any other Defaulting Member) (the “Non-Defaulting Members”) shall have the right but not the obligation to deliver written notice (an “Elective Notice”) to the Board and each other Member not later than thirty (30) Days after receipt of the Contribution Default Notice stating that such Non-Defaulting Member agrees to fund the full amount of the Deficiency as a Capital Contribution to the Company (an “Elective Contribution”); provided that two or more Non-Defaulting Members may jointly elect to make Elective Contributions in respect of the full amount of the Deficiency. Each other Non-Defaulting Member shall have the right, but not the obligation, for a period of ten (10) Days after its receipt of an Elective Notice (the “Participation Election Period”), to elect to participate in the Elective Contribution specified in the applicable Elective Notice by providing written notice thereof to the Board and each other Member (a “Participation Notice”). If a Participation Notice is given prior to the expiration of such ten (10)-Day period, then the amount of the Elective Contribution of each Elective Funding Member shall be an amount equal to the product of (x) the Deficiency multiplied by (y) a fraction, the numerator of which shall be the Percentage Interest of such Elective Funding Member and the denominator of which shall be the aggregate Percentage Interests of all such Elective Funding Members. Elective Contributions shall be made by wire transfer in immediately available funds not later than ten (10) Days after the expiration of the Participation Election Period.

(ii)Adjustment of Percentage Interests. In the event that an Elective Funding Member makes an Elective Contribution to the Company, the Percentage Interests of all affected Members will be recalculated based on the respective aggregate Capital Contributions of each Member through and including the date such Elective Contribution is made.

(iii)No Elective Contributions. If there are no Elective Contributions in respect of any Contribution Default by a Non-Funding Member and the Non-Funding Member’s Membership Interest is not purchased pursuant to Section 4.5(d), (x) the Percentage Interests of the Members shall not be adjusted and (y) from and after the occurrence of the relevant Contribution Default until the Total Amount in Default is paid in full, and without prejudice to any other remedies available to the Company and the Non-Defaulting Members under this Agreement, at law or in equity, all distributions from the Company that would

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otherwise be made to the Non-Funding Member pursuant to this Agreement shall not be made to the Non-Funding Member but shall instead be retained by the Company (“Retained Distributions”) and applied, dollar-for-dollar, to reduce the Total Amount in Default. Retained Distributions applied towards the Total Amount in Default shall be deemed paid first, to reimburse the Company for any Collection Costs, second, to the payment of Interest and third, to payment of the outstanding amount of the Deficiency. Retained Distributions shall be treated as having been distributed to the Non-Funding Member and then contributed by the Non-Funding Member to the capital of the Company; provided that any Retained Distributions applied to the payment of Interest that constitutes Deficiency Interest Income shall be treated as having been paid by the Non-Funding Member to the Company.

(f)Budget Cap. Notwithstanding anything contained in this Agreement to the contrary, no Member shall be obligated to make any Capital Contributions in respect of the Committed Facilities to the extent that such Capital Contributions would, taking into account all Capital Contributions previously made by such Member with respect to such Committed Facilities, exceed such Member’s applicable Budget Cap with respect to such Committed Facilities. The Members acknowledge that each Budget Cap applicable to each Member shall initially be set at an amount equal to (i) 110% of such Member’s Percentage Interest of the Initial Facilities Budget (in effect as of the Effective Date) with respect to the Initial Facilities or (ii) the amount in U.S. dollars set forth opposite such Member’s name in Attachment D to the Initial Resolution with respect to the PA Required Expansion Facilities, as applicable, and that the Budget Cap for each Member that voted to approve a Budget Overrun shall be deemed to be automatically increased by an amount equal to such Member’s Percentage Interest of the amount of such Budget Overrun. A Budget Cap applicable to any Member shall not be reduced under any circumstances, including as a result of such Member becoming a Diluting Member or Defaulting Member.

4.3.Dilution.

(a)Notwithstanding anything contained in Section 4.2 to the contrary, any Member that voted in the negative in connection with an Approved Facilities Project approved by the Board in accordance with Section 6.7(b)(iii)(4) shall be permitted to elect, by written notice to the other Members within ten (10) Days after such vote, to have its Percentage Interest diluted (a “Dilution Election”). Any Dilution Election made pursuant to this Section 4.3 shall be final and irrevocable.

(b)Notwithstanding anything contained in Section 4.2 to the contrary, if the Board at any time approves a Budget Overrun in accordance with Section 6.7(b)(iii)(14), the Board shall, no later than two (2) Business Days following such determination, notify the Members in writing of such approval (such notice to include details of the Budget Overrun). Any Member that voted in the negative in connection with the Budget Overrun shall be permitted to elect, by written notice to the other Members within ten (10) Days of its receipt of the notice described in the immediately preceding sentence, to make a Dilution Election.

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(c) Effective upon a Dilution Election: (i) the Member that made such election (the “Diluting Member”) shall have no obligation to make any Capital Contribution(s) to the Company in respect of such Approved Facilities Project or Budget Overrun, as applicable; (ii) the amount of the Capital Contribution(s) that the Diluting Member would otherwise have been obligated to fund absent such election (the “Dilution Shortfall”) shall be made by the other Members as provided in Section 4.3(d); (iii) the Diluting Member shall not be considered to be a Defaulting Member or to have an outstanding Deficiency with respect to such Approved Facilities Project or Budget Overrun, as applicable; (iv) a Diluting Member will be entitled to participate in any future proposed Facilities Project at its then-current Percentage Interest and (v) following the funding of any Dilution Shortfall pursuant to Section 4.3(d), the Diluting Member shall be deemed to have waived all of its rights under Section 10.4. Notwithstanding the foregoing, in no event shall a Diluting Member be relieved of its obligations under Section 4.2 to make any Capital Contributions in respect of any of the Committed Facilities at its then-current Percentage Interest up to the amount of its Budget Cap relating to such Committed Facilities.

(d)Following a Dilution Election, (i) each of the Members holding at least 15% of the Percentage Interests whose designated Managers approved the Budget Overrun or Approved Facilities Project (any such Member, a “Dilution Funding Member”) shall be obligated to make Capital Contributions to the Company of either (1) an amount equal to the Dilution Shortfall multiplied by a fraction, the numerator of which is the Percentage Interest of such Dilution Funding Member and the denominator of which is the aggregate Percentage Interests of all Dilution Funding Members or (2) such other portion of the Dilution Shortfall as may be agreed by the Dilution Funding Members; provided that the entire Dilution Shortfall is funded. The applicable Budget Cap for each Dilution Funding Member shall be increased by the amount of Capital Contributions it makes to fund the Dilution Shortfall, consistent with the above.

(e)Following the making of the Capital Contributions by the Dilution Funding Member(s) pursuant to Section 4.3(d), the Members’ respective Percentage Interests shall be adjusted to reflect such Capital Contributions and the dilution of the Diluting Member’s Percentage Interest. The adjustment of the Members’ respective Percentage Interests shall constitute the sole and exclusive remedy of the Company and each other Member with respect to such Dilution Election.

4.4.Pre-Effective Expenditures

Set forth in Exhibit 4.4 are the amounts of Pre-Effective Expenditures that have been incurred by each Member (or its Affiliates) with respect to the Initial Facilities and that are, as of the Effective Date, approved by the Members and the Company. If any Member or Affiliate thereof has made expenditures or incurred costs prior to the PA Execution Date that are not set forth in Exhibit 4.4 but which such Member desires to be considered as Pre-Effective Expenditures, such Member may, no later than ninety (90) Days after the PA Execution Date, request approval thereof by consent of the Managers designated by the Members holding at least 70% of the Percentage Interests. After all such additional expenditures and costs to be

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considered as Pre-Effective Expenditures hereunder have been approved or disapproved by the Members, each Member whose additional expenditures or costs are approved as Pre-Effective Expenditures pursuant to this Section 4.4 shall be treated as having made an additional Capital Contribution in the amount of such approved Pre-Effective Expenditures and, if after the Effective Date, the applicable Member(s) shall, without the requirement for any Capital Call Notice and not later than two (2) Business Days following its receipt of written notice from the Board, make cash Capital Contributions to the Company in order to equalize the Members’ Capital Contributions in proportion to their respective Percentage Interests (so that all Members’ Capital Contributions made pursuant to Section 4.1(a)¸ Section 4.1(b), Section 4.1(d) and this Section 4.4, after giving effect to the distributions of cash described in Section 4.1(b), Section 4.1(d) and in the proviso to this sentence, are pro rata in proportion to their Initial Percentage Interests); provided, that the amount of such cash Capital Contributions shall immediately be reimbursed to each Member whose (x) cash Capital Contributions pursuant to Section 4.1(b) and Section 4.1(d), plus Pre-Effective Expenditures, less cash distributions pursuant to Section 4.1(b) and Section 4.1(d) are greater than (y) an amount equal to such Member’s respective Initial Percentage Interest times all Pre-Effective Expenditures, in any such case, in the amount of such excess. The assets, if any, acquired by means of the additional Pre-Effective Expenditures of the Members shall be and are hereby contributed to the Company free and clear of any encumbrances, liens or mortgages. All applicable Members agree to execute and deliver any and all assignments and conveyances as may be necessary or appropriate to evidence such contribution.

4.5.    Events of Default

(a)Certain Remedies. If any Event of Default has occurred and is continuing, the Company and the Non-Defaulting Members may each exercise all rights and remedies available under this Agreement, at law or in equity, in connection with enforcing the Company’s and/or such Member’s rights and remedies hereunder in connection with such Event of Default, including court proceedings as may be necessary to collect any Total Amount in Default, as applicable. The Members agree that the Company shall, and each Non-Defaulting Member shall have the right to instruct the Board to, commence any action or proceeding to enforce the Company’s rights hereunder at law or in equity in any court of competent jurisdiction consistent with Section 14.7 below. The Defaulting Member shall indemnify, hold harmless, pay and reimburse the Company, each other Member and their Affiliates and their respective directors, officers, employees and agents from and against any costs and expenses, including reasonable attorneys’ fees and costs, and claims asserted by or on behalf of any Person that result from such Event of Default, including in connection with collecting all or any portion of the relevant Total Amount in Default (the “Collection Costs”); provided, however, the foregoing shall not apply to damages referenced in Section 14.10, other than in the case where the indemnified Person is legally obligated to pay such damages to another Person in connection with such claim. Collection Costs paid by a Defaulting Member to the Company shall be treated as a Capital Contribution by the Defaulting Member.

(b)Impact of Event of Default. If any Event of Default has occurred and is continuing, then for so long as such Event of Default is continuing:

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(i)The Defaulting Member shall, other than with respect to any amendment or restatement of this Agreement or the Certificate in a manner which is materially adverse to the Defaulting Member’s distribution (liquidating or otherwise) and/or allocation rights in this Agreement, forfeit all voting and consent rights of a Member hereunder (including any voting and consent rights relating to the approval, suspension or termination of, or enforcement of rights under, any Transaction Document).

(ii)No Disposition or other transfer or assignment of a Membership Interest (by operation of law or otherwise) in a Disposition, Change in Control or otherwise by a Defaulting Member shall be effective unless the transferee pays to the Company, at the time of such Disposition, transfer or assignment, an amount equal to the Total Amount in Default of such Defaulting Member.

(iii)Neither the Defaulting Member nor any of its Affiliates shall have the right to exercise any rights pursuant to Sections 4.5(d), 10.4 or 10.5.

(iv)A Defaulting Member shall continue to be required to make Capital Contributions pursuant to any Capital Call issued by the Board pursuant to the then-current Budget as approved by the Board and pursuant to the terms of this Agreement.

(c)Affiliates. For all purposes of this Agreement, if any Member is a Defaulting Member, then each Affiliate (other than an Affiliate that is a publicly- traded limited partnership or a publicly-traded limited liability company with partnership tax status, in each case, publicly-traded on a national securities exchange) of such Defaulting Member that is also a Member at the time of such Event of Default shall be deemed to be a Defaulting Member.

(d)Buy-Out Right. Upon the occurrence of an Event of Default (but in the case of a Contribution Default, only if and after the Elective Funding Members fail to deliver Elective Notices in accordance with Section 4.2(e)(i)), any Non-Defaulting Member may (but shall not be obligated to), by delivery of written notice to the Defaulting Member and the other Members, purchase, at any time for so long as such Event of Default is continuing, all of the Defaulting Member’s Membership Interest by written notice to the other Members. In the event that more than one Non-Defaulting Member elects to purchase such Membership Interest, the Non-Defaulting Members so electing to purchase shall be entitled to purchase a portion of such Membership Interest in proportion to their respective Percentage Interests. The purchase price for the defaulting Member’s Membership Interest shall be (i) if the Event of Default occurred prior to the In-Service Date, an amount equal to seventy-five percent (75%) of the amount of all Capital Contributions made by the Defaulting Member as at the date of such Event of Default or (ii) if the Event of Default occurred following the In-Service Date, an amount equal to seventy-five percent (75%) of the Fair Market Value of such Membership Interest as at the date of such Event of Default. If such purchase right is exercised, the closing shall occur within sixty (60) days following the first delivery of a notice to the Defaulting Member pursuant to this Section 4.3(d) or the

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determination of the Fair Market Value of such Membership Interest, as applicable, at such time and place as the relevant Members may agree. At the closing, the Non-Defaulting Member(s) shall pay for the Membership Interest by wire transfer of immediately available funds to one or more accounts of the Defaulting Member designated by the Defaulting Member in writing, and the Membership Interest so purchased shall be conveyed by the Defaulting Member free and clear of all Liens (except those created under or pursuant to this Agreement). Each Member agrees to execute and deliver all related documentation and take such other action in support of the transfer of the Defaulting Member’s Membership Interest as shall be requested by the Non-Defaulting Members in order to carry out the terms and provision of this Section 4.3(d). The right of the Non-Defaulting Members to purchase the Defaulting Member’s Membership Interest shall be in addition to such other rights and remedies hereunder or that may exist at law, in equity or under contract on account of such Event of Default.

(e)Equitable Relief. The Members agree that irreparable damage would occur in the event that any of the provisions of Article 4 were not to be performed in accordance with the terms hereof and that the Members will be entitled to specific performance of the terms hereof in addition to any other remedy available at law or in equity without the obligation to post bond or other security.

(f)Notice. Each Member agrees to notify the Board within five (5) Days of the occurrence of a Fundamental Event affecting it.

4.6.    Interest on and Return of Capital Contributions

(a)No interest shall be paid by the Company in respect of any Member’s Capital Contributions or Capital Account.

(b)Except as otherwise provided herein, no Member may withdraw or receive a return of its Capital Contribution.

4.7.    Financing

(a) The Members anticipate that the Company may, following its acceptance of the FERC Certificate in respect of the Initial Facilities, seek Financing Commitments for the construction and operations of the Committed Facilities and any Approved Facilities Projects. As of the Effective Date, any such Financing Commitments, if approved in accordance with this Agreement, are currently contemplated to be structured to reflect the principles identified in the financing plan approved pursuant to the Initial Resolution. The Members hereby acknowledge and agree that any Financing Commitment shall be subject to the approval of the Managers and/or Members in accordance with this Agreement.

(b)In connection with the Financing Commitments described in Section 4.7(a) above, if or as required by a Financing Entity, each Member shall deliver to such Financing Entity (or the Company, as necessary to secure any Financing Commitment) credit support for the payment of its Capital Contribution obligations in any form

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required by or acceptable to such Financing Entity in connection with an approved Financing Commitment (“Financing Commitment Assurance”). The Members acknowledge that the failure by a Member to provide Financing Commitment Assurance as and when required in connection with an approved Financing Commitment shall constitute a Performance Default.

ARTICLE 5

ALLOCATIONS AND DISTRIBUTIONS

5.1.    Allocations of Profits and Losses

After giving effect to the special allocations set forth in Section 5.2, Profits and Losses for any Allocation Period shall be allocated to the Members in accordance with their Percentage Interests.

5.2.    Special Allocations

Notwithstanding the provisions of Section 5.1, the following allocations shall be made for each Allocation Period in the following order and priority:

(a)If there is a net decrease in Minimum Gain of the Company for an Allocation Period, then there shall be allocated to each Member items of income and gain for that year equal to that Member’s share of the net decrease in Minimum Gain of the Company (within the meaning of Treasury Regulations Section 1.704-2(g)(2)), subject to the exceptions set forth in Treasury Regulations Section 1.704-2(f)(2), (3), and (5). In the event that the application of the minimum gain chargeback requirement would cause a distortion in the economic arrangement between the Members, the Tax Matters Member may request that the Commissioner of the Internal Revenue Service waive the minimum gain chargeback requirement pursuant to Treasury Regulations Section 1.704-2(f)(4). The foregoing is intended to be a “minimum gain chargeback” provision as described in Treasury Regulations Section 1.704-2(f) and shall be interpreted and applied in all respects in accordance with that Regulation.

(b)If during an Allocation Period there is a net decrease in Member Nonrecourse Debt Minimum Gain, then, in addition to the amounts, if any, allocated pursuant to the preceding paragraph, any Member with a share of that Member Nonrecourse Debt Minimum Gain (determined in accordance with Treasury Regulations Section 1.704-2(i)(5)) shall, subject to the exceptions in Treasury Regulations Section 1.704-2(i)(4), be allocated items of income and gain for the year (and, if necessary, for succeeding years) equal to that Member’s share of the net decrease in the Member Nonrecourse Debt Minimum Gain. In the event that the application of the Member Nonrecourse Debt Minimum Gain chargeback requirement would cause a distortion in the economic arrangement among the Members, the Tax Matters Member may request that the Commissioner of the Internal Revenue Service waive the minimum gain chargeback requirement pursuant to Treasury Regulations Section 1.704-2(f)(4) and 1.704-2(i)(4). The foregoing is intended to be the “chargeback of member nonrecourse debt minimum gain” required by Treasury

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Regulations Section 1.704-2(i)(4) and shall be interpreted and applied in all respects in accordance with that Regulation.

(c)Any Nonrecourse Deductions for any Allocation Period shall be allocated between the Members in accordance with their Percentage Interests.

(d)Any Member Nonrecourse Deductions for any Allocation Period shall be specially allocated to the Member who bears (or is deemed to bear) the economic risk of loss with respect to the Member Nonrecourse Debt to which such Member Nonrecourse Deductions are attributable in accordance with Treasury Regulations Section 1.704-2(i)(2).

(e)Losses allocated pursuant to Section 5.1 and items of losses and deductions allocated pursuant to this Section 5.2 shall not exceed the maximum amount of losses and deductions that can be allocated to a Member without causing or increasing a deficit balance in the Member’s Adjusted Capital Account. If, at the end of any Allocation Period, as a result of the allocations otherwise provided for in Section 5.1 and this Section 5.2, the Adjusted Capital Account balance of any Member shall become negative, items of deduction and loss otherwise allocable to such Member for such year, to the extent such items would have caused such negative balance, shall instead be allocated to Members having positive Adjusted Capital Account balances remaining at such time in proportion to such balances. If a Member receives an allocation of Losses or items of losses and deductions otherwise allocable to another Member pursuant to this Section 5.2(e), such Member shall be allocated Profits in subsequent Allocation Periods necessary to reverse the effect of such allocation of Losses or items of losses and deductions, and such allocation of Profits (if any) shall be made before any other Profit allocations pursuant to Section 5.1.

(f)If any Member receives any adjustments, allocations or distributions described in Treasury Regulations Section 1.704-1(b)(2)(ii)(d)(4), (5) or (6), items of Company income and gain shall be specially allocated to such Member in an amount and manner sufficient to eliminate the deficit in such Member’s Adjusted Capital Account (as determined in accordance with Treasury Regulations Section 1.704-1(b)(2)(ii)(d)) created by such adjustments, allocations or distributions as promptly as possible; provided that an allocation pursuant to this paragraph shall be made only to the extent that a Member would have a deficit Adjusted Capital Account balance (as determined as provided in the prior clause), after all other allocations provided for in Section 5.1 and this Section 5.2 have been tentatively made as if this paragraph were not in the Agreement. This paragraph is intended to qualify with the “qualified income offset” requirement in the Treasury Regulations.

(g)If any Member has a deficit in its Adjusted Capital Account, such Member shall be specially allocated items of income and gain in the amount of such deficit as rapidly as possible, provided that an allocation pursuant to this paragraph shall be made if and only to the extent that such Member would have a deficit to its Adjusted Capital Account after all other allocations provided for in this Agreement have been tentatively made as if this paragraph were not in this Agreement.

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(h)All items of deductions and loss for any Deficiency Interest Expense shall be allocated to the Member whose Retained Distributions are required to be applied to the payment of such Deficiency Interest Expense pursuant to Section 4.2(e)(iii).

(i)All items of income or gain for any Deficiency Interest Income shall be allocated to the Members other than the Member whose Retained Distributions are required to be applied to the payment of such Deficiency Interest Income pursuant to Section 4.2(e)(iii) in proportion to their relative Percentage Interests.

(j) All items of deduction and loss attributable to Collection Costs of the Company shall be allocated to the Defaulting Member responsible for the payment of such Collection Costs pursuant to Section 4.5(a), including any Member whose Retained Distributions are required to be applied to the payment of such Collection Costs pursuant to Section 4.2(e)(iii).

(k)In the event that, in any Allocation Period, the Company is deemed to realize gain or loss from the adjustment to the Gross Asset Values of the Company’s assets in connection with the making of Elective Contributions pursuant to Section 4.2(e)(i) or as a result of a Dilution Election pursuant to Section 4.3, such gain or loss will be allocated to the Members in a manner that, to the extent possible, causes the Capital Account balances of the Members to be in proportion to their respective Percentage Interests as adjusted pursuant to Section 4.2(e)(ii) in connection with the making of such Elective Contributions or Section 4.3 in connection with a Dilution Election.

(l)The allocations set forth in subsections (a) through (g) of this Section 5.2 (collectively, the “Regulatory Allocations”) are intended to comply with certain requirements of the Treasury Regulations. The Members intend that, to the extent possible, all Regulatory Allocations that are made be offset either with other Regulatory Allocations or with special allocations pursuant to this Section 5.2. Therefore, notwithstanding any other provisions of this Article 5 (other than the Regulatory Allocations), the Board shall make such offsetting special allocations in whatever manner they determine appropriate so that, after such offsetting allocations are made, each Member’s Adjusted Capital Account balance is, to the extent possible, equal to the Adjusted Capital Account balance such Member would have had if the Regulatory Allocations were not part of this Agreement. In making such determination, the Board shall take into account future Regulatory Allocations that, although not yet made, are likely to offset other Regulatory Allocations previously made.

5.3.    Allocation and Other Rules

(a)Profits, Losses, and any other items of income, gain, loss, or deduction will be allocated to the Members pursuant to this Article 5 as of the last day of each Fiscal Year, provided that Profits, Losses, and the other items will also be allocated at any time the Gross Asset Values of the Company’s assets are adjusted pursuant to

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paragraph (2) of the definition of “Gross Asset Value” in Section 2.1 and in a manner that the Board and Tax Matters Member reasonably deem appropriate to take into account the varying interests of the Members.

(b)Profits, Losses, and any other items of income, gain, loss, deduction, and credit allocable to any Membership Interest that may have been transferred shall be allocated between the transferor and the transferee as agreed by the transferor and the transferee and based on the portion of the calendar year during which each was recognized as owning such interest, without regard to whether cash distributions were made to the transferor or the transferee during that calendar year; provided, however, that this allocation must be made in accordance with a method permissible under Section 706 of the Internal Revenue Code and the applicable Treasury Regulations. If no such agreement has been made, the allocation shall be determined by the Board in its reasonable discretion in accordance with such Treasury Regulations.

(c)The Members are aware of the income tax consequences of the allocations made by this Article 5 and hereby agree to be bound by the provisions of this Article 5 in reporting their shares of Company income and loss for income tax purposes.

5.4.    Allocations for Tax Purposes

(a)Except as otherwise provided herein, for federal income tax purposes, each item of income, gain, loss and deduction shall be allocated among the Members in the same manner as its correlative item of “book” income, gain, loss or deduction is allocated pursuant to Sections 5.1 and 5.2.

(b)In accordance with Section 704(c) of the Internal Revenue Code and the Treasury Regulations thereunder, income and deductions with respect to any property carried on the books of the Company at a Gross Asset Value that differs from such property’s adjusted tax basis shall, solely for federal income tax purposes, be allocated among the Members in a manner to take into account any variation between the adjusted tax basis of such property to the Company and such Gross Asset Value. In making such allocations, the Board shall use the remedial allocation method permitted under Treasury Regulations Section 1.704-3(d).

(c)All recapture of income tax deductions resulting from the Disposition of Company Property shall, to the maximum extent possible, be allocated to the Member to whom the deduction that gave rise to such recapture was allocated hereunder to the extent that such Member is allocated any gain from the Disposition of such Company Property.

(d)All items of income, gain, loss, deduction, and credit allocable to any Membership Interest that may have been transferred shall be allocated between the transferor and the transferee as agreed by the transferor and the transferee and based on the portion of the calendar year during which each was recognized as owning such interest, without regard to whether cash distributions were made to the transferor or

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the transferee during that calendar year; provided, however, that this allocation must be made in accordance with a method permissible under Section 706 of the Internal Revenue Code and the applicable Treasury Regulations. If no such agreement has been made, the allocation shall be determined by the Board in its reasonable discretion in accordance with such Treasury Regulations.

5.5.    Distributions

(a)Except as provided in Section 5.2(d) and Section 11.2(c), the Company shall make distributions of all Available Cash each Fiscal Quarter to the Members within thirty (30) Days after the last Day of the last month of each Fiscal Quarter.

(b)All distributions of Available Cash or otherwise shall be made to the Members in such proportion as the Percentage Interest of each such Member at such time shall bear to the total Percentage Interests owned by all of the Members.

(c)The amount of any non-cash distributable property to be distributed in accordance with this Section 5.5 shall be its Fair Market Value.

(d)    The Company shall distribute any cash contributed to the Company pursuant to Section 4.1(b), Section 4.1(d) and Section 4.4 in the manner set forth in Section 4.1(b), Section 4.1(d) and Section 4.4, as applicable. To the maximum extent permitted by Treasury Regulations Section 1.707-4(d), the Members agree to treat any distributions made pursuant to this Section 5.5(d) as received by each distributee Member in reimbursement of pre-formation capital expenditures.

(e)Notwithstanding any provision to the contrary contained in this Agreement, the Company may not make a distribution to any Member on account of its Membership Interest if such distribution would violate Section 18-607 of the Act or other law.

5.6.    Acknowledgement of Allocation Rules

The Members are aware of the income tax consequences of the allocations and distributions made by this Article 5 and hereby agree to be bound by the provisions of this Article 5 in reporting their shares of Company income and loss for income tax purposes.

5.7.Tax Withholding

To the extent that the Company is required by the Internal Revenue Code (including Internal Revenue Code Sections 1441, 1442, 1445, 1446, 1471, 1472, 1473 and 1474) or pursuant to any provision of any state or local tax law to withhold or to make tax payments on behalf of or with respect to any Member, the Company may withhold such amounts and make such tax payments as so required. All tax payments made on behalf of a Member shall, at the Company’s option, (i) be promptly paid to the Company by the Member on whose behalf such payments were made, or (ii) be repaid by reducing the amount of current or future distributions which would otherwise have been made to such Member, or if such distributions are not sufficient for that purpose, by so reducing the proceeds of liquidation otherwise payable to such

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Member. Whenever the Company selects option (ii) pursuant to the preceding sentence for repayment of a tax payment by the Company, for all other purposes of this Agreement, such Member shall be treated as having received all distributions unreduced by the amount of such tax payment. The Company shall promptly provide written notification to each Member with respect to which the Company has determined it has a tax payment or tax withholding obligation as contemplated under this Section 5.7.

ARTICLE 6

MANAGEMENT AND GOVERNANCE

6.1.    Board

Subject to any approval rights contained herein or in the Act, the powers of the Company shall be exercised by or under the authority of, and the business and affairs of the Company shall be managed under the direction of managers, who shall individually be referred to herein each as a “Manager” or collectively as the “Managers,” and who shall act as a board (when acting as a board, the Managers are referred to herein as the “Board”). Decisions or actions taken by the Board in accordance with the provisions of this Agreement shall constitute decisions or actions by the Company and shall be binding on each Member, Manager, Officer and employee, if any, of the Company. Any Person dealing with the Company, other than a Member or a Member’s Affiliate, may rely on the authority of the Board or the Officers in taking any action in the name of the Company without inquiry into the provisions of this Agreement or compliance with it, regardless of whether that action actually is taken in accordance with the provisions of this Agreement. No Member in its capacity as a Member shall have any unilateral right or authority to take any action on behalf of the Company or to bind or commit the Company to any agreement, transaction or other arrangement with respect to third parties or otherwise or to hold itself out as an agent of the Company. Except as otherwise expressly provided in this Agreement, each Member hereby (a) specifically delegates to the Board its rights and powers to manage and control the business and affairs of the Company in accordance with the provisions of Section 18-407 of the Act, and (b) revokes its right to bind the Company, as contemplated by the provisions of Section 18-402 of the Act.

6.2.    Certain Agreements

Subject to the oversight of the Board and as more specifically set forth in the Operations Agreement, certain activities of the Company will be performed by the Operator in accordance with the Operations Agreement; provided that, notwithstanding the foregoing, neither the Operator nor any Affiliate thereof shall have the authority to take any action without the prior consent of the Managers designated by Members holding at least 70% of the Membership Interests unless such authority is expressly granted in the Operations Agreement. The Managers designated by Members holding at least 70% of the Membership Interests shall be permitted to delegate authority with respect to the supervision of construction and the operation and maintenance of the Facilities and the conduct of certain administrative and supervisory services to the Operator; provided that the Operator shall have no authority over any action or decision subject to approval of the Board under Sections 6.7(b)(i), (ii) or (iii). The Members acknowledge that, pursuant to the Initial Resolution, the Operations Agreement will be ratified

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and approved by the Members and any officer will be entitled to, on behalf of the Company, execute the Operations Agreement.

6.3.Designation of Managers

(a)From and after the Effective Date unless changed in accordance with this Section 6.3, the Board shall be composed of four (4) individuals. Dominion shall have the right to designate one (1) Manager (the “Dominion Manager”), Duke shall have the right to designate one (1) Manager (the “Duke Manager”), Piedmont shall have the right to designate (1) Manager (the “Piedmont Manager”) and AGL shall have the right to designate one (1) Manager (the “AGL Manager”). Each Manager shall serve until his successor is duly selected in accordance with this Agreement and qualified or until such individual’s death, resignation or removal. The Managers as of the Effective Date are set forth on Exhibit 6.3(a).

(b)In addition to the Managers, each of Dominion, Duke, Piedmont and AGL shall have the right to designate one (1) individual to represent its respective designated Manager at any Board meeting at which such Manager is unable to attend (each, an “Alternate Manager”). The term “Manager” shall also refer to any Alternate Manager that is actually performing the duties of the applicable Manager in lieu of such Manager. In addition, the act of an Alternate Manager shall be deemed the act of the Manager for which such Alternate Manager is acting, without the need to produce evidence of the absence or unavailability of such Manager.

(c)Each Manager shall have the full authority to act on behalf of the Member that designated such Manager; the action of a Manager at a meeting (or through a written consent) of the Board shall bind the Member that designated such Manager, and the other Members shall be entitled to rely upon such action without further inquiry or investigation as to the actual authority (or lack thereof) of such Manager.

(d)The Board may by consent of the Managers designated by the Members Holding a Majority of the Percentage Interests establish and name one or more committees, each committee to consist of one or more of the Managers, and any such committee of which shall be dissolved at the written request of any one or more Managers. Any committee established pursuant to this Section 6.3(d) shall have and may exercise all the powers and authority delegated to such committee by the Board.

(e)Each Manager shall vote the entire Percentage Interest of the Member that appointed such Manager.

(f)Each Manager may vote in person or by delivering a written proxy to another Manager. A Manager shall serve until such Manager dies, resigns or is removed from office as provided herein.

(g)The number of Managers serving on the Board may not be increased or decreased except by the consent of the Members holding at least 90% or more of the

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Percentage Interests; provided that in no event shall the Board have less than four Managers.

(h)Managers will not be paid any fee for serving on the Board and each Manager shall be responsible for any out-of-pocket expenses incurred in connection with attending meetings of the Board.

6.4.Removal of Managers

A Manager may be removed from the Board, with or without cause, only by the Member(s) who designated such Manager to serve on the Board.

6.5.    Vacancies

If a vacancy is created on the Board at any time by the death, disability, retirement, resignation or removal of a Manager, the Member(s) that had designated such Manager to serve on the Board shall have the sole and exclusive right to designate a replacement therefor.

6.6.    Meetings of Board

(a)Meetings of the Board, regular or special, may be held either inside or outside the State of Delaware.

(b)Regular meetings of the Board shall occur at least semi-annually and may be called on fifteen (15) Days’ notice (effective upon receipt) to each Manager,

either personally or by facsimile, electronic transmission (including electronic mail), overnight courier, or telegram, by any Manager; provided that such notice may be waived by each applicable member of the Board. Except as otherwise provided by statute, the Certificate or this Agreement, any and all business may be transacted at any regular meeting.

(c)Special meetings of the Board may be called on seven (7) Days’ notice (effective upon receipt) to each Manager, either personally or by facsimile, electronic transmission (including electronic mail) or overnight courier by any Manager. The business to be transacted at, and the purpose of, any regular or special meeting of the Board shall be specified in the notice unless there is a waiver of notice of such meeting.

(d)Emergency meetings of the Board may be called on 24 hours’ notice (effective on receipt) to each Manager, either personally or by facsimile, electronic transmission (including electronic mail) or overnight courier by any Manager. The business to be transacted at and the purpose of the emergency meeting of the Board shall be specified in the notice unless there is a waiver of notice of such meeting; provided, however, emergency meetings of the Board shall only be called for the purpose of acting on incidents and issues that arise in emergency situations for which action may be required by the Company in such a manner or a limited time frame that calling a special meeting of the Board to deal with such incidents or issues is impractical.

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(e)Except for matters in this Agreement specifying other approval or consent requirements or thresholds, at all meetings of the Board the presence in person or by proxy of the Managers designated by the Members then holding at least 70% of the Percentage Interests shall be necessary and sufficient to constitute a quorum for the transaction of business. Each Member shall use all reasonable efforts to cause the Manager(s) designated by it to attend all meetings of the Board.

(f)All meetings of the Board shall be presided over by the chairman of the meeting, who shall be a Manager appointed and approved on an annual basis by the Managers designated by the Members Holding a Majority of the Percentage Interests (the “Chairman”), provided that the office of the Chairman must rotate annually among the Members (excluding Defaulting Members) whose Percentage Interests are at least 4%. The initial Chairman is listed on Exhibit 6.3(a) hereto. The Chairman shall determine the order of business and the procedure at the meeting, including such regulation of the manner of voting and the conduct of discussion as determined by him to be in order, but shall not have a second, deciding vote in such capacity. The Company’s secretary (or if such Person is not available, the Person designated by the Chairman of the meeting to be the acting secretary at a meeting) shall act as the secretary of the meeting who shall make a written record of the proceedings of such meeting which shall be provided to the Members promptly after the meeting. Notwithstanding the preceding rights set forth herein to designate a Chairman, in the event a Member’s right to designate a Manager is terminated pursuant to this Agreement, such Member’s right to designate the Chairman shall also be terminated.

(g)Any action required or permitted to be taken at any meeting of the Board may be taken without a meeting, without prior notice and without a vote if a consent or consents in writing, setting forth the action so taken, is signed by the minimum number of Managers that would be required to take such action at a duly called and convened meeting of the Board. A signature delivered by portable document format attached to an e-mail, a photographic, photostatic, facsimile or similar reproduction of a writing signed by a Manager, shall be regarded as an original signature of the Manager. The Company shall use commercially reasonable efforts to provide reasonable prior notice to all of the Managers of any such action to be taken by written consent of the Board so long as the delay caused by providing the notice to all of the Managers does not materially adversely affect the Company, and, in any event, will promptly deliver such written consent to all Managers that did not execute such consent.

(h)Subject to the provisions of applicable law and this Agreement regarding notice of meetings and the granting of proxies, individuals serving on the Board (i) may, unless otherwise restricted by the Certificate or this Agreement, participate in and hold a meeting of the Board by using conference telephone, electronic transmission, or similar communications equipment by means of which all individuals participating in the meeting can hear each other, and (ii) may grant a proxy to another Manager or delegate its right to act to another Manager which proxy or delegation shall be effective as the attendance or action at the meeting of the Manager giving such proxy or delegation. Participation by a Manager in a meeting pursuant to this Section

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6.6(h) shall constitute presence in person at such meeting, except when an individual participates in the meeting for the express purpose of objecting to the transaction of any business on the ground that the meeting was not lawfully called or convened. Each Manager may invite a reasonable number of advisors (not to exceed five (5) in respect of any Member in the aggregate) to attend meetings of the Board.

(i)Except for actions set forth in this Agreement which expressly require (x) the consent of Managers designated by the Members holding at least 96% of the Percentage Interests, (y) the consent of Managers designated by the Members holding at least 90% of the Percentage Interests or (z) consent of the Managers designated by the Members holding at least 70% of the Percentage Interests, all actions and approvals of the Board shall be approved and passed at a meeting at which a quorum is present by the consent of the Managers designated by the Members Holding a Majority of the Percentage Interests.

6.7.Restricted Action Requiring Board Approval

(a)Subject to the limitations set forth in Sections 6.7(b) or as otherwise provided in this Agreement, the Board shall have the full and exclusive authority to manage the operations and business of the Company and to make any and all decisions on behalf of the Company with respect to the Business of the Company without the approval or consent of any Member.

(b)Notwithstanding anything in this Agreement to the contrary, except for actions taken by a Member or an Affiliate of a Member in its capacity as a party to a Transaction Document which actions are in compliance with the terms of a Transaction Document, the Company shall not, directly or through any Subsidiaries, and the Managers, Members, Officers and agents of the Company shall not approve of or take any action specified in this Agreement requiring (i) the consent of the Managers designated by the Members holding at least 96% or more of the Percentage Interests without obtaining the consent of the Managers designated by the Members holding at least 96% or more of the Percentage Interests, (ii) the consent of the Managers designated by the Members holdings at least 90% or more of the Percentage Interests without obtaining the consent of the Managers designated by the Members holding at least 90% or more of the Percentage Interests, (iii) the consent of the Managers designated by the Members holding at least 70% or more of the Percentage Interests without obtaining the consent of the Managers designated by the Members holding at least 70% or more of the Percentage Interests, and (iv) the consent of the Managers designated by the Members Holding a Majority of the Percentage Interests without obtaining the consent of the Managers designated by the Members Holding a Majority of the Percentage Interests.

(i)In addition to any other matters specified in this Agreement as requiring the consent of the Managers designated by the Members holding at least 96% or more of the Percentage Interests, the Company shall not, directly or through any Subsidiaries, and the Managers, Members or their Affiliates, Officers and agents of the Company shall not approve of or take any of the following

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actions without obtaining the consent of the Managers designated by the Members holding at least 96% or more of the Percentage Interests:

1.dissolution of the Company pursuant to Section 11.1(a);

2.causing or permitting the Company to voluntarily file a bankruptcy petition in a court of competent jurisdiction or a petition seeking a reorganization, liquidation, dissolution or similar relief under any law or otherwise suffer to exist an involuntary proceeding against the Company seeking reorganization, arrangement, composition, readjustment, liquidation, dissolution, or similar relief under any law (but this provision shall not be construed to require any Member to ensure the profitability or solvency of the Company);

3.amending, modifying, changing or otherwise altering in any material respect the FERC Application for the Initial Facilities or recourse rates;

4.providing for the basic geographic configuration, points of receipt and delivery, extensions of the pipeline described in section c. of Schedule A, pipeline diameter or design capacity of the Initial Facilities to be materially different from that set forth in Schedule A;

5.amending any Annual Operating Budget to increase any line item therein by an amount in excess of $200,000 (as such amount may be adjusted from time to time in accordance with Section 14.22);

6.causing or permitting the Company to merge or consolidate with or into, or convert into, any other entity;

7.intentionally conducting any activity or business that may generate income for federal income tax purposes that may not be “qualifying income” (as such term is defined pursuant to Section 7704 of the Internal Revenue Code);

8.electing for the Company to be treated for federal income tax purposes as a corporation; and

9.the actions specified in any other express provision of this Agreement requiring the consent of the Managers designated by the Members holding at least 96% of the Percentage Interests.

(ii)In addition to any other matters specified in this Agreement as requiring the consent of the Managers designated by the Members holding at least 90% or more of the Percentage Interests, the Company shall not, directly or through any Subsidiaries, and the Managers, Members or their Affiliates, Officers and agents of the Company shall not approve of or take any of the following

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actions without obtaining the consent of the Managers designated by the Members holding at least 90% or more of the Percentage Interests:

1.approving a sale or abandonment of the Facilities; and

2.the actions specified in any other express provision of this Agreement requiring the consent of the Managers designated by the Members holding at least 90% of the Percentage Interests.

(iii)In addition to any other matters specified in this Agreement as requiring the consent of the Managers designated by the Members holding at least 70% of the Percentage Interests, the Company shall not, directly or through any Subsidiaries, and the Managers, Members, Operator or their Affiliates, Officers and agents of the Company shall not approve of or take any of the following actions without obtaining the consent of the Managers designated by the Members holding at least 70% of the Percentage Interests:

1.approving any Annual Budget;

2.approving the PA Required Expansion Facilities Budget or any AFP Budget;

3.amending any Annual Capital Budget;

4.approving any Facilities Project;

5.removing any Officer;

6.appointing the Company’s independent certified public accountants or auditors;

7.entering into any Financing Commitment, including any Financing Commitment that, consistent with Section 4.7(b), may require Financing Commitment Assurances from all Members;

8.causing any Lien to be placed on the Facilities or any other material asset of the Company other than Permitted Liens;

9.subject to Section 14.9, amending, modifying, changing or otherwise altering the Operations Agreement;

10.delegating authority to the Operator pursuant to the Operations Agreement;

11.subject to Section 14.9, entering into, amending, suspending or terminating any Material Contract, or taking any action that results in a material default by the Company under any Material Contract;

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12.approving any lease of capacity on the Facilities;

13.causing the Company to enter into any Affiliate Contract;

14.approving additional Capital Contributions from the Members to fund cost overruns in excess of the relevant Aggregate Budget Cap (the aggregate amount of such additional Capital Contributions, a “Budget Overrun”);

15.approving any Precedent Agreement associated with the Facilities that has not been entered into as of the Effective Date;

16.approving the form, purchase, termination or amendment by the Operator of any insurance policy that the Operator obtains and maintains on behalf of the Company pursuant to the Operations Agreement; and

17.the actions specified in any other express provision of this Agreement requiring the consent of the Managers designated by the Members holding at least 70% of the Percentage Interests.

(iv)By way of illustration and not in limitation of any other matters specified in this Agreement as requiring the consent of the Managers designated by the Members Holding a Majority of the Percentage Interests or otherwise the consent of the Board, the Company shall not, directly or through any Subsidiaries, and the Managers, Members, Operator or their Affiliates, Officers and agents of the Company shall not approve of or take any of the following actions without obtaining the consent of the Managers designated by the Members Holding a Majority of the Percentage Interests:

1.selecting a different name for the Company;

2.approving the amount of Available Cash; and

3.any other action that, pursuant to an express provision of this Agreement, requires the approval of the Managers designated by the Members Holding a Majority of the Percentage Interests.

6.8.    FERC Certificate Approval

(a)Voting on FERC Certificate for Initial Facilities. The Board shall immediately review the FERC Certificate for the Initial Facilities upon the Company’s receipt thereof and shall call a special meeting as soon as reasonably practicable (and in any event within twenty-one (21) Days of the Company’s receipt thereof) in order to determine, reasonably and in good faith, whether acceptance of the FERC Certificate for the Initial Facilities has or would have a material adverse effect on the rights, obligations, financial condition, properties or prospects of the Company (an “MAE”). At such special meeting, the Managers shall vote on (i) whether acceptance

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of the FERC Certificate results in an MAE, and (ii) whether to accept the FERC Certificate.

(b)No MAE. If at such special meeting, Managers designated by Members holding at least 70% of the Percentage Interests vote that acceptance of the FERC Certificate would not result in an MAE, then the Company shall also be deemed to accept the FERC Certificate, and the Members whose Managers voted that acceptance of the FERC Certificate would not result in an MAE shall purchase, in proportion to their respective Percentage Interests, the entire Membership Interest(s) of any Member whose Manager voted in good faith that acceptance of the FERC Certificate would result in an MAE (any such Member, a “Disagreeing Member”) at a price equal to ninety-five percent (95%) of all Capital Contributions made by such Disagreeing Member as of the date of such special meeting.

(c)MAE. If at such special meeting, Managers designated by Members holding at least 70% of the Percentage Interests do not vote that acceptance of the FERC Certificate would not result in an MAE, then the Managers shall vote at such special meeting whether to nevertheless accept the FERC Certificate and the following subsections (i) or (ii) shall apply:

(i)    Accept FERC Certificate. If Managers designated by Members holding at least 70% of the Percentage Interests vote to accept the FERC Certificate, then the Company shall be deemed to accept the FERC Certificate, and such Members whose Manager voted to accept the FERC Certificate shall purchase, in proportion to their respective Percentage Interests, the entire Membership Interest(s) of any Member whose Manager voted not to accept the FERC Certificate (any such Member, a “FERC Certificate Non-Accepting Member”) at a price equal to one hundred percent (100%) of all Capital Contributions made by such FERC Certificate Non-Accepting Member as of the date of such special meeting.

(ii)    Reject FERC Certificate. If Managers designated by Members holding at least 70% of the Percentage Interests do not vote to accept the FERC Certificate, then, unless it is otherwise agreed to unanimously by all the Members to take an alternative course of action (including seeking rehearing of the order issuing the FERC Certificate), the Company shall be dissolved and its affairs shall be wound up in accordance with the provisions of Article 11.

(d)The acceptance of any FERC Certificate in respect of the PA Required Expansion Facilities or any Approved Facilities Project shall be subject to the vote of the Managers designated by the Members holding at least 70% of the Percentage Interests.

(e)The closing of any purchase of the Membership Interests of a Disagreeing Member or FERC Certificate Non-Accepting Member shall occur no later than sixty (60) Days after the date of the relevant vote, unless the Members agree upon a different date. At the closing, the Disagreeing Member or FERC Certificate Non-

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Accepting Member, as applicable, shall execute and deliver to the purchasing Members (i) an assignment of its Membership Interest, in form and substance reasonably acceptable to the purchasing Members and (ii) any other instruments reasonably requested by the purchasing Members to give effect to the purchase; and the purchasing Members shall deliver to the Disagreeing Member or FERC Certificate Non-Accepting Member, as applicable, in immediately available funds the purchase price.

6.9.Officers

(a)The Board may, from time to time, designate one or more Persons to be officers of the Company (each, an “Officer”). No Officer need be a resident of the State of Delaware, a Member or a Manager. Any Officers so designated shall have such authority to perform such duties as the Board may, from time to time, delegate to them. The Board may assign titles to particular Officers. The Officers of the Company shall report to the Board as requested from time to time. Unless the Board decides otherwise, if the title is one commonly used for officers of a business corporation formed under the Delaware General Corporation Law (or any successor statute), the assignment of such title shall constitute the delegation to such officer of the authority and duties that are normally associated with that office, subject to the Board’s oversight and any specific delegation of authority and duties made to such Officer by the Board under this Section 6.9(a) and the other terms and provisions hereof, including Section 6.7 hereof. Each Officer shall hold office until his successor is duly designated and qualified or until his death or until he resigns or has been removed in the manner hereinafter provided. Any number of offices may be held by the same person. No Officer shall be employed by the Company.

(b)Any Officer may resign as such at any time. Such resignation shall be made in writing and shall take effect at the time specified therein, or if no time be specified, at the time of its receipt by the Board. The acceptance of a resignation shall not be necessary to make it effective, unless expressly so provided in the resignation. Any Officer may be removed as such, either with or without cause, by the Board; provided, however, that such removal shall be without prejudice to the contract rights, if any, of the Person so removed. Designation of an Officer shall not of itself create contract rights. Any vacancy occurring in any office of the Company may be filled by the Board.

(c)The initial Officers of the Company are listed on Exhibit 6.9(c).

6.10.Duties of Managers

(a)Notwithstanding anything in this Agreement or in the Act to the contrary, a Manager, in performing his or her duties and obligations as a Manager under this Agreement, may act or omit to act solely at the direction of the Member(s) that designated such person to serve on the Board, considering only such factors, including the separate interests of the designating Member(s), as such Manager or Member(s) choose to consider, and any action of such a Manager or failure to act,

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taken or omitted in good faith reliance on the foregoing provisions shall not constitute a breach of any duty (including any fiduciary or other similar duty, to the extent such exists under the Act or other applicable law) on the part of such Manager or Member(s) to the Company or any other Manager, Member, or Officer. No Member shall owe any fiduciary or other similar duties to the Company, any other Member, Manager or Officer except the implied duty of good faith and fair dealing. No Manager shall owe any fiduciary or other similar duty to the Company, any Member (other than the Member appointing such Manager), Manager or Officer except the implied duty of good faith and fair dealing. The Operator shall owe such duties to the Company, Members, Managers and Officers as contemplated in the Operations Agreement.

(b)The Members (and the Members on behalf of the Company) hereby:

(i)agree that (A) the terms of this Section 6.10, to the extent that they modify or limit a duty or other obligation, if any, that a Member or Manager may have to the Company or any other Member, Manager or Officer under the Act or applicable law, are reasonable in form, scope and content; and (B) the terms of this Section 6.10, subject to the last sentence of Section 6.10(a), shall control to the fullest extent possible if it is in conflict with a duty, if any, that a Member or Manager may have to the Company or another Member, Manager or Officer under the Act or other applicable law;

(ii)waive any duty or other obligation, if any, that a Member may have to the Company or another Member, pursuant to the Act or other applicable law, to the extent necessary to give effect to the terms of this Section 6.10, other than the implied duty of good faith and fair dealing;

(iii)agree that (i) the other Members would not be willing to make an investment in the Company, and no person designated by a Member to serve on the Board would be willing to so serve, in the absence of this Section 6.10, and (ii) it has reviewed and understands the provisions of Sections 18-1101(b) and (c) of the Act, and to the extent that at law or in equity, a Member or Manager owes any fiduciary or other duties to the Company or any Member (other than fiduciary duties owed by a Manager to the Member that appointed such Manager), Manager or Officer, such duties are eliminated to the fullest extent permitted pursuant to Section 18-1101(c) of the Act, other than the implied duty of good faith and fair dealing and subject to the last sentence of Section 6.10(a); and

(iv)agree that nothing herein is intended to create a partnership, joint venture, agency or other relationship creating fiduciary or quasi-fiduciary duties or similar duties or obligations or otherwise subject the Members to joint and several liability or vicarious liability for the actions of the other Members or to impose any duty, obligation or liability that would arise therefrom with respect to any or all of the Members or the Company.

6.11.Commercially Sensitive Information

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In any materials submitted to the Board for review and approval, and in all communications between itself and the Members (in their capacity as such), the Managers shall maintain the confidentiality of (and redact from written materials as appropriate) customer names and commercially sensitive information the disclosure or exchange of which between competitors would be inconsistent with applicable federal and state antitrust or unfair competition laws and regulations.  The foregoing confidentiality requirement shall also apply to non-public operational information and non-public customer-specific information, the disclosure of which would violate Applicable Laws (as defined in the Operations Agreement).  Disclosure of any proposals shall be done in a form that prevents the direct or indirect disclosure of customer-specific, competitive-sensitive or operationally sensitive information.  Each Member shall prohibit the use, dissemination or disclosure of such information in any form by a Manager for the purpose of planning, marketing or operating a separate, competing business now or in the future.

6.12.Employees

Secondees.

(a)The Company shall have no employees.

(b)The Members agree that, upon the approval of the Board and the applicable Member, employees of a Member or its Affiliates may be seconded to the Company pursuant to a secondment agreement to be entered into between the Company

and such Member or its Affiliate. Any employee of a Member or its Affiliate seconded to the Company pursuant to this Section 6.12(b) shall enter into a confidentiality agreement satisfactory in form and substance to the Company.

ARTICLE 7

BUDGETS; ACCOUNTING,TAX AND BANKING MATTERS

7.1.Facilities Budgets

(a)The Members acknowledge that, as of the Effective Date, the Board will pursuant to the Initial Resolution approve the Initial Facilities Budget for the period from the Effective Date through the In-Service Date, which budget includes an Annual Capital Budget for the period through December 31, 2014.

(b)Prior to commencing the construction of the PA Required Expansion Facilities, the Board shall develop (in conjunction with the Operator), consider and approve a multi-year budget for development and construction of the PA Required Expansion Facilities (a “PA Required Expansion Facilities Budget”), which budget shall include a maximum capital commitment of each Member in an amount not exceeding such Member’s applicable Budget Cap.

(c)Prior to approving any Approved Facilities Project, the Board shall develop (in conjunction with the Operator), consider and approve a multi-year budget for development and construction of such Approved Facilities Project, in form and substance substantially similar to the Initial Facilities Budget (an “AFP Budget”).

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7.2.Annual Budgets

(a)Not later than November 1 of each Fiscal Year, the Operator shall deliver to the Company an Annual Budget for the next following Fiscal Year. Each Annual Budget shall consist of (i) a budget setting forth the Capital Expenditure requirements of the Company for the relevant Fiscal Year, including maintenance Capital Expenditures and the Capital Expenditures set forth in the relevant Facilities Budget that are applicable to such Fiscal Year, together with, in respect of any period prior to the In-Service Date, such other expenditures that may be incurred during such Fiscal Year (an “Annual Capital Budget”) and (ii) for each Fiscal Year (or portion thereof) following the In-Service Date, a budget setting forth the operational expenditures to be incurred by the Company during such Fiscal Year (an “Annual Operating Budget”). Each Annual Budget shall include an indicative budget for the two Fiscal Years immediately following the next Fiscal Year. Each Annual Capital Budget shall also include a capital call schedule showing the anticipated timing and amount of the Capital Contributions to be required during the Fiscal Year to which such Annual Capital Budget relates. The Members agree that each Annual Budget shall be intended to include all costs and expenses necessary or advisable for the conduct of the Business.

(b)Not later than December 15 of each Fiscal Year, the Board shall consider and approve the Annual Budget for the next following Fiscal Year. As of the Effective Date, the Board hereby approves the initial Annual Budget for the period from the Effective Date through December 31, 2014.

(c)If the Board does not approve the Annual Budget in respect of any Fiscal Year on or prior to the commencement of such Fiscal Year, the Annual Budget for such Fiscal Year shall be the indicative budget applicable to such Fiscal Year that was included with the most recently approved Annual Budget.

(d)The Company, the Managers and the Operator shall use reasonable commercial efforts to conduct the business and operations of the Company consistent in all material respects with the then-applicable Annual Budget.

(e)If, during the Fiscal Year covered by an Annual Budget, a Manager, the Operator or an Officer determines that an adjustment or addition to, or deferral or acceleration of, the estimated costs, expenses or Capital Expenditures of any line items in such Annual Budget is necessary or appropriate, then such person shall submit (or cause to be submitted) to the Board for approval such adjustments or additions, or deferrals or accelerations, as are necessary or required. The Board shall approve or disapprove the adjustments or additions to, or deferrals or accelerations of, the Annual Budget in accordance with Section 6.7(b) as promptly as practicable, but in any event within fifteen (15) Days after receipt of such adjusted draft Annual Budget.

7.3.Books and Records; Reports

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(a)The Company shall keep and maintain full and accurate books of account for the Company in accordance with GAAP consistently applied in accordance with the terms of this Agreement. The Company shall keep books and records indicating the names, addresses, Capital Contributions and Percentage Interests of all Members and shall keep minutes of the proceedings of the Board and the Members and supporting documentation of the transactions with respect to the conduct of the Company’s Business. Such books shall be maintained at the principal United States office of the Company or offsite so long as they are easily accessible. Each Member and its Affiliates and designated representatives shall have full and complete access at all reasonable times to review, inspect and copy the books and records of the Company.

(b)The Company shall provide to each Member the following reports:

(i)As soon as practicable after receipt thereof, any reports provided to the Company or the Board pursuant to the Operations Agreement;

(ii)within thirty (30) Days of the end of any Fiscal Quarter, quarterly consolidated financial statements of the Company (including an unaudited consolidated balance sheet of the Company and its consolidated Subsidiaries as of the end of such Fiscal Quarter and the related unaudited consolidated income statement and statement of cash flows of the Company and its consolidated Subsidiaries for the Fiscal Quarter then ended) for the previous quarter prepared in accordance with GAAP (subject to normal year-end adjustments) and showing any variance between actual and budgeted figures;

(iii)within sixty (60) Days of the end of each Fiscal Year, consolidated financial statements of the Company (including a balance sheet of the Company as of December 31 of each Fiscal Year and the related income statement and statement of cash flows of the Company for the Fiscal Year then ended) and a schedule showing any variance between actual and budgeted figures. The annual financial statements shall be prepared in accordance with GAAP and shall be audited in accordance with generally accepted auditing standards and certified by Deloitte & Touche LLP or another nationally recognized, “Big 4” firm of certified public accountants approved by the Board;

(iv)As soon as available, but not later than thirty (30) Days after the end of each calendar month, monthly financial and business reports, including (A) an operating statement and report of financial condition of the Company for such monthly period and year-to-date, including summary unaudited consolidated balance sheet, consolidated income statement and statement of cash flows of the Company and its consolidated Subsidiaries for such period, (B) a reconciliation report setting forth material discrepancies or variances between (x) amounts included in such reports for such month period and year-to-date and (y) the budgeted amounts as reflected in the Budget for the corresponding periods to which such amounts relate, (C) a summary description of the business activities that took place during such period and the operating and financial performance of

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the Company during such period and year-to-date, including an explanation of material discrepancies described in clause (B) and (D) such other information as any Manager or Member shall reasonably request;

(v)Copies of Annual Budgets, Facilities Budgets and all amendments thereto;

(vi)Notice of material events; and

(vii)such other reports and information (in any form, electronic or otherwise) as any such Member or any Manager may reasonably request, as the Board may determine, or as otherwise required by law.

(c)Each of the quarterly and annual financial statements provided in accordance with Section 7.1 shall include a statement of the Capital Accounts and a summary narrative discussion of such financial statements. Monthly reports shall include a statement as to significant variations from any Annual Budget or Facilities Budget.

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7.4.Fiscal Year

The calendar year shall be selected as the accounting year of the Company.

7.5.Bank Accounts

The Company shall maintain one or more bank accounts in the name of the Company at such bank or banks as may be determined by the Board, which accounts shall be used for the payment of expenditures incurred by the Company in connection with the business of the Company and in which shall be deposited any and all receipts of the Company. All such receipts shall be and remain the property of the Company and shall not be commingled in any way with funds of any other Person. The designated Officers or Managers may invest the Company funds only in (a) readily marketable securities issued by the United States or any agency or instrumentality thereof and backed by the full faith and credit of the United States maturing within three months or less from the date of acquisition, (b) readily marketable securities issued by any state or municipality within the United States of America or any political subdivision, agency or instrumentality thereof, maturing within three months or less from the date of acquisition and rated “A” or better by any recognized rating agency, (c) readily marketable commercial paper rated “Prime 1” by Moody’s or “A 1” by S&P (or comparably rated by such organizations or any successors thereto if the rating system is changed or there are such successors) and maturing in not more than three months after the date of acquisition or (d) certificates of deposit or time deposits issued by any incorporated bank organized and doing business under the laws of the United States of America which is rated at least “A” or “A2” by S&P or Moody’s, which is not in excess of federally insured amounts, and which matures within three months or less from the date of acquisition.

7.6.Capital Accounts

(a)A capital account shall be established and maintained for each Member in accordance with the terms of this Section 7.6 (a “Capital Account”). Each Member’s Capital Account (a) shall be increased by (i) such Member’s Capital Contributions (including amounts deemed contributed by the Member pursuant to Section 4.2(e)(iii) or 4.5(a)), (ii) the amount of any Profits or items of income or gain allocated to such Member pursuant to Sections 5.1 and 5.2, and (iii) the amount of any Company liabilities assumed by the Member or that are secured by any Property distributed to the Member, and (b) shall be decreased by (i) the amount of money distributed to that Member by the Company (including amounts deemed to be distributed to the Member pursuant to Section 4.2(e)(iii), (ii) the Gross Asset Value of property distributed to that Member by the Company, (iii) allocations to that Member of Losses or other items of loss or deduction pursuant to Sections 5.1 and 5.2, and (iv) the amount of any liabilities of the Member assumed by the Company or that are secured by any Property contributed by the Member to the Company.

(b)It is the intention of the Members that the Capital Accounts of each Member be kept in the manner required under Treasury Regulations Section 1.704-1(b)(2)(iv). To the extent any additional adjustment to the Capital Accounts is required by such regulation, the Board is hereby authorized to make such adjustment.

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(c)On the transfer of all or part of a Member’s Membership Interest, the Capital Account of the transferor that is attributable to the transferred Membership Interest shall carry over to the transferee Member in accordance with the provisions of Treasury Regulations Section 1.704-1(b)(2)(iv)(l).

7.7.Tax Partnership

The Members agree to classify the Company as a partnership for federal income tax purposes. Neither the Company, any Member nor any officer or other representative of any of the foregoing shall file an election to classify the Company as an association taxable as a corporation for federal tax purposes.

7.8.Tax Elections.

The Company shall make the following elections:

(a)to elect the calendar year as the Company’s Fiscal Year if permitted by applicable law;

(b)to elect the accrual method of accounting;

(c)to elect, in accordance with Section 754 of the Internal Revenue Code and comparable state law provisions, to adjust basis in the event any Membership Interest is transferred in accordance with this Agreement or any Company Property or cash of the Company is distributed to any Member;

(d)to elect the application of Internal Revenue Code Sections 709(b) and 195(b) with respect to all organizational expenses and start-up expenditure of the Company, respectively; and

(e)to elect with respect to such other federal, state and local tax matters as the Board shall approve.

7.9.Tax Matters Member

The Board shall from time to time designate a Member to act as the “tax matters partner” under Section 6231 of the Internal Revenue Code, subject to replacement by the Board (such Member, the “Tax Matters Member”). The initial Tax Matters Member shall be Dominion. The Tax Matters Member shall promptly notify the Members if any tax return or report of the Company is audited or if any adjustments are proposed by any Governmental Authority. In addition, the Tax Matters Member shall promptly furnish to the Members all notices concerning administrative or judicial proceedings relating to federal income tax matters. During the pendency of any such administrative or judicial proceeding, the Tax Matters Member shall furnish to the Members periodic reports, not less often than monthly, concerning the status of any such proceeding. Without the consent of the Board, the Tax Matters Member shall not extend the statute of limitations, file a request for administrative adjustment, file suit concerning any tax refund or deficiency relating to any Company administrative adjustment or enter into any settlement agreement relating to any Company item of income, gain, loss, deduction or credit for

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any Fiscal Year of the Company. The costs and expenses reasonably incurred by the Tax Matters Member in performing its obligations under this Section 7.9 and Section 7.10 shall be reimbursed to the Tax Matters Member by the Company promptly following the Company’s receipt of an invoice therefor.

7.10.Tax Returns and Reports

The Tax Matters Member shall deliver to each Member the following schedules and tax returns: (i) within two (2) Business Days prior to the federal estimated tax payment date for corporations, an estimated Schedule K-1 through the applicable quarter, (ii) within 60 Days after the Company’s year-end, an estimated Schedule K-1 and (ii) not less than 45 Days prior to the due date for the filing of the Company’s federal information return for the immediately preceding taxable year, a final Schedule K-1, along with copies of all other federal, state, or local income tax returns or reports filed by the Company for the previous year as may be required as a result of the operations of the Company. In addition, on or before the 30^th day after the end of each Fiscal Quarter, the Tax Matters Member shall cause each Member to be furnished with (i) an estimate of the Company’s taxable income for the current Fiscal Year through the end of such Fiscal Quarter and (ii) book and tax basis information for the Company’s assets (including information regarding additions and retirements of assets during such Fiscal Quarter) sufficient to allow such Member to satisfy its own obligations and make its own computations, allocations and adjustments under Code sections 704(b), 704(c) and 754. The Company shall notify each Member promptly (and in any event within 30 days) after it learns that it will earn (or, if not previously reported to the Members pursuant to this Section 7.10, after it learns that it has earned) any gross income which may not be “qualifying income” (as such term is defined pursuant to Section 7704 of the Code); such notification shall include an estimate of each Member’s allocable share of any such gross income.

7.11. Audit Rights

Each Member shall have the right to inspect and audit the books and records of the Company. Such audits shall be conducted at the cost of the Member(s) requesting same. A Member may exercise its audit rights hereunder by giving at least thirty (30) Days’ advance written notice to the Company of the desire to perform such audit, which notice shall include the estimated timing and other particulars related to such audit. The audit shall be conducted during normal business hours of the Company. The audit shall not unreasonably interfere with the operation of the Company. Each Member may conduct no more than one audit per calendar year.

ARTICLE 8

INDEMNIFICATION

8.1.    Right to Indemnification

Subject to the limitations and conditions as provided herein or by applicable law, each Person who was or is made a party or is threatened to be made a party to or is involved in any threatened, pending or completed action, suit or proceeding, whether civil, criminal, administrative, arbitrative or investigative (hereinafter a “Proceeding”), or any appeal in such a Proceeding or any inquiry or investigation that could lead to such a Proceeding, by reason of the

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fact that he or she, or a Person of whom he or she is the legal representative, is or was a Manager or Officer of the Company, or while such a Person is or was serving at the request of the Company as a manager, officer, partner, venturer, member, trustee, employee, agent or similar functionary of another foreign or domestic general partnership, corporation, limited partnership, joint venture, limited liability company, trust, employee benefit plan or other enterprise (other than the Operator in its capacity as such), shall be indemnified by the Company to the extent such Proceeding or other above-described process relates to any such above-described relationships with, status with respect to, or representation of any such Person to the fullest extent permitted by the Act, as the same exists or may hereafter be amended (but, in the case of any such amendment, only to the extent that such amendment permits the Company to provide broader indemnification rights than said applicable law permitted the Company to provide prior to such amendment) against judgments, penalties (including excise and similar taxes and punitive damages), fines, settlements and reasonable expenses (including attorneys’ and experts’ fees) actually incurred by such Person in connection with such Proceeding, and indemnification under this Article 8 shall continue as to a Person who has ceased to serve in the capacity which initially entitled such Person to indemnity hereunder for any and all liabilities and damages related to and arising from such Person’s activities while acting in such capacity; provided, however, that no Person shall be entitled to indemnification under this Section 8.1 in the event the Proceeding involves acts or omissions of such Person which constitute an intentional breach of this Agreement or fraud, gross negligence or willful misconduct on the part of such Person. The rights granted pursuant to this Article 8 shall be deemed contract rights, and no amendment, modification or repeal of this Article 8 shall have the effect of limiting or denying any such rights with respect to actions taken or Proceedings arising prior to any such amendment, modification or repeal. It is expressly acknowledged that the indemnification provided for in this Article 8 may involve indemnification for negligence or under theories of strict liability. The Operator shall only be indemnified to the extent provided in the Operations Agreement.

8.2.Indemnification of Employees and Agents

The Company may indemnify and advance expenses to Persons who are entitled to indemnification under Section 8.1, including current and former employees (if any) or agents of the Company, and those Persons who are or were serving at the request of the Company as a manager, director, officer, partner, venturer, member, trustee, employee (if any), agent or similar functionary of another foreign or domestic general partnership, corporation, limited partnership, joint venture, limited liability company, trust, employee benefit plan or other enterprise against any liability asserted against such Person and incurred by such Person in such a capacity or arising out of such Person’s status as such a Person to the same extent that it may indemnify and advance expenses to a Member under this Article 8.

8.3.Advance Payment

Any right to indemnification conferred in this Article 8 shall include a limited right to be paid or reimbursed by the Company for any and all reasonable expenses as they are incurred by a Person entitled to be indemnified under Section 8.1 who was, or is threatened, to be made a named defendant or respondent in a Proceeding in advance of the final disposition of the Proceeding and without any determination as to such Person’s ultimate entitlement to

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indemnification; provided, however, that the payment of such expenses incurred by any such Person in advance of final disposition of a Proceeding shall be made only upon delivery to the Company of a written affirmation by such Person of such Person’s good faith belief that such Person has met the requirements necessary for indemnification under this Article 8 and a written undertaking, by or on behalf of such Person, to repay all amounts so advanced if it shall ultimately be determined that such indemnified Person is not entitled to be indemnified under this Article 8 or otherwise.

8.4.    Appearance as a Witness

Notwithstanding any other provision of this Article 8, the Company shall pay or reimburse expenses incurred by any Person entitled to be indemnified pursuant to this Article 8 in connection with such Person’s appearance as a witness or other participation in a Proceeding at a time when he is not a named defendant or respondent in the Proceeding.

8.5.Nonexclusivity of Rights

The right to indemnification and the advancement and payment of expenses conferred in this Article 8 shall not be exclusive of any other right which a Person indemnified pursuant to Section 8.1 may have or hereafter acquire under the Act or other applicable law, this Agreement, or any other agreement, vote of Members or otherwise.

8.6.Insurance

The Company may purchase and maintain insurance on behalf of any Person against any liability asserted against him or it and incurred by him or it in any such capacity, or arising out of his or its status as such, whether or not the Company would have the power or the obligation to indemnify him or it against such liability under the provisions of this Article 8.

8.7.Certain Definitions

For purposes of this Article 8, references to “the Company” shall include, in addition to the resulting entity, any constituent entity (including any constituent of a constituent) absorbed in a consolidation or merger which, if its separate existence had continued, would have had power and authority to indemnify its members, managers, officers, and employees or agents, so that any Person who is or was a member, manager or officer of such constituent entity, or is or was serving at the request of such constituent entity as a member, manager or officer of another limited liability company, partnership, joint venture, trust or other enterprise, shall stand in the same position under the provisions of this Article 8 with respect to the resulting or surviving entity as he or it would have with respect to such constituent entity if its separate existence had continued. For purposes of this Article 8, references to “fines” shall include any excise taxes assessed on a Person with respect to an employee benefit plan; and references to “serving at the request of the Company” shall include any service as a Member, Manager or officer of the Company which imposes duties on, or involves services by, such Member, Manager or officer with respect to an employee benefit plan, its participants or beneficiaries; and a Person who acted in good faith and in a manner he or it reasonably believed to be in the interest of the participants and beneficiaries of an employee benefit plan shall be deemed to have acted in a manner “not opposed to the best interests of the Company” as referred to in this Article 8.

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8.8.    Severability

The provisions of this Article 8 are intended to comply with the Act. To the extent that any provision of this Article 8 authorizes or requires indemnification or the advancement of expenses contrary to the Act or the Certificate, the Company’s power to indemnify or advance expenses under such provision shall be limited to that permitted by the Act and the Certificate and any limitation required by the Act or the Certificate shall not affect the validity of any other provision of this Article 8.

ARTICLE 9

COMMITTED FACILITIES; OTHER ACTIVITIES

9.1.Development of Committed Facilities

The Members hereby approve the development of the Committed Facilities, including the acquisition of necessary regulatory approvals for the Committed Facilities and the construction, ownership, operation and maintenance of the Committed Facilities, in accordance with (in the case of the Initial Facilities) the preliminary timetable approved pursuant to the Initial Resolution; provided that such approval is subject to Section 6.8. The Members shall cooperate with the Company and the Operator in their respective efforts to develop the Committed Facilities, and shall, subject to Section 6.8, not take any action or fail to take any action that would delay or obstruct the Company from obtaining the FERC Certificate in respect of any Committed Facilities.

9.2.Development of Approved Facilities Projects

(a)The Members may from time to time consider and approve the development of Facilities Projects other than the Committed Facilities. The Company shall not undertake the development or construction of any Facilities Project other than any Approved Facilities Project approved in accordance with Section 6.7(b)(iii); provided that such approval is subject to Section 6.8.

(b)With respect to the Initial Facilities, “Foundation Shippers” (subscribers holding 300,000 Dt per day or greater of service entitlements) have each secured a one-time right to request an expansion of the Facilities, which right is also set forth in Precedent Agreements. This right may be exercised either (i) at the time of the customer’s election of Optional Quantities or (ii) after the date of a FERC order concerning the Optional Quantity expansion project and during the primary term of that customer’s service agreement with the Company. In order to implement this customer right, the Company will develop a Facilities Project Proposal as specified in Section 9.3(b) and proceed to evaluate the requested project pursuant to the provisions of Section 9.3(c). 

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9.3.Proposed Facilities Projects

(a)Without prejudice to any Member’s rights under Section 9.5, any Member that desires to pursue a potential Competitive Facilities Project shall first submit it to the Company by notifying the Board in writing of the nature of the proposed Competitive Facilities Project, including such details as are then available, and providing a detailed explanation of the reasons why such Competitive Facilities Project is being requested (the “Competitive Facilities Project Notice”). In addition, if any Member believes that the Company should pursue a Base Facilities Project, such Member may notify the Board in writing of the nature of the proposed Base Facilities Project, including such details as are then available, and providing a detailed explanation of the reasons why such Base Facilities Project should be pursued by the Company (the “Base Facilities Project Notice”).

(b)As soon as reasonably practicable and in no event later than sixty (60) Days after receipt of a Competitive Facilities Project Notice or a Base Facilities Project Notice (either such notice, as applicable, a “Facilities Project Notice”), the Board shall vote on whether to authorize a feasibility study for the proposed Facilities Project. If the Members holding at least 70% of the Percentage Interests vote to authorize such a study, which vote shall include approval of the Capital Contributions necessary to fund the study (and shall be made pro rata by the Members voting in favor of authorizing such study), the Company shall instruct the Operator, or such other Person directed by the Board, to prepare and deliver to the Board and each Member, no later than ninety (90) Days after such direction by the Board, the findings of such feasibility study, which shall include a detailed description of the proposed Facilities Project and the preliminary estimated costs (including acquisition expenses, if applicable), projected rate information and the potential financing (the “Facilities Project Proposal”).

(c)Within sixty (60) Days after the Facilities Project Proposal has been received by each Member, the Board shall vote on whether to proceed with the development of the proposed Facilities Project as set forth in such Facilities Project Proposal. If the Members holding at least 70% of the Percentage Interests vote to proceed with the development of the proposed Facilities Project, the Company shall proceed with such development, including the acquisition of necessary regulatory approvals and the Financing Commitment, if any. For the avoidance of doubt, any Member voting not to approve of a Facilities Project pursuant to this Section 9.3(c) may elect to become a Diluting Member in accordance with the provisions of Section 4.3.

(d)If the Members holding at least 70% of the Percentage Interests do not approve of a proposed Competitive Facilities Project pursuant to Section 9.3(c), then, subject to Section 9.5, only the Members that voted to approve the applicable Facilities Project Proposal shall be permitted to undertake such Competitive Facilities Project (or substantially similar project) without regard to the Company or the other Members.

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9.4.Development of Business Opportunities

Other than pursuant to Section 9.3, no Member or any of its Affiliates shall have any obligation to present any investment, acquisition or business opportunity, transaction, agreement, arrangement or other matter to the Company or the Board.

9.5.Certain Opportunities

Notwithstanding anything in this Agreement to the contrary, other than with respect to (w) the Initial Facilities prior to the earlier of (i) the In-Service Date and (ii) the dissolution of the Company, (x) the PA Required Expansion Facilities prior to the earlier of such Facilities being placed in-service and (ii) the dissolution of the Company, (y) any Approved Facilities Project prior to the earlier of (i) such Approved Facilities Project being placed in-service and (ii) the dissolution of the Company and (z) the obligations set forth in Section 9.3: (a) the Members and their Affiliates may engage in or hold an interest of any nature in, directly or indirectly, independently or with others, whether as an equity owner, lender, consultant, employee, operator, manager, partner, joint venturer or otherwise, any business without regard to whether such business is directly or indirectly competitive with the Business conducted or expected to be conducted by the Company and/or its Subsidiaries and without regard to the geographic location of such business, without the consent or approval of the other Members, the Board or the Company, and without any duty or obligation to account to the other Members or the Company in connection therewith and (b) neither the Company nor any Manager, Member or Affiliate of the foregoing shall have any right or obligation, by virtue of this Agreement or otherwise, to share or participate in such other businesses, investments, or activities of a Member or its Affiliates (excluding the Company and its Subsidiaries) or to the income or proceeds derived therefrom. Notwithstanding anything contained in this Agreement to the contrary, and for the avoidance of doubt, (a) each of the Members, its Parent and/or their Affiliates may independently pursue and compete for any or all proposed Competitive Facilities Projects (but not any Base Facilities Project), extensions, expansions and facilities to serve gas and electric end users, municipal gas and electric systems serving end users and electric power plants, in each case within such Member’s Parent’s franchise or established service territory (as it exists at the time of the proposed opportunity), notwithstanding that such franchise or established service territory may overlap with the franchise or established service territory of another Member or its Affiliates, and (b) nothing in this Section 9.5 shall prohibit, restrict or limit in any way the ability of any Affiliate of a Member from soliciting or accepting any offer or submitting a proposal to or negotiating or entering into any agreement with any Person relating to the acquisition of transmission capacity on any existing or proposed interstate pipeline, whether or not it is competing with the Facilities or any Facilities Project.

9.6.Insurance

The Company shall maintain in effect insurance consistent with the insurance contemplated in the Transaction Documents and such other insurance specified in Schedule B hereto and upon such terms and conditions, including deductibles, as decided and agreed upon at least annually by the Members.

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ARTICLE 10

DISPOSITION

10.1.Dispositions; Exception to Application of this Article 10

(a)No Member may Dispose of all or any part of its Membership Interests or any beneficial right or interest therein, or contract to do or permit any of the foregoing, whether voluntarily or by operation of law, and any attempt to do so shall be null and void and not recognized on the Company’s books and records, other than Dispositions: (i) constituting Permitted Transfers, (ii) subject to Section 10.2(a), to a Qualified Transferee or (iii) effected in accordance with this Article 10; provided, however, that notwithstanding anything herein to the contrary a Disposition by a Member (including a Permitted Transfer) shall be null and void ab initio if (A) following the proposed Disposition, the Company would have more than 100 members within the meaning of Section 1.7704-1(h)(1)(ii) of the Treasury Regulations (taking into account Section 1.7704-1(h)(3) of the Treasury Regulations); provided that such limitation shall not apply to any Disposition by any Member of all or part of its Membership Interest to an Affiliate, (B) such Disposition would cause the Company to be taxed as a corporation for federal tax purposes; (C) to the extent it would become the direct holder of a Membership Interest, the transferee fails to deliver to the Company the representations set forth in Annex A and an executed Accession Agreement, or (D) such Disposition would result in the violation of any applicable federal or state securities laws (collectively, (A) through (D), the “Disposition Defaults”). Members shall bear any costs the Company reasonably incurs in connection with Dispositions of any of their respective Membership Interests. The Members agree that following the In-Service Date a Member shall have the right to pledge all or any portion of such Member’s Membership Interest or grant a lien or security interest in all or any portion of such Member’s Membership Interest (a “Pledged Interest”) to any bank or financial institution (a “Lender”) that is subordinate to any lien or security interest granted with respect to such Member’s Membership Interest as a result of any Financing Commitment; provided that it is agreed that if any Lender forecloses upon or otherwise becomes the owner of such Pledged Interest, such Lender shall, subject to none of the Disposition Defaults being applicable with respect to such foreclosure, be deemed a Defaulting Member for purposes of this Agreement.

(b)Unless a Person acquiring any Membership Interests becomes admitted as a Member in accordance with the provisions of Section 10.1(c), such Person shall not be entitled to any of the rights granted to a Member hereunder in respect of such Membership Interests, other than the right to receive only the economic benefits related thereto, including allocations of income, gain, loss, deduction, credit and similar items and distributions to which the assignor would otherwise be entitled, to the extent such items are assigned.

(c)A Person acquiring any Membership Interests shall be admitted as a Member and entitled to all of the rights of a Member in respect of such Membership Interests only if none of the Disposition Defaults are applicable with respect to such

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transfer and either (i) the transfer to such Person was a Permitted Transfer or otherwise effected pursuant to the procedures set forth in this Article 10, (ii) such Person acquired the Membership Interests pursuant to Sections 4.5(d), 6.8 or 10.5 or (iii) in any other case, such Person is a Qualified Transferee.

(d)Notwithstanding any provision herein to the contrary, in no event shall any provision of this Article 10 be applicable in connection with any exchange, reclassification, or other conversion of Membership Interests or other debt or equity securities of the Company into any cash, securities, or other property pursuant to a Disposition of all or substantially all of the Company Properties.

(e)In connection with any Disposition permitted under this Article 10:

(i)each non-Disposing Member shall cooperate in good faith with the Disposing Member, and shall take no action to impede such Disposition or reduce the value of the Membership Interest subject to such Disposition, without prejudice to the rights of such non-Disposing Members to enforce in good faith the other provisions of this Article 10;

(ii)the Company shall, upon the Disposing Member’s reasonable request and at the Disposing Member’s sole cost and expense, cooperate fully with potential acquirers in such prospective transaction by taking all customary and other actions reasonably requested by such holders or such potential acquirers, including making the Company’s properties, books and records, and other assets available for inspection by such potential acquirers and making its employees reasonably available for presentations, interviews and other diligence activities, in each case during normal business hours and upon reasonable advance notice, and subject to reasonable and customary confidentiality provisions; and

(iii)the Disposing Member shall be permitted to take all steps reasonably necessary to carry out an auction of its Membership Interest, including selecting an investment bank, providing confidential information (pursuant to confidentiality agreements), selecting the winning bidder and negotiating the requisite documentation (at its sole cost and expense).

(f)A Member entitled to acquire the Membership Interests of any other Member (whether through a Disposition or through the recalculation of the Percentage Interests) pursuant to Sections 4.5(d), 6.8 or 10.5 shall be entitled to exercise such right through an Affiliate or any Qualified Transferee designated by them; provided that the exercise of such right in such manner otherwise complies with Section 10.1(a).

10.2.Other Restrictions on Dispositions

(a)Notwithstanding anything to the contrary contained herein, for a period beginning on the Effective Date and ending on the In-Service Date, no Member shall Dispose of all or any part of its Membership Interests, or contract to do or permit any such Disposition, whether voluntarily or by operation of law, other than Permitted

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Transfers. Any breach of the foregoing covenant will be deemed a Performance Default and result in such Member being treated as a Defaulting Member.

(b)Except for any Disposition to a Permitted Transferee in accordance with this Article 10 or any Disposition contemplated under Sections 4.3 and 10.5, each Disposition must comply with the following minimum size requirements: (1) if such Member’s Percentage Interest is equal to or less than 10%, the Disposition must include all of the Disposing Member’s Membership Interests and (2) if such Disposing Member’s Percentage Interest is greater than 10%, the Disposition must be of a Membership Interest having a Percentage Interest of at least 10%.

10.3.[RESERVED].

10.4.Preemptive Right

(a)If the Company proposes to issue any Membership Interests to any Person in a transaction or transactions other than the Membership Interests attributable to the Capital Contributions made or agreed to be made by the Members pursuant to Article 4 as in effect on the date hereof, each Member (other than a Defaulting Member or a Diluting Member) shall have the right to purchase directly or through any Affiliate such portion of such Membership Interests sufficient to maintain such Member’s then Percentage Interest, on the same terms and conditions as applied to all Persons purchasing Membership Interests.

(b)In the event of a proposed transaction or transactions, as the case may be, that would give rise to preemptive rights of the Members under Section 10.4(a), the Company shall provide notice (the “Initial Notice”) to the Members no later than ten (10) Business Days prior to the expected consummation of such transaction or transactions. Each Member shall provide notice of its election to exercise such rights within five (5) Business Days after delivery of such Initial Notice from the Company (each Member electing to exercise its preemptive right in such instance is referred to as an “Exercising Member”). The failure of a Member to respond to the Initial Notice and affirmatively exercise its preemptive right in accordance with the terms of this Agreement and the Initial Notice shall be deemed an election not to exercise its preemptive right in connection with such proposed transaction or transactions.

(c)If a Member shall elect not to exercise its respective preemptive right, then the Exercising Members shall have the right to purchase additional Membership Interests (a “Subsequent Purchase”), from those securities as to which no such right was exercised, on a pro rata basis insofar as more than one such Exercising Member desires to so purchase additional securities. In the event of a situation described in the preceding sentence in which a Member elects not to exercise its respective preemptive right with respect to a proposed transaction or transactions, the Company shall provide notice (the “Subsequent Notice”) of such fact within three (3) Business Days following the receipt of all of the notices concerning such elections from the Members

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possessing such preemptive rights. Each Exercising Member shall respond to this Subsequent Notice by sending a response notice with respect thereto within three (3) Business Days after delivery of the Subsequent Notice. The failure of an Exercising Member to respond to such Subsequent Notice and affirmatively exercise its preemptive right in accordance with the terms of this Agreement shall be deemed an election not to exercise its preemptive right in connection with such Subsequent Purchase.

10.5.Dominion ROFR

(a)If (a) any Member (for the purposes of this Section 10.5, the “Proposing Member”) (i) proposes to Dispose of all or any part of its Membership Interest to any other Member (other than Dominion or any of its Affiliates which is also a Member) including pursuant to any transaction in which the Membership Interests of more than one Member are directly or indirectly consolidated or (ii) becomes subject to a Change in Control, and (b) after giving effect to such proposed Disposition or Change in Control, the Percentage Interest of the acquiring or surviving Member would be equal to (unless after giving effect to such Disposition or Change in Control there would be only two Members) or greater than the aggregate Percentage Interest of Dominion and each of its Affiliates that is also a Member, then the Proposing Member shall first give notice (a “ROFR Notice”) to Dominion. The ROFR Notice shall set forth the name of the Member to whom the Disposition is proposed or Change in Control affects, Membership Interest subject to such proposed Disposition (the “OfferedInterest”), the price payable for the Offered Interest, and details of the payment terms and all other terms and conditions of the proposed Disposition or Change in Control. Dominion shall have the right, until the date that forty-five (45) days following the date of delivery of the ROFR Notice (the “ROFR Expiration Date”) to deliver to the Proposing Member a written election to purchase (the “PurchaseNotice”) that portion of the Offered Interest as shall be necessary so that no other Member will have a Membership Interest that is equal to (unless after giving effect to such Disposition or Change in Control there would be only two Members) or greater than the aggregate Membership Interests of Dominion and each of its Affiliates that is also a Member (the “ROFR Interest”). The delivery of the Purchase Notice shall constitute an irrevocable commitment to purchase such ROFR Offered Units.

(b)The purchase price and terms and conditions for the purchase of the ROFR Interest pursuant to this Section 10.5 shall be the price and terms and conditions set forth in the applicable ROFR Notice; provided that the Proposing Member shall at a minimum make customary representations and warranties concerning (i) the Proposing Member’s valid title to and ownership of the ROFR Interest, free and clear of all liens, claims and encumbrances (excluding those arising in connection with a Financing Commitment or under applicable securities laws), (ii) the Proposing Member’s authority, power and right to enter into and consummate the sale of the ROFR Interest, (iii) the absence of any violation, default or acceleration of any agreement to which the Proposing Member is subject or by which its assets are bound as a result of the agreement to sell and the sale of the ROFR Interest, and (iv) the absence of, or compliance with, any governmental or third party consents, approvals,

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filings or notifications required to be obtained or made by the Proposing Member in connection with the sale of the ROFR Interest. The closing shall occur no later than sixty (60) Days after the date of delivery of the Purchase Notice, unless the Proposing Member and Dominion agree upon a different date. At the closing, the Proposing Member shall execute and deliver to Dominion (i) an assignment of the ROFR Interest, in form and substance reasonably acceptable to Dominion and (ii) any other instruments reasonably requested by Dominion to give effect to the purchase; and Dominion shall deliver to the Proposing Member in immediately available funds the purchase price.

(c)If the Purchase Notice is not delivered prior to the ROFR Expiration Date, the (i) Proposing Member may Dispose all, but not less than all, of the ROFR Interest or (ii) the Change in Control may be completed, in each case within 90 Days after the ROFR Expiration Date. If the ROFR Interest is not so Disposed or the Change in Control is not completed within such 90-day period, the Proposing Member may not sell any of the ROFR Interest without again complying in full with the provisions of this Section 10.5.

ARTICLE 11

DISSOLUTION, LIQUIDATION, AND TERMINATION

11.1.Dissolution

The Company shall dissolve and its affairs shall be wound up on the first to occur of the following:

(a)the consent of the Managers designated by the Members holding at least the amount of Percentage Interests as are required by Section 6.7(b)(i) to dissolve the Company;

(b)if the PA Execution Date has not occurred by December 31, 2014, unless the Managers designated by the Members holding at least 70% of the Percentage Interests elect not to dissolve the Company;

(c)entry of a decree of judicial dissolution of the Company under Section 18-802 of the Act; or

(d)unless the Members otherwise agree, upon consummation of the Disposition of all or substantially all of the Company Properties.

11.2.Liquidation and Termination

On dissolution of the Company, the liquidator shall be the Board or a Person selected by Managers designated by the Members holding at least 70% of the Percentage Interests. The liquidator shall proceed diligently to wind up the affairs of the Company at the direction of the Board and make final distributions as provided herein and in the Act. The costs of liquidation shall be borne as a Company expense. The steps to be accomplished by the liquidator are as follows:

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(a)As promptly as possible after dissolution and again after final liquidation, the liquidator shall cause a proper accounting to be made of the Company Property, liabilities, and operations through the last Day of the calendar month in which the dissolution occurs or the final liquidation is completed, as applicable.

(b)The liquidator shall pay, satisfy or discharge from Company funds all of the debts (including debts owing to any Member), liabilities and obligations of the Company (including all expenses incurred in liquidation) or otherwise make adequate provision for payment and discharge thereof (including the establishment of a cash escrow fund for contingent liabilities in such amount and for such term as the liquidator may reasonably determine).

(c)To the extent that the Company has any remaining property:

(i)The liquidator may sell any or all of the Company’s property and any resulting gain or loss from each sale shall be computed and allocated to the Capital Accounts of the Members as provided in Article 5.

(ii)All remaining Company Property shall be distributed to the Members in accordance with the positive balances in their Capital Accounts, after giving effect to all contributions, distributions and allocations for all periods; provided that if the Company liquidates as a result of the dissolution event set forth in Section 11.1(b), then after making any distributions required to be made pursuant to Section 5.5(d) in the manner set forth in Section 4.1(d), all remaining Company Property shall be distributed to the Member that contributed such Company Property irrespective of the balances in the Member’s Capital Accounts and the remaining provisions of this Section 11.2(c)(ii) shall have no effect. If the amounts of Company Property that would be distributed to the Members upon liquidation if such distributions were made pursuant to Section 5.5(b) do not correspond to the respective Capital Account balances of the Members, then income, gain, loss and deduction for the Fiscal Year in which the liquidation occurs shall be reallocated among the Members to cause, to the extent possible, the Members’ Capital Accounts immediately prior to such distribution to correspond to the amounts that would be distributed to the Members if liquidating distributions were made pursuant to Section 5.5(b); provided that, for purposes of this Section 11.2(c)(ii), the amount otherwise distributable to a Member pursuant to Section 5.5(b) shall be reduced by such Member’s Unfunded Default Amount, if any, and increased by such Member’s Undistributed Deficiency Interest Amount, if any.

(iii)All distributions in kind to the Members shall be valued for purposes of determining each Member’s interest therein at its Fair Market Value at the time of such distribution, and such distributions shall be made subject to the liability of each distributee for costs, expenses, and liabilities theretofore incurred or for which the Company has committed prior to the date of termination, and those costs, expenses, and liabilities shall be allocated to the distributee pursuant to this Section 11.2.

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(iv)Any distribution to the Members in liquidation of the Company shall be made by the later of the end of the taxable year in which the liquidation occurs or 90 Days after the date of such liquidation. For purposes of the preceding sentence, the term “liquidation” shall have the same meaning as set forth in Treasury Regulations Section 1.704-1(b)(2)(ii). The distribution of cash and/or property or assets to a Member in accordance with the provisions of this Section 11.2 constitutes a complete return to the Member of its Capital Contribution and a complete distribution to the Member of its Membership Interest and all of the Company Properties and constitutes a compromise to which all Members have consented within the meaning of Section 18-502(b) of the Act. To the extent that a Member returns funds to the Company, it has no claim against any other Member for those funds.

(v)If a sale of the Company is structured as a Disposition of Membership Interests (whether a direct sale, a merger, an exchange of interests, or other similar transaction), the amount of the aggregate purchase price to be allocated among the Members shall be determined in a manner consistent with the amounts that would have been distributed to the Members if the Company had been liquidated in accordance with this Section 11.2 and if the total liquidating distributions with respect to all Membership Interests had equaled the aggregate purchase price being paid for all the Membership Interests.

11.3.Deficit Capital Accounts

Notwithstanding anything to the contrary contained in this Agreement, and notwithstanding any custom or rule of law to the contrary, no Member shall be obligated to restore a deficit balance in its Capital Account at any time.

11.4.Certificate of Cancellation

On completion of the distribution of property as provided herein, the Company shall be terminated and the Members shall file a certificate of cancellation with the Secretary of State of Delaware, cancel any other filings made pursuant to Section 1.5, and take such other actions as may be necessary to terminate the Company.

ARTICLE 12

REPRESENTATIONS AND WARRANTIES

12.1.Representations and Warranties of the Members

Each Member hereby represents and warrants to the Company and each other Member that (a) it is duly formed, validly existing and (if applicable) in good standing under the laws of the state of its formation, and if required by applicable law is duly qualified to do business and (if applicable) is in good standing in the jurisdiction of its principal place of business (if not formed therein); (b) it has full corporate, limited liability company, partnership, trust, or other applicable power and authority to execute and agree to this Agreement and the Transaction Documents to which it is a party and to perform its obligations hereunder and thereunder and all necessary actions by the board of directors, shareholders, managers, members, partners, trustees,

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beneficiaries, or other Persons necessary for the due authorization, execution, delivery, and performance of this Agreement and the Transaction Documents to which it is a party by that Member have been duly taken; (c) it has duly executed and delivered this Agreement and the Transaction Documents to which it is a party and this Agreement and the Transaction Documents to which it is a party are enforceable against such Member in accordance with their respective terms, subject to bankruptcy, moratorium, insolvency and other applicable law generally affecting creditors’ rights and general principles of equity (whether applied in a proceeding in a court of law or equity); (d) its authorization, execution, delivery, and performance of this Agreement and the Transaction Documents to which it is a party does not conflict with any material obligation under any other material agreement or arrangement to which that Member is a party or by which it is bound; and (e) it (i) has been furnished with such information about the Company and the Membership Interest as that Member has requested, (ii) has made its own independent inquiry and investigation into, and based thereon has formed an independent judgment concerning, the Company and that Member’s Membership Interest therein, (iii) has adequate means of providing for its current needs and possible individual contingencies and is able to bear the economic risks of this investment and has a sufficient net worth to sustain a loss of its entire investment in the Company in the event such loss should occur, (iv) has such knowledge and experience in financial and business matters as to be capable of evaluating the merits and risks of an investment in the Company, (v) is an “accredited investor” within the meaning of “accredited investor” under Regulation D of the Securities Act and (vi) understands and agrees that its Membership Interest shall not be sold, pledged, hypothecated or otherwise transferred except in accordance with the terms of this Agreement and pursuant to an applicable exemption from registration under the Securities Act and other applicable securities laws. Upon the occurrence and during the continuation of any event or condition which would cause a Member to be in breach of a representation or warranty contained in clause (e) of this Article 12, the breaching Person shall be treated as a Defaulting Member.

ARTICLE 13

EFFECTIVENESS

13.1.Effectiveness

This Agreement shall become effective upon the Effective Date; provided, however, that, notwithstanding anything contained in this Agreement to the contrary, prior to the PA Execution Date, no Member shall have any obligation to make any Capital Contribution to the Company (including the initial Capital Contributions described in Section 4.1).

ARTICLE 14

GENERAL PROVISIONS

14.1.Notices

Except as expressly set forth to the contrary in this Agreement, all notices, requests, or consents provided for or permitted to be given under this Agreement must be in writing and must be given by personal delivery, by certified or registered United States mail (postage prepaid, return receipt requested), by a nationally recognized overnight delivery service for next Day delivery, or by facsimile or other electronic transmission, to the addresses given for that Member

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on Exhibit 3.1 or such other address as that Member may specify by written notice to the other Members. All notices, requests, and consents to be sent to the Company must be sent to or made at the address of the Company’s principal place of business or such other address as the Company may specify by notice to the Members. All such notices, requests and other communications will be effective only upon receipt, except that if received after 5:00 p.m. (in the recipient’s time zone) on a Business Day or if received on a Day that is not a Business Day, such notice, request or communication will not be effective until the next succeeding Business Day.

14.2.Amendment or Modification

Provided that all Members receive no less than five (5) Business Days prior written notice, the Board, acting with the consent of the Managers designated by the Members holding at least 96% of the Percentage Interests, may amend any provision of this Agreement or the Certificate, and execute, swear to, acknowledge, deliver, file and record whatever documents may be required in connection therewith; provided, however, that any such amendment that has a material adverse effect on any Member must be approved by the express prior written consent of such Member.

14.3.Entire Agreement

This Agreement, together with the Transaction Documents, and the exhibits or schedules thereto and any agreements or documents specifically referenced herein or therein, constitute the entire agreement and understanding of the Members in respect of the subject matter set forth herein and supersede all prior understandings, agreements or representations by or among the Members, written or oral, to the extent they relate in any way to the subject matter hereof or the transactions contemplated herein.

14.4.Extensions; Waivers

Any Member may, for itself only, (a) extend the time for the performance of any of the obligations of any other Member under this Agreement, (b) waive any inaccuracies in the representations and warranties of any other Member contained herein or in any document delivered pursuant hereto and (c) waive compliance with any of the agreements or conditions for the benefit of such Member contained herein. Any such extension or waiver will be valid only if set forth in a writing signed by the Member to be bound thereby. No waiver by any Member of any default, misrepresentation or breach of warranty or covenant hereunder, whether intentional or not, may be deemed to extend to any prior or subsequent default, misrepresentation or breach of warranty or covenant hereunder or affect in any way any rights arising because of any prior or subsequent such occurrence. Neither the failure nor any delay on the part of any Member to exercise any right or remedy under this Agreement will operate as a waiver thereof, nor will any single or partial exercise of any right or remedy preclude any other or further exercise of the same or of any other right or remedy.

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14.5.    Assignment; Binding Effect

Except as expressly provided herein, no Member may assign either this Agreement or any of its rights, interests or obligations hereunder without the prior written approval of all the other Members, and any such assignment by a Member without prior written approval of all the other Members will be deemed a Performance Default and result in such Member being treated as a Defaulting Member. All of the terms, agreements, covenants, representations, warranties and conditions of this Agreement are binding upon, and inure to the benefit of and are enforceable by, the Members and their respective successors and permitted assigns.

14.6.Governing Law

THIS AGREEMENT AND THE PERFORMANCE OF THE TRANSACTIONS AND OBLIGATIONS OF THE MEMBERS HEREUNDER WILL BE GOVERNED BY AND CONSTRUED IN ACCORDANCE WITH THE LAWS OF THE STATE OF DELAWARE, WITHOUT GIVING EFFECT TO ANY CHOICE OF LAW PRINCIPLES.

14.7.Dispute Resolution

Should a dispute arise among the Members relating to this Agreement, any Member may seek to resolve any such dispute through negotiations among the Senior Executives by providing the other Members written notice of its intent to invoke this Section 14.7. The Senior Executives will meet at a mutually acceptable time and place within fifteen (15) Days after such notice and thereafter as often as they reasonably deem necessary to exchange relevant information and to attempt to resolve the dispute. All negotiations and communications pursuant to this Section 14.7 will be treated and maintained by the Members as confidential information and will be treated as compromise and settlement negotiations for purposes of the federal and state rules of evidence. If the matter has not been resolved within fifteen (15) Days after the initial written notice set forth above, or such longer period as may be mutually agreed upon by all of the Members, the Members will meet to discuss the retention of a mediator for the purpose of resolving the Dispute through non-binding mediation. Participation in such mediation will be voluntary. If the Members agree to non-binding mediation, they will mutually agree upon a mediator within twenty (20) days of the initial meeting of the Members with respect to the retention of a mediator. The Members will seek to resolve the dispute in an expeditious manner, and to the extent possible, within thirty (30) days of commencement of mediation. The cost of any mediation under this Section 14.7 will be divided equally among the Members. Absent an agreement to mediate, each Member retains all rights to agree at that time to arbitration or to resort to any other means to resolve the dispute in its sole discretion.

14.8.Waiver of Jury Trial

THE MEMBERS WAIVE ALL RIGHT TO TRIAL BY JURY IN ANY ACTION OR PROCEEDING TO ENFORCE OR DEFEND ANY RIGHTS UNDER THIS AGREEMENT AND ANY DOCUMENT EXECUTED IN CONNECTION HEREWITH.

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14.9.Affiliate Contracts

(a)As of the Effective Date, the Members anticipate that the Company will enter into each of the Affiliate Contracts specified on Exhibit 14.9.

(b)The Members intend each Affiliate Contract shall be entered into on an arm’s-length basis and on terms and conditions competitive at then-prevailing market conditions. The negotiation of each Affiliate Contract or modification to any Affiliate Contract shall be conducted on behalf of the Company (or the applicable Subsidiary) by or under the direction of at least two of the Managers, acting in good faith and in the best interests of the Company (or the applicable Subsidiary), designated by the Acting Members holding collectively at least 45% of the Percentage Interests, and all decisions of the Company (or the applicable Subsidiary) concerning such Affiliate Contract relating to the commencement, termination, withdrawal or settlement of, or decision to consent to, any claim or Proceeding, or the admission of liability by the Company (or the applicable Subsidiary) arising in relation to, or any material waiver under, any Affiliate Contract, shall be approved solely by at least two of the Managers, acting in good faith and in the best interests of the Company (or the applicable Subsidiary), designated by the Acting Members holding collectively at least 45% of the Percentage Interests. Notwithstanding anything to the contrary contained in this Agreement, at least two of the Managers designated by the Acting Members holding collectively at least 45% of the Percentage Interests may cause the Company to terminate any Affiliate Contract in accordance with its terms, including the Operations Agreement.

14.10.No Consequential Damages

No Member shall assert, and each Member hereby waives, any claim against any indemnifying Person on any theory of liability for special, indirect, consequential or punitive damages (as opposed to direct or actual damages) of any kind whatsoever, whether or not foreseeable, or for any loss of business, goodwill, opportunity or profit, whether arising directly or indirectly and whether or not foreseeable, even if the Member is actually aware of or has been advised of the likelihood of such loss or damage and regardless of whether the claim for such loss or damage is made in negligence, for breach of contract, breach of trust, breach of fiduciary obligation or otherwise arising out of, in connection with, or as a result of, this Agreement or any agreement or instrument contemplated hereby.

14.11.    Severability

The provisions of this Agreement will be deemed severable and the invalidity or unenforceability of any provision will not affect the validity or enforceability of the other provisions hereof; provided that if any provision of this Agreement is found to be unenforceable in accordance with its terms, the Members agree that such provisions shall be deemed modified to the minimum extent necessary consistent with its objectives to make such provision enforceable, and/or to delete specific words or phrases, and in its reduced form, such provision will then be enforceable and will be enforced, and if such provision is not capable of being so modified, it shall be deemed excised from this Agreement, and the remaining provisions of this Agreement shall in all circumstances remain in full force and effect.

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14.12.    Further Assurances

In connection with this Agreement and the transactions contemplated hereby, each Member shall execute and deliver any additional documents and instruments and perform any additional acts that may be necessary or appropriate to effectuate and perform the provisions of this Agreement and those transactions.

14.13.    Title to Company Property

All Company Property owned by the Company, whether real or personal, tangible or intangible, shall be deemed to be owned by the Company, and no Member, Officer, Manager or Person acting as an operator under any Transaction Document, individually, shall have any ownership of such Company Property. The Company shall hold all Company Properties in its own name. All Company Property shall be recorded as the property of the Company in its books and records without regard to the name in which record title to such assets is held.

14.14.    Intellectual Property

All Intellectual Property Rights (excluding any Intellectual Property Rights of the Operator) invented, discovered, improved or otherwise developed as part of the Facilities (the “IP Rights”) shall be owned by the Company. The Members shall be entitled to use, license or otherwise exploit the IP Rights, and may grant a world-wide royalty-free license to the Affiliate of any Member, only for the evaluation, pursuit, development and operation of the Facilities and for no other purpose. In the event that any IP Right is determined by the Company or a Member to be registrable, the Company shall file applications relating to such IP Rights. Each Member acknowledges the inherent risk of error in the acquisition, interpretation and use of the IP Rights, and that no representation or warranty, express or implied, is made with respect to (a) the completeness, utility or accuracy of any Intellectual Property Rights disclosed to it or (b) the merchantability or fitness for a particular purpose or the freedom from infringement of any third party Intellectual Property Rights by its use of such Intellectual Property Rights.

14.15. Press Releases and Public Announcements

Neither the Company nor any Member shall (and shall use all reasonable efforts to cause its Affiliates not to) release or otherwise disseminate any press releases, public announcements or statements of a material nature regarding the Company or the Business without the consent of the Members holding at least 96% of the Percentage Interests. Notwithstanding the foregoing, the Company may issue such press releases and public announcements or statements in the normal and ordinary course of its business; provided, however, that if any such release, statement or other communication contains a description of, or may be of a sensitive nature to, any Member, the Company shall obtain the consent of such Member at the earliest reasonably practicable time prior to publishing such release, statement or communication.

14.16. No Third Party Beneficiaries

Except as otherwise provided in Article 8, it is the intent of the Members that no third-party beneficiary rights be created or deemed to exist in favor of any Person not a party to this Agreement, unless otherwise expressly agreed to in writing by the Members.

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14.17. Confidentiality

Each Member agrees that all non-public information received from or otherwise relating to the Company, its Subsidiaries and businesses, their Members, or any third party who has entrusted the Company with confidential information regarding the Business, operations or prospects of the Company with the expectation that such information will be kept confidential, is confidential and will not be (i) disclosed or otherwise released to any other Person (other than (A) to another Member or to such Member’s directors, managers, partners, employees, counsel, financial and tax advisors, lenders, rating agencies and analysts for a valid business purpose, (B) in the case of a Member who is also a Manager or officer of the Company, in carrying out its duties in the best interests of the Company and (C) any potential bona fide transferee of a Membership Interest; provided that such potential transferee agrees to maintain the confidentiality of the confidential information on terms no less restrictive than those set forth in this Section 14.17) or (ii) used for anything other than as necessary and appropriate in carrying out the Business of the Company. Any recipient of such confidential information shall be advised of its confidential status, and the disclosing Member shall be responsible for any breaches hereof by any Person to whom such Member provides confidential information. The restrictions set forth herein do not apply to (i) information that is or becomes available to such Member on a non-confidential basis from a source (other than the Company) that is not known by such Member to be bound by a confidentiality agreement, (ii) information that was known by such Member prior to disclosure by or at the direction of the Company; (iii) information that is independently developed by such Member without violating any obligations under this Agreement; or (iv) any disclosures required by a national stock exchange, the rules or regulations of the U.S. Securities and Exchange Commission, applicable law or regulatory authority with respect to a Member or its Affiliates. Notwithstanding the foregoing, neither Section 14.15 nor this Section 14.17 shall be construed to restrict a Member or its Affiliate from disclosing information with respect to its investment in the Company in the ordinary course of its business and pursuant to its customary investor relations process; provided the Members agree to coordinate in advance with respect to any disclosure of material non-public information pertaining to the Company or its financial or operational performance that a Member knows, or reasonably should know, would be sensitive to another Member or would otherwise trigger additional disclosures or compliance filings by another Member.

14.18. Headings

The article and section headings contained in this Agreement are inserted for convenience only and will not affect in any way the meaning or interpretation of this Agreement.

14.19.Construction

This Agreement has been freely and fairly negotiated among the Members. If an ambiguity or question of intent or interpretation arises, this Agreement will be construed as if drafted jointly by the Members and no presumption or burden of proof will arise favoring or disfavoring any Member because of the authorship of any provision of this Agreement. Any reference to any law will be deemed to refer to such law as amended and all rules and regulations promulgated thereunder, unless the context requires otherwise. The words “include,” “includes,” and “including” will be deemed to be followed by “without limitation.” Pronouns in masculine,

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feminine, and neuter genders will be construed to include any other gender, and words in the singular form will be construed to include the plural and vice versa, unless the context otherwise requires. The words “this Agreement,” “herein,” “hereof,” “hereby,” “hereunder,” and words of similar import refer to this Agreement as a whole and not to any particular subdivision unless expressly so limited. The Members intend that each representation, warranty, and covenant contained herein will have independent significance. If any Member has breached any representation, warranty, or covenant contained herein in any respect, the fact that there exists another representation, warranty or covenant relating to the same subject matter (regardless of the relative levels of specificity) which the Member has not breached will not detract from or mitigate the fact that the Member is in breach of the first representation, warranty, or covenant. Time is of the essence in the performance of this Agreement.

14.20. Fair Market Value Determination

(a)If the Fair Market Value of a Membership Interest is to be determined for purposes of this Agreement, the affected Members shall first seek to determine such Fair Market Value by mutual written agreement within a reasonable time, not to exceed thirty (30) Days. If the affected Members cannot reach a mutual written agreement as set forth in the foregoing sentence, the process in Section 14.20(b) to determine such Fair Market Value shall control.

(b)Appraisal. Upon expiration of the thirty (30)-Day period set forth in Section 14.20(a) above, the affected Members seeking to determine Fair Market Value of a Membership Interest (each an “Affected Member,” and collectively, the “Affected Members”), shall request in writing (the “FMV Notice”) that the Board appoint an independent third party appraisal firm of nationally recognized standing having recognized expertise in the valuation of natural gas transmission pipelines (“Appraiser”) to make such determination. Within ten (10) Days after receipt of the FMV Notice, the Board will engage an Appraiser to determine the Fair Market Value of the Membership Interest at issue. Within thirty (30) Days of being appointed, the Appraiser will deliver to the Board and the Affected Members a detailed report (including all assumptions and relevant information employed in making such determination) setting forth its calculation of the Fair Market Value of the Membership Interest (the “FMV Report”) at issue, and such report and the determination of Fair Market Value set forth therein shall be final and binding on the Affected Members. The cost of such FMV Report and all fees and expenses of the Appraiser shall be paid in equal portions by the Affected Members. Each Affected Member shall cooperate in good faith with the Appraiser, and will provide the Appraiser with all information and documentation reasonably requested by it in connection with preparation of the FMV Report.

14.21.Counterparts; Effectiveness

This Agreement may be executed in two or more counterparts, each of which will be deemed an original but all of which together will constitute one and the same instrument. This Agreement will become effective when one or more counterparts have been signed by each of the Members and delivered to the other Members, which delivery may be made by exchange of

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copies of the signature page by facsimile or electronic transmission. For purposes of determining whether a party has signed this Agreement or any document contemplated hereby or any amendment or waiver hereof, a handwritten signature on a paper document or a facsimile or electronic transmission of a handwritten original signature will constitute a signature.

14.22. Adjustment for Inflation

The amount set forth in Section 6.7(b)(i)(5) shall, without requiring any amendment to this Agreement, be automatically adjusted for inflation effective as of January 1 of each calendar year by multiplying such amount by a fraction, (i) the numerator of which is the average monthly United States Department of Labor Statistics Consumer Price Index for All Urban Consumers (CPI-U) published by the Bureau of Labor Statistics, United States Department of Labor, Washington, DC (http://www.bls.gov/cpi) (“CPI”) for the twelve (12) month period immediately preceding such January 1, and (ii) the denominator of which is the average monthly CPI for the twelve (12) month period immediately preceding the Effective Date; provided that such adjusted amount shall in no event be less than $200,000.

14.23. Legal Representation

Each Member hereby acknowledges that the Member has been advised that the Member should seek and has had the opportunity to seek independent legal counsel to review this Agreement and the other Transaction Documents on the Member’s behalf and to obtain the advice of such legal counsel relating to such documentation. Each Member further acknowledges and agrees that with respect to such documentation, unless otherwise specifically acknowledged and agreed to in writing by the Company, the Members and the applicable independent legal counsel: (a) the law firm of Locke Lord LLP is legal counsel solely to Duke and (b) the law firm of Hogan Lovells US LLP is legal counsel solely to Dominion and the Operator with respect to the Transaction Documents.

[Signature page follows]

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IN WITNESS WHEREOF, the Members hereby duly execute and deliver this Agreement in counterparts, effective as of the Effective Date.

DUKE ENERGY ACP, LLC

By:     /s/ Phillip C. Grigsby

Name: Phillip C. Grigsby

Title: President

PIEDMONT ACP COMPANY, LLC

By:     /s/ Thomas E. Skains

Name: Thomas E. Skains

Title: Chairman and President

DOMINION ATLANTIC COAST PIPELINE, LLC

By:     /s/ Diane Leopold

Name: Diane Leopold

Title: President

MAPLE ENTERPRISE HOLDINGS, INC.

By:     /s/ Henry P. Linginfelter

Name: Henry P. Linginfelter

Title: Executive Vice President

Limited Liability Company Agreement
Signature Page

ANNEX A

TRANSFEREE TAX REPRESENTATIONS

The transferee is the sole beneficial owner of the interest in the Company to be registered in its name (the “Membership Interest”);

1.such transferee either (i) is not a grantor trust, partnership or S corporation for U.S. federal income tax purposes or (ii) was not formed with, and will not be used for, a principal purpose of permitting the Company to satisfy the 100 member limitation contained in Treasury Regulations Section 1.7704-1(h)(1)(ii); ¹

2.such transferee did not acquire, and will not transfer, its Membership Interest through (a) a national, non-U.S., regional, local or other securities exchange, (b) PORTAL or (c) over-the-counter market (including an interdealer quotation system that regularly disseminates firm buy or sell quotations by identified brokers or dealers by electronic means or otherwise);

3.such transferee did not acquire, and will not transfer, its Membership Interest from, to or through (a) a person, such as a broker or dealer, that makes a market in, or regularly quotes prices for, the Membership Interest or (b) a person that regularly makes available to the public (including customers or subscribers) bid or offer quotes with respect to the Membership Interest and stands ready to effect, buy or sell transactions at the quoted prices for itself or on behalf of others; and

4.such transferee will only transfer its Membership Interest to a buyer who provides representations similar to these. These representations may from time to time be revised by the Board on the advice of counsel.

¹Paragraph 1 not required to be included if transferee is an Affiliate of the transferor Member.

ANNEX A

ANNEX B

ACCESSION AGREEMENT

This Accession Agreement (this “Accession”) is executed by the undersigned (the “Transferee”) for the benefit of Atlantic Coast Pipeline,LLC, a Delaware limited liability company (the “Company”) pursuant to the terms of the Limited Liability Company Agreement of the Company, dated as of ___________ ___, 2014, and all Annexes, Exhibits and Schedules thereto, together with all amendments thereto, copies of which are attached hereto as Exhibit A and are incorporated herein by reference (collectively, the “Agreement”). By the execution of this Accession, the Transferee hereby agrees as follows:

1.Capitalized terms used but not otherwise defined in this Accession have the meanings assigned to such terms in the Agreement. Transferee acknowledges that Transferee is acquiring certain Membership Interests in the Company which are subject to the terms and conditions set forth in the Agreement and the certificate of formation of the Company, a copy of which certificate of formation is attached hereto as Exhibit B (the “Certificate”).

2.Transferee (a) agrees that the Membership Interests acquired by Transferee shall be bound by and subject to the terms of the Agreement and the Certificate and (b) accedes to and agrees to be bound by the Certificate and the Agreement with the same force and effect as if the undersigned was a party thereto. Transferee’s execution of this Accession shall not constitute admission of the Transferee as a Member of the Company unless and until Transferee has complied with all of the requirements of the Agreement.

3.This Accession may be delivered by electronic transmission, including by facsimile or in portable document format, and such delivery shall be deemed to be an original. This Accession shall be governed by the laws of the State of Delaware without regard to principles of conflicts of law.

4.This Accession shall be binding upon and inure to the benefit of Transferee and the Company and their respective heirs, executors, administrators, successors, legal representatives and permitted assigns.

5.Any notice required or permitted by the Accession or the Agreement shall be given to Transferee at the address listed under the Transferee’s signature below.

[Remainder of page intentionally left blank. Signature page follows.]

ANNEX B

IN WITNESS WHEREOF, the undersigned hereby executes this Accession as of _________, 20__.

TRANSFEREE:

[____________________________]

By:

Name:

Title:

Notice    Address:

ANNEX B

ANNEX C

FORM OF CAPITAL CALL NOTICE

[Letterhead of the Company]

Date: ______________

[The Members]

Ladies and Gentlemen:

Reference is made to that certain Limited Liability Company Agreement dated as of September 2, 2014 by and among Dominion Atlantic Coast Pipeline, LLC, Duke Energy ACP, LLC, Piedmont ACP Company, LLC and Maple Enterprise Holdings, Inc. (the “LLC Agreement”). Capitalized terms used herein and not otherwise defined shall have the meaning given to such terms in the LLC Agreement.

This Capital Call Notice is delivered pursuant to Section 4.2(b) of the LLC Agreement. The aggregate amount of Capital Contributions from the Members due on the Capital Contribution Date set forth below is equal to $_________________. The amount due from each Member on such Capital Contribution Date is as follows:

[Member]:$____________

[Member]:$____________

[Member]:$____________

[Member]:$____________

and all such amounts shall be paid to the Company’s account on the Capital Contribution Date in Dollars in immediately available funds.

The purpose of such Capital Contribution is to fund [specify purpose and relevant budget].

The Capital Contribution Date, by which such Capital Contributions shall be made is [specify Business Day that is at least 20 days from the date on which this instruction is given].

ANNEX C

Wire instructions are as follows:

For credit to the Company’s account:

Account No.:

__________:

Attn:

Yours sincerely,

ATLANTIC COAST PIPELINE, LLC

By: _________________________________

Name:

Title: Authorized Representative

ANNEX C

EXHIBIT 2.1

INITIAL PRECEDENT AGREEMENTS

Agreement	Capacity (in Dt per day)
Precedent Agreement for Firm Transportation Services Atlantic Coast Pipeline, LLC to be entered into between the Company and Duke Energy Carolinas, LLC.	452,750
Precedent Agreement for Firm Transportation Services Atlantic Coast Pipeline, LLC to be entered into between the Company and Duke Energy Progress, Inc.	272,250
Precedent Agreement for Firm Transportation Services Atlantic Coast Pipeline, LLC to be entered into between the Company and Piedmont Natural Gas Company, Inc.	160,000
Precedent Agreement for Firm Transportation Services Atlantic Coast Pipeline, LLC to be entered into between the Company and Public Service Company of North Carolina, Inc.	100,000
Precedent Agreement for Firm Transportation Services Atlantic Coast Pipeline, LLC to be entered into between the Company and Virginia Natural Gas, Inc.	75,000
Precedent Agreement for Firm Transportation Services Atlantic Coast Pipeline, LLC to be entered into between the Company and Virginia Power Services Energy Corp., Inc.	300,000

EXHIBIT 2.1

EXHIBIT 3.1

MEMBER ADDRESSES, CAPITAL CONTRIBUTIONS, AND PERCENTAGE INTERESTS

Name and Addressesof Members	CapitalContributions	Initial Percentage Interest
Duke Energy ACP, LLC 550 South Tryon Charlotte, NC 28202 Attention: Phillip C. Grigsby Facsimile: E-mail:	$3,684,000	40%
Piedmont ACP Company, LLC 4720 Piedmont Row Drive Charlotte, NC 28210 Attention: Karl W. Newlin Facsimile: E-mail:	$911,000	10%
Dominion Atlantic Coast Pipeline LLC 707 East Main Street, 19th Floor Richmond, VA   23219 Attention: Anne E. Bomar Facsimile: E-mail:	0	45%
Maple Enterprise Holdings, Inc. 10 Peachtree Place, NE Atlanta, GA 30309 Attention: Hank Linginfelter Facsimile: E-mail:	$460,500	5%

EXHIBIT 3.1

EXHIBIT 4.4

PRE-EFFECTIVE EXPENDITURES

Member	Pre-Effective Expenditures ($)
Duke Energy ACP, LLC	$0
Piedmont ACP Company, LLC	$10,000
Dominion Atlantic Coast Pipeline, LLC	$9,200,000
Maple Enterprise Holdings, Inc.	$0

EXHIBIT 4.4

EXHIBIT 6.3(a)

DESIGNATED MANAGERS

I.Duke Manager(s)

Phillip C. Grigsby

Duke Alternate Managers

Lance C. Stotts

II.Piedmont Manager(s)

Karl W. Newlin

Piedmont Alternative Managers

Franklin H. Yoho

III.Dominion Manager(s)

Anne E. Bomar

Dominion Alternate Managers

Donald R. Raikes

IV.AGL Manager(s)

Charles Rawson

AGL Alternate Managers

Tim Sherwood

Initial Chairman:Anne E. Bomar

EXHIBIT 6.3(a)

EXHIBIT 6.9(c)

OFFICERS

The initial officers of the Company shall be as follows:

Vice President - Phillip C. Grigsby

Vice President - Anne E. Bomar

Vice President - Karl W. Newlin

Vice President - Henry P. Linginfelter

EXHIBIT 6.9(c)

EXHIBIT 14.9

AFFILIATE CONTRACTS

1. The Initial Precedent Agreements

2. The Operations Agreement

3. A capacity lease agreement between the Company and Piedmont or its Affiliate for the leasing of pipeline transportation capacity on Piedmont’s or its Affiliate’s system.

4. A firm transportation service agreement between the Company and Dominion Transmission, Inc. for up to 1,500,000 Dt per day.

EXHIBIT 14.9

SCHEDULE A

INITIAL FACILITIES

The Initial Facilities will consist of the following:

a. approximately 294 miles of 42” diameter pipeline;

b. approximately 178 miles of 36” diameter pipeline;

c. approximately 75 miles of 20” diameter pipeline;

d. approximately 108,275 Hp of gas fired compression;

e. approximately eight measurement and regulation stations, as may be required to meet obligations established under precedent agreements with customers to be served by the Initial Facilities, including:

i. a 1,600,000 Dt/d receipt interconnection with Dominion Transmission, Inc. at Marts Junction, located in Lewis County, West Virginia;

ii. a 350,000 Dt/d delivery interconnection with Columbia Gas Transmission Corporation located in Randolph County, West Virginia;

iii. a 1,450,000 Dt/d bi-directional interconnection with Transcontinental Gas Pipe Line Corporation located in Buckingham County, Virginia;

iv. a 350,000 Dt/d delivery interconnection with The Virginia Electric and Power Company located in Brunswick County, Virginia;

v. a 350,000 Dt/d delivery interconnection with Virginia Natural Gas Company located in Chesapeake County, Virginia;

vi. a 1,085,000 Dt/d delivery interconnection with Piedmont Natural Gas Company, Inc. (“Piedmont”) located in Johnston County NC;

vii. a 200,000 Dt/d delivery interconnection with Piedmont located in Cumberland County, North Carolina;

viii. a 985,000 Dt/d delivery interconnection with Piedmont located in Robeson County, North Carolina;

f. a contract with Dominion Transmission, Inc. for sufficient firm transportation service to provide receipt point access and deliveries to Marts Junction, under Precedent Agreements with customers to be served by the Initial Facilities;

g. a lease of capacity from Piedmont for sufficient quantities to provide deliveries under a Precedent Agreement with Public Service Company of North Carolina, Inc.; and

h. such other ancillary and/or related facilities, equipment, services and/or leases authorized pursuant to the FERC Certificate for the Initial Facilities.

SCHEDULE A

SCHEDULE B

MINIMUM INSURANCE COVERAGE

The Operator shall cause the Company to maintain at least the following types of insurance in amounts and with deductibles, terms and conditions, and effective dates as determined by the Members.

General/Excess Liability Insurance

Commercial Automobile Insurance - For any owned, hired, rented or non-owned automotive equipment.

Umbrella Liability Insurance

Property Insurance

Business Interruption Insurance - At Company’s option

Workers Compensation Insurance - For any employees if required by law

Directors and Officers Liability Insurance - At Company’s option

SCHEDULE B

EX-12

									Exhibit 12
PIEDMONT NATURAL GAS COMPANY, INC. AND SUBSIDIARIES
Computation of Ratio of Earnings to Fixed Charges
For Fiscal Years Ended October 31, 2010 through 2014
(in thousands except ratio amounts)
	2014		2013		2012		2011		2010
Earnings:
Pre-tax income from continuing operations	$	205,116	$	193,081	$	171,714	$	158,320	$	153,687
Distributed income of equity investees	28,772		26,839		24,962		25,714		47,094
Fixed charges	72,602		57,549		46,978		54,239		55,567
Total Adjusted Earnings	$	306,490	$	277,469	$	243,654	$	238,273	$	256,348
Fixed Charges:
Interest	$	69,876	$	54,840	$	43,908	$	51,639	$	53,226
Amortization of debt expense	1,171		1,029		1,401		1,063		647
Amortization of loss - reacquired debt	238		238		238		99		—
One-third of rental expense	1,317		1,442		1,431		1,438		1,694
Total Fixed Charges	$	72,602	$	57,549	$	46,978	$	54,239	$	55,567
Ratio of Earnings to Fixed Charges	4.22		4.82		5.19		4.39		4.61

EX-21

Exhibit 21

List of Subsidiaries

October 31, 2014

Name	State of Incorporation	Identity of Business Unit
Subsidiaries of Piedmont Natural Gas Company, Inc.:
Piedmont Energy Partners, Inc.	North Carolina	Holding Company
Piedmont Hardy Storage Company, LLC	North Carolina	Member of Hardy Storage Company, LLC
Piedmont ENCNG Company, LLC	North Carolina	Member of Piedmont Hardy Storage Company, LLC
Subsidiaries of Piedmont Energy Partners, Inc.:
Piedmont Interstate Pipeline Company	North Carolina	Member of Pine Needle LNG Company, L.L.C.
Piedmont Intrastate Pipeline Company	North Carolina	Member of Cardinal Pipeline Company, L.L.C.
Piedmont Energy Company	North Carolina	Member of SouthStar Energy Services LLC
Piedmont Constitution Pipeline Company, LLC	North Carolina	Member of Constitution Pipeline Company, LLC
Subsidiary of Piedmont ENCNG Company, LLC:
Piedmont ACP Company, LLC	North Carolina	Member of Atlantic Coast Pipeline, LLC

EX-23.1

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement Nos. 333-184895 and 333-196561 on Form S-3, and in Registration Statement Nos. 333-76140, 333-132738, 333-161888 and 333-166298 on Form S-8, and in Post-Effective Amendment No. 1 to Registration Statement No. 333-76140 on Form S-8 of our reports dated December 23, 2014, relating to the consolidated financial statements of Piedmont Natural Gas Company, Inc. and subsidiaries, and the effectiveness of Piedmont Natural Gas Company, Inc. and subsidiaries’ internal control over financial reporting, appearing in this Annual Report on Form 10-K of Piedmont Natural Gas Company, Inc. for the year ended October 31, 2014.

/s/ Deloitte & Touche LLP

Charlotte, North Carolina

December 23, 2014

EX-31.1

Exhibit 31.1

CERTIFICATION

I, Thomas E. Skains, certify that:

1. I have reviewed this Annual Report on Form 10-K of Piedmont Natural Gas Company, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	December 23, 2014	/s/ Thomas E. Skains
		Thomas E. Skains
		Chairman of the Board, President
		and Chief Executive Officer
		(Principal Executive Officer)

EX-31.2

Exhibit 31.2

CERTIFICATION

I, Karl W. Newlin, certify that:

1. I have reviewed this Annual Report on Form 10-K of Piedmont Natural Gas Company, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	December 23, 2014	/s/ Karl W. Newlin
		Karl W. Newlin
		Senior Vice President and Chief Financial Officer
		(Principal Financial Officer)

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY

ACT OF 2002

In connection with the Annual Report of Piedmont Natural Gas Company, Inc. (the “Company”), on Form 10-K for the period ended October 31, 2014, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Thomas E. Skains, Chairman of the Board, President and Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that to my knowledge:

(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

December 23, 2014

/s/ Thomas E. Skains

Thomas E. Skains

Chairman of the Board, President and Chief Executive Officer

A signed original of this written statement required by Section 906, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY

ACT OF 2002

In connection with the Annual Report of Piedmont Natural Gas Company, Inc. (the “Company”), on Form 10-K for the period ended October 31, 2014, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Karl W. Newlin, Senior Vice President and Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that to my knowledge:

(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

December 23, 2014

/s/ Karl W. Newlin

Karl W. Newlin

Senior Vice President and Chief Financial Officer

A signed original of this written statement required by Section 906, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

XML

Selected Quarterly Financial Data (Tables)

12 Months Ended

Oct. 31, 2014

Quarterly Financial Data [Abstract]

Schedule of Quarterly Financial Information [Table Text Block]

Selected Quarterly Financial Data (In thousands except per share amounts) (Unaudited)

										Earnings (Loss)
							Net			Per Share of
	Operating				Operating		Income			Common Stock
	Revenues		Margin		Income		(Loss)			Basic			Diluted
Fiscal Year 2014
January 31	$	657,733	$	261,512	$	102,319	$	97,572		$	1.27		$	1.26
April 30	462,247		211,523		67,299		62,540			0.80			0.80
July 31	164,187		104,847		3,254		(7,344		)	(0.09		)	(0.09		)
October 31	185,821		112,326		6,993		(8,967		)	(0.11		)	(0.11		)
Fiscal Year 2013
January 31	$	515,875	$	231,623	$	86,213	$	85,923		$	1.19		$	1.18
April 30	399,411		183,856		51,504		55,790			0.74			0.74
July 31	162,943		97,000		591		(2,293		)	(0.03		)	(0.03		)
October 31	200,000		109,011		5,886		(5,003		)	(0.07		)	(0.07		)

XML

Income Taxes (Details) (USD $)	12 Months Ended
	Oct. 31, 2014	Oct. 31, 2013	Oct. 31, 2012	Oct. 31, 2011	Jul. 31, 2013
NC Tax Law [Line Items]
Non Operating Income Tax Expense Benefit	$ 11,642,000	$ 8,612,000	$ 9,116,000
Regulatory Liabilities	604,829,000	541,897,000
Effective Income Tax Rate Reconciliation, Amount [Abstract]
Federal taxes at 35%	83,517,000	77,127,000	69,322,000
State income taxes, net of federal benefit	10,389,000	8,506,000	8,624,000
Amortization of investment tax credits	(209,000)	(267,000)	(334,000)
Other, net	1,121,000	580,000	605,000
Total	94,818,000	85,946,000	78,217,000
Deferred tax assets:
Benefit of loss carryforwards	39,532,000	66,087,000
Revenues and cost of gas	4,960,000	0
Employee benefits and compensation	16,547,000	13,834,000
Revenue requirement	20,320,000	19,062,000
Utility plant	5,631,000	10,386,000
Other	12,869,000	12,796,000
Total deferred tax assets	99,859,000	122,165,000
Valuation allowance	(505,000)	(505,000)	(505,000)	(505,000)
Total deferred tax assets, net	99,354,000	121,660,000
Deferred tax liabilities:
Utility Plant	724,172,000	652,822,000
Revenues and cost of gas	4,340,000	21,257,000
Equity Method Investments	42,998,000	38,710,000
Deferred costs	65,828,000	59,221,000
Other	18,065,000	18,324,000
Total Deferred Tax Liabilities	855,403,000	790,334,000
Net Deferred Income Tax Liabilities	756,049,000	668,674,000
Valuation Allowance [Abstract]
Balance at beginning of year	505,000	505,000	505,000	505,000
Credited to income tax expense	0	0	0
Balance at end of year	505,000	505,000	505,000	505,000
Unrecognized Tax Benefits	0	0
Tax Law 2013 [Member] | State and Local Jurisdiction [Member] | North Carolina
NC Tax Law [Line Items]
Number Of Additional Rate Reductions	2
Rate Reduction Percentage	1.00%
Non Operating Income Tax Expense Benefit	3,000,000	(1,000,000)
Tax Law 2013 [Member] | State and Local Jurisdiction [Member] | Tax Year 2013 [Member] | North Carolina
NC Tax Law [Line Items]
Statutory Tax Rate					6.90%
Tax Law 2013 [Member] | State and Local Jurisdiction [Member] | Tax Year 2014 [Member] | North Carolina
NC Tax Law [Line Items]
Statutory Tax Rate					6.00%
Tax Law 2013 [Member] | State and Local Jurisdiction [Member] | Tax Year 2015 [Member] | North Carolina
NC Tax Law [Line Items]
Statutory Tax Rate					5.00%
Deferred Income Tax Charge [Member] | Tax Law 2013 [Member] | State and Local Jurisdiction [Member] | North Carolina
NC Tax Law [Line Items]
Adjustment To Noncurrent Deferred Income Tax Balances		25,000,000
Regulatory Liabilities	$ 27,000,000	$ 24,000,000

XML

Commitment & Contingencies - Long Term Contracts (Details) (Maximum [Member])	12 Months Ended
	Oct. 31, 2014
Pipeline And Storage Capacity Contracts [Member]
Long-term Purchase Commitment [Line Items]
Long-term Purchase Commitment, Time Period	21 years
Gas Supply Contracts [Member]
Long-term Purchase Commitment [Line Items]
Long-term Purchase Commitment, Time Period	3 years
Telecommunications And Technology Outsourcing Contracts [Member]
Long-term Purchase Commitment [Line Items]
Long-term Purchase Commitment, Time Period	5 years

XML

Equity Method Investments (Details) (USD $)	12 Months Ended			0 Months Ended	1 Months Ended
	Oct. 31, 2014	Oct. 31, 2013	Oct. 31, 2012	Jul. 01, 2013	Sep. 30, 2013	Jun. 30, 2013
Schedule of Equity Method Investments [Line Items]
Retained Earnings, Undistributed Earnings from Equity Method Investees	$ 0
Capital contributions to or payments to acquire equity method investments	37,642,000	41,348,000	3,566,000
Cardinal Pipeline Company [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	21.49%
Equity Method Investment, Description of Principal Activities	Cardinal owns and operates an intrastate natural gas pipeline in North Carolina and is regulated by the NCUC. Cardinal has firm, long-term service agreements with local distribution companies for 100% of the firm transportation capacity on the pipeline, of which Piedmont subscribes to approximately 53%. Cardinal is dependent on the Williams – Transco pipeline system to deliver gas into its system for service to its customers.
Pipeline Subscription Capacity Percentage	100.00%
Pipeline Transportation Capacity Subscribed	53.00%
Summarized Financial Information Percentage	100.00%	100.00%	100.00%
Transportation or gas storage costs	8,825,000	8,775,000	6,613,000
Trade accounts payable	747,000	755,000
Equity Method Investment, Summarized Financial Information [Abstract]
Current assets	8,856,000	15,179,000
Noncurrent assets	111,881,000	116,414,000
Current liabilities	1,468,000	2,637,000
Noncurrent liabilities	45,402,000	45,273,000
Revenues	16,705,000	17,649,000	16,165,000
Gross profit	16,705,000	17,649,000	16,165,000
Income before income taxes	8,042,000	9,361,000	10,433,000
Pine Needle Company [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	45.00%					40.00%
Equity Method Investment, Description of Principal Activities	Pine Needle LNG Company, L.L.C. (Pine Needle), a North Carolina limited liability company, owns an interstate LNG storage facility in North Carolina and is regulated by the FERC. Pine Needle has firm, long-term service agreements for 100% of the storage capacity of the facility, of which Piedmont subscribes to approximately 64%.
Pipeline Subscription Capacity Percentage	100.00%
Pipeline Transportation Capacity Subscribed	64.00%
Capital contributions to or payments to acquire equity method investments				2,900,000
Summarized Financial Information Percentage	100.00%	100.00%	100.00%
Transportation or gas storage costs	11,364,000	11,098,000	10,410,000
Trade accounts payable	989,000	940,000
Equity Method Investment, Additional Information	Effective July 1, 2013, we acquired Hess Corporation’s 5% membership interest in Pine Needle for $2.9 million,which increased our membership interest from 40% to 45%.
Equity Method Investment, Summarized Financial Information [Abstract]
Current assets	8,812,000	9,225,000
Noncurrent assets	70,837,000	74,710,000
Current liabilities	38,029,000	3,531,000
Noncurrent liabilities	0	35,391,000
Revenues	18,025,000	16,810,000	16,390,000
Gross profit	18,025,000	16,810,000	16,390,000
Income before income taxes	6,011,000	5,804,000	5,832,000
Additional Equity Method Ownership Percentage Acquired				5.00%
South Star Energy Services [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	15.00%
Equity Method Investment, Description of Principal Activities	SouthStar primarily sells natural gas in the unregulated retail gas market to residential, commercial and industrial customers in the eastern United States, primarily in Georgia and Illinois. We account for our investment in SouthStar using the equity method, as we have board representation with equal voting rights on significant governance matters and policy decisions, and thus, exercise significant influence over the operations of SouthStar.
Capital contributions to or payments to acquire equity method investments					22,500,000
Summarized Financial Information Percentage	100.00%	100.00%	100.00%
Operating revenues	3,541,000	3,291,000	2,442,000
Trade accounts receivable	460,000	441,000
Equity Method Investment, Additional Information	In September 2013, GNGC contributed its retail natural gas marketing assets and customer accounts located in Illinois. AGL acquired these retail assets and customers from Nicor Inc. in December 2011 and additional retail natural gas assets and customer accounts in a separate transaction in June 2013. We made an additional $22.5 million capital contribution to SouthStar, maintaining our 15% equity ownership, related to this transaction.
Equity Method Investment, Summarized Financial Information [Abstract]
Current assets	196,286,000	199,425,000
Noncurrent assets	143,420,000	147,571,000
Current liabilities	51,435,000	76,346,000
Noncurrent liabilities	83,000	31,000
Revenues	845,695,000	639,426,000	585,291,000
Gross profit	234,581,000	174,993,000	161,122,000
Income before income taxes	136,569,000	102,805,000	94,631,000
Hardy Storage [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	50.00%
Equity Method Investment, Description of Principal Activities	Hardy Storage owns and operates an underground interstate natural gas storage facility located in Hardy and Hampshire Counties, West Virginia, that is regulated by the FERC. Hardy Storage has firm, long-term service agreements for 100% of the storage capacity of the facility, of which Piedmont subscribes to approximately 40%.
Summarized Financial Information Percentage	100.00%	100.00%	100.00%
Transportation or gas storage costs	9,461,000	9,702,000	9,702,000
Trade accounts payable	774,000	808,000
Storage Capacity Subscription Percentage	100.00%
Storage Capacity Subscribed	40.00%
Equity Method Investment, Summarized Financial Information [Abstract]
Current assets	12,644,000	7,641,000
Noncurrent assets	157,861,000	161,282,000
Current liabilities	17,316,000	12,378,000
Noncurrent liabilities	78,830,000	87,184,000
Revenues	23,804,000	24,375,000	24,359,000
Gross profit	23,804,000	24,375,000	24,359,000
Income before income taxes	10,497,000	10,582,000	9,939,000
Constitution Pipeline Company [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	24.00%
Equity Method Investment, Description of Principal Activities	The purpose of the joint venture is to develop, construct, own and operate approximately 120 miles of interstate natural gas pipeline and related facilities connecting shale natural gas supplies and gathering systems in Susquehanna County, Pennsylvania, to the Iroquois Gas Transmission and Tennessee Gas Pipeline systems in New York. We have committed to fund an amount in proportion to our ownership interest for the development and construction of the new pipeline, which is expected to cost approximately $680 million at the project level. As of October 31, 2014, our fiscal year contributions were $37.6 million, with our total equity contributions for the project totaling $53.5 million to date. On December 2, 2014, FERC issued a certificate of public convenience and necessity approving construction of the Constitution pipeline. The target in-service date of the project is late 2015 or 2016. The capacity of the pipeline is 100% subscribed under fifteen year service agreements with two Marcellus producer-shippers with a negotiated rate structure.
Pipeline Subscription Capacity Percentage	100.00%
Capital contributions to or payments to acquire equity method investments	37,600,000
Total Contributions To Equity Method Investments For Project	53,500,000
Summarized Financial Information Percentage	100.00%	100.00%
Estimated Pipeline Development And Construction Costs	730,000,000
Pipeline Target In Service Date	late 2015 or 2016
Equity Method Investment, Summarized Financial Information [Abstract]
Current assets	11,273,000	10,944,000
Noncurrent assets	219,208,000	62,438,000
Current liabilities	7,667,000	7,960,000
Noncurrent liabilities	0	0
Revenues	0	0
Gross profit	0	0
Income before income taxes	10,091,000	3,459,000
Atlantic Coast Pipeline [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	10.00%
Equity Method Investment, Description of Principal Activities	ACP intends to construct, operate and maintain a 550 mile natural gas pipeline, with associated compression, from West Virginia through Virginia into eastern North Carolina. The pipeline is proposed to provide interstate natural gas transportation services for Marcellus and Utica gas supplies into southeastern markets. ACP, which is regulated by the FERC, will be designed with an initial capacity of 1.5 billion cubic feet per day with a target in-service date of late 2018. The capacity of ACP is substantially subscribed by the members of ACP, other utilities and related companies under twenty-year contracts.
Capital contributions to or payments to acquire equity method investments	0
Pipeline Target In Service Date	late 2018
Long-term Purchase Commitment, Period	20 years
Equity Method Investment, Summarized Financial Information [Abstract]
Estimated Percentage Project Financing	70.00%
Atlantic Coast Pipeline [Member] | Minimum [Member]
Schedule of Equity Method Investments [Line Items]
Estimated Pipeline Development And Construction Costs	4,500,000,000
Atlantic Coast Pipeline [Member] | Maximum [Member]
Schedule of Equity Method Investments [Line Items]
Estimated Pipeline Development And Construction Costs	$ 5,000,000,000

XML

Financial Instruments & Related Fair Value (Details) (USD $)	12 Months Ended
	Oct. 31, 2014 MMBTU	Oct. 31, 2013 MMBTU
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gas Options Total Coverage	29,200,000	25,400,000
Fair Value Measurement Transfers Between Levels Activity	$ 0	$ 0
Derivative Liability	0	0
Derivative Asset, Collateral, Obligation to Return Cash, Offset	0	0
Derivative Liability, Collateral, Right to Reclaim Cash, Offset	0	0
Assets [Abstract]
Derivative Asset	4,898,000	1,834,000
Marketable Securities	3,941,000	3,194,000
Total Recurring Fair Value Assets	8,839,000	5,028,000
Long-term debt, carrying value	1,425,000,000	1,275,000,000
Long-term debt, fair value	1,617,453,000	1,409,892,000
Discount on issuance of notes	570,000	143,000
Current Assets, Gas purchase derivative assets	4,898,000	1,834,000
Gas purchase options	6,162,000	(6,303,000)
Amount Of Gain (Loss) Deferred Under PGA Procedures	6,162,000	(6,303,000)
Percentage Of Annual Gas Purchase Options and All Other Costs Related To Hedging Approved For Recovery Under TIP	1.00%
Concentration Risk [Line Items]
Concentration Risk, Benchmark Description	“Trade accounts receivable” in “Current Assets” in the Condensed Consolidated Balance Sheets
Concentration Risk, Customer	We are exposed to credit risk as a result of transactions for the purchase and sale of natural gas and related products and services and management agreements of our transportation capacity, storage capacity and supply contracts with major companies in the energy industry and within our utility operations serving industrial, commercial, power generation, residential and municipal energy consumers. These transactions principally occur in the eastern, gulf coast and mid-west regions of the United States. We believe that this geographic concentration does not contribute significantly to our overall exposure to credit risk. Credit risk associated with trade accounts receivable for the natural gas distribution segment is mitigated by the large number of individual customers and diversity in our customer base. We enter into contracts with third parties to buy and sell natural gas. A significant portion of these transactions are with, or are associated with, energy producers, utility companies, off-system municipalities and natural gas marketers.
Accounts Receivable [Member]
Concentration Risk [Line Items]
Concentration Risk Amount	3,500,000
Accounts Receivable [Member] | Credit Concentration Risk [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	5.00%
Money Market Funds [Member]
Assets [Abstract]
Marketable Securities	469,000	380,000
Equity Funds [Member]
Assets [Abstract]
Marketable Securities	3,472,000	2,814,000
Fair Value, Inputs, Level 1 [Member]
Assets [Abstract]
Derivative Asset	4,898,000	1,834,000
Total Recurring Fair Value Assets	8,839,000	5,028,000
Fair Value, Inputs, Level 1 [Member] | Money Market Funds [Member]
Assets [Abstract]
Marketable Securities	469,000	380,000
Fair Value, Inputs, Level 1 [Member] | Equity Funds [Member]
Assets [Abstract]
Marketable Securities	3,472,000	2,814,000
Fair Value, Inputs, Level 2 [Member]
Assets [Abstract]
Derivative Asset
Total Recurring Fair Value Assets	0	0
Fair Value, Inputs, Level 2 [Member] | Money Market Funds [Member]
Assets [Abstract]
Marketable Securities
Fair Value, Inputs, Level 2 [Member] | Equity Funds [Member]
Assets [Abstract]
Marketable Securities
Fair Value, Inputs, Level 3 [Member]
Assets [Abstract]
Derivative Asset
Total Recurring Fair Value Assets	0	0
Fair Value, Inputs, Level 3 [Member] | Money Market Funds [Member]
Assets [Abstract]
Marketable Securities
Fair Value, Inputs, Level 3 [Member] | Equity Funds [Member]
Assets [Abstract]
Marketable Securities

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Employee Benefit Plans (Tables)

12 Months Ended

Oct. 31, 2014

General Discussion of Pension and Other Postretirement Benefits [Abstract]

Supplemental Executive Retirement Plans

The funding to the DCR plan accounts for the years ended October 31, 2014 and 2013, and the amounts recorded as liabilities for these deferred compensation plans as of October 31, 2014 and 2013 are presented below.

In thousands	2014		2013
Funding	$	524	$	434
Liability:
Current	214		199
Noncurrent	4,248		3,328

Term Life Insurance Premiums

The cost of these premiums is presented below.

In thousands	2014		2013		2012
Term life policies of certain officers at the vice president level and above	$	30	$	27	$	43
Officers and director-level employees	32		28		25

Schedule of Defined Benefit Plans Disclosures [Table Text Block]

A reconciliation of changes in the plans’ benefit obligations and fair value of assets for the years ended October 31, 2014 and 2013, and a statement of the funded status and the amounts reflected in the Consolidated Balance Sheets for the years ended October 31, 2014 and 2013 are presented below.

	Qualified Pension						Nonqualified Pension						Other Benefits
In thousands	2014			2013			2014			2013			2014			2013
Accumulated benefit obligation at year end	$	252,706		$	230,175		$	5,925		$	4,736		N/A			N/A
Change in projected benefit obligation:
Obligation at beginning of year	$	272,403		$	293,327		$	4,736		$	5,569		$	33,678		$	34,830
Service cost	10,865			12,005			—			—			1,109			1,327
Interest cost	11,781			9,946			200			157			1,448			1,130
Plan amendments	—			—			485			—			—			—
Actuarial (gain) loss	23,646			(24,859		)	956			(540		)	3,734			(1,094		)
Participant contributions	—			—			—			—			805			641
Administrative expenses	(465		)	(534		)	—			—			—			—
Benefit payments	(15,544		)	(17,482		)	(452		)	(450		)	(2,957		)	(3,156		)
Obligation at end of year	302,686			272,403			5,925			4,736			37,817			33,678
Change in fair value of plan assets:
Fair value at beginning of year	300,661			272,337			—			—			25,961			23,663
Actual return on plan assets	31,791			26,340			—			—			1,874			2,848
Employer contributions	20,000			20,000			452			450			2,064			1,965
Participant contributions	—			—			—			—			805			641
Administrative expenses	(465		)	(534		)	—			—			—			—
Benefit payments	(15,544		)	(17,482		)	(452		)	(450		)	(2,957		)	(3,156		)
Fair value at end of year	336,443			300,661			—			—			27,747			25,961
Funded status at year end - over (under)	$	33,757		$	28,258		$	(5,925	)	$	(4,736	)	$	(10,070	)	$	(7,717	)
Noncurrent assets	$	33,757		$	28,258		$	—		$	—		$	—		$	—
Current liabilities	—			—			(521		)	(445		)	—			—
Noncurrent liabilities	—			—			(5,404		)	(4,291		)	(10,070		)	(7,717		)
Net amount recognized	$	33,757		$	28,258		$	(5,925	)	$	(4,736	)	$	(10,070	)	$	(7,717	)
Amounts Not Yet Recognized as a Component
of Cost and Recognized in a Deferred
Regulatory Account:
Unrecognized transition obligation	$	—		$	—		$	—		$	—		$	—		$	—
Unrecognized prior service credit (cost)	15,046			17,243			(439		)	(196		)	—			—
Unrecognized actuarial loss	(103,038		)	(96,338		)	(1,745		)	(820		)	(3,995		)	(354		)
Regulatory asset	(87,992		)	(79,095		)	(2,184		)	(1,016		)	(3,995		)	(354		)
Cumulative employer contributions in
excess of cost	121,749			107,353			(3,741		)	(3,720		)	(6,075		)	(7,363		)
Net amount recognized	$	33,757		$	28,258		$	(5,925	)	$	(4,736	)	$	(10,070	)	$	(7,717	)

Components Of Net Periodic Benefit Cost

Net periodic benefit cost for the years ended October 31, 2014, 2013 and 2012 includes the following components.

	Qualified Pension									Nonqualified Pension									Other Benefits
In thousands	2014			2013			2012			2014			2013			2012			2014			2013			2012
Service cost	$	10,865		$	12,005		$	9,573		$	—		$	—		$	39		$	1,109		$	1,327		$	1,387
Interest cost	11,781			9,946			10,640			200			157			203			1,448			1,130			1,347
Expected return on plan assets	(22,530		)	(21,105		)	(20,289		)	—			—			—			(1,782		)	(1,663		)	(1,551		)
Amortization of transition obligation	—			—			—			—			—			—			—			667			667
Amortization of prior service cost
(credit)	(2,198		)	(2,198		)	(2,198		)	243			81			81			—			—			—
Amortization of net loss	7,685			11,202			5,966			31			161			49			—			—			—
Net periodic benefit cost	5,603			9,850			3,692			474			399			372			775			1,461			1,850
Other changes in plan assets and benefit
obligation recognized through
regulatory asset or liability:
Prior service cost	—			—			—			485			—			—			—			—			—
Net loss (gain)	14,385			(30,094		)	43,945			956			(540		)	629			3,641			(2,278		)	2,209
Amounts recognized as a component of
net periodic benefit cost:
Transition obligation	—			—			—			—			—			—			—			(667		)	(667		)
Amortization of net loss	(7,685		)	(11,202		)	(5,966		)	(31		)	(161		)	(49		)	—			—			—
Prior service (cost) credit	2,198			2,198			2,198			(243		)	(81		)	(81		)	—			—			—
Total recognized in regulatory asset
(liability)	8,898			(39,098		)	40,177			1,167			(782		)	499			3,641			(2,945		)	1,542
Total recognized in net periodic benefit
and regulatory asset (liability)	$	14,501		$	(29,248	)	$	43,869		$	1,641		$	(383	)	$	871		$	4,416		$	(1,484	)	$	3,392

Amortization Recorded As A Regulatory Asset Or Liability Expected Refunds For Defined Benefit Plans

The 2015 estimated amortization of the following items for our plans, which are recorded as a regulatory asset or liability instead of accumulated OCIL discussed above, are as follows.

	Qualified			Nonqualified		Other
In thousands	Pension			Pension		Benefits
Amortization of unrecognized prior service (credit) cost	$	(2,198	)	$	231	$	—
Amortization of unrecognized actuarial loss	8,121			85		29

Benefit Obligation Benchmark Discount Rate

As of October 31, 2014, the benchmark by plan was as follows.

Pension plan	4.13	%
NCNG SERP	3.64	%
Directors’ SERP	3.74	%
Piedmont SERP	3.10	%
OPEB	4.03	%

The Weighted Average Assumptions Used To Determine The Benefit Obligation and Net Periodic Benefit Cost

The weighted average assumptions used in the measurement of the benefit obligation as of October 31, 2014 and 2013 are presented below.

	Qualified Pension				Nonqualified Pension				Other Benefits
	2014		2013		2014		2013		2014		2013
Discount rate	4.13	%	4.55	%	3.69	%	3.98	%	4.03	%	4.44	%
Rate of compensation increase	3.68	%	3.72	%	N/A		N/A		N/A		N/A

The weighted average assumptions used to determine the net periodic benefit cost as of October 31, 2014, 2013 and 2012 are presented below.

	Qualified Pension						Nonqualified Pension
	2014		2013		2012		2014		2013		2012
Discount rate	4.55	%	3.51	%	4.67	%	3.98	%	2.95	%	4.10	%
Expected long-term rate of return on plan assets	7.75	%	8.00	%	8.00	%	N/A		N/A		N/A
Rate of compensation increase	3.72	%	3.76	%	3.78	%	N/A		N/A		N/A
	Other Benefits
	2014		2013		2012
Discount rate	4.44	%	3.34	%	4.36	%
Expected long-term rate of return on plan assets	7.75	%	8.00	%	8.00	%
Rate of compensation increase	N/A		N/A		N/A

Anticipated Employer Contribution To Benefit Plans

We anticipate that we will contribute the following amounts to our plans in 2015.

In thousands
Qualified pension plan *	$	10,000
Nonqualified pension plans	521
MPP plan	1,300
OPEB plan	1,500

* Funded in November 2014.

Expected Benefit Payments For The Next Ten Years

Benefit payments, which reflect expected future service, as appropriate, are expected to be paid for the next ten years ending October 31 as follows.

	Qualified		Nonqualified		Other
In thousands	Pension		Pension		Benefits
2015	$	29,946	$	521	$	2,409
2016	16,794		507		2,449
2017	16,332		491		2,527
2018	19,197		472		2,606
2019	20,685		490		2,682
2020 - 2024	110,459		2,149		14,179

Assumed Health Care Cost Trend Rates

The assumed health care cost trend rates used in measuring the accumulated OPEB obligation for the medical plans for all participants as of October 31, 2014 and 2013 are presented below.

	2014		2013
Health care cost trend rate assumed for next year	7.40	%	7.40	%
Rate to which the cost trend is assumed to decline (the ultimate trend rate)	5.00	%	5.00	%
Year that the rate reaches the ultimate trend rate	2027		2027

Effect of One-Percentage-Point Change in Assumed Health Care Cost Trend Rates

The health care cost trend rate assumptions could have a significant effect on the amounts reported. A change of 1% would have the following effects.

In thousands	1% Increase		1% Decrease
Effect on total of service and interest cost components of net periodic
postretirement health care benefit cost for the year ended October 31, 2014	$	31	$	(32	)
Effect on the health care cost component of the accumulated postretirement
benefit obligation as of October 31, 2014	829		(841		)

Redemption Limitations, Restrictions and Notice Requirements

As stated above, some of our investments for the qualified pension plan have redemption limitations, restrictions and notice requirements which are further explained below.

			Redemptions
	Redemption		Notice
Investment	Frequency	Other Redemption Restrictions	Period
Common trust fund - International growth	Monthly	None	30 days
Hedge fund of funds	Quarterly	Redeemed in whole or part but not less than the minimum redemption amount for each currency. Redemption within one year of purchase is subject to 1.5% redemption fee. Redeemed on “first in first out” basis. None of our investment is subject to the redemption fee. Fund’s Board of Directors may limit or suspend share redemptions until a further notification ending suspension. No such notification has been received as of October 31, 2014.	65 days
Private equity fund of funds	Limited	Investors have only very limited withdrawal rights for specific legal or regulatory reasons. Any transfer of interest will be subject to approval.	(1)
Commodities fund of funds	Monthly	Redemption within one year of purchase is subject to 1% redemption fee. None of our investment is subject to the redemption fee. If 95% or more of the balance is requested, 95% of the balance will be paid within 30 days. Any outstanding balance or interest owed will be paid after the annual audit is complete.	35 days
Bank loans	Daily	None	30 days

(1) The investment cannot be redeemed. We receive distributions only through the liquidation of the underlying assets. The assets are expected to be liquidated over the next 10 to 12 years.

The Qualified Pension and The OPEB Plan's Asset Allocations By Level Within the Fair Value Hierarchy

The OPEB plan’s asset allocations by level within the fair value hierarchy at October 31, 2014 and 2013 are presented below.

	Qualified Pension Plan as of October 31, 2014
				Significant Other Observable Inputs(Level 2)
	Quoted Prices In Active Markets (Level 1)						Significant Unobservable Inputs (Level 3)
										Total Carrying Value			% of Total
In thousands
Cash and cash equivalents	$	27,932		$	435		$	—		$	28,367		8	%
Fixed Income Securities:													45	%
U.S. treasuries	—			27,224			—			27,224			8	%
Long duration bonds	—			48,049			—			48,049			14	%
Corporate bonds	—			49,816			—			49,816			15	%
High yield bonds	8,100			—			—			8,100			3	%
Common trust fund - Bank loans	—			16,187			—			16,187			5	%
Collateralized mortgage
obligations	—			1,035			—			1,035			—	%
Derivatives	48			(49		)	—			(1		)	—	%
Equity Securities:													31	%
Large cap core index	9,982			—			—			9,982			3	%
Large cap value	19,937			—			—			19,937			6	%
Large cap growth	19,745			—			—			19,745			6	%
Small cap value	31,329			—			—			31,329			9	%
Common trust fund - International
growth	—			22,877			—			22,877			7	%
Real Estate:													5	%
Global REIT	16,675			—			—			16,675			5	%
Other Investments:													11	%
Hedge fund of funds	—			19,829			—			19,829			6	%
Private equity fund of funds	—			—			7,158			7,158			2	%
Commodities fund of funds	—			10,134			—			10,134			3	%
Total assets at fair value	$	133,748		$	195,537		$	7,158		$	336,443		100	%
Percent of fair value hierarchy	40		%	58		%	2		%	100		%

The qualified pension plan’s asset allocations by level within the fair value hierarchy at October 31, 2014 and 2013 are presented below.

	Other Benefits as of October 31, 2014
				Significant Other Observable Inputs(Level 2)
	Quoted Prices In Active Markets (Level 1)						Significant Unobservable Inputs (Level 3)
										Total Carrying Value			% of Total
In thousands
Cash and cash equivalents	$	2,590		$	—		$	—		$	2,590		9	%
Fixed Income Securities:													44	%
U.S. treasuries	2,013			—			—			2,013			7	%
Corporate bonds / Other fixed income
securities	10,187			—			—			10,187			37	%
Equity Securities:													42	%
Large cap value	1,269			—			—			1,269			4	%
Large cap growth	1,310			—			—			1,310			5	%
Small cap value	1,336			—			—			1,336			5	%
Small cap growth	1,319			—			—			1,319			5	%
Large cap index	2,532			—			—			2,532			9	%
International blend	3,846			—			—			3,846			14	%
Real Estate:													5	%
Global REIT	1,345			—			—			1,345			5	%
Total assets at fair value	$	27,747		$	—		$	—		$	27,747		100	%
Percent of fair value hierarchy	100		%	—		%	—		%	100		%

	Other Benefits as of October 31, 2013
				Significant Other Observable Inputs(Level 2)
	Quoted Prices In Active Markets (Level 1)						Significant Unobservable Inputs (Level 3)
										Total Carrying Value			% of Total
In thousands
Cash and cash equivalents	$	982		$	—		$	—		$	982		4	%
Fixed Income Securities:													46	%
U.S. treasuries	2,582			—			—			2,582			10	%
Corporate bonds / Other fixed income
securities	9,232			—			—			9,232			36	%
Equity Securities:													45	%
Large cap value	1,327			—			—			1,327			5	%
Large cap growth	1,352			—			—			1,352			5	%
Small cap value	1,331			—			—			1,331			5	%
Small cap growth	1,313			—			—			1,313			5	%
Large cap index	2,384			—			—			2,384			9	%
International blend	4,206			—			—			4,206			16	%
Real Estate:													5	%
Global REIT	1,252			—			—			1,252			5	%
Total assets at fair value	$	25,961		$	—		$	—		$	25,961		100	%
Percent of fair value hierarchy	100		%	—		%	—		%	100		%

	Qualified Pension Plan as of October 31, 2013
				Significant Other Observable Inputs(Level 2)
	Quoted Prices In Active Markets (Level 1)						Significant Unobservable Inputs (Level 3)
										Total Carrying Value			% of Total
In thousands
Cash and cash equivalents	$	5,566		$	156		$	—		$	5,722		2	%
Fixed Income Securities:													38	%
U.S. treasuries	—			24,078			—			24,078			8	%
Long duration bonds	—			34,041			—			34,041			11	%
Corporate bonds	—			42,701			—			42,701			14	%
High yield bonds	14,680			—			—			14,680			5	%
Collateralized mortgage
obligations	—			1,098			—			1,098			—	%
Derivatives	6			(17		)	—			(11		)	—	%
Equity Securities:													43	%
Large cap core index	12,023			—			—			12,023			4	%
Large cap value	16,908			—			—			16,908			6	%
Large cap growth	17,823			—			—			17,823			6	%
Small cap value	30,831			—			—			30,831			10	%
Common trust fund - International
value	—			24,460			—			24,460			8	%
Common trust fund - International
growth	—			27,270			—			27,270			9	%
Real Estate:													5	%
Global REIT	15,042			—			—			15,042			5	%
Other Investments:													12	%
Hedge fund of funds	—			18,571			—			18,571			6	%
Private equity fund of funds	—			—			4,659			4,659			2	%
Commodities fund of funds	—			10,765			—			10,765			4	%
Total assets at fair value	$	112,879		$	183,123		$	4,659		$	300,661		100	%
Percent of fair value hierarchy	37		%	61		%	2		%	100		%

Level 3 Qualified Pension Plan Reconciliation

The following is a reconciliation of the assets in the qualified pension plan that are classified as Level 3 in the fair value hierarchy.

	Private
	Equity Fund
In thousands	of Funds
Balance, October 31, 2012	$	3,522
Actual return on plan assets:
Relating to assets still held at the reporting date	116
Relating to assets sold during the period	61
Purchases, sales and settlements (net)	960
Transfer in/out of Level 3	—
Balance, October 31, 2013	4,659
Actual return on plan assets:
Relating to assets still held at the reporting date	1,031
Relating to assets sold during the period	113
Purchases, sales and settlements (net)	1,355
Transfer in/out of Level 3	—
Balance, October 31, 2014	$	7,158

401(k) Matching Contributions

For the years ended October 31, 2014, 2013 and 2012, we made matching contributions to participant accounts as follows.

In thousands	2014		2013		2012
401(k) matching contributions	$	6,134	$	5,688	$	5,400

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Business Segments (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended								12 Months Ended
	Oct. 31, 2014	Jul. 31, 2014	Apr. 30, 2014	Jan. 31, 2014	Oct. 31, 2013	Jul. 31, 2013	Apr. 30, 2013	Jan. 31, 2013	Oct. 31, 2014 segment	Oct. 31, 2013	Oct. 31, 2012
Segment Reporting Information [Line Items]
Number of Reportable Segments									3
Segment Reporting, Disclosure of Major Customers									0
Segment Reporting Information [Abstract]
Revenues from external customers	$ 185,821	$ 164,187	$ 462,247	$ 657,733	$ 200,000	$ 162,943	$ 399,411	$ 515,875	$ 1,469,988	$ 1,278,229	$ 1,122,780
Margin	112,326	104,847	211,523	261,512	109,011	97,000	183,856	231,623	690,208	621,490	575,446
Operations and maintenance expenses									271,101	253,301	242,701
Depreciation									119,014	112,225	103,210
Operating income (loss) before income taxes									262,655	221,176	194,560
Income from equity method investments									32,753	26,056	23,904
Interest expense									54,686	24,938	20,097
Income before income taxes									238,619	220,363	198,064
Total assets	4,612,700				4,182,423				4,612,700	4,182,423	3,563,887
Equity method investments in non-utility activities	170,171				128,469				170,171	128,469	87,867
Construction expenditures									460,444	599,999	529,576
Segment Reporting Information, Operating Income (Loss) [Abstract]
Segment operating income before income taxes									262,655	221,176	194,560
Utility income taxes									(83,176)	(77,334)	(69,101)
Operating Income	6,993	3,254	67,299	102,319	5,886	591	51,504	86,213	179,865	144,194	125,723
Segment Reporting Information, Profit (Loss) [Abstract]
Income before income taxes for reportable segments									238,619	220,363	198,064
Income taxes									(94,818)	(85,946)	(78,217)
Net Income	(8,967)	(7,344)	62,540	97,572	(5,003)	(2,293)	55,790	85,923	143,801	134,417	119,847
Segment Consolidated Assets [Abstract]
Total Assets	4,784,253				4,368,609				4,784,253	4,368,609
Operating Segments [Member]
Segment Consolidated Assets [Abstract]
Total Assets	4,612,700				4,182,423				4,612,700	4,182,423
Intersegment Eliminations [Member]
Segment Consolidated Assets [Abstract]
Total Assets	171,553				186,186				171,553	186,186
Regulated Operation [Member]
Segment Reporting Information [Abstract]
Revenues from external customers									1,469,988	1,278,229	1,122,780
Margin									690,208	621,490	575,446
Operations and maintenance expenses									270,877	253,120	242,599
Depreciation									118,996	112,207	103,192
Operating income (loss) before income taxes									263,041	221,528	194,824
Income from equity method investments									0	0	0
Interest expense									54,686	24,938	20,097
Income before income taxes									206,253	194,659	174,424
Total assets	4,442,185				4,053,591				4,442,185	4,053,591	3,475,640
Equity method investments in non-utility activities	0				0				0	0	0
Construction expenditures									460,444	599,999	529,576
Segment Reporting Information, Profit (Loss) [Abstract]
Income before income taxes for reportable segments									206,253	194,659	174,424
Regulated Non-Utility Activities [Member]
Segment Reporting Information [Abstract]
Revenues from external customers									0	0	0
Margin									0	0	0
Operations and maintenance expenses									132	103	31
Depreciation									0	0	0
Operating income (loss) before income taxes									(183)	(150)	(78)
Income from equity method investments									12,318	10,584	9,709
Interest expense									0	0	0
Income before income taxes									12,135	10,434	9,631
Total assets	129,206				90,097				129,206	90,097	69,749
Equity method investments in non-utility activities	129,206				90,097				129,206	90,097	69,749
Construction expenditures									0	0	0
Segment Reporting Information, Operating Income (Loss) [Abstract]
Segment operating income before income taxes									183	150	78
Segment Reporting Information, Profit (Loss) [Abstract]
Income before income taxes for reportable segments									12,135	10,434	9,631
Unregulated Non-Utility Activities [Member]
Segment Reporting Information [Abstract]
Revenues from external customers									0	0	0
Margin									0	0	0
Operations and maintenance expenses									92	78	71
Depreciation									18	18	18
Operating income (loss) before income taxes									(203)	(202)	(186)
Income from equity method investments									20,435	15,472	14,195
Interest expense									0	0	0
Income before income taxes									20,231	15,270	14,009
Total assets	41,309				38,735				41,309	38,735	18,498
Equity method investments in non-utility activities	40,965				38,372				40,965	38,372	18,118
Construction expenditures									0	0	0
Segment Reporting Information, Operating Income (Loss) [Abstract]
Segment operating income before income taxes									203	202	186
Segment Reporting Information, Profit (Loss) [Abstract]
Income before income taxes for reportable segments									$ 20,231	$ 15,270	$ 14,009

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Summary Of Significant Accounting Policies (Policies)

12 Months Ended

Oct. 31, 2014

Accounting Policies [Abstract]

Consolidation, Policy [Policy Text Block]

The consolidated financial statements reflect the accounts of Piedmont and its wholly-owned subsidiaries whose financial statements are prepared for the same reporting period as Piedmont using consistent accounting policies. Investments in non-utility activities, or joint ventures, are accounted for under the equity method as we do not have controlling voting interests or otherwise exercise control over the management of such companies.

The consolidated financial statements of Piedmont have been prepared in conformity with generally accepted accounting principles in the United States of America (GAAP) and under the rules of the Securities and Exchange Commission (SEC).

Inter-company transactions have been eliminated in consolidation where appropriate; however, we have not eliminated inter-company profit on sales to affiliates and costs from affiliates in accordance with accounting regulations prescribed under rate-based regulation.

Use of Estimates, Policy [Policy Text Block]

In accordance with GAAP, we make certain estimates and assumptions regarding reported amounts of assets, liabilities, revenues and expenses and the related disclosures, using historical experience and other assumptions that we believe are reasonable at the time. Our estimates may involve complex situations requiring a high degree of judgment in the application and interpretation of existing literature or in the development of estimates that impact our financial statements. These estimates and assumptions affect the reported amounts of assets and liabilities as of the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from these estimates and assumptions, which are evaluated on a continual basis.

Segment Reporting, Policy [Policy Text Block]

Our segments are based on the components of the Company for which we produce separate financial information internally that is used regularly by the chief operating decision maker in deciding how to allocate resources and in assessing performance. Our chief operating decision maker is the executive management team comprised of senior level management. Our segments are identified based on products and services, regulatory environments and our current corporate organization and business decision-making activities. We evaluate the performance of the regulated utility segment based on margin, operations and maintenance (O&M) expenses and operating income. We evaluate the performance of the regulated non-utility activities segment and the unregulated non-utility activities segment based on earnings from and our cash flows in the ventures.

Rate Regulated Basis of Accounting, Policy [Policy Text Block]

Our utility operations are subject to regulation with respect to rates, service area, accounting and various other matters by the regulatory commissions in the states in which we operate. The accounting regulations provide that rate-regulated public utilities account for and report assets and liabilities consistent with the economic effect of the manner in which independent third-party regulators establish rates. In applying these regulations, we capitalize certain costs and benefits as regulatory assets and liabilities, respectively, in order to provide for recovery from or refund to utility customers in future periods. Generally, regulatory assets are amortized to expense and regulatory liabilities are amortized to income over the period authorized by our regulators.

Our regulatory assets are recoverable through either base rates or rate riders specifically authorized by a state regulatory commission. Base rates are designed to provide both a recovery of cost and a return on investment during the period the rates are in effect. As such, all of our regulatory assets are subject to review by the respective state regulatory commissions during any future rate proceedings. In the event that accounting for the effects of regulation were no longer applicable, we would recognize a write-off of the regulatory assets and regulatory liabilities that would result in an adjustment to net income or accumulated other comprehensive income (OCI). Our utility operations continue to recover their costs through cost-based rates established by the state regulatory commissions.

Utility Plant And Depreciation, Policy

Depreciation rates for utility plant are approved by our regulatory commissions.

As authorized by our regulatory commissions, the estimated costs of removal on certain regulated properties are collected through depreciation expense through rates with a corresponding credit to accumulated depreciation. Our approved depreciation rates are comprised of two components, one based on average service life and one based on cost of removal for certain regulated properties. Therefore, through depreciation expense, we collect and record estimated non-legal costs of removal on any depreciable asset that includes cost of removal in its depreciation rate.

We compute depreciation expense using the straight-line method

Utility plant is stated at original cost, including direct labor and materials, contractor costs, allocable overhead charges, such as engineering, supervision, corporate office salaries and expenses, pensions and insurance, and an allowance for funds used during construction (AFUDC) that is calculated under a formula prescribed by our state regulators. We apply the group method of accounting, where the costs of homogeneous assets are aggregated and depreciated by applying a rate based on the average expected useful life of the assets. Major expenditures that last longer than a year and improve or lengthen the expected useful life of the overall property from original expectations that are recoverable in regulatory rate base are capitalized while expenditures not meeting these criteria are expensed as incurred. The costs of property retired or otherwise disposed of are removed from utility plant and charged to accumulated depreciation for recovery or refund through future rates. On certain assets, like land, that are nondepreciable, we record a gain or loss upon the disposal of the property

Cash and Cash Equivalents, Policy [Policy Text Block]

We consider instruments purchased with an original maturity at date of purchase of three months or less to be cash equivalents, particularly affecting the Consolidated Statements of Cash Flows.

With respect to cash overdrafts, book overdrafts are included within operating cash flows while any bank overdrafts are included with financing cash flows.

Trade Receivables And Allowance For Doubtful Accounts, Policy

We write off our customers’ accounts when they are deemed to be uncollectible. Pursuant to orders issued by the NCUC, the PSCSC and the TRA, we are authorized to recover all uncollected gas costs through the purchased gas adjustment (PGA).

Trade accounts receivable consist of natural gas sales and transportation services, merchandise sales and service work. We bill customers monthly with payment due within 30 days. We maintain an allowance for doubtful accounts, which we adjust periodically, based on the aging of receivables and our historical and projected charge-off activity.

Our policy requires counterparties to have an investment-grade credit rating at the time of the contract. In situations where counterparties do not have investment grade or functionally equivalent credit ratings, our policy requires credit enhancements that include letters of credit or parental guaranties. In either circumstance, the policy specifies limits on the contract amount and duration based on the counterparty’s credit rating and/or credit support.

Inventories, Policy

We maintain gas inventories on the basis of average cost. Injections into storage are priced at the purchase cost at the time of injection, and withdrawals from storage are priced at the weighted average purchase price in storage. The cost of gas in storage is recoverable under rate schedules approved by state regulatory commissions. Inventory activity is subject to regulatory review on an annual basis in gas cost recovery proceedings.

Under the terms of the agreements, we receive asset management fees, which are recorded as secondary market transactions and shared between our utility customers and our shareholders.

Materials, supplies and merchandise inventories are valued at the lower of average cost or market and removed from such inventory at average cost.

Fair Value Measurements, Policy [Policy Text Block]

We are able to classify fair value balances based on the observance of those inputs at the lowest level that is significant to the fair value measurement, in its entirety, in the following fair value hierarchy levels as set forth in the fair value guidance.

In determining whether to categorize the fair value measurement of an instrument as Level 2 or Level 3, we must use judgment to assess whether we have the ability as of the measurement date to redeem an investment at its net asset value per share (NAV) in the near term. We consider when we might have the ability to redeem the investment by reviewing contractual restrictions in effect as of the investment date as well as any potential restrictions that the investee may impose. Regarding our benefit plans’ investments, “near term” is the ability to redeem an investment in no more than 180 days.

Transfers between different levels of the fair value hierarchy may occur based on the level of observable inputs used to value the instruments for the period. These transfers represent existing assets or liabilities previously categorized as Level 1 or Level 2 for which the inputs to the estimate became less observable or assets and liabilities previously classified as Level 2 or Level 3 for which the lowest significant input became more observable during the period. Transfers into and out of each level are measured at the actual date of the event or change in circumstances causing the transfer.

We utilize market data or assumptions that market participants would use in valuing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. We primarily apply the market approach for fair value measurements and endeavor to utilize the best available information. Accordingly, we use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs.

We obtain market price data from multiple sources in order to value some of our Level 2 transactions and this data is representative of transactions that occurred in the marketplace.

For some qualified pension plan assets, the determination of Level 2 assets was completed through a process of reviewing each individual security while consulting research and other metrics provided by investment managers, including a pricing matrix detailing the pricing source and security type, annual audited financial statements and a review of valuation policies and procedures used by the investment managers as well as our investment advisor.

The carrying values of receivables, short-term debt, accounts payable, accrued interest and other current assets and liabilities approximate fair value as all amounts reported are to be collected or paid within one year.

Goodwill and Intangible Assets, Goodwill, Policy [Policy Text Block]

Goodwill is the excess of the purchase price over the fair value of identifiable net assets acquired in a business combination. We annually evaluate goodwill for impairment as of October 31, or more frequently if impairment indicators arise during the year. These indicators include, but are not limited to, a significant change in operating performance, the business climate, legal or regulatory factors, or a planned sale or disposition of a significant portion of the business. We test goodwill using a fair value approach at a reporting unit level, generally equivalent to our operating segments as discussed in Note 14 to the consolidated financial statements. An impairment charge would be recognized if the carrying value of the reporting unit, including goodwill, exceeded its fair value.

Equity Method Investments And Long Lived Assets, Policy

We review our equity method investments and long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable.

Marketable Securities, Policy [Policy Text Block]

We have classified these marketable securities as trading securities since their inception as the assets are held in rabbi trusts. Trading securities are recorded at fair value on the Consolidated Balance Sheets with any gains or losses recognized currently in earnings.

The money market investments in the trusts approximate fair value due to the short period of time to maturity. The fair values of the equity securities are based on quoted market prices as traded on the exchanges.

Unamortized Debt Expense, Policy

Should we reacquire long-term debt prior to its term date and simultaneously issue new debt, we defer the gain or loss resulting from the transaction, essentially the remaining unamortized debt expense, and amortize it over the life of the new debt in accordance with established regulatory practice. Where the refunding of the debt is not simultaneous, we defer the gain or loss resulting from the reacquisition of the debt and amortize it over the remaining life of the redeemed debt in accordance with established regulatory practice. For income tax purposes, any gain or loss would be recognized as incurred.

Unamortized debt expense consists of costs, such as underwriting and broker dealer fees, discounts and commissions, legal fees, accountant fees, registration fees and rating agency fees, related to issuing long-term debt and the short-term syndicated revolving credit facility. We amortize long-term debt expense on a straight-line basis, which approximates the effective interest method, over the life of the related debt

We amortize bank debt expense over the life of the syndicated revolving credit facility

Common Stock Issuance and Repurchase Policy

we may repurchase shares on the open market and such shares are then canceled and become authorized but unissued shares. It is our policy to issue new shares for share-based employee awards and shareholder and employee investment plans.

Asset Retirement Obligations, Policy [Policy Text Block]

The estimated cash flows to settle conditional AROs are discounted using the credit adjusted risk-free rate

We apply the accounting guidance for conditional AROs that requires recognition of a liability for the fair value of conditional AROs when incurred if the liability can be reasonably estimated. The NCUC, the PSCSC and the TRA have approved placing these ARO costs in deferred accounts to preserve the regulatory treatment of these costs

Revenue Recognition, Policy [Policy Text Block]

Revenues are recognized monthly on the accrual basis, which includes estimated amounts for gas delivered to customers but not yet billed under the cycle-billing method from the last meter reading date to month end.

Secondary market revenues associated with the commodity are recognized when the physical sales are delivered based on contract or market prices. Asset management fees for storage and transportation remitted on a monthly basis are recognized as earned given the monthly capacity costs associated with the contracts involved. Asset management fees remitted in a lump sum are deferred and amortized ratably into income over the period in which they are earned, which is typically the contract term.

Utility sales, transportation and secondary market revenues are reported net of excise taxes, sales taxes and franchise fees.

We record revenues when services are provided to our distribution service customers. Utility sales and transportation revenues are based on rates approved by state regulatory commissions. Base rates charged to jurisdictional customers may not be changed without approval by the regulatory commission in that jurisdiction; however, the wholesale cost of gas component of rates may be adjusted periodically under PGA provisions.

Non-regulated merchandise and service work includes the sale, installation and/or maintenance of natural gas appliances and gas piping beyond the meter. Revenue is recognized when the sale is made or the work is performed. If the customer is eligible for and elects financing through us, the finance fee income is recognized on a monthly basis based on principal, rate and term.

Capitalization and Amortization of Fuel Costs, Policy [Policy Text Block]

We review gas costs and deferral activity periodically (including deferrals under the margin decoupling and WNA mechanisms) and, with regulatory commission approval, increase rates to collect under-recoveries or decrease rates to refund over-recoveries over a subsequent period.

We charge our utility customers for natural gas consumed using natural gas cost recovery mechanisms as set by the regulatory commissions in states in which we operate. Rate schedules for utility sales and transportation customers include PGA provisions that provide for the recovery of prudently incurred gas costs. With regulatory commission approval, we revise rates periodically without formal rate proceedings to reflect changes in the wholesale cost of gas. We charge our secondary market customers for natural gas based on negotiated contract terms. Under PGA provisions, charges to cost of gas are based on the amount recoverable under approved rate schedules. Within our cost of gas, we include amounts for lost and unaccounted for gas and adjustments to reflect the gains and losses associated with gas price hedging derivatives.

Taxes, Policy

Deferred income taxes are determined based on the estimated future tax effects of differences between the book and tax basis of assets and liabilities. We have provided valuation allowances to reduce the carrying amount of deferred tax assets to amounts that are more likely than not to be realized. To the extent that the establishment of deferred income taxes is different from the recovery of taxes through the ratemaking process, the differences are deferred in accordance with rate-regulated accounting provisions, and a regulatory asset or liability is recognized for the impact of tax expenses or benefits that will be collected from or refunded to customers in different periods pursuant to rate orders.

We amortize these deferred investment and energy tax credits to income over the estimated useful lives of the property to which the credits relate.

We recognize accrued interest and penalties, if any, related to uncertain tax positions as operating expenses in the Consolidated Statements of Comprehensive Income.

Excise taxes, sales taxes and franchises fees separately stated on customer bills are recorded on a net basis as liabilities payable to the applicable jurisdictions. All other taxes other than income taxes are recorded as general taxes. General taxes consist of property taxes, payroll taxes, Tennessee gross receipt taxes, franchise taxes, tax on company use and other miscellaneous taxes.

We have two categories of income taxes in the Consolidated Statements of Comprehensive Income: current and deferred. Current income tax expense consists of federal and state income taxes less applicable tax credits related to the current year.

Earnings Per Share, Policy [Policy Text Block]

We compute basic earnings per share (EPS) using the daily weighted average number of shares of common stock outstanding during each period. In the calculation of fully diluted EPS, shares of common stock to be issued under approved incentive compensation plans are contingently issuable shares, as determined by applying the treasury stock method, and are added to average common shares outstanding, resulting in a potential reduction in diluted EPS.

Consolidation, Variable Interest Entity, Policy [Policy Text Block]

On a quarterly basis, we reassess whether we have a controlling financial interest in and are the primary beneficiary of a VIE. The quarterly reassessment process considers whether we have acquired or divested the power to direct the activities of the VIE through changes in governing documents or other circumstances. The reassessment also considers whether we have acquired or disposed of a financial interest that could be significant to the VIE, or whether an interest in the VIE has become significant or is no longer significant. The consolidation status of the VIEs with which we are involved may change as a result of such reassessments. Changes in consolidation status are applied prospectively, with assets and liabilities of a newly consolidated VIE initially recorded at fair value. A gain or loss may be recognized upon deconsolidation of a VIE depending on the carrying values of deconsolidated assets and liabilities compared to the fair value of retained interests and ongoing contractual arrangements.

Subsequent Events, Policy [Policy Text Block]

We monitor significant events occurring after the balance sheet date and prior to the issuance of the financial statements to determine the impacts, if any, of events on the financial statements to be issued.

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Employee Share Based Plans (Details) (USD $)	12 Months Ended			1 Months Ended	0 Months Ended
	Oct. 31, 2014	Oct. 31, 2013	Oct. 31, 2012	Dec. 31, 2011	Dec. 15, 2014	Dec. 12, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number Of Performance Periods Under ICP Plans	3 years
Maximum Statutory Withholdings Allowed	50.00%
Stock Issued During Period, Shares, Share-based Compensation, Gross	100,000	96,000	25,000
Compensation expense	$ 8,496,000	$ 4,526,000	$ 5,730,000
Tax Benefit	2,476,000	1,538,000	2,080,000
Liability	15,130,000	11,098,000
Incentive Compensation Plan Expected Payout In One Year	7,204,000
Incentive Compensation Plan Expected Payout In Two Years	4,980,000
Incentive Compensation Plan Expected Payout In Three Years	2,946,000
Employee Stock Purchase Plan Exercise Price As A Percentage Of Fair Market Value	95.00%
Stock Compensation Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number Of Incentive Compensation Plan Awards	3
Long Term Incentive Plan Two Performance Measures [Member] | Stock Compensation Plan [Member] | EPS Performance [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocation Of Performance Units	50.00%
Long Term Incentive Plan Two Performance Measures [Member] | Stock Compensation Plan [Member] | Annual Shareholder Return [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocation Of Performance Units	50.00%
Long Term Incentive Plan Three Performance Measures [Member] | Stock Compensation Plan [Member] | EPS Performance [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocation Of Performance Units	37.50%
Long Term Incentive Plan Three Performance Measures [Member] | Stock Compensation Plan [Member] | Annual Shareholder Return [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocation Of Performance Units	37.50%
Long Term Incentive Plan Three Performance Measures [Member] | Stock Compensation Plan [Member] | Return On Equity [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocation Of Performance Units	25.00%
Retention Stock Unit Award Eligible Officers [Member] | Stock Compensation Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Requisite Service Period	3 years
Retention Stock Unit Award President And Cheif Executive Officer [Member] | Stock Compensation Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period				64,700
Share-based Compensation Arrangement by Share-based Payment Award, Award Requisite Service Period	5 years
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights	In accordance with the vesting schedule, 20% of the units vested on December 15, 2014, 30% of the units vest on December 15, 2015 and 50% of the units vest on December 15, 2016.
Retention Stock Unit Award President And Cheif Executive Officer [Member] | Stock Compensation Plan [Member] | Share-based Compensation Award, Tranche One [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage	20.00%
Retention Stock Unit Award President And Cheif Executive Officer [Member] | Stock Compensation Plan [Member] | Share-based Compensation Award, Tranche One [Member] | Subsequent Event [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock Award Vested, Shares, Gross					14,461
Stock Issued During Period, Shares, Share-based Compensation, Gross					7,231
Share Price						$ 37.89
Payments Related to Tax Withholding for Share-based Compensation					$ 300,000
Share-based Compensation Arrangement by Share-based Payment Award, Description					The award which vested on December 15, 2014 covered 20% of the grant, including accrued dividends, for a total of 14,461 shares of common stock. After the withholding of $.3 million for federal and state income taxes, our President and Chief Executive Officer received 7,231 shares at the New York Stock Exchange composite closing price on December 12, 2014 of $37.89 per share.
Retention Stock Unit Award President And Cheif Executive Officer [Member] | Stock Compensation Plan [Member] | Share-based Compensation Award, Tranche Two [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage	30.00%
Retention Stock Unit Award President And Cheif Executive Officer [Member] | Stock Compensation Plan [Member] | Share-based Compensation Award, Tranche Three [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage	50.00%

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Earnings Per Share (Details) (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended								12 Months Ended
	Oct. 31, 2014	Jul. 31, 2014	Apr. 30, 2014	Jan. 31, 2014	Oct. 31, 2013	Jul. 31, 2013	Apr. 30, 2013	Jan. 31, 2013	Oct. 31, 2014	Oct. 31, 2013	Oct. 31, 2012
Earnings Per Share [Abstract]
Net income	$ (8,967)	$ (7,344)	$ 62,540	$ 97,572	$ (5,003)	$ (2,293)	$ 55,790	$ 85,923	$ 143,801	$ 134,417	$ 119,847
Average shares of common stock outstanding for basic earnings per share									77,883	74,884	71,977
Contingently issuable shares under incentive compensation plans									310	289	301
Contingently issuable shares under forward sale agreements									0	160	0
Average shares of dilutive stock									78,193	75,333	72,278
Basic (usd per share)	$ (0.11)	$ (0.09)	$ 0.80	$ 1.27	$ (0.07)	$ (0.03)	$ 0.74	$ 1.19	$ 1.85	$ 1.80	$ 1.67
Diluted (usd per share)	$ (0.11)	$ (0.09)	$ 0.80	$ 1.26	$ (0.07)	$ (0.03)	$ 0.74	$ 1.18	$ 1.84	$ 1.78	$ 1.66

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Variable Interest Entities (Tables)

12 Months Ended

Oct. 31, 2014

Variable Interest Entity, Not Primary Beneficiary, Disclosures [Abstract]

Schedule Of Variable Interest Entities Investment Balances [Table Text Block]

As of October 31, 2014 and 2013, our investment balances are as follows.

	October 31,		October 31,
In thousands	2014		2013
Cardinal	$	16,073	$	18,207
Pine Needle	18,689		20,270
SouthStar	40,965		38,372
Hardy Storage	37,179		34,681
Constitution	57,255		16,939
ACP	10
Total equity method investments in non-utility activities	$	170,171	$	128,469

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Income Taxes Operating Loss Carryforwards (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Oct. 31, 2014	Oct. 31, 2013
Domestic Tax Authority [Member] | Internal Revenue Service (IRS) [Member]
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards, Limitations on Use	subject to an annual limitation of $.3 million
Operating Loss Carryforwards, Annual Amount Subject To Limitation	$ 0.3
Deferred Tax Assets, Tax Credit Carryforwards, Alternative Minimum Tax	2.4
State and Local Jurisdiction [Member]
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards	7.2	6.4
NOL Carryforward 1 [Member] | Domestic Tax Authority [Member] | Internal Revenue Service (IRS) [Member]
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards	97.0	178.1
Operating Loss Carryforwards, Expiration Date	Oct. 31, 2033
NOL Carryforward 2 [Member] | Domestic Tax Authority [Member] | Internal Revenue Service (IRS) [Member]
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards	$ 5.9	$ 5.9
Minimum [Member] | State and Local Jurisdiction [Member]
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards, Expiration Date	Oct. 31, 2020
Minimum [Member] | NOL Carryforward 2 [Member] | Domestic Tax Authority [Member] | Internal Revenue Service (IRS) [Member]
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards, Expiration Date	Oct. 31, 2021
Maximum [Member] | State and Local Jurisdiction [Member]
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards, Expiration Date	Oct. 31, 2028
Maximum [Member] | NOL Carryforward 2 [Member] | Domestic Tax Authority [Member] | Internal Revenue Service (IRS) [Member]
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards, Expiration Date	Oct. 31, 2025

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Commitment & Contingencies (Details) (USD $)	12 Months Ended
	Oct. 31, 2014 regulatory_commission sites	Oct. 31, 2013	Oct. 31, 2012	Mar. 01, 2012	Dec. 31, 2013
Guarantor Obligations [Line Items]
Payments for Rent	$ 4,701,000	$ 4,729,000	$ 3,712,000
Operating Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract]
Operating Leases, Future Minimum Payments Due, Next Twelve Months	4,600,000
Operating Leases, Future Minimum Payments, Due in Two Years	4,491,000
Operating Leases, Future Minimum Payments, Due in Three Years	4,297,000
Operating Leases, Future Minimum Payments, Due in Four Years	4,225,000
Operating Leases, Future Minimum Payments, Due in Five Years	4,137,000
Operating Leases, Future Minimum Payments, Due Thereafter	27,359,000
Operating Leases Future Minimum Payments Due	49,109,000
Unrecorded Unconditional Purchase Obligation [Line Items]
Unrecorded Unconditional Purchase Obligation, Due in Next Twelve Months	223,250,000
Unrecorded Unconditional Purchase Obligation, Due within Two Years	154,335,000
Unrecorded Unconditional Purchase Obligation, Due within Three Years	146,450,000
Unrecorded Unconditional Purchase Obligation, Due within Four Years	142,559,000
Unrecorded Unconditional Purchase Obligation, Due within Five Years	132,266,000
Unrecorded Unconditional Purchase Obligation, Due after Five Years	627,602,000
Unrecorded Unconditional Purchase Obligation	1,426,462,000
Number Of Regulatory Commissions	3
MGP Sites Under Settlement	9
Site Contingency, Unasserted Claims	0
Site Contingency [Line Items]
Environmental Costs Incurred to Date	6,912,000
Undiscounted Environmental Liability	1,259,000
Regulatory Assets [Line Items]
Regulatory Assets	213,867,000	246,306,000
Environmental costs
Regulatory Assets [Line Items]
Regulatory Assets	8,000,000
Tennessee Regulatory Authority [Member] | Environmental costs | General Rate Application Settlement 2012 [Member]
Regulatory Assets [Line Items]
Regulatory Assets				2,000,000
Amortization Time Period For Specified Expenses	8 years
NCUC [Member] | Environmental costs | General Rate Case Proceeding 2013 [Member]
Regulatory Assets [Line Items]
Regulatory Assets					6,300,000
Amortization Time Period For Specified Expenses	5 years
PSCSC [Member] | Environmental costs | Settlement With Office of Regulatory Staff October 2014 [Member]
Regulatory Assets [Line Items]
Regulatory Assets	100,000
Amortization Time Period For Specified Expenses	1 year
Anderson SC MGP Site [Member]
Site Contingency [Line Items]
Environmental Costs Incurred to Date	7,000
Undiscounted Environmental Liability	890,000
Hickory NC MGP Site [Member]
Site Contingency [Line Items]
Environmental Costs Incurred to Date	1,494,000
Undiscounted Environmental Liability	18,000
Reidsville NC MGP Site [Member]
Site Contingency [Line Items]
Environmental Costs Incurred to Date	641,000
Undiscounted Environmental Liability	199,000
Huntersville NC LNG Site [Member]
Site Contingency [Line Items]
Environmental Costs Incurred to Date	4,738,000
Undiscounted Environmental Liability	81,000
Charlotte NC UST Site [Member]
Site Contingency [Line Items]
Environmental Costs Incurred to Date	32,000
Undiscounted Environmental Liability	33,000
Clemmons NC UST Site [Member]
Site Contingency [Line Items]
Environmental Costs Incurred to Date	0
Undiscounted Environmental Liability	38,000
Pipeline And Storage Capacity Contracts [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Unrecorded Unconditional Purchase Obligation, Due in Next Twelve Months	158,984,000
Unrecorded Unconditional Purchase Obligation, Due within Two Years	149,412,000
Unrecorded Unconditional Purchase Obligation, Due within Three Years	145,579,000
Unrecorded Unconditional Purchase Obligation, Due within Four Years	142,433,000
Unrecorded Unconditional Purchase Obligation, Due within Five Years	132,186,000
Unrecorded Unconditional Purchase Obligation, Due after Five Years	627,602,000
Unrecorded Unconditional Purchase Obligation	1,356,196,000
Gas Supply Contracts [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Unrecorded Unconditional Purchase Obligation, Due in Next Twelve Months	8,657,000
Unrecorded Unconditional Purchase Obligation, Due within Two Years	137,000
Unrecorded Unconditional Purchase Obligation, Due within Three Years	135,000
Unrecorded Unconditional Purchase Obligation, Due within Four Years	0
Unrecorded Unconditional Purchase Obligation, Due within Five Years	0
Unrecorded Unconditional Purchase Obligation, Due after Five Years	0
Unrecorded Unconditional Purchase Obligation	8,929,000
Telecommunications And Technology Outsourcing Contracts [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Unrecorded Unconditional Purchase Obligation, Due in Next Twelve Months	14,601,000
Unrecorded Unconditional Purchase Obligation, Due within Two Years	4,786,000
Unrecorded Unconditional Purchase Obligation, Due within Three Years	736,000
Unrecorded Unconditional Purchase Obligation, Due within Four Years	126,000
Unrecorded Unconditional Purchase Obligation, Due within Five Years	80,000
Unrecorded Unconditional Purchase Obligation, Due after Five Years	0
Unrecorded Unconditional Purchase Obligation	20,329,000
Others [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Unrecorded Unconditional Purchase Obligation, Due in Next Twelve Months	41,008,000
Unrecorded Unconditional Purchase Obligation, Due within Two Years	0
Unrecorded Unconditional Purchase Obligation, Due within Three Years	0
Unrecorded Unconditional Purchase Obligation, Due within Four Years	0
Unrecorded Unconditional Purchase Obligation, Due within Five Years	0
Unrecorded Unconditional Purchase Obligation, Due after Five Years	0
Unrecorded Unconditional Purchase Obligation	41,008,000
Letter of Credit [Member]
Guarantor Obligations [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	1,800,000
Surety Bond [Member]
Guarantor Obligations [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	$ 4,800,000

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Summary of Significant Accounting Policies

12 Months Ended

Oct. 31, 2014

Accounting Policies [Abstract]

Significant Accounting Policies [Text Block]

Summary of Significant Accounting Policies

Nature of Operations and Basis of Consolidation

Piedmont Natural Gas Company, Inc. is an energy services company primarily engaged in the distribution of natural gas to residential, commercial, industrial and power generation customers in portions of North Carolina, South Carolina and Tennessee. We are invested in joint venture, energy-related businesses, including unregulated retail natural gas marketing, regulated interstate natural gas transportation and storage and regulated intrastate natural gas transportation. Our utility operations are regulated by three state regulatory commissions. Unless the context requires otherwise, references to “we,” “us,” “our,” “the Company” or “Piedmont” means consolidated Piedmont Natural Gas Company, Inc. and its subsidiaries. For further information on regulatory matters, see Note 2 to the consolidated financial statements.

The consolidated financial statements reflect the accounts of Piedmont and its wholly-owned subsidiaries whose financial statements are prepared for the same reporting period as Piedmont using consistent accounting policies. Investments in non-utility activities, or joint ventures, are accounted for under the equity method as we do not have controlling voting interests or otherwise exercise control over the management of such companies. Our ownership interest in each entity is recorded in “Equity method investments in non-utility activities” in “Noncurrent Assets” in the Consolidated Balance Sheets at cost plus post-acquisition contributions and earnings based on our share in each of the joint ventures less any distributions received from the joint venture, and if applicable, less any impairment in value of the investment. Earnings or losses from equity method investments are recorded in “Income from equity method investments” in “Other Income (Expense)” in the Consolidated Statements of Comprehensive Income. Revenues and expenses of all other non-utility activities are included in “Non-operating income” in “Other Income (Expense)” in the Consolidated Statements of Comprehensive Income. Inter-company transactions have been eliminated in consolidation where appropriate; however, we have not eliminated inter-company profit on sales to affiliates and costs from affiliates in accordance with accounting regulations prescribed under rate-based regulation. For further information on equity method investments and related party transactions, see Note 12 to the consolidated financial statements.

We monitor significant events occurring after the balance sheet date and prior to the issuance of the financial statements to determine the impacts, if any, of events on the financial statements to be issued. All subsequent events of which we are aware were evaluated. There are no subsequent events that had a material impact on our financial position, results of operations or cash flows. For further information, see Note 15 to the consolidated financial statements.

Use of Estimates

The consolidated financial statements of Piedmont have been prepared in conformity with generally accepted accounting principles in the United States of America (GAAP) and under the rules of the Securities and Exchange Commission (SEC). In accordance with GAAP, we make certain estimates and assumptions regarding reported amounts of assets, liabilities, revenues and expenses and the related disclosures, using historical experience and other assumptions that we believe are reasonable at the time. Our estimates may involve complex situations requiring a high degree of judgment in the application and interpretation of existing literature or in the development of estimates that impact our financial statements. These estimates and assumptions affect the reported amounts of assets and liabilities as of the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from these estimates and assumptions, which are evaluated on a continual basis.

Segment Reporting

Our segments are based on the components of the Company for which we produce separate financial information internally that is used regularly by the chief operating decision maker in deciding how to allocate resources and in assessing performance. Our chief operating decision maker is the executive management team comprised of senior level management. Our segments are identified based on products and services, regulatory environments and our current corporate organization and business decision-making activities. We evaluate the performance of the regulated utility segment based on margin, operations and maintenance (O&M) expenses and operating income. We evaluate the performance of the regulated non-utility activities segment and the unregulated non-utility activities segment based on earnings from and our cash flows in the ventures.

Beginning with the fourth quarter of 2014, we have three reportable business segments, regulated utility, regulated non-utility activities and unregulated non-utility activities. The regulated utility segment is the gas distribution business, where we include the operations of merchandising and its related service work and home service agreements, with activities conducted by the utility. Operations of our regulated non-utility activities segment are comprised of our equity method investments in joint ventures with regulated activities that are held by our wholly-owned subsidiaries. Operations of our unregulated non-utility activities segment are comprised primarily of our equity method investment in a joint venture with unregulated activities that is held by a wholly-owned subsidiary; activities of our other minor subsidiaries are also included. See Note 14 to the consolidated financial statements for further discussion of segments.

Rate-Regulated Basis of Accounting

Our utility operations are subject to regulation with respect to rates, service area, accounting and various other matters by the regulatory commissions in the states in which we operate. The accounting regulations provide that rate-regulated public utilities account for and report assets and liabilities consistent with the economic effect of the manner in which independent third-party regulators establish rates. In applying these regulations, we capitalize certain costs and benefits as regulatory assets and liabilities, respectively, in order to provide for recovery from or refund to utility customers in future periods. Generally, regulatory assets are amortized to expense and regulatory liabilities are amortized to income over the period authorized by our regulators.

Our regulatory assets are recoverable through either base rates or rate riders specifically authorized by a state regulatory commission. Base rates are designed to provide both a recovery of cost and a return on investment during the period the rates are in effect. As such, all of our regulatory assets are subject to review by the respective state regulatory commissions during any future rate proceedings. In the event that accounting for the effects of regulation were no longer applicable, we would recognize a write-off of the regulatory assets and regulatory liabilities that would result in an adjustment to net income or accumulated other comprehensive income (OCI). Our utility operations continue to recover their costs through cost-based rates established by the state regulatory commissions. As a result, we believe that the accounting prescribed under rate-based regulation remains appropriate. It is our opinion that all regulatory assets are recoverable in current rates or in future rate proceedings.

Regulatory assets and liabilities in the Consolidated Balance Sheets as of October 31, 2014 and 2013 are as follows.

In thousands	2014		2013
Regulatory Assets:
Current:
Unamortized debt expense	$	1,490	$	1,274
Amounts due from customers	16,108		66,321
Environmental costs	1,568		1,480
Deferred operations and maintenance expenses	916		739
Deferred pipeline integrity expenses	3,470		3,149
Deferred pension and other retirement benefits costs	2,769		2,768
Robeson liquefied natural gas (LNG) development costs	917		382
Other	1,850		1,091
Total current	29,088		77,204
Noncurrent:
Unamortized debt expense	15,402		14,149
Environmental costs	6,470		7,936
Deferred operations and maintenance expenses	4,721		5,637
Deferred pipeline integrity expenses	24,694		16,300
Deferred pension and other retirement benefits costs	18,799		17,968
Amounts not yet recognized as a component of pension and other retirement benefit costs	94,265		80,604
Regulatory cost of removal asset	18,275		22,974
Robeson LNG development costs	509		1,426
Other	1,644		2,108
Total noncurrent	184,779		169,102
Total	$	213,867	$	246,306

Regulatory Liabilities:
Current:
Amounts due to customers	$	46,231	$	—
Noncurrent:
Regulatory cost of removal obligations	506,574		493,111
Deferred income taxes	51,930		48,647
Amounts not yet recognized as a component of pension and other retirement costs	94		139
Total noncurrent	558,598		541,897
Total	$	604,829	$	541,897

As of October 31, 2014, we have $18.3 million of asset retirement obligations (AROs) and $98.1 million of other regulatory assets on which we do not earn a return. Included in deferred pension and other retirement costs are amounts related to pension funding for our Tennessee jurisdiction. The recovery of these amounts is authorized by the Tennessee Regulatory Authority (TRA) on a deferred cash basis.

Utility Plant and Depreciation

Utility plant is stated at original cost, including direct labor and materials, contractor costs, allocable overhead charges, such as engineering, supervision, corporate office salaries and expenses, pensions and insurance, and an allowance for funds used during construction (AFUDC) that is calculated under a formula prescribed by our state regulators. We apply the group method of accounting, where the costs of homogeneous assets are aggregated and depreciated by applying a rate based on the average expected useful life of the assets. Major expenditures that last longer than a year and improve or lengthen the expected useful life of the overall property from original expectations that are recoverable in regulatory rate base are capitalized while expenditures not meeting these criteria are expensed as incurred. The costs of property retired or otherwise disposed of are removed from utility plant and charged to accumulated depreciation for recovery or refund through future rates. On certain assets, like land, that are nondepreciable, we record a gain or loss upon the disposal of the property that is recorded in “Non-operating income” in “Other Income (Expense)” in the Consolidated Statements of Comprehensive Income.

The classification of total utility plant, net, for the years ended October 31, 2014 and 2013 is presented below.

In thousands	2014			2013
Intangible plant	$	3,374		$	3,374
Other storage plant	180,058			171,349
Transmission plant	1,787,990			1,403,829
Distribution plant	2,623,560			2,505,160
General plant	421,763			335,847
Asset retirement cost	11			7,565
Contributions in aid of construction	(5,259		)	(5,187		)
Total utility plant in service	5,011,497			4,421,937
Less accumulated depreciation	(1,166,922		)	(1,088,331		)
Total utility plant in service, net	3,844,575			3,333,606
Construction work in progress	141,693			297,717
Plant held for future use	3,155			3,155
Total utility plant, net	$	3,989,423		$	3,634,478

Contributions in aid of construction represent nonrefundable donations or contributions received from third-parties for partial or full reimbursement for construction expenditures for utility plant in service.

AFUDC represents the estimated costs of funds from both debt and equity sources used to finance the construction of major projects and is capitalized for ratemaking purposes when the completed projects are placed in service. The portion of AFUDC attributable to borrowed funds is shown as a reduction of “Utility Interest Charges” in the Consolidated Statements of Comprehensive Income. Any portion of AFUDC attributable to equity funds would be included in “Other Income (Expense)” in the Consolidated Statements of Comprehensive Income. For the three years ended October 31, 2014, 2013 and 2012, all of our AFUDC was attributable to borrowed funds.

AFUDC for the years ended October 31, 2014, 2013 and 2012 is presented below.

In thousands	2014		2013		2012
AFUDC	$	16,427	$	30,975	$	25,211

In accordance with utility accounting practice, we classified real estate and development costs associated with a LNG peak storage facility in the eastern part of North Carolina as “Plant held for future use” in the Consolidated Balance Sheets, due to construction being suspended in March 2009. As of 2012, approximately $3.2 million of the “Plant held for future use” related to land costs and approximately $3.5 million related to non-real estate costs. In May 2013, we filed a general rate application with the North Carolina Utilities Commission (NCUC) requesting rate recovery of the non-real estate costs. Under the settlement of the 2013 North Carolina general rate proceeding approved by the NCUC in December 2013, we agreed to the amortization and collection of $1.2 million of non-real estate costs that is recorded as a regulatory asset to be amortized over 38 months beginning January 1, 2014 through February 2017. Under the settlement of our June 2014 rate stabilization adjustment (RSA) filing with the Public Service Commission of South Carolina (PSCSC) that was approved in October 2014, we agreed to the amortization and collection of $.5 million of non-real estate costs that is recorded as a regulatory asset to be amortized over 12 months beginning November 1, 2014. We recorded cumulative amortization of $1.8 million of non-real estate costs in fiscal year 2013 that is included in the Consolidated Statements of Comprehensive Income in “Other Income (Expense)” in “Non-operating expense.” For further information on the 2013 general rate proceeding settlement of these costs for North Carolina or the 2014 RSA filing for South Carolina, see Note 2 to the consolidated financial statements.

We compute depreciation expense using the straight-line method over periods ranging from 5 to 80 years. The composite weighted-average depreciation rates were 2.54% for 2014, 2.77% for 2013 and 2.94% for 2012.

Depreciation rates for utility plant are approved by our regulatory commissions. In North Carolina, we are required to conduct a depreciation study every five years and file the results with the regulatory commission. No such five-year requirement exists in South Carolina or Tennessee; however, we periodically propose revised rates in those states based on depreciation studies. Our last system-wide depreciation study based on fiscal year 2009 data was completed in 2011 and filed with the appropriate regulatory commission in all jurisdictions. New depreciation rates were approved effective November 1, 2011 for South Carolina, March 1, 2012 for Tennessee and January 1, 2014 for North Carolina.

As authorized by our regulatory commissions, the estimated costs of removal on certain regulated properties are collected through depreciation expense through rates with a corresponding credit to accumulated depreciation. Our approved depreciation rates are comprised of two components, one based on average service life and one based on cost of removal for certain regulated properties. Therefore, through depreciation expense, we collect and record estimated non-legal costs of removal on any depreciable asset that includes cost of removal in its depreciation rate. Because the estimated removal costs are a non-legal obligation, we account for them as a regulatory liability and present the accumulated removal costs in “Regulatory Liabilities” in “Rate-Regulated Basis of Accounting” in this Note 1. For further discussion of this regulatory liability, see “Asset Retirement Obligations” in this Note 1.

Cash and Cash Equivalents

We consider instruments purchased with an original maturity at date of purchase of three months or less to be cash equivalents, particularly affecting the Consolidated Statements of Cash Flows. We have no restrictions on our cash balances that would impact the payment of dividends as of October 31, 2014 and 2013.

Trade Accounts Receivable and Allowance for Doubtful Accounts

Trade accounts receivable consist of natural gas sales and transportation services, merchandise sales and service work. We bill customers monthly with payment due within 30 days. We maintain an allowance for doubtful accounts, which we adjust periodically, based on the aging of receivables and our historical and projected charge-off activity. Our estimate of recoverability could differ from actual experience based on customer credit issues, the level of natural gas prices and general economic conditions. We write off our customers’ accounts when they are deemed to be uncollectible. Pursuant to orders issued by the NCUC, the PSCSC and the TRA, we are authorized to recover all uncollected gas costs through the purchased gas adjustment (PGA). As a result, only the portion of accounts written off relating to the non-gas costs, or margin, is included in base rates and, accordingly, only this portion is included in the provision for uncollectibles expense. Non-regulated merchandise and service work receivables due beyond one year are included in “Other noncurrent assets” in “Noncurrent Assets” in the Consolidated Balance Sheets.

We are exposed to credit risk when we enter into contracts with third parties to buy and sell natural gas. We also enter into short-term contracts with third parties to manage some of our supply and capacity assets for the purpose of maximizing their value. Our policy requires counterparties to have an investment-grade credit rating at the time of the contract. In situations where counterparties do not have investment grade or functionally equivalent credit ratings, our policy requires credit enhancements that include letters of credit or parental guaranties. In either circumstance, the policy specifies limits on the contract amount and duration based on the counterparty’s credit rating and/or credit support. In order to minimize our exposure, we continually re-evaluate third-party credit worthiness and market conditions and modify our requirements accordingly.

Our principal business activity is the distribution of natural gas. We believe that we have provided an adequate allowance for any receivables which may not be ultimately collected. As of October 31, 2014 and 2013, our trade accounts receivable consisted of the following.

In thousands	2014			2013
Gas receivables	$	64,400		$	78,540
Non-regulated merchandise and service work receivables	3,012			2,274
Allowance for doubtful accounts	(2,152		)	(1,604		)
Trade accounts receivable	$	65,260		$	79,210

A reconciliation of the changes in the allowance for doubtful accounts for the years ended October 31, 2014, 2013 and 2012 is presented below.

In thousands	2014			2013			2012
Balance at beginning of year	$	1,604		$	1,579		$	1,347
Additions charged to uncollectibles expense	6,959			5,314			4,584
Accounts written off, net of recoveries	(6,411		)	(5,289		)	(4,352		)
Balance at end of year	$	2,152		$	1,604		$	1,579

Inventories

We maintain gas inventories on the basis of average cost. Injections into storage are priced at the purchase cost at the time of injection, and withdrawals from storage are priced at the weighted average purchase price in storage. The cost of gas in storage is recoverable under rate schedules approved by state regulatory commissions. Inventory activity is subject to regulatory review on an annual basis in gas cost recovery proceedings.

We enter into service contracts, or asset management arrangements (AMAs), with counterparties to efficiently manage portions of our gas supply, transportation capacity and storage capacity to serve our customers. These AMAs are structured in compliance with Federal Energy Regulatory Commission (FERC) Order 712. Generally, under an AMA, we receive a fixed monthly payment which is set at inception of the arrangement, and in return, we may assign the gas supply and/or storage inventory and release the transportation capacity and storage capacity to the asset manager for the term of the agreement. The inventory is assigned at no cost, and the same quantities are required to be returned at the expiration of the agreements. One agreement allows us to call on inventory during the summer months to satisfy operational requirements, if needed. The inventory that is assigned to the asset manager is available for our use during the winter heating season, November through March. We account for these amounts on the Consolidated Balance Sheets as a current asset in the inventories section as “Gas in storage.” From the period of April through October, the inventory that is not available for our use is reclassified on the Consolidated Balance Sheets as a current asset in “Prepayments,” and the inventory that is available for our use remains in “Gas in storage.”

At October 31, 2014 and 2013, such counterparties held natural gas storage assets as recorded in “Prepayments,” with a value of $35 million and $31.5 million, respectively, through such asset management relationships. Under the terms of the agreements, we receive asset management fees, which are recorded as secondary market transactions and shared between our utility customers and our shareholders. The AMAs expire at various times through March 31, 2017. For further information on the revenue sharing of secondary market transactions, see Note 2 to the consolidated financial statements.

Materials, supplies and merchandise inventories are valued at the lower of average cost or market and removed from such inventory at average cost.

Fair Value Measurements

We have financial and nonfinancial assets and liabilities subject to fair value measurement. The financial assets and liabilities measured and carried at fair value in the Consolidated Balance Sheets are cash and cash equivalents, marketable securities held in rabbi trusts established for our deferred compensation plans and derivative assets and liabilities, if any, that are held for our utility operations. The carrying values of receivables, short-term debt, accounts payable, accrued interest and other current assets and liabilities approximate fair value as all amounts reported are to be collected or paid within one year. Our nonfinancial assets and liabilities include our qualified pension and postretirement plan assets and liabilities that are recorded at fair value in the Consolidated Balance Sheets in accordance with employers’ accounting and related disclosures of postretirement plans.

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date, or exit date. We utilize market data or assumptions that market participants would use in valuing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. We primarily apply the market approach for fair value measurements and endeavor to utilize the best available information. Accordingly, we use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The fair value of our financial assets and liabilities are subject to potentially significant volatility based on changes in market prices, the portfolio valuation of our contracts, as well as the maturity and settlement of those contracts, and subsequent newly originated transactions, each of which directly affects the estimated fair value of our financial instruments. We are able to classify fair value balances based on the observance of those inputs at the lowest level that is significant to the fair value measurement, in its entirety, in the following fair value hierarchy levels as set forth in the fair value guidance.

Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities as of the reporting date. Active markets have sufficient frequency and volume to provide pricing information for the asset or liability on an ongoing basis. Our Level 1 items consist of financial instruments of exchange-traded derivatives, investments in marketable securities and benefit plan assets held in registered investment companies and individual stocks.

Level 2 inputs are inputs other than quoted prices in active markets included in Level 1 and are either directly or indirectly corroborated or observable as of the reporting date, generally using valuation methodologies. These methodologies are primarily industry-standard methodologies that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. We obtain market price data from multiple sources in order to value some of our Level 2 transactions and this data is representative of transactions that occurred in the marketplace. Our Level 2 items include non-exchange-traded derivative instruments, such as some qualified pension plan assets held in hedge fund of funds, commodities fund of funds, common trust funds, collateralized mortgage obligations, swaps, futures, currency forwards, corporate bonds and government and agency obligations that are valued at the closing price reported in the active market for similar assets in which the individual securities are traded or based on yields currently available on comparable securities of issuers with similar credit ratings or based on the most recent available financial information for the respective funds and securities. For some qualified pension plan assets, the determination of Level 2 assets was completed through a process of reviewing each individual security while consulting research and other metrics provided by investment managers, including a pricing matrix detailing the pricing source and security type, annual audited financial statements and a review of valuation policies and procedures used by the investment managers as well as our investment advisor.

Level 3 inputs include significant pricing inputs that are generally less observable from objective sources and may be used with internally developed methodologies that result in management’s best estimate of fair value. Our Level 3 inputs include cost estimates for removal (contract fees or manpower/equipment estimates), inflation factors, risk premiums, the remaining life of long-lived assets, the credit adjusted risk free rate to discount for the time value of money over an appropriate time span, and the most recent available financial information of an investment in a diversified private equity fund of funds for some of our qualified pension plan assets. We do not have any other assets or liabilities classified as Level 3.

In determining whether to categorize the fair value measurement of an instrument as Level 2 or Level 3, we must use judgment to assess whether we have the ability as of the measurement date to redeem an investment at its net asset value per share (NAV) in the near term. We consider when we might have the ability to redeem the investment by reviewing contractual restrictions in effect as of the investment date as well as any potential restrictions that the investee may impose. Regarding our benefit plans’ investments, “near term” is the ability to redeem an investment in no more than 180 days.

Transfers between different levels of the fair value hierarchy may occur based on the level of observable inputs used to value the instruments for the period. These transfers represent existing assets or liabilities previously categorized as Level 1 or Level 2 for which the inputs to the estimate became less observable or assets and liabilities previously classified as Level 2 or Level 3 for which the lowest significant input became more observable during the period. Transfers into and out of each level are measured at the actual date of the event or change in circumstances causing the transfer.

For the fair value measurements of our derivatives and marketable securities, see Note 7 to the consolidated financial statements. For the fair value measurements of our benefit plan assets, see Note 9 to the consolidated financial statements.

Goodwill, Equity Method Investments and Long-Lived Assets

Goodwill is the excess of the purchase price over the fair value of identifiable net assets acquired in a business combination. We annually evaluate goodwill for impairment as of October 31, or more frequently if impairment indicators arise during the year. These indicators include, but are not limited to, a significant change in operating performance, the business climate, legal or regulatory factors, or a planned sale or disposition of a significant portion of the business. We test goodwill using a fair value approach at a reporting unit level, generally equivalent to our operating segments as discussed in Note 14 to the consolidated financial statements. An impairment charge would be recognized if the carrying value of the reporting unit, including goodwill, exceeded its fair value. All of our goodwill is attributable to the regulated utility segment.

Our annual goodwill impairment assessment was performed as of October 31, 2014, and we determined that there was no impairment to the carrying value of our goodwill. No impairment was recognized during the years ended October 31, 2014, 2013 and 2012. The fair value of our regulated utility reporting unit substantially exceeds the carrying value, including goodwill.

We review our equity method investments and long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable. In April 2014, we recorded a $2 million write-off for an investment that was accounted for on the cost basis. The write-off was recorded to "Non-operating expense" in the Consolidated Statements of Comprehensive Income. There were no events or circumstances during the years ended October 31, 2013 and 2012 that resulted in any impairment charges. For further information on equity method investments, see Note 12 to the consolidated financial statements.

Marketable Securities

We have marketable securities that are invested in money market and mutual funds that are liquid and actively traded on the exchanges. These securities are assets that are held in rabbi trusts established for our deferred compensation plans. For further information on the deferred compensation plans, see Note 9 to the consolidated financial statements.

We have classified these marketable securities as trading securities since their inception as the assets are held in rabbi trusts. Trading securities are recorded at fair value on the Consolidated Balance Sheets with any gains or losses recognized currently in earnings. We do not intend to engage in active trading of the securities, and participants in the deferred compensation plans may redirect their deemed investments at any time. We have matched the current portion of the deferred compensation liability with the current asset and noncurrent deferred compensation liability with the noncurrent asset; the current portion has been included in “Other current assets” in “Current Assets” in the Consolidated Balance Sheets.

The money market investments in the trusts approximate fair value due to the short period of time to maturity. The fair values of the equity securities are based on quoted market prices as traded on the exchanges. The composition of these securities as of October 31, 2014 and 2013 is as follows.

	2014				2013
In thousands	Cost		Fair Value		Cost		Fair Value
Current trading securities:
Money markets	$	22	$	22	$	—	$	—
Mutual funds	106		192		134		199
Total current trading securities	128		214		134		199
Noncurrent trading securities:
Money markets	447		447		380		380
Mutual funds	2,598		3,280		1,995		2,615
Total noncurrent trading securities	3,045		3,727		2,375		2,995
Total trading securities	$	3,173	$	3,941	$	2,509	$	3,194

Unamortized Debt Expense

Unamortized debt expense consists of costs, such as underwriting and broker dealer fees, discounts and commissions, legal fees, accountant fees, registration fees and rating agency fees, related to issuing long-term debt and the short-term syndicated revolving credit facility. We amortize long-term debt expense on a straight-line basis, which approximates the effective interest method, over the life of the related debt with lives ranging from 5 to 30 years. We amortize bank debt expense over the life of the syndicated revolving credit facility, which is five years.

Should we reacquire long-term debt prior to its term date and simultaneously issue new debt, we defer the gain or loss resulting from the transaction, essentially the remaining unamortized debt expense, and amortize it over the life of the new debt in accordance with established regulatory practice. Where the refunding of the debt is not simultaneous, we defer the gain or loss resulting from the reacquisition of the debt and amortize it over the remaining life of the redeemed debt in accordance with established regulatory practice. For income tax purposes, any gain or loss would be recognized as incurred.

Issuances and Repurchases of Common Stock

As discussed in Note 6 to the consolidated financial statements, from time to time we may repurchase shares on the open market and such shares are then canceled and become authorized but unissued shares. It is our policy to issue new shares for share-based employee awards and shareholder and employee investment plans. We present net shares issued under these awards and plans in “Common Stock Issued” in the Consolidated Statements of Stockholders’ Equity. Shares withheld by us to satisfy tax withholding obligations related to the vesting of shares awarded under the Incentive Compensation Plan have been immaterial to date.

Asset Retirement Obligations

The accounting guidance for AROs addresses the financial accounting and reporting for AROs associated with the retirement of long-lived assets that result from the acquisition, construction, development and operation of the assets. The accounting guidance requires the recognition of the fair value of a liability for AROs in the period in which the liability is incurred if a reasonable estimate of fair value can be made. We have determined that conditional AROs exist for our underground mains and services.

We have costs of removal that are non-legal obligations as defined by the accounting guidance. The costs of removal are a component of our depreciation rates in accordance with long-standing regulatory treatment. Because these estimated removal costs meet the requirements of rate-regulated accounting guidance, we have accounted for these non-legal AROs in “Regulatory Liabilities” as presented in “Rate-Regulated Basis of Accounting” in this Note 1. In the rate setting process, the liability for non-legal costs of removal is treated as a reduction to the net rate base upon which the regulated utility has the opportunity to earn its allowed rate of return. For further discussion of these costs of removal as a component of depreciation, see “Utility Plant and Depreciation” in this Note 1.

We apply the accounting guidance for conditional AROs that requires recognition of a liability for the fair value of conditional AROs when incurred if the liability can be reasonably estimated. The NCUC, the PSCSC and the TRA have approved placing these ARO costs in deferred accounts to preserve the regulatory treatment of these costs; therefore, accretion is not reflected in the Consolidated Statements of Comprehensive Income as the regulatory treatment provides for deferral of the accretion as a regulatory asset with a corresponding deferral of the accretion recorded as a regulatory liability. AROs are capitalized concurrently by increasing the carrying amount of the related asset by the same amount as the regulatory liability. In periods subsequent to the initial measurement, any changes in the liability resulting from the passage of time (accretion) or due to the revisions of either timing or the amount of the originally estimated cash flows to settle conditional AROs must be recognized. The estimated cash flows to settle conditional AROs are discounted using the credit adjusted risk-free rate, which ranged from 4.40% to 5.15% with a weighted average of 5.09% for the twelve months ended October 31, 2014. The estimate was calculated using a time value weighted average credit adjusted risk-free rate. We have recorded a liability on our distribution and transmission mains and services.

The cost of removal obligations recorded in the Consolidated Balance Sheets as of October 31, 2014 and 2013 are presented below.

In thousands	2014		2013
Regulatory non-legal AROs	$	506,574	$	493,111
Conditional AROs	14,647		27,016
Total cost of removal obligations	$	521,221	$	520,127

A reconciliation of the changes in conditional AROs for the year ended October 31, 2014 and 2013 is presented below.

In thousands	2014			2013
Beginning of period	$	27,016		$	28,629
Liabilities incurred during the period	2,108			2,052
Liabilities settled during the period	(3,576		)	(2,389		)
Accretion	1,548			1,641
Adjustment to estimated cash flows	(12,449		)	(2,917		)
End of period	$	14,647		$	27,016

Revenue Recognition

We record revenues when services are provided to our distribution service customers. Utility sales and transportation revenues are based on rates approved by state regulatory commissions. Base rates charged to jurisdictional customers may not be changed without approval by the regulatory commission in that jurisdiction; however, the wholesale cost of gas component of rates may be adjusted periodically under PGA provisions. In North Carolina, a margin decoupling mechanism provides for the recovery of our approved margin from residential and commercial customers on an annual basis independent of weather and consumption patterns. The margin decoupling mechanism provides for semi-annual rate adjustments to refund any over-collection of margin or to recover any under-collection of margin. In South Carolina, a RSA tariff mechanism achieves the objectives of margin decoupling for residential and commercial customers with a one year lag. Under the RSA tariff mechanism, we reset our rates in South Carolina based on updated costs and revenues on an annual basis. In South Carolina and Tennessee, a weather normalization adjustment (WNA) is calculated for residential and commercial customers during the winter heating season November through March, and in Tennessee, the months of April and October. The WNA mechanisms are designed to partially offset the impact that warmer-than-normal or colder-than-normal weather has on customer billings during the winter heating season. The WNA formulas do not ensure full recovery of approved margin during periods when customer consumption patterns vary from those used to establish the WNA factors. In all states, the gas cost portion of our costs is recoverable through PGA procedures and is not affected by the margin decoupling mechanism or the WNA mechanism.

We have integrity management riders (IMRs) in our tariffs in North Carolina, effective February 1, 2014, and in Tennessee effective January 1, 2014, related to our ongoing system integrity programs. These IMRs provide for rate adjustments to allow us to recover and earn on those investments without the necessity of filing general rate cases. The North Carolina IMR was approved in December 2013 in the settlement of our 2013 general rate case. Under the North Carolina IMR tariff, we will make annual filings by November 30 of each year for costs closed to plant through October with revised rates effective the following February 1. The Tennessee IMR tariff was approved in December 2013 with the settlement of our August 2013 IMR filing. Under the Tennessee IMR, we will file to adjust rates to be effective each January 1 based on capital expenditures related to mandated safety and integrity programs that were incurred by the previous October 31. For further discussion of the IMRs, see Note 2 to the consolidated financial statements.

Revenues are recognized monthly on the accrual basis, which includes estimated amounts for gas delivered to customers but not yet billed under the cycle-billing method from the last meter reading date to month end. The unbilled revenue estimate reflects factors requiring judgment related to estimated usage by customer class, customer mix, changes in weather during the period and the impact of the WNA or margin decoupling mechanisms, as applicable.

Secondary market revenues associated with the commodity are recognized when the physical sales are delivered based on contract or market prices. Asset management fees for storage and transportation remitted on a monthly basis are recognized as earned given the monthly capacity costs associated with the contracts involved. Asset management fees remitted in a lump sum are deferred and amortized ratably into income over the period in which they are earned, which is typically the contract term. See Note 2 to the consolidated financial statements regarding revenue sharing of secondary market transactions.

Utility sales, transportation and secondary market revenues are reported net of excise taxes, sales taxes and franchise fees. For further information regarding taxes, see “Taxes” in this Note 1.

Non-regulated merchandise and service work includes the sale, installation and/or maintenance of natural gas appliances and gas piping beyond the meter. Revenue is recognized when the sale is made or the work is performed. If the customer is eligible for and elects financing through us, the finance fee income is recognized on a monthly basis based on principal, rate and term.

Cost of Gas and Deferred Purchased Gas Adjustments

We charge our utility customers for natural gas consumed using natural gas cost recovery mechanisms as set by the regulatory commissions in states in which we operate. Rate schedules for utility sales and transportation customers include PGA provisions that provide for the recovery of prudently incurred gas costs. With regulatory commission approval, we revise rates periodically without formal rate proceedings to reflect changes in the wholesale cost of gas. We charge our secondary market customers for natural gas based on negotiated contract terms. Under PGA provisions, charges to cost of gas are based on the amount recoverable under approved rate schedules. Within our cost of gas, we include amounts for lost and unaccounted for gas and adjustments to reflect the gains and losses associated with gas price hedging derivatives. By jurisdiction, differences between gas costs incurred and gas costs billed to customers, such that no operating margin is recognized related to these costs, are deferred and included in “Amounts due from customers” in “Regulatory Assets” or “Amounts due to customers” in “Regulatory Liabilities” as presented in “Rate-Regulated Basis of Accounting” in this Note 1. We review gas costs and deferral activity periodically (including deferrals under the margin decoupling and WNA mechanisms) and, with regulatory commission approval, increase rates to collect under-recoveries or decrease rates to refund over-recoveries over a subsequent period.

Taxes

We have two categories of income taxes in the Consolidated Statements of Comprehensive Income: current and deferred. Current income tax expense consists of federal and state income taxes less applicable tax credits related to the current year. Deferred income tax expense generally is equal to the changes in the deferred income tax liability and regulatory tax liability during the year. Deferred taxes are primarily attributable to utility plant, deferred gas costs, revenues and cost of gas, equity method investments, benefit of loss carryforwards and employee benefits and compensation. The determination of our provision for income taxes requires judgment, the use of estimates, and the interpretation and application of complex tax laws. Judgment is required in assessing the timing and amounts of deductible and taxable items.

Deferred income taxes are determined based on the estimated future tax effects of differences between the book and tax basis of assets and liabilities. We have provided valuation allowances to reduce the carrying amount of deferred tax assets to amounts that are more likely than not to be realized. To the extent that the establishment of deferred income taxes is different from the recovery of taxes through the ratemaking process, the differences are deferred in accordance with rate-regulated accounting provisions, and a regulatory asset or liability is recognized for the impact of tax expenses or benefits that will be collected from or refunded to customers in different periods pursuant to rate orders.

Deferred investment tax credits, including energy credits, associated with our utility operations are presented in the Consolidated Balance Sheets. We amortize these deferred investment and energy tax credits to income over the estimated useful lives of the property to which the credits relate.

We recognize accrued interest and penalties, if any, related to uncertain tax positions as operating expenses in the Consolidated Statements of Comprehensive Income. This is consistent with the recognition of these items in prior reporting periods.

Excise taxes, sales taxes and franchises fees separately stated on customer bills are recorded on a net basis as liabilities payable to the applicable jurisdictions. All other taxes other than income taxes are recorded as general taxes. General taxes consist of property taxes, payroll taxes, Tennessee gross receipt taxes, franchise taxes, tax on company use and other miscellaneous taxes.

Consolidated Statements of Cash Flows

With respect to cash overdrafts, book overdrafts are included within operating cash flows while any bank overdrafts are included with financing cash flows.

Recently Issued Accounting Guidance

In July 2013, the Financial Accounting Standards Board (FASB) issued accounting guidance on presenting an unrecognized tax benefit when net operating loss (NOL) carryforwards exist. The guidance was issued in an effort to eliminate diversity in practice resulting from a lack of guidance on this topic in current US GAAP. The update provides that an unrecognized tax benefit, or a portion of an unrecognized tax benefit, should be presented in the financial statements as a reduction to a deferred tax asset for a NOL carryforward, a similar tax loss, or a tax credit carryforward, except under certain circumstances outlined in the update. The amendments in the update are effective for annual periods, and interim periods within those periods, beginning after December 15, 2013, with early adoption permitted. The adoption of this disclosure guidance will have no impact on our financial position, results of operations or cash flows.

In May 2014, the FASB and the International Accounting Standards Board issued converged accounting guidance on the recognition of revenue from contracts with customers. Under the new standard, entities will recognize revenue to depict the transfer of goods and services to customers in amounts that reflect the payment to which the entity expects to be entitled in exchange for those goods or services. The disclosure requirements will provide information about the nature, amount, timing and uncertainty of revenue and cash flows from an entity’s contracts with customers. The new guidance is effective for annual periods beginning after December 15, 2016, and interim periods within those periods, which for us is our fiscal year 2018.

An accounting utility subgroup has identified five issues (scope for cost-of-service-tariff sales, contract modifications, variable consideration, multiple element arrangements and sales of real estate) that are not clear within the standard and require revenue implementation guidance. The revenue implementation guide is expected to be published prior to the standard becoming effective in 2017; however, no date has been set.

We are currently evaluating the effect on our financial position, results of operations and cash flows. The evaluation includes identifying revenues streams by like contracts to allow for ease of implementation once the utility sub-group has issued the revenue implementation guide.

In June 2014, the FASB amended accounting guidance to eliminate certain financial reporting requirements for development stage entities, including an amendment to variable interest entity (VIE) guidance. The modification to the guidance may change the consolidation analysis, consolidation decision and disclosure requirements for a reporting entity that has an interest in an entity in the development stage. The amendments in the update are effective for annual periods, and interim periods within those periods, beginning after December 15, 2015, with early adoption permitted. We will consider this guidance regarding our current joint venture investments where the investment infrastructure is under development and any future investments that are development stage projects, particularly any disclosures about risks and uncertainties of the development of the project and our equity method investment.

In August 2014, the FASB issued accounting guidance on determining when and how reporting entities must disclose going concern uncertainties in their financial statements. The new standard requires management to perform interim and annual assessments of an entity's ability to continue as a going concern within one year of the date of issuance of the entity's financial statements. An entity must provide certain disclosures if there is a "substantial doubt about the entity's ability to continue as a going concern." The standard is effective for annual periods ending after December 15, 2016, and interim periods thereafter; early adoption is permitted. The adoption of this assessment will have no impact on our financial position, results of operations or cash flows.

Reclassifications and Changes in Presentation

Reclassifications have been made to certain prior year financial statements to conform with the current year presentation. Within “Cash Flows From Operating Activities” in the Consolidated Statements of Cash Flows, we have changed the presentation of cash flows from regulatory assets and liabilities, previously included within the line items “Other assets” and “Other liabilities,” respectively, to provide additional detail and to present such information within separate line items, “Regulatory assets” and “Regulatory liabilities.”  The 2013 and 2012 presentation has been changed to conform to the current year presentation. The reclassifications had no effect on previously reported amounts for net cash flows from operating, investing or financing activities.

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Long Term Debt (Details) (USD $)	12 Months Ended	1 Months Ended	0 Months Ended
	Oct. 31, 2014	Apr. 30, 2014	Sep. 18, 2014	Aug. 01, 2013	Oct. 31, 2013
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 1,425,000,000				$ 1,275,000,000
Current maturities of long-term debt	0				100,000,000
Discount on issuance of notes	570,000				143,000
Long-term debt	1,424,430,000				1,174,857,000
Long-term Debt, Fiscal Year Maturity [Abstract]
Long-term Debt, Maturities, Repayments of Principal in Next Twelve Months	0
Long-term Debt, Maturities, Repayments of Principal in Year Two	40,000,000
Long-term Debt, Maturities, Repayments of Principal in Year Three	35,000,000
Long-term Debt, Maturities, Repayments of Principal in Year Four	0
Long-term Debt, Maturities, Repayments of Principal in Year Five	0
Long-term Debt, Maturities, Repayments of Principal after Year Five	1,350,000,000
Total Long-term Debt	1,425,000,000				1,275,000,000
Net Earnings Available For Restricted Payments	1,100,000,000
Debt Instrument, Covenant Description	The default provisions of some or all of our senior debt include: Failure to make principal or interest payments, Bankruptcy, liquidation or insolvency, Final judgment against us in excess of $1 million that after 60 days is not discharged, satisfied or stayed pending appeal, Specified events under the Employee Retirement Income Security Act of 1974, Change in control, and Failure to observe or perform covenants, including: Interest coverage of at least 1.75 times. Funded debt cannot exceed 70% of total capitalization. Funded debt of all subsidiaries in the aggregate cannot exceed 15% of total capitalization. Restrictions on permitted liens; Restrictions on paying dividends, on or repurchasing our stock or making investments in subsidiaries; and Restrictions on burdensome agreements.
Senior Debt Default Provision, Interest Coverage Ratio	1.75
Interest Coverage Ratio	4.29
Senior Debt Default Provision, Ratio of Indebtedness to Net Capital	0.7
Ratio of Indebtedness to Net Capital	0.58
Senior Debt Default Provision, Funded Debt of Subsidiaries	0.15
Funded Debt Of Subsidiaries	0
NCUC [Member]
Long-term Debt, Fiscal Year Maturity [Abstract]
Public Utilities, Approved Debt Equity Securities Limit, Amount	1,000,000,000	1,000,000,000
Debt and Equity Shelf Registration, Term	3 years
Unsecured Debt [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	1,425,000,000				1,275,000,000
Long-term Debt, Fiscal Year Maturity [Abstract]
Total Long-term Debt	1,425,000,000				1,275,000,000
Senior Notes 2.92% [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	2.92%
Debt Instrument, Maturity Date	Jun. 06, 2016
Senior Notes 2.92% [Member] | Unsecured Debt [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	40,000,000				40,000,000
Long-term Debt, Fiscal Year Maturity [Abstract]
Total Long-term Debt	40,000,000				40,000,000
Senior Notes 8.51% [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	8.51%
Debt Instrument, Maturity Date	Sep. 30, 2017
Senior Notes 8.51% [Member] | Unsecured Debt [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	35,000,000				35,000,000
Long-term Debt, Fiscal Year Maturity [Abstract]
Total Long-term Debt	35,000,000				35,000,000
Senior Notes 4.24% [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	4.24%
Debt Instrument, Maturity Date	Jun. 06, 2021
Senior Notes 4.24% [Member] | Unsecured Debt [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	160,000,000				160,000,000
Long-term Debt, Fiscal Year Maturity [Abstract]
Total Long-term Debt	160,000,000				160,000,000
Senior Notes 3.47% [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	3.47%
Debt Instrument, Maturity Date	Jul. 16, 2027
Senior Notes 3.47% [Member] | Unsecured Debt [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	100,000,000				100,000,000
Long-term Debt, Fiscal Year Maturity [Abstract]
Total Long-term Debt	100,000,000				100,000,000
Senior Notes 3.57% [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	3.57%
Debt Instrument, Maturity Date	Jul. 16, 2027
Senior Notes 3.57% [Member] | Unsecured Debt [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	200,000,000				200,000,000
Long-term Debt, Fiscal Year Maturity [Abstract]
Total Long-term Debt	200,000,000				200,000,000
Senior Notes 4.10% [Member]
Debt Instrument [Line Items]
Discount on issuance of notes	432,000		435,000
Debt Instrument, Interest Rate, Stated Percentage	4.10%
Debt Instrument, Maturity Date	Sep. 18, 2034
Long-term Debt, Fiscal Year Maturity [Abstract]
Debt Instrument, Face Amount			250,000,000
Debt Instrument, Issuance Date	Sep. 18, 2014
Debt Instrument, Term	20 years
Proceeds from Debt, Net of Issuance Costs			247,700,000
Debt Issuance Discount Percentage			0.174%
Senior Notes 4.10% [Member] | Debt Instrument, Redemption, Period One [Member]
Debt Instrument, Redemption [Line Items]
Debt Instrument, Redemption, Description	redemption price equal to the greater of a) 100% of the principal amount plus any accrued and unpaid interest to the date of redemption, or b) the sum of the present values of the remaining scheduled payments of principal and interest on the notes to be redeemed, discounted to the date of redemption on a semi-annual basis at the Treasury Rate as defined in the indenture, plus 15 basis points and any accrued and unpaid interest to the date of redemption.
Debt Instrument, Redemption Period, Start Date	Sep. 18, 2014
Debt Instrument, Redemption Period, End Date	Mar. 17, 2034
Debt Instrument, Redemption Price, Percentage	100.00%
Senior Notes 4.10% [Member] | Debt Instrument, Redemption, Period One [Member] | Base Rate [Member]
Debt Instrument, Redemption [Line Items]
Debt Instrument Redemption Interest Rate	0.15%
Senior Notes 4.10% [Member] | Debt Instrument, Redemption, Period Two [Member]
Debt Instrument, Redemption [Line Items]
Debt Instrument, Redemption, Description	100% of the principal amount plus any accrued and unpaid interest to the date of redemption.
Debt Instrument, Redemption Period, Start Date	Mar. 18, 2034
Debt Instrument, Redemption Period, End Date	Sep. 18, 2034
Debt Instrument, Redemption Price, Percentage	100.00%
Senior Notes 4.10% [Member] | Unsecured Debt [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	250,000,000				0
Long-term Debt, Fiscal Year Maturity [Abstract]
Total Long-term Debt	250,000,000				0
Senior Notes 4.65% [Member]
Debt Instrument [Line Items]
Discount on issuance of notes	138,000			144,000	143,000
Debt Instrument, Interest Rate, Stated Percentage	4.65%
Debt Instrument, Maturity Date	Aug. 01, 2043
Long-term Debt, Fiscal Year Maturity [Abstract]
Debt Instrument, Face Amount				300,000,000
Debt Instrument, Issuance Date	Aug. 01, 2013
Debt Instrument, Term	30 years
Proceeds from Debt, Net of Issuance Costs				297,200,000
Debt Issuance Discount Percentage				0.048%
Senior Notes 4.65% [Member] | Debt Instrument, Redemption, Period One [Member]
Debt Instrument, Redemption [Line Items]
Debt Instrument, Redemption, Description	redemption price equal to the greater of a) 100% of the principal amount plus any accrued and unpaid interest to the date of redemption, or b) the sum of the present values of the remaining scheduled payments of principal and interest on the notes to be redeemed, discounted to the date of redemption on a semi-annual basis at the Treasury Rate as defined in the indenture, plus 15 basis points and any accrued and unpaid interest to the date of redemption.
Debt Instrument, Redemption Period, Start Date	Aug. 01, 2013
Debt Instrument, Redemption Period, End Date	Jan. 31, 2043
Debt Instrument, Redemption Price, Percentage	100.00%
Senior Notes 4.65% [Member] | Debt Instrument, Redemption, Period One [Member] | Base Rate [Member]
Debt Instrument, Redemption [Line Items]
Debt Instrument Redemption Interest Rate	0.15%
Senior Notes 4.65% [Member] | Debt Instrument, Redemption, Period Two [Member]
Debt Instrument, Redemption [Line Items]
Debt Instrument, Redemption, Description	100% of the principal amount plus any accrued and unpaid interest to the date of redemption.
Debt Instrument, Redemption Period, Start Date	Feb. 01, 2043
Debt Instrument, Redemption Period, End Date	Aug. 01, 2043
Debt Instrument, Redemption Price, Percentage	100.00%
Senior Notes 4.65% [Member] | Unsecured Debt [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	300,000,000				300,000,000
Long-term Debt, Fiscal Year Maturity [Abstract]
Total Long-term Debt	300,000,000				300,000,000
Medium Term Notes 5.00% [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	5.00%
Debt Instrument, Maturity Date	Dec. 19, 2013
Medium Term Notes 5.00% [Member] | Unsecured Debt [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	0				100,000,000
Long-term Debt, Fiscal Year Maturity [Abstract]
Total Long-term Debt	0				100,000,000
Medium Term Notes 6.87% [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	6.87%
Debt Instrument, Maturity Date	Oct. 06, 2023
Medium Term Notes 6.87% [Member] | Unsecured Debt [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	45,000,000				45,000,000
Long-term Debt, Fiscal Year Maturity [Abstract]
Total Long-term Debt	45,000,000				45,000,000
Medium Term Notes 8.45% [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	8.45%
Debt Instrument, Maturity Date	Sep. 19, 2024
Medium Term Notes 8.45% [Member] | Unsecured Debt [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	40,000,000				40,000,000
Long-term Debt, Fiscal Year Maturity [Abstract]
Total Long-term Debt	40,000,000				40,000,000
Medium Term Notes 7.40% [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	7.40%
Debt Instrument, Maturity Date	Oct. 03, 2025
Medium Term Notes 7.40% [Member] | Unsecured Debt [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	55,000,000				55,000,000
Long-term Debt, Fiscal Year Maturity [Abstract]
Total Long-term Debt	55,000,000				55,000,000
Medium Term Notes 7.50% [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	7.50%
Debt Instrument, Maturity Date	Oct. 09, 2026
Medium Term Notes 7.50% [Member] | Unsecured Debt [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	40,000,000				40,000,000
Long-term Debt, Fiscal Year Maturity [Abstract]
Total Long-term Debt	40,000,000				40,000,000
Medium Term Notes 7.95% [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	7.95%
Debt Instrument, Maturity Date	Sep. 14, 2029
Medium Term Notes 7.95% [Member] | Unsecured Debt [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	60,000,000				60,000,000
Long-term Debt, Fiscal Year Maturity [Abstract]
Total Long-term Debt	60,000,000				60,000,000
Medium Term Notes 6.00% [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	6.00%
Debt Instrument, Maturity Date	Dec. 19, 2033
Medium Term Notes 6.00% [Member] | Unsecured Debt [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	100,000,000				100,000,000
Long-term Debt, Fiscal Year Maturity [Abstract]
Total Long-term Debt	$ 100,000,000				$ 100,000,000

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Short Term Debt (Tables)

12 Months Ended

Oct. 31, 2014

Line of Credit Facility [Abstract]

Schedule of Line of Credit Facilities [Table Text Block]

A summary of the short-term debt activity under our CP program for the twelve months ended October 31, 2014 is as follows

In thousands
Minimum amount outstanding	$	275,000
Maximum amount outstanding	$	625,000
Minimum interest rate	.10		%
Maximum interest rate	.43		%
Weighted average interest rate	.19		%

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Long Term Debt (Tables)

12 Months Ended

Oct. 31, 2014

Long-term Debt, Unclassified [Abstract]

Schedule of Long-term Debt Instruments [Table Text Block]

All of our long-term debt is unsecured and is issued at fixed rates. Long-term debt as of October 31, 2014 and 2013 is as follows.

In thousands	2014		2013
Senior Notes:
2.92%, due June 6, 2016	$	40,000	$	40,000
8.51%, due September 30, 2017	35,000		35,000
4.24%, due June 6, 2021	160,000		160,000
3.47%, due July 16, 2027	100,000		100,000
3.57%, due July 16, 2027	200,000		200,000
4.10%, due September 18, 2034	250,000		—
4.65%, due August 1, 2043	300,000		300,000
Medium-Term Notes:
5.00%, due December 19, 2013	—		100,000
6.87%, due October 6, 2023	45,000		45,000
8.45%, due September 19, 2024	40,000		40,000
7.40%, due October 3, 2025	55,000		55,000
7.50%, due October 9, 2026	40,000		40,000
7.95%, due September 14, 2029	60,000		60,000
6.00%, due December 19, 2033	100,000		100,000
Total	1,425,000		1,275,000
Less current maturities	—		100,000
Less discount on issuance of notes *	570		143
Total	$	1,424,430	$	1,174,857

* The discount on the 4.65% senior notes was $138 and $143 at October 31, 2014 and 2013, respectively. The discount on the 4.10% senior notes was $432 at October 31, 2014.

Schedule of Maturities of Long-term Debt [Table Text Block]

Current maturities for the next five years ending October 31 and thereafter are as follows.

In thousands
2015	$	—
2016	40,000
2017	35,000
2018	—
2019	—
Thereafter	1,350,000
Total	$	1,425,000

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Variable Interest Entities (Details) (Variable Interest Entity, Not Primary Beneficiary [Member], USD $) In Thousands, unless otherwise specified	Oct. 31, 2014	Oct. 31, 2013
Variable Interest Entity [Line Items]
Variable Interest Entity, Nonconsolidated, Carrying Amount, Assets	$ 170,171	$ 128,469
Cardinal Pipeline Company [Member]
Variable Interest Entity [Line Items]
Variable Interest Entity, Nonconsolidated, Carrying Amount, Assets	16,073	18,207
Pine Needle Company [Member]
Variable Interest Entity [Line Items]
Variable Interest Entity, Nonconsolidated, Carrying Amount, Assets	18,689	20,270
South Star Energy Services [Member]
Variable Interest Entity [Line Items]
Variable Interest Entity, Nonconsolidated, Carrying Amount, Assets	40,965	38,372
Hardy Storage [Member]
Variable Interest Entity [Line Items]
Variable Interest Entity, Nonconsolidated, Carrying Amount, Assets	37,179	34,681
Constitution Pipeline Company [Member]
Variable Interest Entity [Line Items]
Variable Interest Entity, Nonconsolidated, Carrying Amount, Assets	57,255	16,939
Atlantic Coast Pipeline [Member]
Variable Interest Entity [Line Items]
Variable Interest Entity, Nonconsolidated, Carrying Amount, Assets	$ 10

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Short Term Debt (Details) (USD $)	12 Months Ended
	Oct. 31, 2014	Oct. 31, 2013
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$ 850,000,000
Ratio of Indebtedness to Net Capital	0.58
Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Expiration Date	Oct. 01, 2017
Line of Credit Facility, Current Borrowing Capacity	850,000,000
Line of Credit Facility, Commitment Fee Description	$35,000 plus 8.5 basis
Line of Credit Facility, Frequency of Commitment Fee Payment	annual
Line of Credit Facility, Commitment Fee Amount	35,000
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage	0.085%
Line of Credit Facility, Interest Rate Description	30-day London Interbank Offered Rate (LIBOR) plus from 75 to 125 basis points
Line of Credit Facility, Covenant Terms	total debt to total capitalization of no greater than 70%
Line of Credit Facility, Covenant Compliance	actual ratio was 58%
Debt Covenant Total Debt To Total Capital Ratio	70.00%
Ratio of Indebtedness to Net Capital	0.58
Letter of Credit [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Current Borrowing Capacity	10,000,000	10,000,000
Letters of Credit Outstanding, Amount	1,800,000	2,100,000
Commercial Paper [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Current Borrowing Capacity	850,000,000
Line of Credit Facility, Interest Rate Description	interest based on, among other things, the size and maturity date of the note, the frequency of the issuance and our credit ratings, plus a spread of 5 basis points
Short-term Debt, Description	$850 million unsecured CP program that is backstopped by the revolving syndicated credit facility. The amounts outstanding under the revolving syndicated credit facility and the CP program, either individually or in the aggregate, cannot exceed $850 million. The notes issued under the CP program may have maturities not to exceed 397 days from the date of issuance and bear interest based on, among other things, the size and maturity date of the note, the frequency of the issuance and our credit ratings, plus a spread of 5 basis points. Any borrowings under the CP program rank equally with our other unsecured debt.
Maximum Number Of Possible Days Outstanding For Commercial Paper Program	397 days
Commercial Paper	355,000,000	400,000,000
Short-term Debt, Weighted Average Interest Rate	0.17%	0.36%
Minimum Amount Outstanding During Period	275,000,000
Maximum Amount Outstanding During Period	$ 625,000,000
Commercial Paper [Member] | Minimum [Member]
Line of Credit Facility [Line Items]
Number Days Outstanding From Issuance Until Maturity	4 days
Line of Credit Facility, Interest Rate During Period	0.10%
Commercial Paper [Member] | Maximum [Member]
Line of Credit Facility [Line Items]
Number Days Outstanding From Issuance Until Maturity	28 days
Line of Credit Facility, Interest Rate During Period	0.43%
Commercial Paper [Member] | Weighted Average [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Interest Rate During Period	0.19%
Base Rate [Member] | Commercial Paper [Member]
Line of Credit Facility [Line Items]
Debt Instrument Redemption Interest Rate	0.05%
London Interbank Offered Rate (LIBOR) [Member] | Revolving Credit Facility [Member] | Minimum [Member]
Line of Credit Facility [Line Items]
Debt Instrument Redemption Interest Rate	0.75%
London Interbank Offered Rate (LIBOR) [Member] | Revolving Credit Facility [Member] | Maximum [Member]
Line of Credit Facility [Line Items]
Debt Instrument Redemption Interest Rate	1.25%

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Stockholders' Equity (Tables)

12 Months Ended

Oct. 31, 2014

Stockholders' Equity Note [Abstract]

Schedule of Common Stock Outstanding Roll Forward [Table Text Block]

Changes in common stock for the years ended October 31, 2014, 2013 and 2011 are as follows.

In thousands	Shares		Amount
Balance, October 31, 2011	72,318		$	446,791
Issued to participants in the Employee Stock Purchase Plan (ESPP)	30		894
Issued to the Dividend Reinvestment and Stock Purchase Plan (DRIP)	677		20,508
Issued to participants in the Incentive Compensation Plan (ICP)	25		796
Shares repurchased under Accelerated Share Repurchase (ASR) agreement	(800	)	(26,528		)
Balance, October 31, 2012	72,250		442,461
Issued to ESPP	33		1,056
Issued to DRIP	720		22,791
Issued to ICP	96		3,065
Issuance of common stock through public share offering, net of underwriting fees	3,000		92,640
Costs from issuance of common stock	—		(369		)
Balance, October 31, 2013	76,099		561,644
Issued to ESPP	34		1,143
Issued to DRIP	698		23,443
Issued to ICP	100		3,315
Issuance of common stock through forward sale agreements, net of expenses	1,600		47,290
Balance, October 31, 2014	78,531		$	636,835

Schedule Shares Reserved For Issuance [Table Text Block]

As of October 31, 2014, our shares of common stock were reserved for issuance as follows.

In thousands
ESPP	176
DRIP	840
ICP	950
Total	1,966

Schedule of Accumulated Other Comprehensive Income (Loss) [Table Text Block]

Changes in each component of accumulated OCIL are presented below for the years ended October 31, 2014 and 2013.

Changes in Accumulated OCIL (1)
In thousands	2014			2013
Accumulated OCIL beginning balance, net of tax	$	(284	)	$	(305	)
Hedging activities of equity method investments:
OCIL before reclassifications, net of tax	355			(109		)
Amounts reclassified from accumulated OCIL, net of tax	(284		)	130
Total current period activity of hedging activities of equity method investments, net of tax	71			21
Net current period benefit activities of equity method investments, net of tax	(24		)
Accumulated OCIL ending balance, net of tax	$	(237	)	$	(284	)

⁽¹⁾ Amounts in parentheses indicate debits to accumulated OCIL.

Reclassification out of Accumulated Other Comprehensive Income [Table Text Block]

A reconciliation of the effect on certain line items of net income on amounts reclassified out of each component of accumulated OCIL is presented below for the years ended October 31, 2014 and 2013.

	Reclassification Out of Accumulated OCIL (1)
	Years Ended
	October 31						Affected Line Items on Statement of  Comprehensive Income
In thousands	2014			2013
Hedging activities of equity method investments	$	(461	)	$	215		Income from equity method investments
Income tax expense	177			(85		)	Income taxes
Hedging activities of equity method investments	(284		)	$	130
Net benefit activities of equity method investments	(40		)				Income from equity method investments
Income tax expense	16						Income taxes
Net benefit activities of equity method investments	(24		)
Total reclassification for the period, net of tax	$	(308	)	$	130

⁽¹⁾ Amounts in parentheses indicate debits to accumulated OCIL.

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Financial Instruments & Related Fair Value (Tables)

12 Months Ended

Oct. 31, 2014

Financial Instruments And Related Fair Value Detail [Abstract]

Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block]

We have had no transfers between any level during the years ended October 31, 2014 and 2013.

Recurring Fair Value Measurements as of October 31, 2014
			Significant				Effects of
	Quoted Prices		Other		Significant		Netting and
	in Active		Observable		Unobservable		Cash Collateral		Total
	Markets		Inputs		Inputs		Receivables/		Carrying
In thousands	(Level 1)		(Level 2)		(Level 3)		Payables		Value
Assets:
Derivatives held for distribution operations	$	4,898	$	—	$	—	$	—	$	4,898
Debt and equity securities held as trading securities:
Money markets	469		—		—		—		469
Mutual funds	3,472		—		—		—		3,472
Total fair value assets	$	8,839	$	—	$	—	$	—	$	8,839

Recurring Fair Value Measurements as of October 31, 2013
			Significant				Effects of
	Quoted Prices		Other		Significant		Netting and
	in Active		Observable		Unobservable		Cash Collateral		Total
	Markets		Inputs		Inputs		Receivables/		Carrying
In thousands	(Level 1)		(Level 2)		(Level 3)		Payables		Value
Assets:
Derivatives held for distribution operations	$	1,834	$	—	$	—	$	—	$	1,834
Debt and equity securities held as trading securities:
Money markets	380		—		—		—		380
Mutual funds	2,814		—		—		—		2,814
Total fair value assets	$	5,028	$	—	$	—	$	—	$	5,028

The following table sets forth, by level of the fair value hierarchy, our financial assets that were accounted for at fair value on a recurring basis as of October 31, 2014 and 2013.

Fair Value, by Balance Sheet Grouping [Table Text Block]

The following table presents the fair value and balance sheet classification of our financial options for natural gas as of October 31, 2014 and 2013.

Fair Value of Derivative Instruments
In thousands	2014		2013
Derivatives Not Designated as Hedging Instruments under Derivative Accounting Standards:
Asset Financial Instruments:
Current Assets - Gas purchase derivative assets (December 2014 - November 2015)	$	4,898
Current Assets - Gas purchase derivative assets (December 2013 - October 2014)			$	1,834

The carrying amount and fair value of our long-term debt, including the current portion, which is classified within Level 2, are shown below.

	Carrying
In thousands	Amount *		Fair Value
As of October 31, 2014	$	1,425,000	$	1,617,453
As of October 31, 2013	1,275,000		1,409,892

* Excludes discount on issuance of notes of $570 and $143 as of October 31, 2014 and 2013, respectively.

Amount Of Gain Loss Recognized On Derivatives And Deferred Under PGA Procedures [Table Text Block]

The following table presents the impact that financial instruments not designated as hedging instruments under derivative accounting standards would have had on the Consolidated Statements of Comprehensive Income for the twelve months ended October 31, 2014 and 2013, absent the regulatory treatment under our approved PGA procedures.

	Amount of					Amount of					Location of Gain (Loss)
	Gain (Loss) Recognized					Gain (Loss) Deferred					Recognized through
	on Derivative Instruments					Under PGA Procedures					PGA Procedures
	Twelve Months Ended					Twelve Months Ended
	October 31					October 31
In thousands	2014		2013			2014		2013
Gas purchase options	$	6,162	$	(6,303	)	$	6,162	$	(6,303	)	Cost of Gas

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Consolidated Statements of Stockholders Equity (Parentheticals) (USD $)	12 Months Ended
	Oct. 31, 2014	Oct. 31, 2013	Oct. 31, 2012
Statement of Stockholders' Equity [Abstract]
Dividends declared per share	$ 1.27	$ 1.23	$ 1.19

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Commitment & Contingencies (Tables)

12 Months Ended

Oct. 31, 2014

Commitments and Contingencies Disclosure [Abstract]

Schedule of Rent Expense [Table Text Block]

Operating lease payments for the years ended October 31, 2014, 2013 and 2012 are as follows.

In thousands	2014		2013		2012
Operating lease payments (1)	$	4,701	$	4,729	$	3,712

⁽¹⁾ Operating lease payments do not include payments for common area maintenance, utilities or tax payments.

Schedule of Future Minimum Rental Payments for Operating Leases [Table Text Block]

Future minimum lease obligations for the next five years ending October 31 and thereafter are as follows.

In thousands
2015	$	4,600
2016	4,491
2017	4,297
2018	4,225
2019	4,137
Thereafter	27,359
Total	$	49,109

Long-term Purchase Commitment [Table Text Block]

As of October 31, 2014, future unconditional purchase obligations for the next five years ending October 31 and thereafter are as follows.

	Pipeline		Gas Supply		Telecommunications
	Storage		Reservation		and Information
In thousands	Capacity		Fees		Technology		Other		Total
2015	$	158,984	$	8,657	$	14,601	$	41,008	$	223,250
2016	149,412		137		4,786		—		154,335
2017	145,579		135		736		—		146,450
2018	142,433		—		126		—		142,559
2019	132,186		—		80		—		132,266
Thereafter	627,602		—		—		—		627,602
Total	$	1,356,196	$	8,929	$	20,329	$	41,008	$	1,426,462

Schedule of Environmental Loss Contingencies by Site [Table Text Block]

The following table summarizes information regarding our environmental sites as of October 31, 2014.

			Costs		Undiscounted
	Site		Incurred		Environmental
In thousands	Type	Site Status	to Date		Liability *
Anderson, SC	MGP	Site Investigation Work Plan submitted to the South Carolina Department of Health and Environmental Control.	$	7	$	890
Hickory, NC	MGP	Remediation complete. Land use restrictions in progress.	1,494		18
Reidsville, NC	MGP	Remediation complete. Land use restrictions filed.	641		199
Huntersville, NC	LNG	Soil remediation complete. Quarterly and semi-annual groundwater sampling in progress. Lead-based paint remediation complete.	4,738		81
Charlotte, NC	UST	USTs removed. Tank closure process in progress with the North Carolina Department of Environment and Natural Resources.	32		33
Clemmons, NC	UST	Potential responsible party for propane tank	—		38
Totals			$	6,912	$	1,259
* Estimated based on assumptions using actual costs incurred, the timing of future payments and inflation factors, among others.

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Summary Of Significant Accounting Policies (Details) (USD $)	1 Months Ended	12 Months Ended
	Apr. 30, 2014	Oct. 31, 2014 segment	Oct. 31, 2013	Oct. 31, 2012	Dec. 31, 2013
Segment Reporting [Abstract]
Number of Reportable Segments		3
Regulatory Assets [Line Items]
Regulatory Assets, Current		$ 29,088,000	$ 77,204,000
Regulatory Assets, Noncurrent		184,779,000	169,102,000
Total Regulatory Assets		213,867,000	246,306,000
Other Regulatory Assets On Which We Do Not Earn a Return		98,100,000
Regulatory Liabilities [Line Items]
Regulatory Liability, Current		46,231,000	0
Regulatory Liability, Noncurrent		558,598,000	541,897,000
Total Regulatory Liabilities		604,829,000	541,897,000
Public Utility, Property, Plant and Equipment [Line Items]
Plant held for future use		3,155,000	3,155,000
Intangible plant		3,374,000	3,374,000
Other storage plant		180,058,000	171,349,000
Transmission plant		1,787,990,000	1,403,829,000
Distribution plant		2,623,560,000	2,505,160,000
General plant		421,763,000	335,847,000
Asset retirement cost		11,000	7,565,000
Contributions in aid of construction		(5,259,000)	(5,187,000)
Total utility plant in service		5,011,497,000	4,421,937,000
Less accumulated depreciation		(1,166,922,000)	(1,088,331,000)
Utility plant in service, net		3,844,575,000	3,333,606,000
Construction work in progress		141,693,000	297,717,000
Plant held for future use		3,155,000	3,155,000
Total utility plant, net		3,989,423,000	3,634,478,000
Public Utilities, Property, Plant and Equipment, Amount of Loss (Recovery) on Plant Abandonment			1,800,000
Property, Plant and Equipment [Line Items]
Allowance for borrowed funds used during construction		16,427,000	30,975,000	25,211,000
Composite weighted-average depreciation rates		2.54%	2.77%	2.94%
Accounts, Notes, Loans and Financing Receivable, Net, Current [Abstract]
Gas receivables		64,400,000	78,540,000
Non-regulated merchandise and service work receivables		3,012,000	2,274,000
Allowance for doubtful accounts		(2,152,000)	(1,604,000)	(1,579,000)
Trade accounts receivable		65,260,000	79,210,000
Customers Payment Due Date		30 days
Movement in Valuation Allowances and Reserves [Roll Forward]
Balance at beginning of year		1,604,000	1,579,000	1,347,000
Additions charged to uncollectibles expense		6,959,000	5,314,000	4,584,000
Accounts written off, net of recoveries		(6,411,000)	(5,289,000)	(4,352,000)
Balance at end of year		2,152,000	1,604,000	1,579,000
Inventory, Net [Abstract]
Natural Gas Inventories Not Available For Sale Held by Asset Manager		35,000,000	31,500,000
Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract]
Near Term Redemption		180 days
Goodwill and Intangible Assets Disclosure [Abstract]
Goodwill, Accumulated Impairment Loss		0
Goodwill, Impairment Loss		0	0	0
Asset Impairment Charges	2,000,000		0	0
Investment Measurement [Line Items]
Current trading securities (cost)		128,000	134,000
Noncurrent trading securities(cost)		3,045,000	2,375,000
Current trading securities		214,000	199,000
Noncurrent trading securities		3,727,000	2,995,000
Total trading securities		3,941,000	3,194,000
Total trading securities (cost)		3,173,000	2,509,000
Deferred Finance Costs [Abstract]
Long Term Debt Expense Amortization Period		5 to 30 years
Short Term Debt Expense Amortization Period		5 years
Asset Retirement Obligations [Line Items]
Regulatory non-legal AROs		506,574,000	493,111,000
Conditional cost of removal obligations		14,647,000	27,016,000
Total cost of removal obligations		521,221,000	520,127,000
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning of period		27,016,000	28,629,000
Liabilities incurred during the period		2,108,000	2,052,000
Liabilities settled during the period		(3,576,000)	(2,389,000)
Accretion		1,548,000	1,641,000
Adjustment to estimated cash flows		(12,449,000)	(2,917,000)
End of period		14,647,000	27,016,000	28,629,000
Weighted Average Risk Free Rate		5.09%
Money Market Funds [Member]
Investment Measurement [Line Items]
Current trading securities (cost)		22,000	0
Noncurrent trading securities(cost)		447,000	380,000
Current trading securities		22,000	0
Noncurrent trading securities		447,000	380,000
Total trading securities		469,000	380,000
Equity Funds [Member]
Investment Measurement [Line Items]
Current trading securities (cost)		106,000	134,000
Noncurrent trading securities(cost)		2,598,000	1,995,000
Current trading securities		192,000	199,000
Noncurrent trading securities		3,280,000	2,615,000
Total trading securities		3,472,000	2,814,000
Minimum [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life		5 years
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Credit Adjusted Risk Free Rate		4.40%
Maximum [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life		80 years
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Credit Adjusted Risk Free Rate		5.15%
Land Costs [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Plant held for future use				3,200,000
Plant held for future use				3,200,000
Non-real Estate Costs [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Plant held for future use				3,500,000
Plant held for future use				3,500,000
Amount Due To Customers
Regulatory Liabilities [Line Items]
Regulatory Liability, Current		46,231,000	0
Asset Retirement Obligation Costs [Member]
Regulatory Liabilities [Line Items]
Regulatory Liability, Noncurrent		506,574,000	493,111,000
Deferred Income Tax Charge [Member]
Regulatory Liabilities [Line Items]
Regulatory Liability, Noncurrent		51,930,000	48,647,000
Amounts Not Yet Recognized As Component Of Pension and Other Post Retirement Benefit Costs [Member]
Regulatory Liabilities [Line Items]
Regulatory Liability, Noncurrent		94,000	139,000
NCUC [Member]
Property, Plant and Equipment [Line Items]
Depreciation Study Requirement		5 years
Unamortized debt expense
Regulatory Assets [Line Items]
Regulatory Assets, Current		1,490,000	1,274,000
Regulatory Assets, Noncurrent		15,402,000	14,149,000
Amounts due from customers
Regulatory Assets [Line Items]
Regulatory Assets, Current		16,108,000	66,321,000
Environmental costs
Regulatory Assets [Line Items]
Regulatory Assets, Current		1,568,000	1,480,000
Regulatory Assets, Noncurrent		6,470,000	7,936,000
Total Regulatory Assets		8,000,000
Environmental costs | PSCSC [Member] | Settlement With Office of Regulatory Staff October 2014 [Member]
Regulatory Assets [Line Items]
Regulatory Assets, Current		100,000
Total Regulatory Assets		100,000
Amortization Time Period For Specified Expenses		1 year
Regulatory Noncurrent Asset, End Date for Recovery		Oct. 31, 2015
Deferred operations and maintenance expenses
Regulatory Assets [Line Items]
Regulatory Assets, Current		916,000	739,000
Regulatory Assets, Noncurrent		4,721,000	5,637,000
Deferred operations and maintenance expenses | NCUC [Member]
Regulatory Assets [Line Items]
Total Regulatory Assets		5,600,000	6,400,000
Deferred pipeline integrity expenses
Regulatory Assets [Line Items]
Regulatory Assets, Current		3,470,000	3,149,000
Regulatory Assets, Noncurrent		24,694,000	16,300,000
Deferred pipeline integrity expenses | NCUC [Member]
Regulatory Assets [Line Items]
Total Regulatory Assets		28,200,000	19,400,000
Deferred pension and other retirement benefits costs
Regulatory Assets [Line Items]
Regulatory Assets, Current		2,769,000	2,768,000
Regulatory Assets, Noncurrent		18,799,000	17,968,000
Amounts Not Yet Recognized As Component Of Pension and Other Post Retirement Benefit Costs [Member]
Regulatory Assets [Line Items]
Regulatory Assets, Noncurrent		94,265,000	80,604,000
Asset Retirement Obligation Costs [Member]
Regulatory Assets [Line Items]
Regulatory Assets, Noncurrent		18,275,000	22,974,000
Amount Of Regulatory Costs Approved To Be Accrued Not Included In Rate Base		18,300,000
Robeson LNG Development Cost [Member]
Regulatory Assets [Line Items]
Regulatory Assets, Current		917,000	382,000
Regulatory Assets, Noncurrent		509,000	1,426,000
Robeson LNG Development Cost [Member] | NCUC [Member] | General Rate Application Settlement 2013 [Member]
Regulatory Assets [Line Items]
Total Regulatory Assets					1,200,000
Amortization Time Period For Specified Expenses		38 months
Regulatory Noncurrent Asset, End Date for Recovery		Feb. 28, 2017
Robeson LNG Development Cost [Member] | PSCSC [Member] | Settlement With Office of Regulatory Staff October 2014 [Member]
Regulatory Assets [Line Items]
Regulatory Assets, Current		500,000
Amortization Time Period For Specified Expenses		12 months
Regulatory Noncurrent Asset, End Date for Recovery		Oct. 31, 2015
Other Regulatory Assets (Liabilities) [Member]
Regulatory Assets [Line Items]
Regulatory Assets, Current		1,850,000	1,091,000
Regulatory Assets, Noncurrent		$ 1,644,000	$ 2,108,000

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Income Taxes Income Tax Examination (Details) (Internal Revenue Service (IRS) [Member])	12 Months Ended
	Oct. 31, 2014
Tax Year 2010 [Member]
Income Tax Examination [Line Items]
Income Tax Examination, Year under Examination	2010
Tax Year 2011 [Member]
Income Tax Examination [Line Items]
Income Tax Examination, Year under Examination	2011
Tax Year 2012 [Member]
Income Tax Examination [Line Items]
Income Tax Examination, Year under Examination	2012

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Consolidated Balance Sheets (USD $) In Thousands, unless otherwise specified	Oct. 31, 2014	Oct. 31, 2013
Utility Plant:
Utility plant in service	$ 5,011,497	$ 4,421,937
Less accumulated depreciation	1,166,922	1,088,331
Utility plant in service, net	3,844,575	3,333,606
Construction work in progress	141,693	297,717
Plant held for future use	3,155	3,155
Total utility plant, net	3,989,423	3,634,478
Other Physical Property, at cost (net of accumulated depreciation of $904 in 2014 and $876 in 2013)	355	382
Current Assets:
Cash and cash equivalents	9,643	8,063
Trade accounts receivable (less allowance for doubtful accounts of $2,152 in 2014 and $1,604 in 2013)	65,260	79,210
Income taxes receivable	36,100	31,065
Other receivables	3,361	1,988
Unbilled utility revenues	21,093	24,967
Inventories:
Gas in storage	84,081	73,929
Materials, supplies and merchandise	1,652	1,725
Gas purchase derivative assets, at fair value	4,898	1,834
Regulatory assets	29,088	77,204
Prepayments	39,030	35,038
Deferred income taxes	53,418	12,695
Other current assets	326	338
Total current assets	347,950	348,056
Noncurrent Assets:
Equity method investments in non-utility activities	170,171	128,469
Goodwill	48,852	48,852
Regulatory assets	184,779	169,102
Marketable securities, at fair value	3,727	2,995
Overfunded postretirement asset	33,757	28,258
Other noncurrent assets	5,239	8,017
Total noncurrent assets	446,525	385,693
Total	4,784,253	4,368,609
Stockholders’ equity:
Cumulative preferred stock - no par value - 175 shares authorized	0	0
Common stock – no par value – shares authorized: 200,000; shares outstanding: 78,531 in 2014 and 76,099 in 2013	636,835	561,644
Retained earnings	672,004	627,236
Accumulated other comprehensive loss	(237)	(284)
Total stockholders’ equity	1,308,602	1,188,596
Long-term debt	1,424,430	1,174,857
Total capitalization	2,733,032	2,363,453
Current Liabilities:
Current maturities of long-term debt	0	100,000
Short-term debt	355,000	400,000
Trade accounts payable	85,299	96,281
Other accounts payable	54,349	43,855
Accrued interest	27,982	28,205
Customers’ deposits	19,994	19,831
General taxes accrued	23,828	21,454
Regulatory liabilities	46,231	0
Other current liabilities	9,303	7,024
Total current liabilities	621,986	716,650
Noncurrent Liabilities:
Deferred income taxes	809,467	681,369
Unamortized federal investment tax credits	1,193	1,402
Accumulated provision for postretirement benefits	15,471	12,042
Regulatory liabilities	558,598	541,897
Conditional cost of removal obligations	14,647	27,016
Other noncurrent liabilities	29,859	24,780
Total noncurrent liabilities	1,429,235	1,288,506
Commitments and Contingencies
Total	$ 4,784,253	$ 4,368,609

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Stockholders' Equity (Details) (USD $)	0 Months Ended					3 Months Ended								12 Months Ended			0 Months Ended
	Dec. 16, 2013	Feb. 04, 2013	Jan. 29, 2013	Feb. 28, 2012	Jan. 05, 2012	Oct. 31, 2014	Jul. 31, 2014	Apr. 30, 2014	Jan. 31, 2014	Oct. 31, 2013	Jul. 31, 2013	Apr. 30, 2013	Jan. 31, 2013	Oct. 31, 2014	Oct. 31, 2013	Oct. 31, 2012	Feb. 19, 2013	Dec. 16, 2005	Sep. 30, 2004	Mar. 06, 2009
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Common Stock, Shares, Outstanding, Beginning Balance									76,099,000				72,250,000	76,099,000	72,250,000	72,318,000
Common Stock, Value, Issued, Beginning Balance									$ 561,644,000				$ 442,461,000	$ 561,644,000	$ 442,461,000	$ 446,791,000
Stock Issued During Period, Shares, Employee Stock Purchase Plans														34,000	33,000	30,000
Stock Issued During Period, Value, Employee Stock Purchase Plan														1,143,000	1,056,000	894,000
Stock Issued During Period, Shares, Dividend Reinvestment Plan														698,000	720,000	677,000
Stock Issued During Period, Value, Dividend Reinvestment Plan														23,443,000	22,791,000	20,508,000
Shares Issued During Period Shares Incentive Compensation Plan (ICP)														100,000	96,000	25,000
Shares Issued During Period Value Incentive Compensation Plan (ICP)														3,315,000	3,065,000	796,000
Shares Repurchased During Period Shares Accelerated Share Repurchase (ASR) Plan					(800,000)											(800,000)
Shares repurchased under Accelerated Share Repurchase (ASR) agreement																(26,528,000)
Issuance of commons stock shares through public share offering, net of underwriting fees	1,600,000.0	3,000,000												1,600,000	3,000,000
Issuance of common stock through public share offering, net of underwriting fees														47,290,000	92,640,000
Expenses from Issuance of Common Stock														(12,000)	(369,000)
Common Stock, Shares, Outstanding, Ending Balance						78,531,000				76,099,000				78,531,000	76,099,000	72,250,000
Common Stock, Value, Issued, Ending Balance						636,835,000				561,644,000				636,835,000	561,644,000	442,461,000
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated OCIL beginning balance, net of tax									(284,000)				(305,000)	(284,000)	(305,000)
Total other comprehensive income														47,000	21,000	147,000
Accumulated OCIL ending balance, net of tax						(237,000)				(284,000)				(237,000)	(284,000)	(305,000)
Accelerated Share Repurchases, Initial Price Paid Per Share					$ 33.77
Stock Repurchased During Period Value At Initial Price ASR Plan					(27,000,000)
Accelerated Share Repurchases, Settlement (Payment) or Receipt				500,000
Accelerated Share Repurchases Weighted Average Purchase Price Per Share				$ 33.25
Accelerated Share Repurchases Discount On Weighted Average Purchase Price Per Share				$ 0.09
Accelerated Share Repurchases, Final Price Paid Per Share				$ 33.16
Class of Stock [Line Items]
Common Stock, Capital Shares Reserved for Future Issuance						1,966,000								1,966,000
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Income (Loss) from Equity Method Investments														32,753,000	26,056,000	23,904,000
Income taxes														(11,642,000)	(8,612,000)	(9,116,000)
Net Income						(8,967,000)	(7,344,000)	62,540,000	97,572,000	(5,003,000)	(2,293,000)	55,790,000	85,923,000	143,801,000	134,417,000	119,847,000
Forward Contract Indexed to Issuer's Equity [Line Items]
Maximum Number Of Shares To Be Purchased			4,600,000
Common Stock Issued, Value	47,300,000	92,600,000												75,203,000	119,552,000	22,198,000
Common Stock Issued, Shares	1,600,000.0	3,000,000												1,600,000	3,000,000
Shares Issued, Price Per Share		$ 32
Underwriter Discount		$ 1.12
Net Settlement Price Per Share	$ 30.88	$ 30.88
Forward Contract Indexed to Issuer's Equity, Settlement Date														Dec. 16, 2013
Combined Forward Sale Agreements [Member]
Forward Contract Indexed to Issuer's Equity [Line Items]
Forward Contract Indexed to Issuer's Equity, Shares		1,600,000.0
Forward Sale Agreement [Member]
Forward Contract Indexed to Issuer's Equity [Line Items]
Forward Contract Indexed to Issuer's Equity, Shares		1,000,000
Additional Forward Sale Agreement [Member]
Forward Contract Indexed to Issuer's Equity [Line Items]
Shares Option To Purchase Exercised By Underwriters																	600,000
Additional Forward Sale Agreement [Member] | Maximum [Member]
Forward Contract Indexed to Issuer's Equity [Line Items]
Forward Contract Indexed to Issuer's Equity, Indexed Shares		600,000.0
Reclassification out of Accumulated Other Comprehensive Income [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Net Income														(308,000)	130,000
Common Stock Open Market Purchase Program [Member]
Class of Stock [Line Items]
Stock Repurchase Program, Number of Shares Authorized to be Repurchased																		6,000,000	3,000,000
ASR Program [Member]
Class of Stock [Line Items]
Additional Authorized Common Stock Repurchases Shares																		4,000,000
Common Stock Open Market Purchase Program and ASR Program [Member]
Class of Stock [Line Items]
Stock Repurchase Program, Number of Shares Authorized to be Repurchased																		10,000,000
Additional Authorized Common Stock Repurchases Shares																				4,000,000
Employee Stock Purchase Plan [Member]
Class of Stock [Line Items]
Common Stock, Capital Shares Reserved for Future Issuance						176,000								176,000
Dividend Reinvestment Plan [Member]
Class of Stock [Line Items]
Common Stock, Capital Shares Reserved for Future Issuance						840,000								840,000
Stock Compensation Plan [Member]
Class of Stock [Line Items]
Common Stock, Capital Shares Reserved for Future Issuance						950,000								950,000
Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax														355,000	(109,000)
Amounts reclassified, net of tax														(284,000)	130,000
Total other comprehensive income														71,000	21,000
Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Income (Loss) from Equity Method Investments														(461,000)	215,000
Income taxes														177,000	(85,000)
Net Income														(284,000)	130,000
Accumulated Defined Benefit Plans Adjustment [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Total other comprehensive income														(24,000)
Accumulated Defined Benefit Plans Adjustment [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Income (Loss) from Equity Method Investments														(40,000)
Income taxes														16,000
Net Income														$ (24,000)

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Consolidated Statements Of Cash Flows (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Oct. 31, 2014	Oct. 31, 2013	Oct. 31, 2012
Cash Flows from Operating Activities:
Net income	$ 143,801	$ 134,417	$ 119,847
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	129,343	120,797	109,230
Allowance for doubtful accounts	548	25	232
Impairment loss on investment	2,000	0	0
Net gain on sale of property	(817)	(349)	0
Income from equity method investments	(32,753)	(26,056)	(23,904)
Distributions of earnings from equity method investments	24,843	22,139	19,590
Deferred income taxes, net	87,136	57,637	99,159
Changes in assets and liabilities:
Gas purchase derivatives, at fair value	(3,064)	1,319	(381)
Receivables	16,196	(23,327)	5,403
Inventories	(10,079)	(2,059)	18,897
Settlement of legal asset retirement obligations	(3,575)	(2,389)	(2,038)
Regulatory assets	20,297	43,338	(93,268)
Other assets	(2,829)	4,629	(2,314)
Accounts payable	18	2,381	4,283
Provision for postretirement benefits, net	(2,070)	(53,515)	45,507
Regulatory liabilities	49,468	23,429	(2,990)
Other liabilities	12,149	10,831	7,262
Net cash provided by operating activities	430,612	313,247	304,515
Cash Flows from Investing Activities:
Utility capital expenditures	(460,444)	(599,999)	(529,576)
Allowance for borrowed funds used during construction	(16,427)	(30,975)	(25,211)
Contributions to equity method investments	(37,642)	(41,348)	(3,566)
Distributions of capital from equity method investments	3,929	4,700	5,372
Proceeds from sale of property	1,883	1,951	1,250
Investments in marketable securities	(454)	(414)	(606)
Other	4,708	2,609	3,044
Net cash used in investing activities	(504,447)	(663,476)	(549,293)
Cash Flows from Financing Activities:
Borrowings under credit facility	0	10,000	350,000
Repayments under credit facility	0	(10,000)	(681,000)
Net (repayments) borrowings - commercial paper	(45,000)	35,000	365,000
Proceeds from issuance of long-term debt, net of discount	249,565	299,856	300,000
Repayment of long-term debt	(100,000)	0	0
Expenses related to issuance of debt	(2,871)	(3,250)	(3,908)
Proceeds from issuance of common stock, net of expenses	47,290	92,271	0
Issuance of common stock through dividend reinvestment and employee stock plans	25,556	24,610	22,123
Repurchases of common stock	0	0	(26,528)
Dividends paid	(99,151)	(92,146)	(85,693)
Other	26	(8)	(34)
Net cash provided by financing activities	75,415	356,333	239,960
Net Increase (Decrease) in Cash and Cash Equivalents	1,580	6,104	(4,818)
Cash and Cash Equivalents at Beginning of Year	8,063	1,959	6,777
Cash and Cash Equivalents at End of Year	9,643	8,063	1,959
Cash Paid During the Year for:
Interest	64,276	50,275	44,571
Income Taxes:
Income taxes paid	10,840	5,760	4,770
Income taxes refunded	30	169	8,437
Income taxes, net	10,810	5,591	(3,667)
Noncash Investing and Financing Activities:
Accrued construction expenditures	$ 38,869	$ 39,389	$ 43,643

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Income Taxes (Tables)

12 Months Ended

Oct. 31, 2014

Income Tax Disclosure [Abstract]

Schedule of Components of Income Tax Expense (Benefit) [Table Text Block]

The components of income tax expense for the years ended October 31, 2014, 2013 and 2012 are presented below.

	2014					2013						2012
In thousands	Federal			State		Federal			State			Federal			State
Charged (Credited) to operating
income:
Current (1)	$	(1,653	)	$	950	$	(3,032	)	$	919		$	(29,062	)	$	1,857
Deferred (1)	70,654			13,434		67,885			11,829			86,496			10,144
Tax Credits:
Amortization	(209		)	—		(267		)	—			(334		)	—
Total	68,792			14,384		64,586			12,748			57,100			12,001
Charged (Credited) to other income
(expense):
Current	4,233			870		6,049			984			5,636			1,027
Deferred	5,811			728		2,225			(646		)	2,214			239
Total	10,044			1,598		8,274			338			7,850			1,266
Total	$	78,836		$	15,982	$	72,860		$	13,086		$	64,950		$	13,267

⁽¹⁾ Includes utilization of federal NOL carryforward benefit of $28.6 million for the year ended October 31, 2014 and the generation of a NOL carryforward benefit of $62.3 million for the year ended October 31, 2013.

Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]

A reconciliation of income tax expense at the federal statutory rate to recorded income tax expense for the years ended October 31, 2014, 2013 and 2012 is presented below.

In thousands	2014			2013			2012
Federal taxes at 35%	$	83,517		$	77,127		$	69,322
State income taxes, net of federal benefit	10,389			8,506			8,624
Amortization of investment tax credits	(209		)	(267		)	(334		)
Other, net	1,121			580			605
Total	$	94,818		$	85,946		$	78,217

Schedule of Deferred Tax Assets and Liabilities [Table Text Block]

As of October 31, 2014 and 2013, deferred income taxes consisted of the following temporary differences.

In thousands	2014			2013
Deferred tax assets:
Benefit of loss carryforwards	$	39,532		$	66,087
Revenues and cost of gas	4,960			—
Employee benefits and compensation	16,547			13,834
Revenue requirement	20,320			19,062
Utility plant	5,631			10,386
Other	12,869			12,796
Total deferred tax assets	99,859			122,165
Valuation allowance	(505		)	(505		)
Total deferred tax assets, net	99,354			121,660
Deferred tax liabilities:
Utility plant	724,172			652,822
Revenues and cost of gas	4,340			21,257
Equity method investments	42,998			38,710
Deferred costs	65,828			59,221
Other	18,065			18,324
Total deferred tax liabilities	855,403			790,334
Net deferred income tax liabilities	$	756,049		$	668,674

Summary of Valuation Allowance [Table Text Block]

A reconciliation of changes in the deferred tax valuation allowance for the years ended October 31, 2014, 2013 and 2012 is presented below.

In thousands	2014		2013		2012
Balance at beginning of year	$	505	$	505	$	505
Credited to income tax expense	—		—		—
Balance at end of year	$	505	$	505	$	505

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Business Segments

12 Months Ended

Oct. 31, 2014

Segment Reporting [Abstract]

Segment Reporting Disclosure [Text Block]

Business Segments

We have three reportable business segments, regulated utility, regulated non-utility activities and unregulated non-utility activities. Our segments are identified based on products and services, regulatory environments and our current corporate organization and business decision-making activities. The regulated utility segment is the gas distribution business, where we include the operations of merchandising and its related service work and home service agreements, with activities conducted by the parent company. Although the operations of our regulated utility segment are located in three states under the jurisdiction of individual state regulatory commissions, the operations are managed as one unit having similar economic and risk characteristics within one company.

Prior to this fiscal year ended October 31, 2014, we aggregated the regulated non-utility activities and unregulated non-utility activities into one segment, the non-utility activities segment. These activities shared a majority of characteristics that permitted aggregation under relevant accounting guidance. Based on this accounting guidance, the unaggregated operating activities individually have never met the quantitative thresholds for separate disclosure. In September 2014 with the formation of ACP and our equity membership in the venture, our current and future commitment to fund construction of regulated pipelines through our equity method investments became more significant and, as a result, we have changed our segment presentation to separately disclose our non-utility activities into regulated non-utility and unregulated non-utility activities. The effect on our company's risk profile of regulation versus non-regulation of our equity method investments and management’s view that this segmentation will provide disclosures that will help users of our financial statements to better understand how management assesses organizational performance and makes decisions about the allocation of resources were key factors in our decision to modify our reportable segments. We anticipate significant growth in our regulated non-utility activities as compared to our unregulated non-utility activities. This is especially so given our equity ownership in Constitution and ACP, both FERC regulated pipelines. Once these pipelines are in operation, the earnings contribution is expected to increase for this segment.

Operations of our regulated non-utility activities segment are comprised of our equity method investments in joint ventures with regulated activities that are held by our wholly-owned subsidiaries. Operations of our unregulated non-utility activities segment are comprised primarily of our equity method investment in a joint venture with unregulated activities that is held by a wholly-owned subsidiary; activities of our other minor subsidiaries are also included.

Operations of the regulated utility segment are reflected in “Operating Income” in the Consolidated Statements of Comprehensive Income. Operations of the regulated non-utility activities and unregulated non-utility activities segments are included in the Consolidated Statements of Comprehensive Income in “Other Income (Expense)” in “Income from equity method investments” and “Non-operating income.” All of our operations are within the United States. No single customer accounts for more than 10% of our consolidated revenues.

Operations by segment for the years ended October 31, 2014, 2013 and 2012, and as of October 31, 2014, 2013 and 2012 are presented below. The information provided for fiscal years 2013 and 2012 have been restated to align with management's view of the non-utility activities.

			Regulated			Unregulated
	Regulated		Non-Utility			Non-Utility
In thousands	Utility		Activities			Activities			Total
2014
Revenues from external customers	$	1,469,988	$	—		$	—		$	1,469,988
Margin	690,208		—			—			690,208
Operations and maintenance expenses	270,877		132			92			271,101
Depreciation	118,996		—			18			119,014
Operating income (loss) before income taxes	263,041		(183		)	(203		)	262,655
Income from equity method investments	—		12,318			20,435			32,753
Interest expense	54,686		—			—			54,686
Income before income taxes	206,253		12,135			20,231			238,619
Total assets	4,442,185		129,206			41,309			4,612,700
Equity method investments in non-utility activities	—		129,206			40,965			170,171
Construction expenditures	460,444		—			—			460,444
			Regulated			Unregulated
	Regulated		Non-Utility			Non-Utility
In thousands	Utility		Activities			Activities			Total
2013
Revenues from external customers	$	1,278,229	$	—		$	—		$	1,278,229
Margin	621,490		—			—			621,490
Operations and maintenance expenses	253,120		103			78			253,301
Depreciation	112,207		—			18			112,225
Operating income (loss) before income taxes	221,528		(150		)	(202		)	221,176
Income from equity method investments	—		10,584			15,472			26,056
Interest expense	24,938		—			—			24,938
Income before income taxes	194,659		10,434			15,270			220,363
Total assets	4,053,591		90,097			38,735			4,182,423
Equity method investments in non-utility activities	—		90,097			38,372			128,469
Construction expenditures	599,999		—			—			599,999
			Regulated			Unregulated
	Regulated		Non-Utility			Non-Utility
In thousands	Utility		Activities			Activities			Total
2012
Revenues from external customers	$	1,122,780	$	—		$	—		$	1,122,780
Margin	575,446		—			—			575,446
Operations and maintenance expenses	242,599		31			71			242,701
Depreciation	103,192		—			18			103,210
Operating income (loss) before income taxes	194,824		(78		)	(186		)	194,560
Income from equity method investments	—		9,709			14,195			23,904
Interest expense	20,097		—			—			20,097
Income before income taxes	174,424		9,631			14,009			198,064
Total assets	3,475,640		69,749			18,498			3,563,887
Equity method investments in non-utility activities	—		69,749			18,118			87,867
Construction expenditures	529,576		—			—			529,576

Reconciliations to the consolidated financial statements for the years ended October 31, 2014, 2013 and 2012, and as of October 31, 2014 and 2013 are as follows.

In thousands	2014			2013			2012
Operating Income:
Segment operating income before income taxes	$	262,655		$	221,176		$	194,560
Utility income taxes	(83,176		)	(77,334		)	(69,101		)
Regulated non-utility activities operating loss before income taxes	183			150			78
Unregulated non-utility activities operating loss before income taxes	203			202			186
Total	$	179,865		$	144,194		$	125,723
Net Income:
Income before income taxes for reportable segments	$	238,619		$	220,363		$	198,064
Income taxes	(94,818		)	(85,946		)	(78,217		)
Total	$	143,801		$	134,417		$	119,847

In thousands	2014		2013
Consolidated Assets:
Total assets for reportable segments	$	4,612,700	$	4,182,423
Eliminations/Adjustments	171,553		186,186
Total	$	4,784,253	$	4,368,609

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Equity Method Investments (Tables)

12 Months Ended

Oct. 31, 2014

Equity Method Investments and Joint Ventures [Abstract]

Equity Method Investments [Table Text Block]

We have related party transactions as a transportation customer of Cardinal, and we record the transportation costs charged by Cardinal in “Cost of Gas” in the Consolidated Statements of Comprehensive Income. For each of the years ended October 31, 2014, 2013 and 2012, these transportation costs and the amounts we owed Cardinal as of October 31, 2014 and 2013 are as follows.

In thousands	2014		2013		2012
Transportation costs	$	8,825	$	8,775	$	6,613
Trade accounts payable	747		755

We have related party transactions as a customer of Hardy Storage, and we record the storage costs charged by Hardy Storage in “Cost of Gas” in the Consolidated Statements of Comprehensive Income. For the years ended October 31, 2014, 2013 and 2012, these gas storage costs and the amounts we owed Hardy Storage as of October 31, 2014 and 2013 are as follows.

In thousands	2014		2013		2012
Gas storage costs	$	9,461	$	9,702	$	9,702
Trade accounts payable	774		808

Summarized financial information provided to us by Hardy Storage for 100% of Hardy Storage as of October 31, 2014 and 2013, and for the twelve months ended October 31, 2014, 2013 and 2012 is presented below.

In thousands	2014		2013		2012
Current assets	$	12,644	$	7,641
Noncurrent assets	157,861		161,282
Current liabilities	17,316		12,378
Noncurrent liabilities	78,830		87,184
Revenues	23,804		24,375		$	24,359
Gross profit	23,804		24,375		24,359
Income before income taxes	10,497		10,582		9,939

Summarized financial information provided to us by Cardinal for 100% of Cardinal as of September 30, 2014 and 2013, and for the twelve months ended September 30, 2014, 2013 and 2012 is presented below.

In thousands	2014		2013		2012
Current assets	$	8,856	$	15,179
Noncurrent assets	111,881		116,414
Current liabilities	1,468		2,637
Noncurrent liabilities	45,402		45,273
Revenues	16,705		17,649		$	16,165
Gross profit	16,705		17,649		16,165
Income before income taxes	8,042		9,361		10,433

We have related party transactions as we sell wholesale gas supplies to SouthStar, and we record the amounts billed to SouthStar in “Operating Revenues” in the Consolidated Statements of Comprehensive Income. For the years ended October 31, 2014, 2013 and 2012, our operating revenues from these sales and the amounts SouthStar owed us as of October 31, 2014 and 2013 are as follows.

In thousands	2014		2013		2012
Operating revenues	$	3,541	$	3,291	$	2,442
Trade accounts receivable	460		441

Summarized financial information provided to us by SouthStar for 100% of SouthStar as of September 30, 2014 and 2013, and for the twelve months ended September 30, 2014, 2013 and 2012 is presented below.

In thousands	2014		2013*		2012
Current assets	$	196,286	$	199,425
Noncurrent assets	143,420		147,571
Current liabilities	51,435		76,346
Noncurrent liabilities	83		31
Revenues	845,695		639,426		$	585,291
Gross profit	234,581		174,993		161,122
Income before income taxes	136,569		102,805		94,631

* Amounts have been changed to reflect restatement of AGL's Form 10-K for the year ended December 31, 2013. The restatement had an immaterial impact on SouthStar's results.

We have related party transactions as a customer of Pine Needle, and we record the storage costs charged by Pine Needle in “Cost of Gas” in the Consolidated Statements of Comprehensive Income. For the years ended October 31, 2014, 2013 and 2012, these gas storage costs and the amounts we owed Pine Needle as of October 31, 2014 and 2013 are as follows.

In thousands	2014		2013		2012
Gas storage costs	$	11,364	$	11,098	$	10,410
Trade accounts payable	989		940

Summarized financial information provided to us by Pine Needle for 100% of Pine Needle as of September 30, 2014 and 2013, and for the twelve months ended September 30, 2014, 2013 and 2012 is presented below.

In thousands	2014		2013		2012
Current assets	$	8,812	$	9,225
Noncurrent assets	70,837		74,710
Current liabilities	38,029		3,531
Noncurrent liabilities	—		35,391
Revenues	18,025		16,810		$	16,390
Gross profit	18,025		16,810		16,390
Income before income taxes	6,011		5,804		5,832

Summarized financial information provided to us by Constitution for 100% of Constitution as of September 30, 2014 and 2013, and for the twelve months ended September 30, 2014 and 2013 is presented below.

In thousands	2014		2013 (1)
Current assets	$	11,273	$	10,944
Noncurrent assets	219,208		62,438
Current liabilities	7,667		7,960
Noncurrent liabilities	—		—
Revenues	—		—
Gross profit	—		—
Income before income taxes	10,091		3,459
(1) Presented in the period in which we have a membership interest in Constitution, and not prior periods when we had no membership interest in Constitution. Our membership in Constitution began in November 2012.

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Selected Quarterly Financial Data

12 Months Ended

Oct. 31, 2014

Quarterly Financial Data [Abstract]

Quarterly Financial Information [Text Block]

Selected Quarterly Financial Data (In thousands except per share amounts) (Unaudited)

										Earnings (Loss)
							Net			Per Share of
	Operating				Operating		Income			Common Stock
	Revenues		Margin		Income		(Loss)			Basic			Diluted
Fiscal Year 2014
January 31	$	657,733	$	261,512	$	102,319	$	97,572		$	1.27		$	1.26
April 30	462,247		211,523		67,299		62,540			0.80			0.80
July 31	164,187		104,847		3,254		(7,344		)	(0.09		)	(0.09		)
October 31	185,821		112,326		6,993		(8,967		)	(0.11		)	(0.11		)
Fiscal Year 2013
January 31	$	515,875	$	231,623	$	86,213	$	85,923		$	1.19		$	1.18
April 30	399,411		183,856		51,504		55,790			0.74			0.74
July 31	162,943		97,000		591		(2,293		)	(0.03		)	(0.03		)
October 31	200,000		109,011		5,886		(5,003		)	(0.07		)	(0.07		)

The pattern of quarterly earnings is the result of the highly seasonal nature of the business as variations in weather conditions and our regulated utility rate designs generally result in greater earnings during the winter months. Basic earnings per share are calculated using the weighted average number of shares outstanding during the quarter. The annual amount may differ from the total of the quarterly amounts due to changes in the number of shares outstanding during the year.

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Consolidated Statements Of Stockholders' Equity (USD $) In Thousands, unless otherwise specified	Total	Common Stock [Member]	Retained Earnings [Member]	Accumulated Other Comprehensive Income (Loss) [Member]
Stockholders' Equity, beginning balance at Oct. 31, 2011	$ 996,923	$ 446,791	$ 550,584	$ (452)
Comprehensive Income:
Net income	119,847		119,847
Other comprehensive income	147			147
Comprehensive Income	119,994
Common Stock Issued	22,198	22,198
Common Stock Repurchased	(26,528)	(26,528)
Tax Benefit from Dividends Paid on ESOP Shares	110		110
Dividends Declared	(85,693)		(85,693)
Stockholders' Equity, ending balance at Oct. 31, 2012	1,027,004	442,461	584,848	(305)
Comprehensive Income:
Net income	134,417		134,417
Other comprehensive income	21			21
Comprehensive Income	134,438
Common Stock Issued	119,552	119,552
Expenses from Issuance of Common Stock	(369)	(369)
Tax Benefit from Dividends Paid on ESOP Shares	117		117
Dividends Declared	(92,146)		(92,146)
Income Loss Hedging Activities Of Equity Method Investments [Abstract]
Hedging activities of equity method investments	(284)
Stockholders' Equity, ending balance at Oct. 31, 2013	1,188,596	561,644	627,236	(284)
Comprehensive Income:
Net income	143,801		143,801
Other comprehensive income	47			47
Comprehensive Income	143,848
Common Stock Issued	75,203	75,203
Expenses from Issuance of Common Stock	(12)	(12)
Tax Benefit from Dividends Paid on ESOP Shares	118		118
Dividends Declared	(99,151)		(99,151)
Income Loss Hedging Activities Of Equity Method Investments [Abstract]
Hedging activities of equity method investments	(213)
Benefit activities of equity method investments	(24)
Stockholders' Equity, ending balance at Oct. 31, 2014	$ 1,308,602	$ 636,835	$ 672,004	$ (237)

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Consolidated Balance Sheets (Parentheticals) (USD $) In Thousands, except Share data, unless otherwise specified	Oct. 31, 2014	Oct. 31, 2013
Statement of Financial Position [Abstract]
Other Physical Property accumulated depreciation	$ 904	$ 876
Trade Accounts Receivable, allowance for doubtful accounts	$ 2,152	$ 1,604
Preferred Stock, No Par Value	$ 0	$ 0
Preferred Stock, Shares Authorized	175,000	175,000
Common Stock, No Par Value	$ 0	$ 0
Common Stock, Shares Authorized	200,000,000	200,000,000
Common Stock, Shares, Outstanding	78,531,000	76,099,000

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Employee Benefit Plans

12 Months Ended

Oct. 31, 2014

General Discussion of Pension and Other Postretirement Benefits [Abstract]

Pension and Other Postretirement Benefits Disclosure [Text Block]

Employee Benefit Plans

Under accounting guidance, we are required to recognize all obligations related to defined benefit pension and other postretirement employee benefits (OPEB) plans and quantify the plans’ funded status as an asset or liability on the Consolidated Balance Sheets. In accordance with accounting guidance, we measure the plans’ assets and obligations that determine our funded status as of the end of our fiscal year, October 31. We are required to recognize as a component of OCI the changes in the funded status that occurred during the year that are not recognized as part of net periodic benefit cost; however, in 2006, we obtained regulatory treatment from the NCUC, the PSCSC and the TRA to record the amount that would have been recorded in accumulated OCI as a regulatory asset or liability as the future recovery of pension and OPEB costs is probable. To date, our regulators have allowed future recovery of our pension and OPEB costs. For the impact of this regulatory treatment, see the following table of actuarial plan information that specifies the amounts not yet recognized as a component of cost and recognized as a regulatory asset or liability. Our plans’ assets are required to be accounted for at fair value.

Pension Benefits

We have a noncontributory, tax-qualified defined benefit pension plan (qualified pension plan) for our eligible employees. A defined benefit plan specifies the amount of benefit that an eligible participant eventually will receive upon retirement using information about that participant. An employee became eligible on the January 1 or July 1 following either the date on which he or she attained age 30 or attained age 21 and completed 1,000 hours of service during the 12-month period commencing on the employment date. Plan benefits are generally based on credited years of service and the level of compensation during the five consecutive years of the last ten years prior to retirement or termination during which the participant received the highest compensation. Our policy is to fund the plan in an amount not in excess of the amount that is deductible for income tax purposes. The qualified pension plan is closed to employees hired after December 31, 2007. Employees hired prior to January 1, 2008 continue to participate in the qualified pension plan. Employees are vested after five years of service and can be credited with up to a total of 35 years of service. When a vested employee leaves the company, his benefit payment will be calculated as the greater of the accrued benefit as of December 31, 2007 under a specific formula plus the accrued benefit calculated under a second formula for years of service after December 31, 2007, or the benefit for all years of service up to 35 years under the second formula.

The investment objectives of the qualified pension plan are oriented to meet both the current ongoing and future commitments to the participants and designed to grow at an acceptable rate of return for the risks permitted under the investment policy guidelines. Assets are structured to provide for both short-term and long-term needs and to meet the objectives of the qualified pension plan as specified by the Benefits Committee of the Board of Directors.

Our primary investment objective of the qualified pension plan is to generate sufficient assets to meet plan liabilities. The plan’s assets will therefore be invested to maximize long-term returns in a manner that is consistent with the plan’s liabilities, cash flow requirements and risk tolerance. The plan’s liabilities are defined in terms of participant salaries. Given the nature of these liabilities and recognizing the long-term benefits of investing in return-generating assets, the qualified pension plan seeks to invest in a diversified portfolio to:

• Achieve full funding over the longer term, and

• Control year-to-year fluctuations in pension expense that is created by asset and liability volatility.

We consider the historical long-term return experience of our assets, the current and targeted allocation of our plan assets and the expected long-term rates of return. Investment advisors assist us in deriving expected long-term rates of return. These rates are generally based on a 20-year horizon for various asset classes, our expected investments of plan assets and active asset management instead of a passive investment strategy of an index fund.

The investment philosophy of the qualified pension plan is to maintain a balanced portfolio which is diversified across asset classes. The portfolio is primarily composed of equity and fixed income investments in order to provide diversification as to issuers, economic sectors, markets and investment instruments. Risk and quality are viewed in the context of the diversification requirements of the aggregate portfolio. We measure and monitor investment risk on an ongoing basis through quarterly investment portfolio reviews, annual liability measurements and periodic asset/liability studies. We do not have a concentration of assets in a single entity, industry, country, commodity or class of investment fund.

The qualified pension plan maintains a 45% target allocation to fixed income securities, including U.S. treasuries, corporate bonds, high yield debt, asset-backed securities and derivatives. The derivatives in the fixed income portfolio are fully collateralized. The investment guidelines limit liabilities created with derivatives in the fixed income portfolio to cash equivalents plus 10% of the portfolio’s market value. The aggregate risk exposure of the plan can be no greater than that which could be achieved without using derivatives. The qualified pension plan maintains a 35% target allocation to equities, including exposure to large cap growth, large cap value and small cap domestic equity securities, as well as exposure to international equity. There is a 5% target allocation to real estate in a diversified global real estate investment trust (REIT) fund. The remaining 15% target allocation is for investments in other types of funds, including commodities, hedge funds and private equity funds that follow several diversified strategies.

Employees hired or rehired after December 31, 2007 cannot participate in the qualified pension plan but are participants in the Money Purchase Pension (MPP) plan, a defined contribution pension plan that allows the employee to direct the investments and assume the risk of investment returns. A defined contribution plan specifies the amount of the employer’s annual contribution to individual participant accounts established for the retirement benefit. Eligible employees who have completed 30 days of continuous service and have attained age 18 are eligible to participate. Under the MPP plan, we annually deposit a percentage of each participant’s pay into an account of the MPP plan. This contribution equals 4% of the participant’s compensation plus an additional 4% of compensation above the social security wage base up to the Internal Revenue Service (IRS) compensation limit. The participant is vested in this plan after three years of service. During the year ended October 31, 2014, we contributed $.9 million to the MPP plan.

OPEB Plan

We provide certain postretirement health care and life insurance benefits to eligible retirees. The liability associated with such benefits is funded in irrevocable trust funds that can only be used to pay the benefits. Employees are first eligible to retire and receive these benefits at age 55 with ten or more years of service after the age of 45. Employees who met this requirement in 1993 or who retired prior to 1993 are in a “grandfathered” group for whom we pay the full cost of the retiree’s coverage. Retirees not in the grandfathered group have a portion of the cost of retiree coverage paid by us, subject to certain annual contribution limits. Retirees are responsible for the full cost of dependent coverage. Effective January 1, 2008, new employees have to complete ten years of service after age 50 to be eligible for benefits, and no benefits are provided to those employees after age 65 when they are automatically eligible for Medicare benefits to cover health costs. Our OPEB plan includes a defined dollar benefit to pay the premiums for Medicare Part D. Employees who meet the eligibility requirements to retire also receive a life insurance benefit. For employees who retire after July 1, 2005, this benefit is $15,000. The life insurance amount for employees who retired prior to this date was calculated as a percentage of their basic life insurance prior to retirement.

OPEB plan assets are comprised of mutual funds within a 401(h) and Voluntary Employees’ Beneficiary Association trusts. The investment philosophy is similar to the qualified pension plan as discussed above. We target an OPEB allocation of 45% to fixed income securities, including U.S. treasuries, corporate bonds, high yield bonds and asset-backed securities. The OPEB plan maintains a 47% target allocation to equities, which includes exposure to large cap growth, large cap value and small cap domestic equity, as well as exposure to international equity. The OPEB plan maintains a 5% target allocation to real estate in a diversified global REIT fund and a 3% target allocation to cash. We do not have a concentration of assets in a single entity, industry, country, commodity or class of investment fund.

Supplemental Executive Retirement Plans

We have pension liabilities related to supplemental executive retirement plans (SERPs) for certain former employees, non-employee directors or surviving spouses. There are no assets related to these SERPs, and no additional benefits accrue to the participants. Payments to the participants are made from operating funds during the year. Actuarial information for these nonqualified plans is presented below.

We have a non-qualified defined contribution restoration plan (DCR plan) for all officers at the vice president level and above where benefits payable under the plan are informally funded annually through a rabbi trust with a bank as the trustee. We contribute 13% of the total cash compensation (base salary, short-term incentive and MVP incentive) that exceeds the IRS compensation limit to the DCR plan account of each covered executive. Participants may not contribute to the DCR plan. Vesting under the DCR plan is five-year cliff vesting, including service prior to adoption of the plan on January 1, 2009, of annual company contributions, and prospective five-year cliff vesting for the one-time opening balances of four Vice Presidents to compensate them for the loss of future benefits under this DCR plan as compared with a terminated SERP. Participants in the DCR plan may provide instructions to us for the deemed investment of their plan accounts. Distribution will occur upon separation of service or death of the participant.

We have a voluntary deferred compensation plan for the benefit of all director-level employees and officers, where we make no contributions to this plan. Benefits under this plan, known as the Voluntary Deferral Plan, are also informally funded monthly through a rabbi trust with a bank as the trustee. Participants may defer up to 50% of base salary with elections made by December 31 prior to the upcoming calendar year, and up to 95% of annual incentive pay with elections made by April 30. Vesting is immediate and deferrals are held in the rabbi trust. Participants may provide instructions to us for the deemed investment of their plan accounts. Distributions can be made from the Voluntary Deferral Plan on a specified date that is at least two years from the date of deferral, on separation of service or upon death.

The funding to the DCR plan accounts for the years ended October 31, 2014 and 2013, and the amounts recorded as liabilities for these deferred compensation plans as of October 31, 2014 and 2013 are presented below.

In thousands	2014		2013
Funding	$	524	$	434
Liability:
Current	214		199
Noncurrent	4,248		3,328

We provide term life insurance policies for certain officers at the vice president level and above who were former participants in a terminated SERP; the level of the insurance benefit is dependent upon the level of the benefit provided under the terminated SERP. These life insurance policies are owned exclusively by each officer. Premiums on these policies are paid and expensed. We also provide a term life insurance benefit equal to $200,000 to all officers and director-level employees for which we bear the cost of the policies. The cost of these premiums is presented below.

In thousands	2014		2013		2012
Term life policies of certain officers at the vice president level and above	$	30	$	27	$	43
Officers and director-level employees	32		28		25

Actuarial Plan Information

A reconciliation of changes in the plans’ benefit obligations and fair value of assets for the years ended October 31, 2014 and 2013, and a statement of the funded status and the amounts reflected in the Consolidated Balance Sheets for the years ended October 31, 2014 and 2013 are presented below.

	Qualified Pension						Nonqualified Pension						Other Benefits
In thousands	2014			2013			2014			2013			2014			2013
Accumulated benefit obligation at year end	$	252,706		$	230,175		$	5,925		$	4,736		N/A			N/A
Change in projected benefit obligation:
Obligation at beginning of year	$	272,403		$	293,327		$	4,736		$	5,569		$	33,678		$	34,830
Service cost	10,865			12,005			—			—			1,109			1,327
Interest cost	11,781			9,946			200			157			1,448			1,130
Plan amendments	—			—			485			—			—			—
Actuarial (gain) loss	23,646			(24,859		)	956			(540		)	3,734			(1,094		)
Participant contributions	—			—			—			—			805			641
Administrative expenses	(465		)	(534		)	—			—			—			—
Benefit payments	(15,544		)	(17,482		)	(452		)	(450		)	(2,957		)	(3,156		)
Obligation at end of year	302,686			272,403			5,925			4,736			37,817			33,678
Change in fair value of plan assets:
Fair value at beginning of year	300,661			272,337			—			—			25,961			23,663
Actual return on plan assets	31,791			26,340			—			—			1,874			2,848
Employer contributions	20,000			20,000			452			450			2,064			1,965
Participant contributions	—			—			—			—			805			641
Administrative expenses	(465		)	(534		)	—			—			—			—
Benefit payments	(15,544		)	(17,482		)	(452		)	(450		)	(2,957		)	(3,156		)
Fair value at end of year	336,443			300,661			—			—			27,747			25,961
Funded status at year end - over (under)	$	33,757		$	28,258		$	(5,925	)	$	(4,736	)	$	(10,070	)	$	(7,717	)
Noncurrent assets	$	33,757		$	28,258		$	—		$	—		$	—		$	—
Current liabilities	—			—			(521		)	(445		)	—			—
Noncurrent liabilities	—			—			(5,404		)	(4,291		)	(10,070		)	(7,717		)
Net amount recognized	$	33,757		$	28,258		$	(5,925	)	$	(4,736	)	$	(10,070	)	$	(7,717	)
Amounts Not Yet Recognized as a Component
of Cost and Recognized in a Deferred
Regulatory Account:
Unrecognized transition obligation	$	—		$	—		$	—		$	—		$	—		$	—
Unrecognized prior service credit (cost)	15,046			17,243			(439		)	(196		)	—			—
Unrecognized actuarial loss	(103,038		)	(96,338		)	(1,745		)	(820		)	(3,995		)	(354		)
Regulatory asset	(87,992		)	(79,095		)	(2,184		)	(1,016		)	(3,995		)	(354		)
Cumulative employer contributions in
excess of cost	121,749			107,353			(3,741		)	(3,720		)	(6,075		)	(7,363		)
Net amount recognized	$	33,757		$	28,258		$	(5,925	)	$	(4,736	)	$	(10,070	)	$	(7,717	)

In 2006 with the implementation of accounting guidance for employers’ accounting for defined benefit pension and other postretirement plans, the NCUC, the PSCSC and the TRA approved our request to place certain defined benefit postretirement obligations in a deferred regulatory account instead of OCIL as presented above. The regulators have allowed future recovery of our pension and OPEB costs to this date.

Net periodic benefit cost for the years ended October 31, 2014, 2013 and 2012 includes the following components.

	Qualified Pension									Nonqualified Pension									Other Benefits
In thousands	2014			2013			2012			2014			2013			2012			2014			2013			2012
Service cost	$	10,865		$	12,005		$	9,573		$	—		$	—		$	39		$	1,109		$	1,327		$	1,387
Interest cost	11,781			9,946			10,640			200			157			203			1,448			1,130			1,347
Expected return on plan assets	(22,530		)	(21,105		)	(20,289		)	—			—			—			(1,782		)	(1,663		)	(1,551		)
Amortization of transition obligation	—			—			—			—			—			—			—			667			667
Amortization of prior service cost
(credit)	(2,198		)	(2,198		)	(2,198		)	243			81			81			—			—			—
Amortization of net loss	7,685			11,202			5,966			31			161			49			—			—			—
Net periodic benefit cost	5,603			9,850			3,692			474			399			372			775			1,461			1,850
Other changes in plan assets and benefit
obligation recognized through
regulatory asset or liability:
Prior service cost	—			—			—			485			—			—			—			—			—
Net loss (gain)	14,385			(30,094		)	43,945			956			(540		)	629			3,641			(2,278		)	2,209
Amounts recognized as a component of
net periodic benefit cost:
Transition obligation	—			—			—			—			—			—			—			(667		)	(667		)
Amortization of net loss	(7,685		)	(11,202		)	(5,966		)	(31		)	(161		)	(49		)	—			—			—
Prior service (cost) credit	2,198			2,198			2,198			(243		)	(81		)	(81		)	—			—			—
Total recognized in regulatory asset
(liability)	8,898			(39,098		)	40,177			1,167			(782		)	499			3,641			(2,945		)	1,542
Total recognized in net periodic benefit
and regulatory asset (liability)	$	14,501		$	(29,248	)	$	43,869		$	1,641		$	(383	)	$	871		$	4,416		$	(1,484	)	$	3,392

The 2015 estimated amortization of the following items for our plans, which are recorded as a regulatory asset or liability instead of accumulated OCIL discussed above, are as follows.

	Qualified			Nonqualified		Other
In thousands	Pension			Pension		Benefits
Amortization of unrecognized prior service (credit) cost	$	(2,198	)	$	231	$	—
Amortization of unrecognized actuarial loss	8,121			85		29

The discount rate has been separately determined for each plan by projecting the plan’s cash flows and developing a zero-coupon spot rate yield curve using non-arbitrage pricing and non-callable bonds rated AA or better by either Moody’s Investors Service’s or Standard & Poor’s Ratings Services that have a yield higher than the regression mean yield curve. The discount rate can vary from plan year to plan year. As of October 31, 2014, the benchmark by plan was as follows.

Pension plan	4.13	%
NCNG SERP	3.64	%
Directors’ SERP	3.74	%
Piedmont SERP	3.10	%
OPEB	4.03	%

Equity market performance has a significant effect on our market-related value of plan assets. In determining the market-related value of plan assets, we use the following methodology: The asset gain or loss is determined each year by comparing the fund’s actual return to the expected return, based on the disclosed expected return on investment assumption. Such asset gain or loss is then recognized ratably over a five-year period. Thus, the market-related value of assets as of year end is determined by adjusting the market value of assets by the portion of the prior five years’ gains or losses that has not yet been recognized, meaning that 20% of the prior five years’ asset gains and losses are recognized each year. This method has been applied consistently in all years presented in the consolidated financial statements.

We amortize unrecognized prior-service cost over the average remaining service period for active employees. We amortize the unrecognized transition obligation over the average remaining service period for active employees expected to receive benefits under the plan as of the date of transition. We amortize gains and losses in excess of 10% of the greater of the benefit obligation and the market-related value of assets over the average remaining service period for active employees. The amortization period used for the purposes mentioned above for the NCNG SERP and the Piedmont SERP is an expected future lifetime as there are no active members in these plans. The method of amortization in all cases is straight-line.

The weighted average assumptions used in the measurement of the benefit obligation as of October 31, 2014 and 2013 are presented below.

	Qualified Pension				Nonqualified Pension				Other Benefits
	2014		2013		2014		2013		2014		2013
Discount rate	4.13	%	4.55	%	3.69	%	3.98	%	4.03	%	4.44	%
Rate of compensation increase	3.68	%	3.72	%	N/A		N/A		N/A		N/A

In addition to the assumptions in the above table, we also use subjective factors such as withdrawal and mortality rates in determining benefit obligations for all of our benefit plans. As of October 31, 2014, we updated our assumed mortality rates to incorporate the new set of mortality tables issued by the Society of Actuaries in October 2014.

The weighted average assumptions used to determine the net periodic benefit cost as of October 31, 2014, 2013 and 2012 are presented below.

	Qualified Pension						Nonqualified Pension
	2014		2013		2012		2014		2013		2012
Discount rate	4.55	%	3.51	%	4.67	%	3.98	%	2.95	%	4.10	%
Expected long-term rate of return on plan assets	7.75	%	8.00	%	8.00	%	N/A		N/A		N/A
Rate of compensation increase	3.72	%	3.76	%	3.78	%	N/A		N/A		N/A
	Other Benefits
	2014		2013		2012
Discount rate	4.44	%	3.34	%	4.36	%
Expected long-term rate of return on plan assets	7.75	%	8.00	%	8.00	%
Rate of compensation increase	N/A		N/A		N/A

We anticipate that we will contribute the following amounts to our plans in 2015.

In thousands
Qualified pension plan *	$	10,000
Nonqualified pension plans	521
MPP plan	1,300
OPEB plan	1,500

* Funded in November 2014.

The Pension Protection Act of 2006 (PPA) specified funding requirements for single employer defined benefit pension plans. The PPA established a 100% funding target for plan years beginning after December 31, 2007, and we are in compliance.

Benefit payments, which reflect expected future service, as appropriate, are expected to be paid for the next ten years ending October 31 as follows.

	Qualified		Nonqualified		Other
In thousands	Pension		Pension		Benefits
2015	$	29,946	$	521	$	2,409
2016	16,794		507		2,449
2017	16,332		491		2,527
2018	19,197		472		2,606
2019	20,685		490		2,682
2020 - 2024	110,459		2,149		14,179

The assumed health care cost trend rates used in measuring the accumulated OPEB obligation for the medical plans for all participants as of October 31, 2014 and 2013 are presented below.

	2014		2013
Health care cost trend rate assumed for next year	7.40	%	7.40	%
Rate to which the cost trend is assumed to decline (the ultimate trend rate)	5.00	%	5.00	%
Year that the rate reaches the ultimate trend rate	2027		2027

The health care cost trend rate assumptions could have a significant effect on the amounts reported. A change of 1% would have the following effects.

In thousands	1% Increase		1% Decrease
Effect on total of service and interest cost components of net periodic
postretirement health care benefit cost for the year ended October 31, 2014	$	31	$	(32	)
Effect on the health care cost component of the accumulated postretirement
benefit obligation as of October 31, 2014	829		(841		)

Fair Value Measurements

Mutual funds are valued at the quoted NAV per share, which is computed as of the close of business on our balance sheet date. Mutual funds with a publicly quoted NAV per share are classified as Level 1; mutual funds with a NAV per share that is not publicly available are classified as Level 2.

Following is a description of the valuation methodologies used for assets measured at fair value in our qualified pension plan.

Cash and cash equivalents – These are Level 1 assets valued at face value as they are primarily cash or cash equivalents. The assets that are Level 2 assets have been valued at the market value of the shares held by the plan at the valuation date for a money market mutual fund.

U.S. treasuries – These are Level 2 assets whose values are based on observable market information including quotes from a quotation reporting system, established market makers or pricing services. This asset class includes long duration fixed income investments.

Long duration bonds – These are Level 2 assets in an actively managed private series long duration fixed income fund valued using pricing models that consider various observable inputs, such as benchmark yields, reported trades, broker quotes and issuer spreads.

Corporate bonds, collateralized mortgage obligations, municipals – These are Level 2 assets valued based on primarily observable market information or broker quotes on a non-active market. This class includes long duration fixed income investments.

High yield bonds – These are Level 1 assets valued at the quoted NAV of high yield fixed income mutual fund shares.

Derivatives – The Level 1 assets were valued using a compilation of observable market information on an active market. The Level 2 assets were valued using broker quotes on a non-active market.

Large cap core index – These are Level 1 assets valued at the quoted NAV of the low-cost equity index mutual fund that tracks the Standard & Poor’s 500 Stock Index (S&P 500 Index).

Large cap value and small cap value – These are Level 1 assets valued at the market price of the active market on which the individual security is traded.

Large cap growth and global REIT – These are Level 1 assets valued at the quoted NAV of mutual fund shares in managed equity funds.

Common trust funds – International growth and bank loans (and for 2013, international value) – These are Level 2 assets held in common trust funds in which we own interests that are valued at the NAV of the funds as traded on international exchanges. Currently there are no restrictions on redemptions for the funds.

Hedge fund of funds – This is a Level 2 asset with the value of our investment based on the estimated fair value of the underlying holdings in the portfolio at a NAV. These investments are across a variety of markets through investment funds or managed accounts that invest in equities, equity-related instruments, fixed income and other debt-related instruments. Currently there are no restrictions on redemptions for the fund.

Private equity fund of funds – This is a Level 3 asset invested in hedge fund of funds valued based on a quarterly compilation of the financial statements from the underlying partnerships in which the fund invests. There are currently redemption restrictions for this fund. The target allocation for this investment is 3.5% but is still being funded through capital calls; $5.4 million of the original $12 million subscription remains unfunded. Until a 3.5% allocation can be achieved, the balance of the 3.5% allocation is invested in a low-cost equity index fund that tracks the S&P 500 Index. Our investment is in various funds that invests in North American companies; allocate capital to private equity funds; invest in venture capital partnerships; and private equity partnerships in emerging markets.

Commodities fund of funds – This is a Level 2 asset with the value of our investment based on the estimated fair value of the various holdings in the portfolio as reported in the financial statements at a NAV. Currently there are no restrictions on redemptions for the fund. These investments are in commodities fund of funds that are actively managed through a well-diversified group of underlying managers.

As stated above, some of our investments for the qualified pension plan have redemption limitations, restrictions and notice requirements which are further explained below.

			Redemptions
	Redemption		Notice
Investment	Frequency	Other Redemption Restrictions	Period
Common trust fund - International growth	Monthly	None	30 days
Hedge fund of funds	Quarterly	Redeemed in whole or part but not less than the minimum redemption amount for each currency. Redemption within one year of purchase is subject to 1.5% redemption fee. Redeemed on “first in first out” basis. None of our investment is subject to the redemption fee. Fund’s Board of Directors may limit or suspend share redemptions until a further notification ending suspension. No such notification has been received as of October 31, 2014.	65 days
Private equity fund of funds	Limited	Investors have only very limited withdrawal rights for specific legal or regulatory reasons. Any transfer of interest will be subject to approval.	(1)
Commodities fund of funds	Monthly	Redemption within one year of purchase is subject to 1% redemption fee. None of our investment is subject to the redemption fee. If 95% or more of the balance is requested, 95% of the balance will be paid within 30 days. Any outstanding balance or interest owed will be paid after the annual audit is complete.	35 days
Bank loans	Daily	None	30 days

(1) The investment cannot be redeemed. We receive distributions only through the liquidation of the underlying assets. The assets are expected to be liquidated over the next 10 to 12 years.

The qualified pension plan’s asset allocations by level within the fair value hierarchy at October 31, 2014 and 2013 are presented below. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and their consideration within the fair value hierarchy levels. For further information on a description of the fair value hierarchy, see “Fair Value Measurements” in Note 1 to the consolidated financial statements.

	Qualified Pension Plan as of October 31, 2014
				Significant Other Observable Inputs(Level 2)
	Quoted Prices In Active Markets (Level 1)						Significant Unobservable Inputs (Level 3)
										Total Carrying Value			% of Total
In thousands
Cash and cash equivalents	$	27,932		$	435		$	—		$	28,367		8	%
Fixed Income Securities:													45	%
U.S. treasuries	—			27,224			—			27,224			8	%
Long duration bonds	—			48,049			—			48,049			14	%
Corporate bonds	—			49,816			—			49,816			15	%
High yield bonds	8,100			—			—			8,100			3	%
Common trust fund - Bank loans	—			16,187			—			16,187			5	%
Collateralized mortgage
obligations	—			1,035			—			1,035			—	%
Derivatives	48			(49		)	—			(1		)	—	%
Equity Securities:													31	%
Large cap core index	9,982			—			—			9,982			3	%
Large cap value	19,937			—			—			19,937			6	%
Large cap growth	19,745			—			—			19,745			6	%
Small cap value	31,329			—			—			31,329			9	%
Common trust fund - International
growth	—			22,877			—			22,877			7	%
Real Estate:													5	%
Global REIT	16,675			—			—			16,675			5	%
Other Investments:													11	%
Hedge fund of funds	—			19,829			—			19,829			6	%
Private equity fund of funds	—			—			7,158			7,158			2	%
Commodities fund of funds	—			10,134			—			10,134			3	%
Total assets at fair value	$	133,748		$	195,537		$	7,158		$	336,443		100	%
Percent of fair value hierarchy	40		%	58		%	2		%	100		%

	Qualified Pension Plan as of October 31, 2013
				Significant Other Observable Inputs(Level 2)
	Quoted Prices In Active Markets (Level 1)						Significant Unobservable Inputs (Level 3)
										Total Carrying Value			% of Total
In thousands
Cash and cash equivalents	$	5,566		$	156		$	—		$	5,722		2	%
Fixed Income Securities:													38	%
U.S. treasuries	—			24,078			—			24,078			8	%
Long duration bonds	—			34,041			—			34,041			11	%
Corporate bonds	—			42,701			—			42,701			14	%
High yield bonds	14,680			—			—			14,680			5	%
Collateralized mortgage
obligations	—			1,098			—			1,098			—	%
Derivatives	6			(17		)	—			(11		)	—	%
Equity Securities:													43	%
Large cap core index	12,023			—			—			12,023			4	%
Large cap value	16,908			—			—			16,908			6	%
Large cap growth	17,823			—			—			17,823			6	%
Small cap value	30,831			—			—			30,831			10	%
Common trust fund - International
value	—			24,460			—			24,460			8	%
Common trust fund - International
growth	—			27,270			—			27,270			9	%
Real Estate:													5	%
Global REIT	15,042			—			—			15,042			5	%
Other Investments:													12	%
Hedge fund of funds	—			18,571			—			18,571			6	%
Private equity fund of funds	—			—			4,659			4,659			2	%
Commodities fund of funds	—			10,765			—			10,765			4	%
Total assets at fair value	$	112,879		$	183,123		$	4,659		$	300,661		100	%
Percent of fair value hierarchy	37		%	61		%	2		%	100		%

The following is a reconciliation of the assets in the qualified pension plan that are classified as Level 3 in the fair value hierarchy.

	Private
	Equity Fund
In thousands	of Funds
Balance, October 31, 2012	$	3,522
Actual return on plan assets:
Relating to assets still held at the reporting date	116
Relating to assets sold during the period	61
Purchases, sales and settlements (net)	960
Transfer in/out of Level 3	—
Balance, October 31, 2013	4,659
Actual return on plan assets:
Relating to assets still held at the reporting date	1,031
Relating to assets sold during the period	113
Purchases, sales and settlements (net)	1,355
Transfer in/out of Level 3	—
Balance, October 31, 2014	$	7,158

During the year, the qualified pension plan raises cash from various plan assets in order to fund periodic and lump sum benefit payments. Cash is raised as needed primarily from investments that have exceeded their target allocation and is dependent upon the number of retirees seeking lump sum distributions.

There are significant unobservable inputs used in the fair value measurements of our investment in the private equity fund of funds’ limited partnerships. We are subject to the business risks inherent in the markets in which the partnerships are invested. The success or failure of the underlying businesses of the various partnerships that have been funded would result in a higher or lower fair value measurement.

Following is a description of the valuation methodologies used for assets measured at fair value in our OPEB plan with all of the OPEB plan’s assets invested in mutual funds.

Cash and cash equivalents – These are Level 1 assets having maturities of three months or less when purchased and are considered to be cash equivalents.

U.S. treasuries – These are Level 1 assets in an actively managed mutual fund measured at NAV.

Corporate bonds/Other fixed income securities – These are Level 1 assets valued at the quoted NAV of mutual fund investments that are primarily invested in investment grade securities that mature within ten years. The OPEB plan maintains a 5% target allocation to high yield fixed income.

Large cap value, large cap growth, small cap growth, small cap value – These are Level 1 assets valued at the quoted NAV as invested in mutual funds that invest by a specific style.

Large cap index – These are Level 1 assets valued at the NAV as invested in a low-cost equity index mutual fund that tracks the S&P 500 Index.

International blend – These are Level 1 assets valued at the quoted NAV of mutual fund shares in managed global equity funds outside of the United States whose styles include both growth and value investments.

Global REIT – These are Level 1 assets valued at the quoted NAV of mutual fund shares in a managed equity fund that invests globally but primarily in the United States.

The OPEB plan’s asset allocations by level within the fair value hierarchy at October 31, 2014 and 2013 are presented below. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and their placement within the fair value hierarchy levels. For further information on a description of the fair value hierarchy, see “Fair Value Measurements” in Note 1 to the consolidated financial statements.

	Other Benefits as of October 31, 2014
				Significant Other Observable Inputs(Level 2)
	Quoted Prices In Active Markets (Level 1)						Significant Unobservable Inputs (Level 3)
										Total Carrying Value			% of Total
In thousands
Cash and cash equivalents	$	2,590		$	—		$	—		$	2,590		9	%
Fixed Income Securities:													44	%
U.S. treasuries	2,013			—			—			2,013			7	%
Corporate bonds / Other fixed income
securities	10,187			—			—			10,187			37	%
Equity Securities:													42	%
Large cap value	1,269			—			—			1,269			4	%
Large cap growth	1,310			—			—			1,310			5	%
Small cap value	1,336			—			—			1,336			5	%
Small cap growth	1,319			—			—			1,319			5	%
Large cap index	2,532			—			—			2,532			9	%
International blend	3,846			—			—			3,846			14	%
Real Estate:													5	%
Global REIT	1,345			—			—			1,345			5	%
Total assets at fair value	$	27,747		$	—		$	—		$	27,747		100	%
Percent of fair value hierarchy	100		%	—		%	—		%	100		%

	Other Benefits as of October 31, 2013
				Significant Other Observable Inputs(Level 2)
	Quoted Prices In Active Markets (Level 1)						Significant Unobservable Inputs (Level 3)
										Total Carrying Value			% of Total
In thousands
Cash and cash equivalents	$	982		$	—		$	—		$	982		4	%
Fixed Income Securities:													46	%
U.S. treasuries	2,582			—			—			2,582			10	%
Corporate bonds / Other fixed income
securities	9,232			—			—			9,232			36	%
Equity Securities:													45	%
Large cap value	1,327			—			—			1,327			5	%
Large cap growth	1,352			—			—			1,352			5	%
Small cap value	1,331			—			—			1,331			5	%
Small cap growth	1,313			—			—			1,313			5	%
Large cap index	2,384			—			—			2,384			9	%
International blend	4,206			—			—			4,206			16	%
Real Estate:													5	%
Global REIT	1,252			—			—			1,252			5	%
Total assets at fair value	$	25,961		$	—		$	—		$	25,961		100	%
Percent of fair value hierarchy	100		%	—		%	—		%	100		%

401(k) Plan

We maintain a 401(k) plan that is a profit-sharing plan under Section 401(a) of the Internal Revenue Code of 1986, as amended (the Tax Code), which includes qualified cash or deferred arrangements under Tax Code Section 401(k). The 401(k) plan is subject to the provisions of the Employee Retirement Income Security Act. Eligible employees who have completed 30 days of continuous service and have attained age 18 are eligible to participate. Participants may defer a portion of their base salary and cash incentive payments to the plan, and we match a portion of their contributions. Employee contributions vest immediately, and company contributions vest after six months of service.

Employees receive a company match of 100% up to the first 5% of eligible pay contributed. Employees may contribute up to 50% of eligible pay to the 401(k) on a pre-tax basis, up to the Tax Code annual contribution and compensation limits. We automatically enroll all eligible non-participating employees in the 401(k) plan at a 2% contribution rate unless the employee chooses not to participate by notifying our record keeper. For employees who are automatically enrolled in the 401(k) plan, we automatically increase their contributions by 1% each year to a maximum of 5% unless the employee chooses to opt out of the automatic increase by contacting our record keeper. If the employee does not make an investment election, employee contributions and matches are automatically invested in a diversified portfolio of stocks and bonds. Participants may direct up to 20% of their contributions and company matching contributions as an investment in the Piedmont Stock Fund. Employees may change their contribution rate and investments at any time. For the years ended October 31, 2014, 2013 and 2012, we made matching contributions to participant accounts as follows.

In thousands	2014		2013		2012
401(k) matching contributions	$	6,134	$	5,688	$	5,400

As a result of a plan merger effective in 2001, participants’ accounts in our employee stock ownership plan (ESOP) were transferred into the participants’ 401(k) accounts. Former ESOP participants may remain invested in Piedmont common stock in their 401(k) plan or may sell the common stock at any time and reinvest the proceeds in other available investment options. The tax benefit of any dividends paid on ESOP shares still in participants’ accounts is reflected in the Consolidated Statement of Stockholders’ Equity as an increase in retained earnings.

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Document And Entity Information (USD $)	12 Months Ended
	Oct. 31, 2014	Dec. 12, 2014	Apr. 30, 2014
Document And Entity Information [Abstract]
Entity Registrant Name	PIEDMONT NATURAL GAS CO INC
Entity Central Index Key	0000078460
Current Fiscal Year End Date	--10-31
Entity Filer Category	Large Accelerated Filer
Document Type	10-K
Document Period End Date	Oct. 31, 2014
Document Fiscal Period Focus	FY
Document Fiscal Year Focus	2014
Amendment Flag	false
Entity Common Stock, Shares Outstanding		78,638,925
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$ 2,764,512,081
Trading Symbol	PNY

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Employee Share Based Plans

12 Months Ended

Oct. 31, 2014

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Disclosure of Compensation Related Costs, Share-based Payments [Text Block]

Employee Share-Based Plans

Under our shareholder approved ICP, eligible officers and other participants are awarded units that pay out depending upon the level of performance achieved by Piedmont during three-year incentive plan performance periods. Distribution of those awards may be made in the form of shares of common stock and withholdings for payment of applicable taxes on the compensation. These plans require that a minimum threshold performance level be achieved in order for any award to be distributed. For the years ended October 31, 2014, 2013 and 2012, we recorded compensation expense, and as of October 31, 2014 and 2013, we accrued a liability for these awards based on the fair market value of our stock at the end of each quarter. The liability is re-measured to market value at the settlement date.

We have granted three series of awards under approved incentive compensation plans, each with a three-year performance period (ending October 31, 2014, October 31, 2015 and October 31, 2016). For each of these performance periods, awards will be based on achievement relative to a target annual compounded increase in basic EPS and the achievement of total shareholder returns relative to a group of peer companies that are domiciled in the United States, publicly traded in the U.S. energy industry with a primary focus on natural gas distribution and transmission businesses in multi-state territories and have similar annual revenues and market capitalization to ours, with each measure being weighted at 50%. The plans with performance periods ending October 31, 2015 (2015 plan) and October 31, 2016 (2016 plan) have an additional performance measure of actual average return on equity compared to the weighted average return on equity allowed by our regulatory commissions. The weighting of the units awarded under the 2015 plan and the 2016 plan is based on EPS at 37.5%, total shareholder return at 37.5% and return on equity at 25% of the total units awarded.

In December 2010, a long-term retention stock unit award under the ICP (where a stock unit equals one share of our common stock upon vesting) was approved for eligible officers and other participants to support our succession planning and retention strategies. This retention stock unit award vested for participants who met the retention requirements at the end of the three-year period ending in December 2013 and settled in the same month with payment in the form of shares of common stock and withholdings for payment of applicable taxes on the compensation. The Compensation Committee of our Board of Directors had the discretion to accelerate the vesting of all or a portion of a participant’s units. For the twelve months ended October 31, 2013 and 2012, we recorded compensation expense and a liability as of October 31, 2013 with compensation expense recorded in fiscal 2014 until December 2013 when the award was settled. The liability, which we accrued for this award based on the fair market value of our stock at the end of each quarter, was re-measured to market value in December 2013, the settlement date.

Also under our approved ICP, 64,700 unvested retention stock units were granted to our President and Chief Executive Officer in December 2011. During the five-year vesting period, any dividend equivalents will accrue on these stock units and be converted into additional units at the same rate and based on the closing price on the same payment date as dividends on our common stock. The stock units will vest, payable in the form of shares of common stock and withholdings for payment of applicable taxes on the compensation, over a five-year period only if he is an employee on each vesting date. In accordance with the vesting schedule, 20% of the units vested on December 15, 2014, 30% of the units vest on December 15, 2015 and 50% of the units vest on December 15, 2016. For the twelve months ended October 31, 2014, 2013 and 2012,we recorded compensation expense, and as of October 31, 2014 and 2013, we accrued a liability for this award based on the fair market value of our stock at the end of each quarter. The liability is re-measured to market value at the settlement date.

The award which vested on December 15, 2014 covered 20% of the grant, including accrued dividends, for a total of 14,461 shares of common stock. After the withholding of $.3 million for federal and state income taxes, our President and Chief Executive Officer received 7,231 shares at the New York Stock Exchange composite closing price on December 12, 2014 of $37.89 per share.

At the time of distribution of awards under the ICP, the number of shares issuable is reduced by the withholdings for payment of applicable income taxes for each participant. The participant may elect income tax withholdings at or above the minimum statutory withholding requirements. The maximum withholdings allowed is 50%. To date, shares withheld for payment of applicable income taxes have been immaterial. We present these net shares issued in the Consolidated Statements of Stockholders’ Equity and in Note 6 to the consolidated financial statements.

The compensation expense related to the incentive compensation plans for the years ended October 31, 2014, 2013 and 2012, and the amounts recorded as liabilities in "Other noncurrent liabilities" in "Noncurrent Liabilities" with the current portion recorded in "Other current liabilities" in "Current Liabilities" in the Consolidated Balance Sheets as of October 31, 2014 and 2013 are presented below.

In thousands	2014		2013		2012
Compensation expense	$	8,496	$	4,526	$	5,730
Tax benefit	2,476		1,538		2,080
Liability	15,130		11,098

Based on current accrual assumptions as of October 31, 2014, the expected payout for the approved incentive compensation awards at target will occur in the following fiscal years.

In thousands	2015		2016		2017
Amount of payout	$	7,204	$	4,980	$	2,946

On a quarterly basis, we issue shares of common stock under the ESPP and account for the issuance as an equity transaction. The exercise price is calculated as 95% of the fair market value on the purchase date of each quarter where fair market value is determined by calculating the mean average of the high and low trading prices on the purchase date.

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Consolidated Statements of Comprehensive Income (USD $) In Thousands, except Per Share data, unless otherwise specified	12 Months Ended
	Oct. 31, 2014	Oct. 31, 2013	Oct. 31, 2012
Statement of Comprehensive Income [Abstract]
Operating Revenues	$ 1,469,988	$ 1,278,229	$ 1,122,780
Cost of Gas	779,780	656,739	547,334
Margin	690,208	621,490	575,446
Operating Expenses:
Operations and maintenance	270,877	253,120	242,599
Depreciation	118,996	112,207	103,192
General taxes	37,294	34,635	34,831
Utility income taxes	83,176	77,334	69,101
Total operating expenses	510,343	477,296	449,723
Operating Income	179,865	144,194	125,723
Other Income (Expense):
Income from equity method investments	32,753	26,056	23,904
Non-operating income	1,842	2,839	1,288
Non-operating expense	(4,331)	(5,122)	(1,855)
Income taxes	(11,642)	(8,612)	(9,116)
Total other income (expense)	18,622	15,161	14,221
Utility Interest Charges:
Interest on long-term debt	61,562	54,158	41,412
Allowance for borrowed funds used during construction	(16,427)	(30,975)	(25,211)
Other	9,551	1,755	3,896
Total utility interest charges	54,686	24,938	20,097
Net Income	143,801	134,417	119,847
Other Comprehensive Income (Loss), net of tax:
Unrealized gain (loss) from hedging activities of equity method investments, net of tax of $225, ($69) and ($530) for the years ended October 31, 2014, 2013 and 2012, respectively	355	(109)	(826)
Reclassification adjustment of realized gain (loss) from hedging activities of equity method investments included in net income, net of tax of ($177), $85 and $621 for the years ended October 31, 2014, 2013 and 2012, respectively	(284)	130	973
Net current period benefit activities of equity method investments, net of tax of ($16) for the year ended October 31, 2014	(24)
Total other comprehensive income	47	21	147
Comprehensive Income	$ 143,848	$ 134,438	$ 119,994
Average Shares of Common Stock:
Basic (in shares)	77,883	74,884	71,977
Diluted (in shares)	78,193	75,333	72,278
Earnings Per Share of Common Stock:
Basic (usd per share)	$ 1.85	$ 1.80	$ 1.67
Diluted (usd per share)	$ 1.84	$ 1.78	$ 1.66

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Long Term Debt

12 Months Ended

Oct. 31, 2014

Long-term Debt, Unclassified [Abstract]

Long-term Debt [Text Block]

Long-Term Debt

Our long-term debt consists of privately placed senior notes issued under note purchase agreements, as well as publicly issued medium-term and senior notes issued under an indenture. All of our long-term debt is unsecured and is issued at fixed rates. Long-term debt as of October 31, 2014 and 2013 is as follows.

In thousands	2014		2013
Senior Notes:
2.92%, due June 6, 2016	$	40,000	$	40,000
8.51%, due September 30, 2017	35,000		35,000
4.24%, due June 6, 2021	160,000		160,000
3.47%, due July 16, 2027	100,000		100,000
3.57%, due July 16, 2027	200,000		200,000
4.10%, due September 18, 2034	250,000		—
4.65%, due August 1, 2043	300,000		300,000
Medium-Term Notes:
5.00%, due December 19, 2013	—		100,000
6.87%, due October 6, 2023	45,000		45,000
8.45%, due September 19, 2024	40,000		40,000
7.40%, due October 3, 2025	55,000		55,000
7.50%, due October 9, 2026	40,000		40,000
7.95%, due September 14, 2029	60,000		60,000
6.00%, due December 19, 2033	100,000		100,000
Total	1,425,000		1,275,000
Less current maturities	—		100,000
Less discount on issuance of notes *	570		143
Total	$	1,424,430	$	1,174,857

* The discount on the 4.65% senior notes was $138 and $143 at October 31, 2014 and 2013, respectively. The discount on the 4.10% senior notes was $432 at October 31, 2014.

Current maturities for the next five years ending October 31 and thereafter are as follows.

In thousands
2015	$	—
2016	40,000
2017	35,000
2018	—
2019	—
Thereafter	1,350,000
Total	$	1,425,000

We had an open combined debt and equity shelf registration statement filed with the SEC in July 2011 that was available for future use until its expiration date of July 6, 2014. In February 2013, we sold shares of common stock under this registration statement. For further information on this transaction, see Note 6 to the consolidated financial statements.

On August 1, 2013, we issued $300 million of thirty-year, unsecured senior notes with an interest rate of 4.65% and at a discount of .048% or $144,000, which we began to amortize ratably over the expected life of the notes, under the registration statement in effect noted above. We have the option to redeem all or part of the notes before the stated maturity prior to February 1, 2043, at a redemption price equal to the greater of a) 100% of the principal amount plus any accrued and unpaid interest to the date of redemption, or b) the sum of the present values of the remaining scheduled payments of principal and interest on the notes to be redeemed, discounted to the date of redemption on a semi-annual basis at the Treasury Rate as defined in the indenture, plus 15 basis points and any accrued and unpaid interest to the date of redemption. We have the option to redeem all or part of the notes before the stated maturity on or after February 1, 2043, at 100% of the principal amount plus any accrued and unpaid interest to the date of redemption. We used the net proceeds of $297.2 million from this issuance to finance capital expenditures, to repay $100 million of our 5% medium-term notes due December 19, 2013 at maturity, to repay outstanding short-term notes under our unsecured commercial paper (CP) program and for general corporate purposes.

In June 2014, we filed with the SEC a combined debt and equity shelf registration statement that became effective on June 6, 2014. The NCUC has approved debt and equity issuances under this shelf registration statement up to $1 billion during its three-year life. Unless otherwise specified at the time such securities are offered for sale, the net proceeds from the sale of the securities will be used to finance capital expenditures, to repay outstanding short-term, unsecured notes under our CP program, to refinance other indebtedness, to repurchase our common stock, to pay dividends and for general corporate purposes.

On September 18, 2014, we issued $250 million of twenty-year, unsecured senior notes with an interest rate of 4.10% and at a discount of .174% or $435,000, which we began to amortize ratably over the expected life of the notes, under the registration statement in effect noted above. We have the option to redeem all or part of the notes before the stated maturity prior to March 18, 2034, at a redemption price equal to the greater of a) 100% of the principal amount plus any accrued and unpaid interest to the date of redemption, or b) the sum of the present values of the remaining scheduled payments of principal and interest on the notes to be redeemed, discounted to the date of redemption on a semi-annual basis at the Treasury Rate as defined in the indenture, plus 15 basis points and any accrued and unpaid interest to the date of redemption. We have the option to redeem all or part of the notes before the stated maturity on or after March 18, 2034, at 100% of the principal amount plus any accrued and unpaid interest to the date of redemption. We used the net proceeds of $247.7 million from this issuance to finance capital expenditures, to repay outstanding short-term, unsecured notes under our CP program and for general corporate purposes.

The amount of cash dividends that may be paid on common stock is restricted by provisions contained in certain note agreements under which long-term debt was issued, with those for the senior notes being the most restrictive. We cannot pay or declare any dividends or make any other distribution on any class of stock or make any investments in subsidiaries or permit any subsidiary to do any of the above (all of the foregoing being “restricted payments”), except out of net earnings available for restricted payments. As of October 31, 2014, our net earnings available for restricted payments were $1.1 billion.

We are subject to default provisions related to our long-term debt and short-term borrowings. Failure to satisfy any of the default provisions may result in total outstanding issues of debt becoming due. There are cross default provisions in all of our debt agreements. As of October 31, 2014, we are in compliance with all default provisions.

The default provisions of some or all of our senior debt include:

• Failure to make principal or interest payments,

• Bankruptcy, liquidation or insolvency,

• Final judgment against us in excess of $1 million that after 60 days is not discharged, satisfied or stayed pending appeal,

• Specified events under the Employee Retirement Income Security Act of 1974,

• Change in control, and

• Failure to observe or perform covenants, including:

• Interest coverage of at least 1.75 times. Interest coverage was 4.29 times as of October 31, 2014;

• Funded debt cannot exceed 70% of total capitalization. Funded debt was 58% of total capitalization as of October 31, 2014;

• Funded debt of all subsidiaries in the aggregate cannot exceed 15% of total capitalization. There is no funded debt of our subsidiaries as of October 31, 2014;

• Restrictions on permitted liens;

• Restrictions on paying dividends, on or repurchasing our stock or making investments in subsidiaries; and

• Restrictions on burdensome agreements.

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Earnings Per Share

12 Months Ended

Oct. 31, 2014

Earnings Per Share [Abstract]

Earnings Per Share [Text Block]

Earnings Per Share

We compute basic earnings per share (EPS) using the daily weighted average number of shares of common stock outstanding during each period. In the calculation of fully diluted EPS, shares of common stock to be issued under approved incentive compensation plans are contingently issuable shares, as determined by applying the treasury stock method, and are added to average common shares outstanding, resulting in a potential reduction in diluted EPS.

A reconciliation of basic and diluted EPS, which includes contingently issuable shares that could affect EPS if performance units ultimately vest or stock agreements settle, for the years ended October 31, 2014, 2013 and 2012 is presented below.

In thousands, except per share amounts	2014		2013		2012
Net Income	$	143,801	$	134,417	$	119,847
Average shares of common stock outstanding for basic earnings per share	77,883		74,884		71,977
Contingently issuable shares under incentive compensation plans	310		289		301
Contingently issuable shares under forward sale agreements	—		160		—
Average shares of dilutive stock	78,193		75,333		72,278
Earnings Per Share of Common Stock:
Basic	$	1.85	$	1.80	$	1.67
Diluted	$	1.84	$	1.78	$	1.66

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Subsequent Events

12 Months Ended

Oct. 31, 2014

Subsequent Events [Abstract]

Subsequent Events [Text Block]

Subsequent Events

We monitor significant events occurring after the balance sheet date and prior to the issuance of the financial statements to determine the impacts, if any, of events on the financial statements to be issued. All subsequent events of which we are aware were evaluated. For information on subsequent event disclosure items related to regulatory matters and employee share-based plans, see Note 2 and Note 10, respectively, to the consolidated financial statements.

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Income Taxes

12 Months Ended

Oct. 31, 2014

Income Tax Disclosure [Abstract]

Income Tax Disclosure [Text Block]

Income Taxes

The components of income tax expense for the years ended October 31, 2014, 2013 and 2012 are presented below.

	2014					2013						2012
In thousands	Federal			State		Federal			State			Federal			State
Charged (Credited) to operating
income:
Current (1)	$	(1,653	)	$	950	$	(3,032	)	$	919		$	(29,062	)	$	1,857
Deferred (1)	70,654			13,434		67,885			11,829			86,496			10,144
Tax Credits:
Amortization	(209		)	—		(267		)	—			(334		)	—
Total	68,792			14,384		64,586			12,748			57,100			12,001
Charged (Credited) to other income
(expense):
Current	4,233			870		6,049			984			5,636			1,027
Deferred	5,811			728		2,225			(646		)	2,214			239
Total	10,044			1,598		8,274			338			7,850			1,266
Total	$	78,836		$	15,982	$	72,860		$	13,086		$	64,950		$	13,267

⁽¹⁾ Includes utilization of federal NOL carryforward benefit of $28.6 million for the year ended October 31, 2014 and the generation of a NOL carryforward benefit of $62.3 million for the year ended October 31, 2013.

A reconciliation of income tax expense at the federal statutory rate to recorded income tax expense for the years ended October 31, 2014, 2013 and 2012 is presented below.

In thousands	2014			2013			2012
Federal taxes at 35%	$	83,517		$	77,127		$	69,322
State income taxes, net of federal benefit	10,389			8,506			8,624
Amortization of investment tax credits	(209		)	(267		)	(334		)
Other, net	1,121			580			605
Total	$	94,818		$	85,946		$	78,217

As of October 31, 2014 and 2013, deferred income taxes consisted of the following temporary differences.

In thousands	2014			2013
Deferred tax assets:
Benefit of loss carryforwards	$	39,532		$	66,087
Revenues and cost of gas	4,960			—
Employee benefits and compensation	16,547			13,834
Revenue requirement	20,320			19,062
Utility plant	5,631			10,386
Other	12,869			12,796
Total deferred tax assets	99,859			122,165
Valuation allowance	(505		)	(505		)
Total deferred tax assets, net	99,354			121,660
Deferred tax liabilities:
Utility plant	724,172			652,822
Revenues and cost of gas	4,340			21,257
Equity method investments	42,998			38,710
Deferred costs	65,828			59,221
Other	18,065			18,324
Total deferred tax liabilities	855,403			790,334
Net deferred income tax liabilities	$	756,049		$	668,674

As of October 31, 2014 and 2013, total net deferred income tax assets were net of a valuation allowance to reduce amounts to the amounts that we believe will be more likely than not realized. We and our wholly-owned subsidiaries file a consolidated federal income tax return and various state income tax returns. As of October 31, 2014 and 2013, we have federal NOL carryforwards of $97 million and $178.1 million, respectively, which expire in 2033. We also have $5.9 million of federal NOL carryforwards as of October 31, 2014 and 2013 that expire in 2021 through 2025 and are subject to an annual limitation of $.3 million. As of October 31, 2014, we have a $2.4 million alternative minimum tax credit carryforward.

As of October 31, 2014 and 2013, we have state NOL carryforwards of $7.2 million and $6.4 million, respectively, that expire from 2020 through 2028. We may use the carryforwards to offset taxable income.

We are no longer subject to federal income tax examinations for tax years ending before and including October 31, 2009, and with few exceptions, state income tax examinations by tax authorities for years ended before and including October 31, 2009. The IRS is currently auditing the federal income tax returns for years ended October 31, 2010, 2011 and 2012.

A reconciliation of changes in the deferred tax valuation allowance for the years ended October 31, 2014, 2013 and 2012 is presented below.

In thousands	2014		2013		2012
Balance at beginning of year	$	505	$	505	$	505
Credited to income tax expense	—		—		—
Balance at end of year	$	505	$	505	$	505

There were no unrecognized tax benefits for the years ended October 31, 2014 and 2013.

In July 2013, legislation was passed in North Carolina affecting corporate taxation. The legislation reduced the corporate income tax rate from 6.9% to 6% for tax years beginning after January 1, 2014 and to 5% for tax years beginning after January 1, 2015. It also provided for two additional 1% rate reductions if the state’s tax collections exceed certain thresholds. We record deferred income taxes on temporary tax differences using the income tax rate in effect when the temporary difference is expected to reverse. As a result of the rate reductions, we adjusted our noncurrent deferred income tax balances at October 31, 2013 by approximately $25 million for temporary differences expected to reverse at a lower rate than under the prior law and recognized a tax benefit of approximately $1 million in net income, the majority of which relates to our regulated non-utility activities segment, with the balance of approximately $24 million recorded in deferred income taxes in “Regulatory Liabilities” as presented in Note 1 to the consolidated financial statements, reflecting a future benefit to our customers. During fiscal 2014, we recorded an additional $3 million for the difference in the tax rate included in our customers' rates and the rate at which the deferred taxes are expected to reverse. This increased our deferred income taxes recorded in “Regulatory Liabilities” to approximately $27 million. Our state regulatory commissions will determine the refund period of this regulatory liability in future proceedings.

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Financial Instruments & Related Fair Value Financial Instruments & Related Fair Value (Notes)

12 Months Ended

Oct. 31, 2014

Financial Instruments & Related Fair Value [Abstract]

Financial Instruments Disclosure [Text Block]

Financial Instruments and Related Fair Value

Derivative Assets and Liabilities under Master Netting Arrangements

We maintain brokerage accounts to facilitate transactions that support our gas cost hedging plans. The accounting guidance related to derivatives and hedging requires that we use a gross presentation, based on our election, for the fair value amounts of our derivative instruments. We use long position gas purchase options to provide some level of protection for our customers in the event of significant commodity price increases. As of October 31, 2014 and 2013, we had long gas purchase options providing total coverage of 29.2 million dekatherms and 25.4 million dekatherms, respectively. The long gas purchase options held at October 31, 2014 are for the period from December 2014 through November 2015.

Fair Value Measurements

We use financial instruments that are not designated as hedges for accounting purposes to mitigate commodity price risk for our customers. We also have marketable securities that are held in rabbi trusts established for certain of our deferred compensation plans. In developing our fair value measurements of these financial instruments, we utilize market data or assumptions about risk and the risks inherent in the inputs to the valuation technique. Fair value refers to the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants in the market in which the entity transacts. We classify fair value balances based on the observance of those inputs into the fair value hierarchy levels as set forth in the fair value accounting guidance and fully described in “Fair Value Measurements” in Note 1 to the consolidated financial statements.

The following table sets forth, by level of the fair value hierarchy, our financial assets that were accounted for at fair value on a recurring basis as of October 31, 2014 and 2013. Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their consideration within the fair value hierarchy levels. We have had no transfers between any level during the years ended October 31, 2014 and 2013. We present our derivative positions at fair value on a gross basis and have only asset positions for all periods presented for the fair value of purchased call options held for our utility operations. There are no derivative contracts in a liability position, and we have posted no cash collateral nor received any cash collateral under our master netting arrangements. Therefore, we have no offsetting disclosures for financial assets or liabilities for our derivatives held for utility operations. Our derivatives held for utility operations are held with one broker as our counterparty.

Recurring Fair Value Measurements as of October 31, 2014
			Significant				Effects of
	Quoted Prices		Other		Significant		Netting and
	in Active		Observable		Unobservable		Cash Collateral		Total
	Markets		Inputs		Inputs		Receivables/		Carrying
In thousands	(Level 1)		(Level 2)		(Level 3)		Payables		Value
Assets:
Derivatives held for distribution operations	$	4,898	$	—	$	—	$	—	$	4,898
Debt and equity securities held as trading securities:
Money markets	469		—		—		—		469
Mutual funds	3,472		—		—		—		3,472
Total fair value assets	$	8,839	$	—	$	—	$	—	$	8,839

Recurring Fair Value Measurements as of October 31, 2013
			Significant				Effects of
	Quoted Prices		Other		Significant		Netting and
	in Active		Observable		Unobservable		Cash Collateral		Total
	Markets		Inputs		Inputs		Receivables/		Carrying
In thousands	(Level 1)		(Level 2)		(Level 3)		Payables		Value
Assets:
Derivatives held for distribution operations	$	1,834	$	—	$	—	$	—	$	1,834
Debt and equity securities held as trading securities:
Money markets	380		—		—		—		380
Mutual funds	2,814		—		—		—		2,814
Total fair value assets	$	5,028	$	—	$	—	$	—	$	5,028

Our regulated utility segment derivative instruments are used in accordance with programs filed with or approved by the NCUC, the PSCSC and the TRA to hedge the impact of market fluctuations in natural gas prices. These derivative instruments are accounted for at fair value each reporting period. In accordance with regulatory requirements, the net gains and losses related to these derivatives are reflected in purchased gas costs and ultimately passed through to customers through our PGA procedures. In accordance with accounting provisions for rate-regulated activities, the unrecovered amounts related to these instruments are reflected as a regulatory asset or liability, as appropriate, in “Amounts due from customers” or “Amounts due to customers” in Note 1 to the consolidated financial statements. These derivative instruments are exchange-traded derivative contracts. Exchange-traded contracts are generally based on unadjusted quoted prices in active markets and are classified within Level 1.

Trading securities include assets in rabbi trusts established for our deferred compensation plans and are included in “Marketable securities, at fair value” in “Noncurrent Assets” in the Consolidated Balance Sheets. Securities classified within Level 1 include funds held in money market and mutual funds which are highly liquid and are actively traded on the exchanges.

Our long-term debt is recorded at unamortized cost. In developing the fair value of our long-term debt, we use a discounted cash flow technique, consistently applied, that incorporates a developed discount rate using long-term debt similarly rated by credit rating agencies combined with the U.S. Treasury benchmark with consideration given to maturities, redemption terms and credit ratings similar to our debt issuances. The carrying amount and fair value of our long-term debt, including the current portion, which is classified within Level 2, are shown below.

	Carrying
In thousands	Amount *		Fair Value
As of October 31, 2014	$	1,425,000	$	1,617,453
As of October 31, 2013	1,275,000		1,409,892

* Excludes discount on issuance of notes of $570 and $143 as of October 31, 2014 and 2013, respectively.

Quantitative and Qualitative Disclosures

The costs of our financial price hedging options for natural gas and all other costs related to hedging activities of our regulated gas costs are recorded in accordance with our regulatory tariffs approved by our state regulatory commissions, and thus are not accounted for as designated hedging instruments under derivative accounting standards. As required by the accounting guidance, the fair value of our financial options is presented on a gross basis with only asset positions for all periods presented. There are no derivative contracts in a liability position, and we have posted no cash collateral nor received any cash collateral under our master netting arrangements; therefore, we have no offsetting disclosures for financial assets or liabilities for our financial option derivatives.

The following table presents the fair value and balance sheet classification of our financial options for natural gas as of October 31, 2014 and 2013.

Fair Value of Derivative Instruments
In thousands	2014		2013
Derivatives Not Designated as Hedging Instruments under Derivative Accounting Standards:
Asset Financial Instruments:
Current Assets - Gas purchase derivative assets (December 2014 - November 2015)	$	4,898
Current Assets - Gas purchase derivative assets (December 2013 - October 2014)			$	1,834

We purchase natural gas for our regulated operations for resale under tariffs approved by state regulatory commissions. We recover the cost of gas purchased for regulated operations through PGA procedures. Our risk management policies allow us to use financial instruments to hedge commodity price risks, but not for speculative trading. The strategy and objective of our hedging programs is to use these financial instruments to reduce gas cost volatility for our customers. Accordingly, the operation of the hedging programs on the regulated utility segment as a result of the use of these financial derivatives is initially deferred as amounts due from customers included as “Regulatory Assets” or amounts due to customers included as “Regulatory Liabilities” in Note 1 to the consolidated financial statements and recognized in the Consolidated Statements of Comprehensive Income as a component of “Cost of Gas” when the related costs are recovered through our rates.

The following table presents the impact that financial instruments not designated as hedging instruments under derivative accounting standards would have had on the Consolidated Statements of Comprehensive Income for the twelve months ended October 31, 2014 and 2013, absent the regulatory treatment under our approved PGA procedures.

	Amount of					Amount of					Location of Gain (Loss)
	Gain (Loss) Recognized					Gain (Loss) Deferred					Recognized through
	on Derivative Instruments					Under PGA Procedures					PGA Procedures
	Twelve Months Ended					Twelve Months Ended
	October 31					October 31
In thousands	2014		2013			2014		2013
Gas purchase options	$	6,162	$	(6,303	)	$	6,162	$	(6,303	)	Cost of Gas

In Tennessee, the cost of gas purchase options and all other costs related to hedging activities up to 1% of total annual gas costs are approved for recovery under the terms and conditions of our TIP approved by the TRA. In South Carolina, the costs of gas purchase options are subject to and are approved for recovery under the terms and conditions of our gas hedging plan approved by the PSCSC. In North Carolina, the costs associated with our hedging program are treated as gas costs subject to an annual cost review proceeding by the NCUC.

Credit and Counterparty Risk

We are exposed to credit risk as a result of transactions for the purchase and sale of natural gas and related products and services and management agreements of our transportation capacity, storage capacity and supply contracts with major companies in the energy industry and within our utility operations serving industrial, commercial, power generation, residential and municipal energy consumers. These transactions principally occur in the eastern, gulf coast and mid-west regions of the United States. We believe that this geographic concentration does not contribute significantly to our overall exposure to credit risk. Credit risk associated with trade accounts receivable for the natural gas distribution segment is mitigated by the large number of individual customers and diversity in our customer base.

We enter into contracts with third parties to buy and sell natural gas. A significant portion of these transactions are with, or are associated with, energy producers, utility companies, off-system municipalities and natural gas marketers. The amount included in “Trade accounts receivable” in “Current Assets” in the Consolidated Balance Sheets attributable to these entities amounted to $3.5 million, or approximately 5% of our gross trade accounts receivable at October 31, 2014. Our policy requires counterparties to have an investment-grade credit rating at the time of the contract, or in situations where counterparties do not have investment-grade or functionally equivalent credit ratings, our policy requires credit enhancements that include letters of credit or parental guaranties. In either circumstance, our policy specifies limits on the contract amount and duration based on the counterparty’s credit rating and/or credit support. In order to minimize our exposure, we continually re-evaluate third-party creditworthiness and market conditions and modify our requirements accordingly.

We also enter into contracts with third parties to manage some of our supply and capacity assets for the purpose of maximizing their value. These arrangements include a counterparty credit evaluation according to our policy described above prior to contract execution and typically have durations of one year or less. In the event that a party is unable to perform under these arrangements, we have exposure to satisfy our underlying supply or demand contractual obligations that were incurred while under the management of this third party. We believe, based on our credit policies as of October 31, 2014, that our financial position, results of operations and cash flows will not be materially affected as a result of nonperformance by any single counterparty.

Natural gas distribution operating revenues and related trade accounts receivable are generated from state-regulated utility natural gas sales and transportation to over one million residential, commercial and industrial customers, including power generation and municipal customers, located in North Carolina, South Carolina and Tennessee. A change in economic conditions may affect the ability of customers to meet their obligations. We have mitigated our exposure to the risk of non-payment of utility bills by our customers. Gas costs related to uncollectible accounts are recovered through PGA procedures in all jurisdictions. To manage the non-gas cost customer credit risk, we evaluate credit quality and payment history and may require cash deposits from our high risk customers that do not satisfy our predetermined credit standards until a satisfactory payment history has been established. Significant increases in the price of natural gas and colder-than-normal weather can slow our collection efforts as customers experience increased difficulty in paying their gas bills, leading to higher than normal trade accounts receivable; however, we believe that our provision for possible losses on uncollectible trade accounts receivable is adequate for our credit loss exposure.

Risk Management

Our financial derivative instruments do not contain material credit-risk-related or other contingent features that could require us to make accelerated payments.

We seek to identify, assess, monitor and manage risk in accordance with defined policies and procedures under the direction of the Treasurer and Chief Risk Officer and our Enterprise Risk Management (ERM) program, including our Energy Price Risk Management Committee. Risk management is guided by senior management with Board of Directors oversight, and senior management takes an active role in the development of policies and procedures.

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Short Term Debt

12 Months Ended

Oct. 31, 2014

Line of Credit Facility [Abstract]

Short-term Debt [Text Block]

Short-Term Debt Instruments

We have an $850 million five-year revolving syndicated credit facility that expires on October 1, 2017. We pay an annual fee of $35,000 plus 8.5 basis points for any unused amount. The facility provides a line of credit for letters of credit of $10 million, of which $1.8 million and $2.1 million were issued and outstanding at October 31, 2014 and 2013, respectively. These letters of credit are used to guarantee claims from self-insurance under our general and automobile liability policies. The credit facility bears interest based on the 30-day London Interbank Offered Rate (LIBOR) plus from 75 to 125 basis points, based on our credit ratings. Amounts borrowed are continuously renewable until the expiration of the facility in 2017 provided that we are in compliance with all terms of the agreement. See Note 4 to the consolidated financial statements for discussion of default provisions, including cross default provisions, in all of our debt agreements.

We have an $850 million unsecured CP program that is backstopped by the revolving syndicated credit facility. The amounts outstanding under the revolving syndicated credit facility and the CP program, either individually or in the aggregate, cannot exceed $850 million. The notes issued under the CP program may have maturities not to exceed 397 days from the date of issuance and bear interest based on, among other things, the size and maturity date of the note, the frequency of the issuance and our credit ratings, plus a spread of 5 basis points. Any borrowings under the CP program rank equally with our other unsecured debt. The notes under the CP program are not registered and are offered and issued pursuant to an exemption from registration. Due to the seasonal nature of our business, amounts borrowed can vary significantly during the year.

As of October 31, 2014, we had $355 million of notes outstanding under the CP program, as included in “Short-term debt” in “Current Liabilities” in the Consolidated Balance Sheets, with original maturities ranging from 4 to 28 days from their dates of issuance at a weighted average interest rate of .17%. As of October 31, 2013, our outstanding notes under the CP program, included in the Consolidated Balance Sheets as stated above, were $400 million at a weighted average interest rate of .36%.

We did not have any borrowings under the revolving syndicated credit facility for the twelve months ended October 31, 2014. A summary of the short-term debt activity under our CP program for the twelve months ended October 31, 2014 is as follows

In thousands
Minimum amount outstanding	$	275,000
Maximum amount outstanding	$	625,000
Minimum interest rate	.10		%
Maximum interest rate	.43		%
Weighted average interest rate	.19		%

Our five-year revolving syndicated credit facility’s financial covenants require us to maintain a ratio of total debt to total capitalization of no greater than 70%, and our actual ratio was 58% at October 31, 2014.

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Stockholders' Equity

12 Months Ended

Oct. 31, 2014

Stockholders' Equity Note [Abstract]

Stockholders' Equity Note Disclosure [Text Block]

Stockholders’ Equity

Capital Stock

Changes in common stock for the years ended October 31, 2014, 2013 and 2011 are as follows.

In thousands	Shares		Amount
Balance, October 31, 2011	72,318		$	446,791
Issued to participants in the Employee Stock Purchase Plan (ESPP)	30		894
Issued to the Dividend Reinvestment and Stock Purchase Plan (DRIP)	677		20,508
Issued to participants in the Incentive Compensation Plan (ICP)	25		796
Shares repurchased under Accelerated Share Repurchase (ASR) agreement	(800	)	(26,528		)
Balance, October 31, 2012	72,250		442,461
Issued to ESPP	33		1,056
Issued to DRIP	720		22,791
Issued to ICP	96		3,065
Issuance of common stock through public share offering, net of underwriting fees	3,000		92,640
Costs from issuance of common stock	—		(369		)
Balance, October 31, 2013	76,099		561,644
Issued to ESPP	34		1,143
Issued to DRIP	698		23,443
Issued to ICP	100		3,315
Issuance of common stock through forward sale agreements, net of expenses	1,600		47,290
Balance, October 31, 2014	78,531		$	636,835

In June 2004, the Board of Directors approved a Common Stock Open Market Purchase Program that authorized the repurchase of up to three million shares of currently outstanding shares of common stock. We implemented the program in September 2004. We utilize a broker to repurchase the shares on the open market, and such shares are canceled and become authorized but unissued shares available for issuance under the ESPP, DRIP and ICP.

On December 16, 2005, the Board of Directors approved an increase in the number of shares in this program from three million to six million to reflect the two-for-one stock split in 2004. The Board also approved at that time an amendment of the Common Stock Open Market Purchase Program to provide for the repurchase of up to four million additional shares of common stock to maintain our debt-to-equity capitalization ratios at target levels. These combined actions increased the total authorized share repurchases from three million to ten million shares. The additional four million shares were referred to as our ASR program. On March 6, 2009, the Board of Directors authorized the repurchase of up to an additional four million shares under the Common Stock Open Market Purchase Program and the ASR program, which were consolidated.

On January 29, 2013, we entered into an underwriting agreement under our open combined debt and equity shelf registration statement to sell up to 4.6 million shares of our common stock of which 3 million direct shares were issued and settled on February 4, 2013 with proceeds of $92.6 million received. The shares were purchased by the underwriters at the net price of $30.88 per share, the offering price to the public of $32 per share per the prospectus less an underwriting discount of $1.12 per share.

The remaining 1.6 million shares under this same underwriting agreement were under forward sale agreements (FSAs) with 1 million shares borrowed by a forward counterparty and sold to the underwriters for resale to the public on February 4, 2013 at the same price as the direct shares; the remaining .6 million shares were subject to a 30-day option by the underwriters to purchase these additional shares at the same price as the direct shares and would be, at our option, either issued at the time of purchase and delivered directly to the underwriters or borrowed and delivered to the underwriters by the forward counterparty. On February 19, 2013, the underwriters exercised their option to purchase the full additional .6 million shares of our common stock where the shares were borrowed from third parties and sold to the underwriters by the forward counterparty. Both of the FSAs had to be settled no later than mid-December 2013. Under the terms of these FSAs, at our election, we could physically settle in shares, cash or net share settle for all or a portion of our obligation under the agreements.

On December 16, 2013, we physically settled the FSAs by issuing 1.6 million shares of our common stock to the forward counterparty and received net proceeds of $47.3 million based on the net settlement price of $30.88 per share, the original offering price, less certain adjustments. We recorded this amount in "Stockholders' equity" as an addition to "Common stock" in the Consolidated Balance Sheets. Upon settlement, we used the net proceeds from these FSA transactions to finance capital expenditures, repay outstanding short-term, unsecured notes under our CP program and for general corporate purposes.

In accordance with ASC 815-40, Derivatives and Hedging - Contracts in Entity’s Own Equity, we classified the FSAs as equity transactions because the forward sale transactions were indexed to our own stock and physical settlement was within our control. As a result of this classification, no amounts were recorded in the consolidated financial statements until settlement of each FSA.

Upon physical settlement of the FSAs, delivery of our shares resulted in dilution to our EPS at the date of the settlement. In quarters prior to the settlement date, any dilutive effect of the FSAs on our EPS occurred during periods when the average market price per share of our common stock was above the per share adjusted forward sale price described above. See Note 3 to the consolidated financial statements for the dilutive effect of the FSAs on our EPS at October 31, 2013 with the inclusion of incremental shares in our average shares of dilutive stock as calculated under the treasury stock method.

On January 4, 2012, we entered into an ASR agreement where we purchased 800,000 shares of our common stock from an investment bank at the closing price that day of $33.77 per share. The settlement and retirement of those shares occurred on January 5, 2012. Total consideration paid to purchase the shares of $27 million was recorded in “Stockholders’ equity” as a reduction in “Common stock” in the Consolidated Balance Sheets.

As part of the ASR, we simultaneously entered into a forward sale contract with the investment bank that was expected to mature in 52 trading days, or March 21, 2012. Under the terms of the forward sale contract, the investment bank was required to purchase, in the open market, 800,000 shares of our common stock during the term of the contract to fulfill its obligation related to the shares it borrowed from third parties and sold to us. At settlement, we, at our option, were required to either pay cash or issue shares of our common stock to the investment bank if the investment bank’s weighted average purchase price, less a $.09 per share discount, was higher than the January 4, 2012 closing price. The investment bank was required to pay us either cash or shares of our common stock, at our option, if the investment bank’s weighted average price, less a $.09 per share discount, for the shares purchased was lower than the initial purchase closing price. At settlement on February 28, 2012, we received $.5 million from the investment bank and recorded this amount in “Stockholders’ equity” as an addition to “Common stock” in the Consolidated Balance Sheets. The $.5 million was the difference between the investment bank’s weighted average purchase price of $33.25 per share less a discount of $.09 per share for a settlement price of $33.16 per share and the initial purchase closing price of $33.77 per share multiplied by 800,000 shares. We had an ASR transaction in 2011 as presented in the table above with a similar structure with the investment bank, which was accounted for in the same manner.

As of October 31, 2014, our shares of common stock were reserved for issuance as follows.

In thousands
ESPP	176
DRIP	840
ICP	950
Total	1,966

Other Comprehensive Income (Loss)

Our OCIL is a part of our accumulated OCIL and is comprised of hedging activities from our equity method investments. For further information on these hedging activities by our equity method investments, see Note 12 to the consolidated financial statements. Beginning in 2014, another component of our accumulated OCIL is the allocation of retirement benefits to SouthStar Energy Services, LLC (SouthStar) by its majority member. Changes in each component of accumulated OCIL are presented below for the years ended October 31, 2014 and 2013.

Changes in Accumulated OCIL (1)
In thousands	2014			2013
Accumulated OCIL beginning balance, net of tax	$	(284	)	$	(305	)
Hedging activities of equity method investments:
OCIL before reclassifications, net of tax	355			(109		)
Amounts reclassified from accumulated OCIL, net of tax	(284		)	130
Total current period activity of hedging activities of equity method investments, net of tax	71			21
Net current period benefit activities of equity method investments, net of tax	(24		)
Accumulated OCIL ending balance, net of tax	$	(237	)	$	(284	)

⁽¹⁾ Amounts in parentheses indicate debits to accumulated OCIL.

A reconciliation of the effect on certain line items of net income on amounts reclassified out of each component of accumulated OCIL is presented below for the years ended October 31, 2014 and 2013.

	Reclassification Out of Accumulated OCIL (1)
	Years Ended
	October 31						Affected Line Items on Statement of  Comprehensive Income
In thousands	2014			2013
Hedging activities of equity method investments	$	(461	)	$	215		Income from equity method investments
Income tax expense	177			(85		)	Income taxes
Hedging activities of equity method investments	(284		)	$	130
Net benefit activities of equity method investments	(40		)				Income from equity method investments
Income tax expense	16						Income taxes
Net benefit activities of equity method investments	(24		)
Total reclassification for the period, net of tax	$	(308	)	$	130

⁽¹⁾ Amounts in parentheses indicate debits to accumulated OCIL.

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Commitment & Contingencies

12 Months Ended

Oct. 31, 2014

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies Disclosure [Text Block]

Commitments and Contingent Liabilities

Leases

We lease certain buildings, land and equipment for use in our operations under noncancelable operating leases. We account for these leases by recognizing the future minimum lease payments as expense on a straight-line basis over the respective minimum lease terms under current accounting guidance.

Operating lease payments for the years ended October 31, 2014, 2013 and 2012 are as follows.

In thousands	2014		2013		2012
Operating lease payments (1)	$	4,701	$	4,729	$	3,712

⁽¹⁾ Operating lease payments do not include payments for common area maintenance, utilities or tax payments.

Future minimum lease obligations for the next five years ending October 31 and thereafter are as follows.

In thousands
2015	$	4,600
2016	4,491
2017	4,297
2018	4,225
2019	4,137
Thereafter	27,359
Total	$	49,109

Long-term contracts

We routinely enter into long-term gas supply commodity and capacity commitments and other agreements that commit future cash flows to acquire services we need in our business. These commitments include pipeline and storage capacity contracts and gas supply contracts to provide service to our customers and telecommunication and information technology contracts and other purchase obligations. Costs arising from the gas supply commodity and capacity commitments, while significant, are pass-through costs to our customers and are generally fully recoverable through our PGA procedures and prudence reviews in North Carolina and South Carolina and under the TIP in Tennessee. The time periods for fixed payments under pipeline and storage capacity contracts are up to twenty-one years. The time periods for fixed payments under gas supply contracts are up to three years. The time periods for the telecommunications and technology outsourcing contracts, maintenance fees for hardware and software applications, usage fees, local and long-distance costs and wireless service are up to five years. Other purchase obligations consist primarily of commitments for pipeline products, vehicles, equipment and contractors.

Certain storage and pipeline capacity contracts require the payment of demand charges that are based on rates approved by the FERC in order to maintain our right to access the natural gas storage or the pipeline capacity on a firm basis during the contract term. The demand charges that are incurred in each period are recognized in the Consolidated Statements of Comprehensive Income as part of gas purchases and included in “Cost of Gas.”

As of October 31, 2014, future unconditional purchase obligations for the next five years ending October 31 and thereafter are as follows.

	Pipeline		Gas Supply		Telecommunications
	Storage		Reservation		and Information
In thousands	Capacity		Fees		Technology		Other		Total
2015	$	158,984	$	8,657	$	14,601	$	41,008	$	223,250
2016	149,412		137		4,786		—		154,335
2017	145,579		135		736		—		146,450
2018	142,433		—		126		—		142,559
2019	132,186		—		80		—		132,266
Thereafter	627,602		—		—		—		627,602
Total	$	1,356,196	$	8,929	$	20,329	$	41,008	$	1,426,462

Legal

We have only routine litigation in the normal course of business. We do not expect any of these routine litigation matters to have a material effect, either individually or in the aggregate, on our financial position, results of operations or cash flows.

Letters of Credit

We use letters of credit to guarantee claims from self-insurance under our general and automobile liability policies. We had $1.8 million in letters of credit that were issued and outstanding at October 31, 2014. Additional information concerning letters of credit is included in Note 5 to the consolidated financial statements.

Surety Bonds

In the normal course of business, we are occasionally required to provide financial commitments in the form of surety bonds to third parties as a guarantee of our performance on commercial obligations. We have agreements that indemnify certain issuers of surety bonds against losses that they may incur as a result of executing surety bonds on our behalf. If we were to fail to perform according to the terms of the underlying contract, any draws upon surety bonds issued on our behalf would then trigger our payment obligation to the surety bond issuer. As of October 31, 2014, we had open surety bonds with a total contingent obligation of $4.8 million.

Environmental Matters

Our three regulatory commissions have authorized us to utilize deferral accounting in connection with environmental costs. Accordingly, we have established regulatory assets for actual environmental costs incurred and for estimated environmental liabilities recorded for manufactured gas plant (MGP) sites, LNG facilities and underground storage tanks (USTs).

In 1997, we entered into a settlement with a third-party with respect to nine MGP sites that we have owned, leased or operated that released us from any investigation and remediation liability. Although no such claims are pending or, to our knowledge, threatened, the settlement did not cover any third-party claims for personal injury, death, property damage and diminution of property value or natural resources.

In connection with the 2003 North Carolina Natural Gas Corporation (NCNG) acquisition, several MGP sites owned by NCNG were transferred to a wholly-owned subsidiary of Progress Energy, Inc. (Progress), now a subsidiary of Duke Energy Corporation (Duke Energy), prior to closing. Progress has complete responsibility for performing all of NCNG’s remediation obligations to conduct testing and clean-up at these sites, including both the costs of such testing and clean-up and the implementation of any affirmative remediation obligations that NCNG has related to the sites. Progress’ responsibility does not include any third-party claims for personal injury, death, property damage, and diminution of property value or natural resources. We know of no such pending or threatened claims.

The following table summarizes information regarding our environmental sites as of October 31, 2014.

			Costs		Undiscounted
	Site		Incurred		Environmental
In thousands	Type	Site Status	to Date		Liability *
Anderson, SC	MGP	Site Investigation Work Plan submitted to the South Carolina Department of Health and Environmental Control.	$	7	$	890
Hickory, NC	MGP	Remediation complete. Land use restrictions in progress.	1,494		18
Reidsville, NC	MGP	Remediation complete. Land use restrictions filed.	641		199
Huntersville, NC	LNG	Soil remediation complete. Quarterly and semi-annual groundwater sampling in progress. Lead-based paint remediation complete.	4,738		81
Charlotte, NC	UST	USTs removed. Tank closure process in progress with the North Carolina Department of Environment and Natural Resources.	32		33
Clemmons, NC	UST	Potential responsible party for propane tank	—		38
Totals			$	6,912	$	1,259
* Estimated based on assumptions using actual costs incurred, the timing of future payments and inflation factors, among others.

We continue to expand our sampling of our pipelines for coatings containing asbestos. Additionally, we continue to educate our employees on the hazards of asbestos and implemented procedures for removing these coatings from our pipelines when we must excavate and expose portions of the pipeline.

As of October 31, 2014, our regulatory assets for unamortized environmental costs in our three-state territory totaled $8 million. We received approval from the TRA to recover $2 million of our deferred Tennessee environmental costs over an eight-year period beginning March 2012, pursuant to the 2012 general rate case proceeding in Tennessee. We will seek recovery of the remaining Tennessee balance in future rate proceedings. The approval by the NCUC in December 2013 of the settlement of the general rate proceeding allowed recovery of $6.3 million of our deferred North Carolina environmental costs over a five-year period beginning January 2014. We received approval from the PSCSC to recover $.1 million of our deferred South Carolina environmental costs over a one-year period beginning November 2014, pursuant to the annual rate stabilization order issued in October 2014.

Further evaluation of the MGP, LNG and UST sites could significantly affect recorded amounts; however, we believe that the ultimate resolution of these matters will not have a material effect on our financial position, results of operations or cash flows.

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Employee Share Based Plans (Tables)

12 Months Ended

Oct. 31, 2014

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Schedule of Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Table Text Block]

The compensation expense related to the incentive compensation plans for the years ended October 31, 2014, 2013 and 2012, and the amounts recorded as liabilities in "Other noncurrent liabilities" in "Noncurrent Liabilities" with the current portion recorded in "Other current liabilities" in "Current Liabilities" in the Consolidated Balance Sheets as of October 31, 2014 and 2013 are presented below.

In thousands	2014		2013		2012
Compensation expense	$	8,496	$	4,526	$	5,730
Tax benefit	2,476		1,538		2,080
Liability	15,130		11,098

Expected Payout For Approved Incentive Compensation Plans [Table Text Block]

Based on current accrual assumptions as of October 31, 2014, the expected payout for the approved incentive compensation awards at target will occur in the following fiscal years.

In thousands	2015		2016		2017
Amount of payout	$	7,204	$	4,980	$	2,946

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Income Taxes Income Tax Expense Components (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Oct. 31, 2014	Oct. 31, 2013	Oct. 31, 2012
Effective Income Tax Rate Reconciliation, Nondeductible Expense, Depreciation and Amortization, Amount [Abstract]
Amortization of investment tax credits	$ (209)	$ (267)	$ (334)
Federal Total	78,836	72,860	64,950
State Total	15,982	13,086	13,267
Regulated Operation [Member]
Income Tax Table Continuing Operations [Line Items]
Current Federal Tax Expense (Benefit)	(1,653)	(3,032)	(29,062)
Current State Tax Expense (Benefit)	950	919	1,857
Deferred Federal Income Tax Expense (Benefit)	70,654	67,885	86,496
Deferred State Income Tax Expense (Benefit)	13,434	11,829	10,144
Effective Income Tax Rate Reconciliation, Nondeductible Expense, Depreciation and Amortization, Amount [Abstract]
Amortization of investment tax credits	(209)	(267)	(334)
Federal Total	68,792	64,586	57,100
State Total	14,384	12,748	12,001
Unregulated Operation [Member]
Income Tax Table Continuing Operations [Line Items]
Current Federal Tax Expense (Benefit)	4,233	6,049	5,636
Current State Tax Expense (Benefit)	870	984	1,027
Deferred Federal Income Tax Expense (Benefit)	5,811	2,225	2,214
Deferred State Income Tax Expense (Benefit)	728	(646)	239
Effective Income Tax Rate Reconciliation, Nondeductible Expense, Depreciation and Amortization, Amount [Abstract]
Federal Total	10,044	8,274	7,850
State Total	1,598	338	1,266
Domestic Tax Authority [Member] | NOL Carryforward 1 [Member]
Income Tax Table Continuing Operations [Line Items]
Deferred Federal Income Tax Expense (Benefit)	$ 28,600	$ (62,300)

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Variable Interest Entities

12 Months Ended

Oct. 31, 2014

Variable Interest Entity, Not Primary Beneficiary, Disclosures [Abstract]

Aggregation Of Variable Interest Entities Disclosures [Text Block]

Variable Interest Entities

Under accounting guidance, a VIE is a legal entity that conducts a business or holds property whose equity, by design, has any of the following characteristics: an insufficient amount of equity at risk to finance its activities, equity owners who do not have the power to direct the significant activities of the entity (or have voting rights that are disproportionate to their ownership interest), or where equity owners do not receive expected losses or returns. An entity may have an interest in a VIE through ownership or other contractual rights or obligations and that interest changes as the entity’s net assets change. The consolidating investor, or the primary beneficiary, is the entity that has the power to direct the activities of a VIE that most significantly impact the VIE’s economic performance, the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE.

On a quarterly basis, we reassess whether we have a controlling financial interest in and are the primary beneficiary of a VIE. The quarterly reassessment process considers whether we have acquired or divested the power to direct the activities of the VIE through changes in governing documents or other circumstances. The reassessment also considers whether we have acquired or disposed of a financial interest that could be significant to the VIE, or whether an interest in the VIE has become significant or is no longer significant. The consolidation status of the VIEs with which we are involved may change as a result of such reassessments. Changes in consolidation status are applied prospectively, with assets and liabilities of a newly consolidated VIE initially recorded at fair value. A gain or loss may be recognized upon deconsolidation of a VIE depending on the carrying values of deconsolidated assets and liabilities compared to the fair value of retained interests and ongoing contractual arrangements.

As of October 31, 2014, we have determined that we are not the primary beneficiary under VIE accounting guidance in any of our equity method investments, as discussed in Note 12 to the consolidated financial statements. Based on our involvement in these investments, we do not have the power to direct the activities of these investments that most significantly impact the VIE’s economic performance. As we are not the consolidating investor, we will continue to apply equity method accounting to these investments, as discussed in Note 12 to the consolidated financial statements. Our maximum loss exposure related to these equity method investments is limited to our equity investment in each entity. As of October 31, 2014 and 2013, our investment balances are as follows.

	October 31,		October 31,
In thousands	2014		2013
Cardinal	$	16,073	$	18,207
Pine Needle	18,689		20,270
SouthStar	40,965		38,372
Hardy Storage	37,179		34,681
Constitution	57,255		16,939
ACP	10
Total equity method investments in non-utility activities	$	170,171	$	128,469

We have also reviewed various lease arrangements, contracts to purchase, sell or deliver natural gas and other agreements in which we hold a variable interest. In these cases, we have determined that we are not the primary beneficiary of the related VIE because we do not have the power to direct the activities of the VIE that most significantly impact the VIE’s economic performance, or the obligation to absorb losses of the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE.

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Summary Of Significant Accounting Policies (Tables)

12 Months Ended

Oct. 31, 2014

Accounting Policies [Abstract]

Schedule of Regulatory Assets [Table Text Block]

Regulatory assets and liabilities in the Consolidated Balance Sheets as of October 31, 2014 and 2013 are as follows.

In thousands	2014		2013
Regulatory Assets:
Current:
Unamortized debt expense	$	1,490	$	1,274
Amounts due from customers	16,108		66,321
Environmental costs	1,568		1,480
Deferred operations and maintenance expenses	916		739
Deferred pipeline integrity expenses	3,470		3,149
Deferred pension and other retirement benefits costs	2,769		2,768
Robeson liquefied natural gas (LNG) development costs	917		382
Other	1,850		1,091
Total current	29,088		77,204
Noncurrent:
Unamortized debt expense	15,402		14,149
Environmental costs	6,470		7,936
Deferred operations and maintenance expenses	4,721		5,637
Deferred pipeline integrity expenses	24,694		16,300
Deferred pension and other retirement benefits costs	18,799		17,968
Amounts not yet recognized as a component of pension and other retirement benefit costs	94,265		80,604
Regulatory cost of removal asset	18,275		22,974
Robeson LNG development costs	509		1,426
Other	1,644		2,108
Total noncurrent	184,779		169,102
Total	$	213,867	$	246,306

Schedule of Regulatory Liabilities [Table Text Block]

Regulatory Liabilities:
Current:
Amounts due to customers	$	46,231	$	—
Noncurrent:
Regulatory cost of removal obligations	506,574		493,111
Deferred income taxes	51,930		48,647
Amounts not yet recognized as a component of pension and other retirement costs	94		139
Total noncurrent	558,598		541,897
Total	$	604,829	$	541,897

Public Utility Property, Plant, and Equipment [Table Text Block]

The classification of total utility plant, net, for the years ended October 31, 2014 and 2013 is presented below.

In thousands	2014			2013
Intangible plant	$	3,374		$	3,374
Other storage plant	180,058			171,349
Transmission plant	1,787,990			1,403,829
Distribution plant	2,623,560			2,505,160
General plant	421,763			335,847
Asset retirement cost	11			7,565
Contributions in aid of construction	(5,259		)	(5,187		)
Total utility plant in service	5,011,497			4,421,937
Less accumulated depreciation	(1,166,922		)	(1,088,331		)
Total utility plant in service, net	3,844,575			3,333,606
Construction work in progress	141,693			297,717
Plant held for future use	3,155			3,155
Total utility plant, net	$	3,989,423		$	3,634,478

AFUDC for the years ended October 31, 2014, 2013 and 2012 is presented below.

In thousands	2014		2013		2012
AFUDC	$	16,427	$	30,975	$	25,211

Schedule of Trade Account Receivables [Table Text Block]

As of October 31, 2014 and 2013, our trade accounts receivable consisted of the following.

In thousands	2014			2013
Gas receivables	$	64,400		$	78,540
Non-regulated merchandise and service work receivables	3,012			2,274
Allowance for doubtful accounts	(2,152		)	(1,604		)
Trade accounts receivable	$	65,260		$	79,210

Schedule of Changes in Allowance for Doubtful Accounts [Table Text Block]

A reconciliation of the changes in the allowance for doubtful accounts for the years ended October 31, 2014, 2013 and 2012 is presented below.

In thousands	2014			2013			2012
Balance at beginning of year	$	1,604		$	1,579		$	1,347
Additions charged to uncollectibles expense	6,959			5,314			4,584
Accounts written off, net of recoveries	(6,411		)	(5,289		)	(4,352		)
Balance at end of year	$	2,152		$	1,604		$	1,579

Marketable Securities [Table Text Block]

The money market investments in the trusts approximate fair value due to the short period of time to maturity. The fair values of the equity securities are based on quoted market prices as traded on the exchanges. The composition of these securities as of October 31, 2014 and 2013 is as follows.

	2014				2013
In thousands	Cost		Fair Value		Cost		Fair Value
Current trading securities:
Money markets	$	22	$	22	$	—	$	—
Mutual funds	106		192		134		199
Total current trading securities	128		214		134		199
Noncurrent trading securities:
Money markets	447		447		380		380
Mutual funds	2,598		3,280		1,995		2,615
Total noncurrent trading securities	3,045		3,727		2,375		2,995
Total trading securities	$	3,173	$	3,941	$	2,509	$	3,194

Schedule of Asset Retirement Obligations [Table Text Block]

The cost of removal obligations recorded in the Consolidated Balance Sheets as of October 31, 2014 and 2013 are presented below.

In thousands	2014		2013
Regulatory non-legal AROs	$	506,574	$	493,111
Conditional AROs	14,647		27,016
Total cost of removal obligations	$	521,221	$	520,127

Schedule of Change in Asset Retirement Obligation [Table Text Block]

A reconciliation of the changes in conditional AROs for the year ended October 31, 2014 and 2013 is presented below.

In thousands	2014			2013
Beginning of period	$	27,016		$	28,629
Liabilities incurred during the period	2,108			2,052
Liabilities settled during the period	(3,576		)	(2,389		)
Accretion	1,548			1,641
Adjustment to estimated cash flows	(12,449		)	(2,917		)
End of period	$	14,647		$	27,016

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Employee Benefit Plans (Details) (USD $)	12 Months Ended
	Oct. 31, 2014	Oct. 31, 2013	Oct. 31, 2012
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Measurement Date	October 31
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Noncurrent assets	$ 33,757,000	$ 28,258,000
Amounts Not Yet Recognized as a Component of Cost and Recognized in a Deferred Regulatory Account
Regulatory asset	(213,867,000)	(246,306,000)
Defined Benefit Plan Actuarial Gains And Losses Amortization Corridor	5 years
Gains And Losses Amortized In Excess Of Percentage	10.00%
Qualified Pension [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plans, General Information	We have a noncontributory, tax-qualified defined benefit pension plan (qualified pension plan) for our eligible employees. A defined benefit plan specifies the amount of benefit that an eligible participant eventually will receive upon retirement using information about that participant. An employee became eligible on the January 1 or July 1 following either the date on which he or she attained age 30 or attained age 21 and completed 1,000 hours of service during the 12-month period commencing on the employment date. Plan benefits are generally based on credited years of service and the level of compensation during the five consecutive years of the last ten years prior to retirement or termination during which the participant received the highest compensation. Our policy is to fund the plan in an amount not in excess of the amount that is deductible for income tax purposes. The qualified pension plan is closed to employees hired after December 31, 2007. Employees hired prior to January 1, 2008 continue to participate in the qualified pension plan. Employees are vested after five years of service and can be credited with up to a total of 35 years of service. When a vested employee leaves the company, his benefit payment will be calculated as the greater of the accrued benefit as of December 31, 2007 under a specific formula plus the accrued benefit calculated under a second formula for years of service after December 31, 2007, or the benefit for all years of service up to 35 years under the second formula.
Standard Eligibility Age For Defined Benefit Plan	30 years
Service Required For Eligibility In Defined Benefit Plan	125 days
Years Of Highest Compensation For Benefit Calculation	5 years
Duration To Complete Service Requirement	12 months
Horizon For DBPP Long Term Rates Of Return	20 years
Period Of Compensation For Benefit Calculation	10 years
Plan Vesting Period Defined Benefit Plan	5 years
Maximum Credited Service Period	35 years
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations	100.00%	100.00%
Defined Benefit Plan, Fair Value of Plan Assets	336,443,000	300,661,000	272,337,000
Defined Benefit Pension Plan Funding Target	100.00%
Defined Benefit Plans, Estimated Future Employer Contributions in Next Fiscal Year	10,000,000
Reconciliation Of Changes In Plan Benefit Obligations And Fair Value Of Assets [Abstract]
Accumulated Benefit Obligation At Year End	252,706,000	230,175,000
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Obligation at beginning of year	272,403,000	293,327,000
Service cost	10,865,000	12,005,000	9,573,000
Interest cost	11,781,000	9,946,000	10,640,000
Plan amendments	0	0
Actuarial (gain) loss	23,646,000	(24,859,000)
Participant contributions	0	0
Administrative expenses	(465,000)	(534,000)
Benefit payments	(15,544,000)	(17,482,000)
Obligation at end of year	302,686,000	272,403,000	293,327,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	300,661,000	272,337,000
Actual return on plan assets	31,791,000	26,340,000
Employer contributions	20,000,000	20,000,000
Participant contributions	0	0
Administrative expenses	(465,000)	(534,000)
Benefit payments	(15,544,000)	(17,482,000)
Fair value at end of year	336,443,000	300,661,000	272,337,000
Funded status at year end - (under) over	33,757,000	28,258,000
Noncurrent assets	33,757,000	28,258,000
Current liabilities	0	0
Noncurrent liabilities	0	0
Net amount recognized	33,757,000	28,258,000
Amounts Not Yet Recognized as a Component of Cost and Recognized in a Deferred Regulatory Account
Unrecognized transition obligation	0	0
Unrecognized prior service (cost) credit	15,046,000	17,243,000
Unrecognized actuarial loss	(103,038,000)	(96,338,000)
Regulatory asset	(87,992,000)	(79,095,000)
Cumulative employer contributions in excess of cost	121,749,000	107,353,000
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost	10,865,000	12,005,000	9,573,000
Interest cost	11,781,000	9,946,000	10,640,000
Expected return on plan assets	(22,530,000)	(21,105,000)	(20,289,000)
Transition obligation	0	0	0
Amortization of prior service cost (credit)	(2,198,000)	(2,198,000)	(2,198,000)
Amortization of net loss	7,685,000	11,202,000	5,966,000
Net periodic benefit cost	5,603,000	9,850,000	3,692,000
Estimated Amortization And Expected Refunds [Abstract]
Amortization of unrecognized prior service cost (credit)	(2,198,000)
Amortization of unrecognized actuarial loss	8,121,000
Other Changes In Plan Assets And Benefit Obligatin Recognized Through Regulatory Asset Or Liability [Abstract]
Prior service cost	0	0	0
Net loss (gain)	14,385,000	(30,094,000)	43,945,000
Amounts Recognized As Component Of Net Periodic Benefit Cost [Abstract]
Transition obligation	0	0	0
Amortization of net loss	(7,685,000)	(11,202,000)	(5,966,000)
Amortization of prior service (cost) credit	2,198,000	2,198,000	2,198,000
Total recognized in regulatory asset (liability)	8,898,000	(39,098,000)	40,177,000
Total Recognized In Net Periodic Benefit Cost And Regulatory Asset (Liability)	14,501,000	(29,248,000)	43,869,000
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Discount Rate	4.13%	4.55%
Rate Of Compensation Increase	3.68%	3.72%
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Discount Rate	4.55%	3.51%	4.67%
Expected Long Term Rate Of Return On Plan Assets	7.75%	8.00%	8.00%
Rate Of Compensation Increase	3.72%	3.76%	3.78%
Defined Benefit Plan, Expected Future Benefit Payments, Fiscal Year Maturity [Abstract]
2015	29,946,000
2016	16,794,000
2017	16,332,000
2018	19,197,000
2019	20,685,000
2020 - 2024	110,459,000
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	300,661,000	272,337,000
Actual return on plan assets:
Fair value at end of year	336,443,000	300,661,000	272,337,000
Qualified Pension [Member] | Minimum [Member]
Defined Benefit Plan Disclosure [Line Items]
Standard Eligibility Age For Defined Benefit Plan	21 years
Qualified Pension [Member] | Cash [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations	8.00%	2.00%
Defined Benefit Plan, Fair Value of Plan Assets	28,367,000	5,722,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	28,367,000	5,722,000
Actual return on plan assets:
Fair value at end of year	28,367,000	5,722,000
Qualified Pension [Member] | Fixed Income Funds [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Target Plan Asset Allocations	45.00%
Defined Benefit Plan, Actual Plan Asset Allocations	45.00%	38.00%
Qualified Pension [Member] | US Treasuries [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations	8.00%	8.00%
Defined Benefit Plan, Fair Value of Plan Assets	27,224,000	24,078,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	27,224,000	24,078,000
Actual return on plan assets:
Fair value at end of year	27,224,000	24,078,000
Qualified Pension [Member] | Long Duration Bonds [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations	14.00%	11.00%
Defined Benefit Plan, Fair Value of Plan Assets	48,049,000	34,041,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	48,049,000	34,041,000
Actual return on plan assets:
Fair value at end of year	48,049,000	34,041,000
Qualified Pension [Member] | Corporate Bonds [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations	15.00%	14.00%
Defined Benefit Plan, Fair Value of Plan Assets	49,816,000	42,701,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	49,816,000	42,701,000
Actual return on plan assets:
Fair value at end of year	49,816,000	42,701,000
Qualified Pension [Member] | High Yield Bonds [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations	3.00%	5.00%
Defined Benefit Plan, Fair Value of Plan Assets	8,100,000	14,680,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	8,100,000	14,680,000
Actual return on plan assets:
Fair value at end of year	8,100,000	14,680,000
Qualified Pension [Member] | Common trust fund - Bank loans [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations	5.00%
Defined Benefit Plan, Fair Value of Plan Assets	16,187,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	16,187,000
Defined Benefit Plan, Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rates [Abstract]
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Investment Redemption, Notice Period	30 days
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Investment Redemption, Frequency	Daily
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Redemption Restriction, Description	None
Actual return on plan assets:
Fair value at end of year	16,187,000
Qualified Pension [Member] | Collateralized Mortgage Obligations [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations	0.00%	0.00%
Defined Benefit Plan, Fair Value of Plan Assets	1,035,000	1,098,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	1,035,000	1,098,000
Actual return on plan assets:
Fair value at end of year	1,035,000	1,098,000
Qualified Pension [Member] | Derivatives [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations	0.00%	0.00%
Defined Benefit Plan, Fair Value of Plan Assets	(1,000)	(11,000)
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	(1,000)	(11,000)
Actual return on plan assets:
Fair value at end of year	(1,000)	(11,000)
Qualified Pension [Member] | Derivatives [Member] | Maximum [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Investment Limitation Percentage	10.00%
Qualified Pension [Member] | Equity Securities [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Target Plan Asset Allocations	35.00%
Defined Benefit Plan, Actual Plan Asset Allocations	31.00%	43.00%
Qualified Pension [Member] | Large Cap Index [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations	3.00%	4.00%
Defined Benefit Plan, Fair Value of Plan Assets	9,982,000	12,023,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	9,982,000	12,023,000
Actual return on plan assets:
Fair value at end of year	9,982,000	12,023,000
Qualified Pension [Member] | Large Cap Value [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations	6.00%	6.00%
Defined Benefit Plan, Fair Value of Plan Assets	19,937,000	16,908,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	19,937,000	16,908,000
Actual return on plan assets:
Fair value at end of year	19,937,000	16,908,000
Qualified Pension [Member] | Large Cap Growth [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations	6.00%	6.00%
Defined Benefit Plan, Fair Value of Plan Assets	19,745,000	17,823,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	19,745,000	17,823,000
Actual return on plan assets:
Fair value at end of year	19,745,000	17,823,000
Qualified Pension [Member] | Small Cap Value [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations	9.00%	10.00%
Defined Benefit Plan, Fair Value of Plan Assets	31,329,000	30,831,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	31,329,000	30,831,000
Actual return on plan assets:
Fair value at end of year	31,329,000	30,831,000
Qualified Pension [Member] | Common Trust Fund International Value [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations		8.00%
Defined Benefit Plan, Fair Value of Plan Assets		24,460,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year		24,460,000
Actual return on plan assets:
Fair value at end of year		24,460,000
Qualified Pension [Member] | Common Trust Fund International Growth [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations	7.00%	9.00%
Defined Benefit Plan, Fair Value of Plan Assets	22,877,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	27,270,000
Fair value at end of year	22,877,000
Defined Benefit Plan, Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rates [Abstract]
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Investment Redemption, Notice Period	30 days
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Investment Redemption, Frequency	Monthly
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Redemption Restriction, Description	None
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	27,270,000
Actual return on plan assets:
Fair value at end of year	22,877,000
Qualified Pension [Member] | Global REIT [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Target Plan Asset Allocations	5.00%
Defined Benefit Plan, Actual Plan Asset Allocations	5.00%	5.00%
Defined Benefit Plan, Fair Value of Plan Assets	16,675,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	15,042,000
Fair value at end of year	16,675,000
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	15,042,000
Actual return on plan assets:
Fair value at end of year	16,675,000
Qualified Pension [Member] | Total Other Investments [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Target Plan Asset Allocations	15.00%
Defined Benefit Plan, Actual Plan Asset Allocations	11.00%	12.00%
Qualified Pension [Member] | Hedge Fund of Funds [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations	6.00%	6.00%
Defined Benefit Plan, Fair Value of Plan Assets	19,829,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	18,571,000
Fair value at end of year	19,829,000
Defined Benefit Plan, Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rates [Abstract]
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Investment Redemption, Notice Period	65 days
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Investment Redemption, Frequency	Quarterly
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Redemption Restriction, Description	Redeemed in whole or part but not less than the minimum redemption amount for each currency. Redemption within one year of purchase is subject to 1.5% redemption fee. Redeemed on “first in first out” basis. None of our investment is subject to the redemption fee. Fund’s Board of Directors may limit or suspend share redemptions until a further notification ending suspension. No such notification has been received as of October 31, 2014.
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	18,571,000
Actual return on plan assets:
Fair value at end of year	19,829,000
Qualified Pension [Member] | Private Equity Fund of Funds [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Target Plan Asset Allocations	3.50%
Defined Benefit Plan, Actual Plan Asset Allocations	2.00%	2.00%
Defined Benefit Plan, Fair Value of Plan Assets	7,158,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	4,659,000
Fair value at end of year	7,158,000
Defined Benefit Plan, Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rates [Abstract]
Initial Unfunded Subscription Balance	12,000,000
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Investment Redemption, Frequency	Limited
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Unfunded Commitments	5,400,000
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Redemption Restriction, Description	Investors have only very limited withdrawal rights for specific legal or regulatory reasons. Any transfer of interest will be subject to approval.
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	4,659,000
Actual return on plan assets:
Fair value at end of year	7,158,000
Qualified Pension [Member] | Private Equity Fund of Funds [Member] | Minimum [Member]
Defined Benefit Plan, Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rates [Abstract]
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Liquidating Investment, Remaining Period	10 years
Qualified Pension [Member] | Private Equity Fund of Funds [Member] | Maximum [Member]
Defined Benefit Plan, Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rates [Abstract]
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Liquidating Investment, Remaining Period	12 years
Qualified Pension [Member] | Commodities Fund of Funds [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations	3.00%	4.00%
Defined Benefit Plan, Fair Value of Plan Assets	10,134,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	10,765,000
Fair value at end of year	10,134,000
Defined Benefit Plan, Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rates [Abstract]
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Investment Redemption, Notice Period	35 days
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Investment Redemption, Frequency	Monthly
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Redemption Restriction, Description	Redemption within one year of purchase is subject to 1% redemption fee. None of our investment is subject to the redemption fee. If 95% or more of the balance is requested, 95% of the balance will be paid within 30 days. Any outstanding balance or interest owed will be paid after the annual audit is complete.
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	10,765,000
Actual return on plan assets:
Fair value at end of year	10,134,000
Qualified Pension [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations	40.00%	37.00%
Defined Benefit Plan, Fair Value of Plan Assets	133,748,000	112,879,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	133,748,000	112,879,000
Actual return on plan assets:
Fair value at end of year	133,748,000	112,879,000
Qualified Pension [Member] | Fair Value, Inputs, Level 1 [Member] | Cash [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	27,932,000	5,566,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	27,932,000	5,566,000
Actual return on plan assets:
Fair value at end of year	27,932,000	5,566,000
Qualified Pension [Member] | Fair Value, Inputs, Level 1 [Member] | US Treasuries [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Qualified Pension [Member] | Fair Value, Inputs, Level 1 [Member] | Long Duration Bonds [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Qualified Pension [Member] | Fair Value, Inputs, Level 1 [Member] | Corporate Bonds [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Qualified Pension [Member] | Fair Value, Inputs, Level 1 [Member] | High Yield Bonds [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	8,100,000	14,680,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	8,100,000	14,680,000
Actual return on plan assets:
Fair value at end of year	8,100,000	14,680,000
Qualified Pension [Member] | Fair Value, Inputs, Level 1 [Member] | Common trust fund - Bank loans [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0
Actual return on plan assets:
Fair value at end of year	0
Qualified Pension [Member] | Fair Value, Inputs, Level 1 [Member] | Collateralized Mortgage Obligations [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Qualified Pension [Member] | Fair Value, Inputs, Level 1 [Member] | Derivatives [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	48,000	6,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	48,000	6,000
Actual return on plan assets:
Fair value at end of year	48,000	6,000
Qualified Pension [Member] | Fair Value, Inputs, Level 1 [Member] | Large Cap Index [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	9,982,000	12,023,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	9,982,000	12,023,000
Actual return on plan assets:
Fair value at end of year	9,982,000	12,023,000
Qualified Pension [Member] | Fair Value, Inputs, Level 1 [Member] | Large Cap Value [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	19,937,000	16,908,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	19,937,000	16,908,000
Actual return on plan assets:
Fair value at end of year	19,937,000	16,908,000
Qualified Pension [Member] | Fair Value, Inputs, Level 1 [Member] | Large Cap Growth [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	19,745,000	17,823,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	19,745,000	17,823,000
Actual return on plan assets:
Fair value at end of year	19,745,000	17,823,000
Qualified Pension [Member] | Fair Value, Inputs, Level 1 [Member] | Small Cap Value [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	31,329,000	30,831,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	31,329,000	30,831,000
Actual return on plan assets:
Fair value at end of year	31,329,000	30,831,000
Qualified Pension [Member] | Fair Value, Inputs, Level 1 [Member] | Common Trust Fund International Value [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets		0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year		0
Actual return on plan assets:
Fair value at end of year		0
Qualified Pension [Member] | Fair Value, Inputs, Level 1 [Member] | Common Trust Fund International Growth [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Qualified Pension [Member] | Fair Value, Inputs, Level 1 [Member] | Global REIT [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	16,675,000	15,042,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	16,675,000	15,042,000
Actual return on plan assets:
Fair value at end of year	16,675,000	15,042,000
Qualified Pension [Member] | Fair Value, Inputs, Level 1 [Member] | Hedge Fund of Funds [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Qualified Pension [Member] | Fair Value, Inputs, Level 1 [Member] | Private Equity Fund of Funds [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Qualified Pension [Member] | Fair Value, Inputs, Level 1 [Member] | Commodities Fund of Funds [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Qualified Pension [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations	58.00%	61.00%
Defined Benefit Plan, Fair Value of Plan Assets	195,537,000	183,123,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	195,537,000	183,123,000
Actual return on plan assets:
Fair value at end of year	195,537,000	183,123,000
Qualified Pension [Member] | Fair Value, Inputs, Level 2 [Member] | Cash [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	435,000	156,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	435,000	156,000
Actual return on plan assets:
Fair value at end of year	435,000	156,000
Qualified Pension [Member] | Fair Value, Inputs, Level 2 [Member] | US Treasuries [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	27,224,000	24,078,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	27,224,000	24,078,000
Actual return on plan assets:
Fair value at end of year	27,224,000	24,078,000
Qualified Pension [Member] | Fair Value, Inputs, Level 2 [Member] | Long Duration Bonds [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	48,049,000	34,041,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	48,049,000	34,041,000
Actual return on plan assets:
Fair value at end of year	48,049,000	34,041,000
Qualified Pension [Member] | Fair Value, Inputs, Level 2 [Member] | Corporate Bonds [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	49,816,000	42,701,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	49,816,000	42,701,000
Actual return on plan assets:
Fair value at end of year	49,816,000	42,701,000
Qualified Pension [Member] | Fair Value, Inputs, Level 2 [Member] | High Yield Bonds [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Qualified Pension [Member] | Fair Value, Inputs, Level 2 [Member] | Common trust fund - Bank loans [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	16,187,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	16,187,000
Actual return on plan assets:
Fair value at end of year	16,187,000
Qualified Pension [Member] | Fair Value, Inputs, Level 2 [Member] | Collateralized Mortgage Obligations [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	1,035,000	1,098,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	1,035,000	1,098,000
Actual return on plan assets:
Fair value at end of year	1,035,000	1,098,000
Qualified Pension [Member] | Fair Value, Inputs, Level 2 [Member] | Derivatives [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	(49,000)	(17,000)
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	(49,000)	(17,000)
Actual return on plan assets:
Fair value at end of year	(49,000)	(17,000)
Qualified Pension [Member] | Fair Value, Inputs, Level 2 [Member] | Large Cap Index [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Qualified Pension [Member] | Fair Value, Inputs, Level 2 [Member] | Large Cap Value [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Qualified Pension [Member] | Fair Value, Inputs, Level 2 [Member] | Large Cap Growth [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Qualified Pension [Member] | Fair Value, Inputs, Level 2 [Member] | Small Cap Value [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Qualified Pension [Member] | Fair Value, Inputs, Level 2 [Member] | Common Trust Fund International Value [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets		24,460,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year		24,460,000
Actual return on plan assets:
Fair value at end of year		24,460,000
Qualified Pension [Member] | Fair Value, Inputs, Level 2 [Member] | Common Trust Fund International Growth [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	22,877,000	27,270,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	22,877,000	27,270,000
Actual return on plan assets:
Fair value at end of year	22,877,000	27,270,000
Qualified Pension [Member] | Fair Value, Inputs, Level 2 [Member] | Global REIT [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Qualified Pension [Member] | Fair Value, Inputs, Level 2 [Member] | Hedge Fund of Funds [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	19,829,000	18,571,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	19,829,000	18,571,000
Actual return on plan assets:
Fair value at end of year	19,829,000	18,571,000
Qualified Pension [Member] | Fair Value, Inputs, Level 2 [Member] | Private Equity Fund of Funds [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Qualified Pension [Member] | Fair Value, Inputs, Level 2 [Member] | Commodities Fund of Funds [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	10,134,000	10,765,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	10,134,000	10,765,000
Actual return on plan assets:
Fair value at end of year	10,134,000	10,765,000
Qualified Pension [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations	2.00%	2.00%
Defined Benefit Plan, Fair Value of Plan Assets	7,158,000	4,659,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	7,158,000	4,659,000
Actual return on plan assets:
Fair value at end of year	7,158,000	4,659,000
Qualified Pension [Member] | Fair Value, Inputs, Level 3 [Member] | Cash [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Qualified Pension [Member] | Fair Value, Inputs, Level 3 [Member] | US Treasuries [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Qualified Pension [Member] | Fair Value, Inputs, Level 3 [Member] | Long Duration Bonds [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Qualified Pension [Member] | Fair Value, Inputs, Level 3 [Member] | Corporate Bonds [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Qualified Pension [Member] | Fair Value, Inputs, Level 3 [Member] | High Yield Bonds [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Qualified Pension [Member] | Fair Value, Inputs, Level 3 [Member] | Common trust fund - Bank loans [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0
Actual return on plan assets:
Fair value at end of year	0
Qualified Pension [Member] | Fair Value, Inputs, Level 3 [Member] | Collateralized Mortgage Obligations [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Qualified Pension [Member] | Fair Value, Inputs, Level 3 [Member] | Derivatives [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Qualified Pension [Member] | Fair Value, Inputs, Level 3 [Member] | Large Cap Index [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Qualified Pension [Member] | Fair Value, Inputs, Level 3 [Member] | Large Cap Value [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Qualified Pension [Member] | Fair Value, Inputs, Level 3 [Member] | Large Cap Growth [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Qualified Pension [Member] | Fair Value, Inputs, Level 3 [Member] | Small Cap Value [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Qualified Pension [Member] | Fair Value, Inputs, Level 3 [Member] | Common Trust Fund International Value [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets		0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year		0
Actual return on plan assets:
Fair value at end of year		0
Qualified Pension [Member] | Fair Value, Inputs, Level 3 [Member] | Common Trust Fund International Growth [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Qualified Pension [Member] | Fair Value, Inputs, Level 3 [Member] | Global REIT [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Qualified Pension [Member] | Fair Value, Inputs, Level 3 [Member] | Hedge Fund of Funds [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Qualified Pension [Member] | Fair Value, Inputs, Level 3 [Member] | Private Equity Fund of Funds [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	7,158,000	4,659,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	4,659,000	3,522,000
Fair value at end of year	7,158,000	4,659,000
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	4,659,000	3,522,000
Actual return on plan assets:
Relating to assets still held at the reporting date	1,031,000	116,000
Relating to assets sold during the period	113,000	61,000
Purchases, sales and settlements (net)	1,355,000	960,000
Transfer in/out of Level 3	0	0
Fair value at end of year	7,158,000	4,659,000
Qualified Pension [Member] | Fair Value, Inputs, Level 3 [Member] | Commodities Fund of Funds [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Supplemental Executive Retirement Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plans, General Information	We have pension liabilities related to supplemental executive retirement plans (SERPs) for certain former employees, non-employee directors or surviving spouses. There are no assets related to these SERPs, and no additional benefits accrue to the participants. Payments to the participants are made from operating funds during the year.
Defined Benefit Plan, Information about Plan Assets [Abstract]
Assets for Participant Benefits	0
Officers and Director-Level Employees Life Insurance [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plans, General Information	We also provide a term life insurance benefit equal to $200,000 to all officers and director-level employees for which we bear the cost of the policies.
Defined Benefit Plan, Information about Plan Assets [Abstract]
Term Life Insurance Per Individual Benefit Provided By Employer	200,000
Term Life Insurance Premiums Paid By Employer	32,000	28,000	25,000
Certain Officers Vice President And Above Life Insurance [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plans, General Information	We provide term life insurance policies for certain officers at the vice president level and above who were former participants in a terminated SERP; the level of the insurance benefit is dependent upon the level of the benefit provided under the terminated SERP. These life insurance policies are owned exclusively by each officer. Premiums on these policies are paid and expensed.
Defined Benefit Plan, Information about Plan Assets [Abstract]
Term Life Insurance Premiums Paid By Employer	30,000	27,000	43,000
Other Postretirement Benefit Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plans, General Information	We provide certain postretirement health care and life insurance benefits to eligible retirees. The liability associated with such benefits is funded in irrevocable trust funds that can only be used to pay the benefits. Employees are first eligible to retire and receive these benefits at age 55 with ten or more years of service after the age of 45. Employees who met this requirement in 1993 or who retired prior to 1993 are in a “grandfathered” group for whom we pay the full cost of the retiree’s coverage. Retirees not in the grandfathered group have a portion of the cost of retiree coverage paid by us, subject to certain annual contribution limits. Retirees are responsible for the full cost of dependent coverage. Effective January 1, 2008, new employees have to complete ten years of service after age 50 to be eligible for benefits, and no benefits are provided to those employees after age 65 when they are automatically eligible for Medicare benefits to cover health costs. Our OPEB plan includes a defined dollar benefit to pay the premiums for Medicare Part D. Employees who meet the eligibility requirements to retire also receive a life insurance benefit. For employees who retire after July 1, 2005, this benefit is $15,000. The life insurance amount for employees who retired prior to this date was calculated as a percentage of their basic life insurance prior to retirement.
Standard Eligibility Age for Defined Benefit Plan Pre Amendment	55 years
Standard Eligibility Age for Defined Benefit Plan Post Amendment	50 years
Age Of Exclusion For Defined Benefit Plan	65 years
Years After Qualifying Age	10 years
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations	100.00%	100.00%
Defined Benefit Plan, Fair Value of Plan Assets	27,747,000	25,961,000	23,663,000
Benefits Provided After Employee Is Eligible for Medicare Benefits	0
Term Life Insurance Per Individual Benefit Provided By Employer	15,000
Defined Benefit Plans, Estimated Future Employer Contributions in Next Fiscal Year	1,500,000
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Obligation at beginning of year	33,678,000	34,830,000
Service cost	1,109,000	1,327,000	1,387,000
Interest cost	1,448,000	1,130,000	1,347,000
Plan amendments	0	0
Actuarial (gain) loss	3,734,000	(1,094,000)
Participant contributions	805,000	641,000
Administrative expenses	0	0
Benefit payments	(2,957,000)	(3,156,000)
Obligation at end of year	37,817,000	33,678,000	34,830,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	25,961,000	23,663,000
Actual return on plan assets	1,874,000	2,848,000
Employer contributions	2,064,000	1,965,000
Participant contributions	805,000	641,000
Administrative expenses	0	0
Benefit payments	(2,957,000)	(3,156,000)
Fair value at end of year	27,747,000	25,961,000	23,663,000
Funded status at year end - (under) over	(10,070,000)	(7,717,000)
Noncurrent assets	0	0
Current liabilities	0	0
Noncurrent liabilities	(10,070,000)	(7,717,000)
Net amount recognized	(10,070,000)	(7,717,000)
Amounts Not Yet Recognized as a Component of Cost and Recognized in a Deferred Regulatory Account
Unrecognized transition obligation	0	0
Unrecognized prior service (cost) credit	0	0
Unrecognized actuarial loss	(3,995,000)	(354,000)
Regulatory asset	(3,995,000)	(354,000)
Cumulative employer contributions in excess of cost	(6,075,000)	(7,363,000)
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost	1,109,000	1,327,000	1,387,000
Interest cost	1,448,000	1,130,000	1,347,000
Expected return on plan assets	(1,782,000)	(1,663,000)	(1,551,000)
Transition obligation	0	667,000	667,000
Amortization of prior service cost (credit)	0	0	0
Amortization of net loss	0	0	0
Net periodic benefit cost	775,000	1,461,000	1,850,000
Estimated Amortization And Expected Refunds [Abstract]
Amortization of unrecognized prior service cost (credit)	0
Amortization of unrecognized actuarial loss	29,000
Other Changes In Plan Assets And Benefit Obligatin Recognized Through Regulatory Asset Or Liability [Abstract]
Prior service cost	0	0	0
Net loss (gain)	3,641,000	(2,278,000)	2,209,000
Amounts Recognized As Component Of Net Periodic Benefit Cost [Abstract]
Transition obligation	0	(667,000)	(667,000)
Amortization of net loss	0	0	0
Amortization of prior service (cost) credit	0	0	0
Total recognized in regulatory asset (liability)	3,641,000	(2,945,000)	1,542,000
Total Recognized In Net Periodic Benefit Cost And Regulatory Asset (Liability)	4,416,000	(1,484,000)	3,392,000
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Discount Rate	4.03%	4.44%
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Discount Rate	4.44%	3.34%	4.36%
Expected Long Term Rate Of Return On Plan Assets	7.75%	8.00%	8.00%
Defined Benefit Plan, Expected Future Benefit Payments, Fiscal Year Maturity [Abstract]
2015	2,409,000
2016	2,449,000
2017	2,527,000
2018	2,606,000
2019	2,682,000
2020 - 2024	14,179,000
Defined Benefit Plan, Assumed Health Care Cost Trend Rates [Abstract]
Defined Benefit Plan, Health Care Cost Trend Rate Assumed for Next Fiscal Year	7.40%	7.40%
Defined Benefit Plan, Ultimate Health Care Cost Trend Rate	5.00%	5.00%
Defined Benefit Plan, Year that Rate Reaches Ultimate Trend Rate	2027	2027
Defined Benefit Plan, Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rates [Abstract]
Effect of One Percentage Point Increase on Service and Interest Cost Components	31,000
Effect of One Percentage Point Decrease on Service and Interest Cost Components	(32,000)
Effect Of One Percentage Point Increase on Postretirement Benefit Obligation	829,000
Effect of One Percentage Point Decrease on Postretirement Benefit Obligation	(841,000)
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	25,961,000	23,663,000
Actual return on plan assets:
Fair value at end of year	27,747,000	25,961,000	23,663,000
Other Postretirement Benefit Plan [Member] | Minimum [Member]
Defined Benefit Plan Disclosure [Line Items]
Standard Eligibility Age for Defined Benefit Plan Pre Amendment	45 years
Other Postretirement Benefit Plan [Member] | Cash [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Target Plan Asset Allocations	3.00%
Defined Benefit Plan, Actual Plan Asset Allocations	9.00%	4.00%
Defined Benefit Plan, Fair Value of Plan Assets	2,590,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	982,000
Fair value at end of year	2,590,000
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	982,000
Actual return on plan assets:
Fair value at end of year	2,590,000
Other Postretirement Benefit Plan [Member] | Fixed Income Funds [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Target Plan Asset Allocations	45.00%
Defined Benefit Plan, Actual Plan Asset Allocations	44.00%	46.00%
Other Postretirement Benefit Plan [Member] | US Treasuries [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations	7.00%	10.00%
Defined Benefit Plan, Fair Value of Plan Assets	2,013,000	2,582,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	2,013,000	2,582,000
Actual return on plan assets:
Fair value at end of year	2,013,000	2,582,000
Other Postretirement Benefit Plan [Member] | Corporate Bonds Other Fixed Income Securities [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Target Plan Asset Allocations	5.00%
Defined Benefit Plan, Actual Plan Asset Allocations	37.00%	36.00%
Defined Benefit Plan, Fair Value of Plan Assets	10,187,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	9,232,000
Fair value at end of year	10,187,000
Defined Benefit Plan, Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rates [Abstract]
Investment Maturity Date	within ten years
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	9,232,000
Actual return on plan assets:
Fair value at end of year	10,187,000
Other Postretirement Benefit Plan [Member] | Equity Securities [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Target Plan Asset Allocations	47.00%
Defined Benefit Plan, Actual Plan Asset Allocations	42.00%	45.00%
Other Postretirement Benefit Plan [Member] | Large Cap Index [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations	9.00%	9.00%
Defined Benefit Plan, Fair Value of Plan Assets	2,532,000	2,384,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	2,532,000	2,384,000
Actual return on plan assets:
Fair value at end of year	2,532,000	2,384,000
Other Postretirement Benefit Plan [Member] | International Blend [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations	14.00%	16.00%
Defined Benefit Plan, Fair Value of Plan Assets	3,846,000	4,206,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	3,846,000	4,206,000
Actual return on plan assets:
Fair value at end of year	3,846,000	4,206,000
Other Postretirement Benefit Plan [Member] | Large Cap Value [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations	4.00%	5.00%
Defined Benefit Plan, Fair Value of Plan Assets	1,269,000	1,327,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	1,269,000	1,327,000
Actual return on plan assets:
Fair value at end of year	1,269,000	1,327,000
Other Postretirement Benefit Plan [Member] | Large Cap Growth [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations	5.00%	5.00%
Defined Benefit Plan, Fair Value of Plan Assets	1,310,000	1,352,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	1,310,000	1,352,000
Actual return on plan assets:
Fair value at end of year	1,310,000	1,352,000
Other Postretirement Benefit Plan [Member] | Small Cap Value [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations	5.00%	5.00%
Defined Benefit Plan, Fair Value of Plan Assets	1,336,000	1,331,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	1,336,000	1,331,000
Actual return on plan assets:
Fair value at end of year	1,336,000	1,331,000
Other Postretirement Benefit Plan [Member] | Small Cap Growth [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations	5.00%	5.00%
Defined Benefit Plan, Fair Value of Plan Assets	1,319,000	1,313,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	1,319,000	1,313,000
Actual return on plan assets:
Fair value at end of year	1,319,000	1,313,000
Other Postretirement Benefit Plan [Member] | Global REIT [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Target Plan Asset Allocations	5.00%
Defined Benefit Plan, Actual Plan Asset Allocations	5.00%	5.00%
Defined Benefit Plan, Fair Value of Plan Assets	1,345,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	1,252,000
Fair value at end of year	1,345,000
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	1,252,000
Actual return on plan assets:
Fair value at end of year	1,345,000
Other Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations	100.00%	100.00%
Defined Benefit Plan, Fair Value of Plan Assets	27,747,000	25,961,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	27,747,000	25,961,000
Actual return on plan assets:
Fair value at end of year	27,747,000	25,961,000
Other Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 1 [Member] | Cash [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	2,590,000	982,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	2,590,000	982,000
Actual return on plan assets:
Fair value at end of year	2,590,000	982,000
Other Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 1 [Member] | US Treasuries [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	2,013,000	2,582,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	2,013,000	2,582,000
Actual return on plan assets:
Fair value at end of year	2,013,000	2,582,000
Other Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 1 [Member] | Corporate Bonds Other Fixed Income Securities [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	10,187,000	9,232,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	10,187,000	9,232,000
Actual return on plan assets:
Fair value at end of year	10,187,000	9,232,000
Other Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 1 [Member] | Large Cap Index [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	2,532,000	2,384,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	2,532,000	2,384,000
Actual return on plan assets:
Fair value at end of year	2,532,000	2,384,000
Other Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 1 [Member] | International Blend [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	3,846,000	4,206,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	3,846,000	4,206,000
Actual return on plan assets:
Fair value at end of year	3,846,000	4,206,000
Other Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 1 [Member] | Large Cap Value [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	1,269,000	1,327,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	1,269,000	1,327,000
Actual return on plan assets:
Fair value at end of year	1,269,000	1,327,000
Other Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 1 [Member] | Large Cap Growth [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	1,310,000	1,352,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	1,310,000	1,352,000
Actual return on plan assets:
Fair value at end of year	1,310,000	1,352,000
Other Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 1 [Member] | Small Cap Value [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	1,336,000	1,331,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	1,336,000	1,331,000
Actual return on plan assets:
Fair value at end of year	1,336,000	1,331,000
Other Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 1 [Member] | Small Cap Growth [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	1,319,000	1,313,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	1,319,000	1,313,000
Actual return on plan assets:
Fair value at end of year	1,319,000	1,313,000
Other Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 1 [Member] | Global REIT [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	1,345,000	1,252,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	1,345,000	1,252,000
Actual return on plan assets:
Fair value at end of year	1,345,000	1,252,000
Other Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations	0.00%	0.00%
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Other Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 2 [Member] | Cash [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Other Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 2 [Member] | US Treasuries [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Other Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 2 [Member] | Corporate Bonds Other Fixed Income Securities [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Other Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 2 [Member] | Large Cap Index [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Other Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 2 [Member] | International Blend [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Other Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 2 [Member] | Large Cap Value [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Other Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 2 [Member] | Large Cap Growth [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Other Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 2 [Member] | Small Cap Value [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Other Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 2 [Member] | Small Cap Growth [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Other Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 2 [Member] | Global REIT [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Other Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations	0.00%	0.00%
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Other Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 3 [Member] | Cash [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Other Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 3 [Member] | US Treasuries [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Other Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 3 [Member] | Corporate Bonds Other Fixed Income Securities [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Other Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 3 [Member] | Large Cap Index [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Other Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 3 [Member] | International Blend [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Other Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 3 [Member] | Large Cap Value [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Other Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 3 [Member] | Large Cap Growth [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Other Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 3 [Member] | Small Cap Value [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Other Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 3 [Member] | Small Cap Growth [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
Other Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 3 [Member] | Global REIT [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at end of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0
NCNG SERP [Member]
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Discount Rate	3.64%
Directors SERP [Member]
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Discount Rate	3.74%
Piedmont SERP [Member]
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Discount Rate	3.10%
Non Qualified Pension [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0	0
Defined Benefit Plans, Estimated Future Employer Contributions in Next Fiscal Year	521,000
Reconciliation Of Changes In Plan Benefit Obligations And Fair Value Of Assets [Abstract]
Accumulated Benefit Obligation At Year End	5,925,000	4,736,000
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Obligation at beginning of year	4,736,000	5,569,000
Service cost	0	0	39,000
Interest cost	200,000	157,000	203,000
Plan amendments	485,000	0
Actuarial (gain) loss	956,000	(540,000)
Participant contributions	0	0
Administrative expenses	0	0
Benefit payments	(452,000)	(450,000)
Obligation at end of year	5,925,000	4,736,000	5,569,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	0	0
Actual return on plan assets	0	0
Employer contributions	452,000	450,000
Participant contributions	0	0
Administrative expenses	0	0
Benefit payments	(452,000)	(450,000)
Fair value at end of year	0	0	0
Funded status at year end - (under) over	(5,925,000)	(4,736,000)
Noncurrent assets	0	0
Current liabilities	(521,000)	(445,000)
Noncurrent liabilities	(5,404,000)	(4,291,000)
Net amount recognized	(5,925,000)	(4,736,000)
Amounts Not Yet Recognized as a Component of Cost and Recognized in a Deferred Regulatory Account
Unrecognized transition obligation	0	0
Unrecognized prior service (cost) credit	(439,000)	(196,000)
Unrecognized actuarial loss	(1,745,000)	(820,000)
Regulatory asset	(2,184,000)	(1,016,000)
Cumulative employer contributions in excess of cost	(3,741,000)	(3,720,000)
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost	0	0	39,000
Interest cost	200,000	157,000	203,000
Expected return on plan assets	0	0	0
Transition obligation	0	0	0
Amortization of prior service cost (credit)	243,000	81,000	81,000
Amortization of net loss	31,000	161,000	49,000
Net periodic benefit cost	474,000	399,000	372,000
Estimated Amortization And Expected Refunds [Abstract]
Amortization of unrecognized prior service cost (credit)	231,000
Amortization of unrecognized actuarial loss	85,000
Other Changes In Plan Assets And Benefit Obligatin Recognized Through Regulatory Asset Or Liability [Abstract]
Prior service cost	485,000	0	0
Net loss (gain)	956,000	(540,000)	629,000
Amounts Recognized As Component Of Net Periodic Benefit Cost [Abstract]
Transition obligation	0	0	0
Amortization of net loss	(31,000)	(161,000)	(49,000)
Amortization of prior service (cost) credit	(243,000)	(81,000)	(81,000)
Total recognized in regulatory asset (liability)	1,167,000	(782,000)	499,000
Total Recognized In Net Periodic Benefit Cost And Regulatory Asset (Liability)	1,641,000	(383,000)	871,000
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Discount Rate	3.69%	3.98%
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Discount Rate	3.98%	2.95%	4.10%
Defined Benefit Plan, Expected Future Benefit Payments, Fiscal Year Maturity [Abstract]
2015	521,000
2016	507,000
2017	491,000
2018	472,000
2019	490,000
2020 - 2024	2,149,000
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	0	0
Actual return on plan assets:
Fair value at end of year	0	0	0
Other Postretirement Benefit Plan [Member]
Defined Contribution Plan Disclosure [Line Items]
Current Liability	214,000	199,000
Noncurrent Liability	4,248,000	3,328,000
Money Purchase Pension Plan [Member]
Defined Contribution Plan Disclosure [Line Items]
Description of Defined Contribution Pension and Other Postretirement Plans	Employees hired or rehired after December 31, 2007 cannot participate in the qualified pension plan but are participants in the Money Purchase Pension (MPP) plan, a defined contribution pension plan that allows the employee to direct the investments and assume the risk of investment returns. A defined contribution plan specifies the amount of the employer’s annual contribution to individual participant accounts established for the retirement benefit. Eligible employees who have completed 30 days of continuous service and have attained age 18 are eligible to participate. Under the MPP plan, we annually deposit a percentage of each participant’s pay into an account of the MPP plan. This contribution equals 4% of the participant’s compensation plus an additional 4% of compensation above the social security wage base up to the Internal Revenue Service (IRS) compensation limit. The participant is vested in this plan after three years of service.
Defined Contribution Plans Estimated Future Employer Contributions In Next Fiscal Year	1,300,000
Money Purchase Pension Plan [Member] | Pension Plan [Member]
Defined Contribution Plan Disclosure [Line Items]
Service Required For Eligibility In Defined Contribution Plan	30 days
Standard Eligibility Age For Defined Contribution Plan	18 years
Defined Contribution Plan, Employer Matching Contribution, Percent of Employees' Gross Pay	4.00%
Employer Contribution Percentage Above IRS Limit	4.00%
Employer Contribution to Plan	900,000
Plan Vesting Period Defined Contribution Plan	3 years
Voluntary Deferral Plan [Member] | Other Postretirement Benefit Plan [Member]
Defined Contribution Plan Disclosure [Line Items]
Employer Contribution to Plan	0
Deferral Limit As Percentage Of Base Salary	50.00%
Plan Deferral Limit As Percentage Of Annual Incentive Pay	95.00%
Distribution Deferral Time Period Minimum In Years	2 years
Defined Contribution Restoration Plan [Member]
Defined Contribution Plan Disclosure [Line Items]
Description of Defined Contribution Pension and Other Postretirement Plans	We have a non-qualified defined contribution restoration plan (DCR plan) for all officers at the vice president level and above where benefits payable under the plan are informally funded annually through a rabbi trust with a bank as the trustee. We contribute 13% of the total cash compensation (base salary, short-term incentive and MVP incentive) that exceeds the IRS compensation limit to the DCR plan account of each covered executive. Participants may not contribute to the DCR plan. Vesting under the DCR plan is five-year cliff vesting, including service prior to adoption of the plan on January 1, 2009, of annual company contributions, and prospective five-year cliff vesting for the one-time opening balances of four Vice Presidents to compensate them for the loss of future benefits under this DCR plan as compared with a terminated SERP. Participants in the DCR plan may provide instructions to us for the deemed investment of their plan accounts. Distribution will occur upon separation of service or death of the participant.
Defined Contribution Restoration Plan [Member] | Other Postretirement Benefit Plan [Member]
Defined Contribution Plan Disclosure [Line Items]
Employer Contribution Percentage Above IRS Limit	13.00%
Employer Contribution to Plan	524,000	434,000
Plan Vesting Period Defined Contribution Plan	5 years
Vice Presidents Eligible For One Time Contribution New DCR Plan	4
Plan 401 K [Member]
Defined Contribution Plan Disclosure [Line Items]
Description of Defined Contribution Pension and Other Postretirement Plans	We maintain a 401(k) plan that is a profit-sharing plan under Section 401(a) of the Internal Revenue Code of 1986, as amended (the Tax Code), which includes qualified cash or deferred arrangements under Tax Code Section 401(k). The 401(k) plan is subject to the provisions of the Employee Retirement Income Security Act. Eligible employees who have completed 30 days of continuous service and have attained age 18 are eligible to participate. Participants may defer a portion of their base salary and cash incentive payments to the plan, and we match a portion of their contributions. Employee contributions vest immediately, and company contributions vest after six months of service. Employees receive a company match of 100% up to the first 5% of eligible pay contributed. Employees may contribute up to 50% of eligible pay to the 401(k) on a pre-tax basis, up to the Tax Code annual contribution and compensation limits. We automatically enroll all eligible non-participating employees in the 401(k) plan at a 2% contribution rate unless the employee chooses not to participate by notifying our record keeper. For employees who are automatically enrolled in the 401(k) plan, we automatically increase their contributions by 1% each year to a maximum of 5% unless the employee chooses to opt out of the automatic increase by contacting our record keeper. If the employee does not make an investment election, employee contributions and matches are automatically invested in a diversified portfolio of stocks and bonds. Participants may direct up to 20% of their contributions and company matching contributions as an investment in the Piedmont Stock Fund. Employees may change their contribution rate and investments at any time.
Plan 401 K [Member] | Other Postretirement Benefit Plan [Member]
Defined Contribution Plan Disclosure [Line Items]
Service Required For Eligibility In Defined Contribution Plan	30 days
Standard Eligibility Age For Defined Contribution Plan	18 years
Defined Contribution Plan, Employer Matching Contribution, Percent of Employees' Gross Pay	5.00%
Employer Contribution to Plan	$ 6,134,000	$ 5,688,000	$ 5,400,000
Plan Vesting Period Defined Contribution Plan	6 months
Employer Match Percentage	100.00%
Defined Contribution Plan, Maximum Annual Contributions Per Employee, Percent	50.00%
Employee Contribution Rate At Enrollment	2.00%
Contribution Annual Automatic Deferral Increase	1.00%
Employee Contribution Automatic Increase Rate Cap	5.00%
Investment In Company Stock Cap	20.00%

XML

Regulatory Matters (Details) (USD $)	12 Months Ended				1 Months Ended	12 Months Ended		24 Months Ended	1 Months Ended					2 Months Ended
	Oct. 31, 2014	Oct. 31, 2013	Oct. 31, 2012	Dec. 31, 1998	Apr. 30, 2014	Dec. 31, 2001	Dec. 31, 2000	Dec. 31, 2001	Nov. 30, 2014	Dec. 31, 2014	May 31, 2012	Oct. 31, 2011	Sep. 30, 2014	Dec. 31, 2014	Jan. 01, 2014	Oct. 31, 2008	Dec. 31, 2013	Aug. 31, 2013	Mar. 01, 2012	Feb. 29, 2012
Public Utilities, Rate Matters, Requested [Abstract]
Public Utilities, Description of Regulatory Scope	Our utility operations are regulated by the NCUC, PSCSC and TRA as to rates, service area, adequacy of service, safety standards, extensions and abandonment of facilities, accounting and depreciation. We are also regulated by the NCUC as to the issuance of long-term debt and equity securities. The NCUC and the PSCSC regulate our gas purchasing practices under a standard of prudence and audit our gas cost accounting practices. The TRA regulates our gas purchasing practices under a gas supply incentive program which compares our actual costs to market pricing benchmarks. As part of this jurisdictional oversight, all three regulatory commissions address our gas supply hedging activities. Additionally, all three regulatory commissions allow for recovery of uncollectible gas costs through the PGA. The portion of uncollectibles related to gas costs is recovered through the deferred account and only the non-gas costs, or margin, portion of uncollectibles is included in base rates and uncollectibles expense.
Regulatory Assets	$ 213,867,000	$ 246,306,000
Regulatory Assets, Current	29,088,000	77,204,000
Payments to Acquire Property, Plant, and Equipment	460,444,000	599,999,000	529,576,000
Operations and maintenance	270,877,000	253,120,000	242,599,000
Total Amount Of Margin Generated From Secondary Market Activity	97,600,000	35,900,000	38,700,000
Amount Of Net Secondary Market Margins Flowed Through To Jurisdictional Customers	72,200,000	26,900,000	29,000,000
Amount Of Net Secondary Market Margins Retained	25,400,000	9,000,000	9,700,000
North Carolina
Public Utilities, Rate Matters, Requested [Abstract]
North Carolina Bond Issuance Amount				200,000,000
Capital Investments In Integrity and Safety Projects	241,900,000
Tennessee
Public Utilities, Rate Matters, Requested [Abstract]
Capital Investments In Integrity and Safety Projects	54,000,000
Deferred operations and maintenance expenses
Public Utilities, Rate Matters, Requested [Abstract]
Regulatory Assets, Current	916,000	739,000
Deferred pipeline integrity expenses
Public Utilities, Rate Matters, Requested [Abstract]
Regulatory Assets, Current	3,470,000	3,149,000
Environmental costs
Public Utilities, Rate Matters, Requested [Abstract]
Regulatory Assets	8,000,000
Regulatory Assets, Current	1,568,000	1,480,000
Robeson LNG Development Cost [Member]
Public Utilities, Rate Matters, Requested [Abstract]
Regulatory Assets, Current	917,000	382,000
Other Regulatory Assets (Liabilities) [Member]
Public Utilities, Rate Matters, Requested [Abstract]
Regulatory Assets, Current	1,850,000	1,091,000
NCUC [Member]
Public Utilities, Rate Matters, Approved [Abstract]
Public Utilities, Approved Debt Equity Securities Limit, Amount	1,000,000,000				1,000,000,000
Public Utilities, Rate Matters, Requested [Abstract]
Request Transfer Plant Held For Future Use To Deferred Regulatory Asset			6,700,000
Percentage Of Net Secondary Market Margins Flowed Through To Customers	75.00%
Percentage Of Net Secondary Market Margins Retained	25.00%
NCUC [Member] | Minimum [Member]
Public Utilities, Rate Matters, Requested [Abstract]
Target Percentage Range Normalized Sales	22.50%
NCUC [Member] | Maximum [Member]
Public Utilities, Rate Matters, Requested [Abstract]
Target Percentage Range Normalized Sales	45.00%
NCUC [Member] | EasternNC Exclusive Franchise Rights [Member]
Public Utilities, Rate Matters, Requested [Abstract]
North Carolina Bond Issuance Amount						149,600,000	38,700,000	188,300,000
Operational Feasibility Assessment Time Period	2 years
NCUC [Member] | General Rate Case Proceeding 2013 [Member]
Public Utilities, Rate Matters, Approved [Abstract]
Overall Rate Base With Approved Rates And Charges															1,800,000,000
Public Utilities, Approved Return on Equity, Percentage	10.00%
Public Utilities, Approved Return on Investment, Percentage	7.51%
Public Utilities, Approved Equity Capital Structure, Percentage	50.70%
Approved Annual Average Revenue Percentage Increase From Last Rate Case	0.70%
NCUC [Member] | General Rate Case Proceeding 2013 [Member] | Sales [Member]
Public Utilities, Rate Matters, Approved [Abstract]
Public Utilities, Approved Rate Increase (Decrease), Amount	30,700,000
Public Utilities, Approved Rate Increase (Decrease), Percentage	3.58%
NCUC [Member] | General Rate Case Proceeding 2013 [Member] | Sales [Member] | Gas Utility Margin [Member]
Public Utilities, Rate Matters, Approved [Abstract]
Public Utilities, Approved Rate Increase (Decrease), Amount	16,800,000
NCUC [Member] | General Rate Case Proceeding 2013 [Member] | Sales [Member] | Fixed Gas Costs [Member]
Public Utilities, Rate Matters, Approved [Abstract]
Public Utilities, Approved Rate Increase (Decrease), Amount	13,800,000
NCUC [Member] | General Rate Case Proceeding 2013 [Member] | Revised Pre-Tax Income [Member]
Public Utilities, Rate Matters, Approved [Abstract]
Public Utilities, Approved Rate Increase (Decrease), Amount	24,200,000
NCUC [Member] | General Rate Case Proceeding 2013 [Member] | Operating Expense [Member]
Public Utilities, Rate Matters, Approved [Abstract]
Public Utilities, Approved Rate Increase (Decrease), Amount	(10,900,000)
NCUC [Member] | North Carolina Public Staff Audit 2011 Gas Cost Review Period [Member]
Public Utilities, Rate Matters, Approved [Abstract]
Percentage Of Allowed Recovery For Gas Costs	100.00%
NCUC [Member] | North Carolina Public Staff Audit 2012 Gas Cost Review Period [Member]
Public Utilities, Rate Matters, Approved [Abstract]
Percentage Of Allowed Recovery For Gas Costs	100.00%
NCUC [Member] | North Carolina Public Staff Audit 2013 Gas Cost Review Period [Member]
Public Utilities, Rate Matters, Approved [Abstract]
Percentage Of Allowed Recovery For Gas Costs	100.00%
NCUC [Member] | North Carolina Public Staff Audit 2013 Gas Cost Review Period [Member] | Subsequent Event [Member]
Public Utilities, Rate Matters, Requested [Abstract]
Public Utilities, Disclosure of Rate Matters									In November 2014, the NCUC approved our accounting of gas costs for the twelve months ended May 31, 2014. We were deemed prudent on our gas purchasing policies and practices during this review period and allowed 100% recovery.
NCUC [Member] | North Carolina Public Staff Audit 2014 Gas Cost Review Period [Member] | Subsequent Event [Member]
Public Utilities, Rate Matters, Approved [Abstract]
Percentage Of Allowed Recovery For Gas Costs									100.00%
NCUC [Member] | North Carolina IMR Adjustment 2014 [Member]
Public Utilities, Rate Matters, Approved [Abstract]
Public Utilities, Approved Rate Increase (Decrease), Amount	800,000
NCUC [Member] | NCUC Petition for IMR Rate Adjustment Filed December 2014 [Member] | Subsequent Event [Member]
Public Utilities, Rate Matters, Requested [Abstract]
Public Utilities, Requested Rate Increase (Decrease), Amount										26,600,000
Public Utilities, Disclosure of Rate Matters										In December 2014, we filed a petition with the NCUC seeking authority to adjust rates to collect an additional $26.6 million in annual IMR margin revenues effective February 1, 2015 based on $241.9 million of capital investments in integrity and safety projects over the twelve-month period ending October 31, 2014. We are waiting on a ruling from the NCUC at this time.
NCUC [Member] | NCUC Petition for Limited Waiver 2014 [Member]
Public Utilities, Rate Matters, Requested [Abstract]
Operations and maintenance	65,000
NCUC [Member] | Deferred operations and maintenance expenses
Public Utilities, Rate Matters, Approved [Abstract]
Deferral Time Period Of Operation And Maintenance Expense	8 years
Public Utilities, Rate Matters, Requested [Abstract]
Regulatory Assets	5,600,000	6,400,000
NCUC [Member] | Deferred operations and maintenance expenses | General Rate Case Proceeding 2008 [Member]
Public Utilities, Rate Matters, Approved [Abstract]
Interest Accrued On Deferred Expenses	7.84%
Amortization Time Period For Specified Expenses	12 years
Public Utilities, Rate Matters, Requested [Abstract]
Regulatory Assets																9,000,000
NCUC [Member] | Deferred operations and maintenance expenses | General Rate Case Proceeding 2013 [Member]
Public Utilities, Rate Matters, Approved [Abstract]
Interest Accrued On Deferred Expenses	6.55%
Amortization Time Period For Specified Expenses	82 months
Regulatory Noncurrent Asset, End Date for Recovery	Oct. 31, 2020
Public Utilities, Rate Matters, Requested [Abstract]
Regulatory Assets																	6,300,000
NCUC [Member] | Deferred pipeline integrity expenses
Public Utilities, Rate Matters, Requested [Abstract]
Regulatory Assets	28,200,000	19,400,000
NCUC [Member] | Deferred pipeline integrity expenses | General Rate Case Proceeding 2013 [Member]
Public Utilities, Rate Matters, Approved [Abstract]
Amortization Time Period For Specified Expenses	5 years
Regulatory Noncurrent Asset, End Date for Recovery	Dec. 31, 2018
Public Utilities, Rate Matters, Requested [Abstract]
Regulatory Assets																		17,300,000
NCUC [Member] | Environmental costs | General Rate Case Proceeding 2013 [Member]
Public Utilities, Rate Matters, Approved [Abstract]
Amortization Time Period For Specified Expenses	5 years
Regulatory Noncurrent Asset, End Date for Recovery	Dec. 31, 2018
Public Utilities, Rate Matters, Requested [Abstract]
Regulatory Assets																	6,300,000
NCUC [Member] | Robeson LNG Development Cost [Member] | General Rate Case Proceeding 2013 [Member]
Public Utilities, Rate Matters, Requested [Abstract]
Regulatory Assets																	1,200,000
NCUC [Member] | Robeson LNG Development Cost [Member] | General Rate Application Settlement 2013 [Member]
Public Utilities, Rate Matters, Approved [Abstract]
Amortization Time Period For Specified Expenses	38 months
Regulatory Noncurrent Asset, End Date for Recovery	Feb. 28, 2017
Public Utilities, Rate Matters, Requested [Abstract]
Regulatory Assets																	1,200,000
PSCSC [Member]
Public Utilities, Rate Matters, Requested [Abstract]
Percentage Of Net Secondary Market Margins Flowed Through To Customers	75.00%
Percentage Of Net Secondary Market Margins Retained	25.00%
Maximum Utility Rate of Return Change Allowed Under RSA	50
PSCSC [Member] | Minimum [Member]
Public Utilities, Rate Matters, Requested [Abstract]
Target Percentage Range Normalized Sales	22.50%
PSCSC [Member] | Maximum [Member]
Public Utilities, Rate Matters, Requested [Abstract]
Target Percentage Range Normalized Sales	45.00%
PSCSC [Member] | Settlement With Office Of Regulatory Staff October 2012 [Member]
Public Utilities, Rate Matters, Approved [Abstract]
Public Utilities, Approved Return on Equity, Percentage	11.30%
PSCSC [Member] | Settlement With Office Of Regulatory Staff October 2012 [Member] | Margin [Member]
Public Utilities, Rate Matters, Approved [Abstract]
Public Utilities, Approved Rate Increase (Decrease), Amount	(1,100,000)
PSCSC [Member] | Settlement With Office Of Regulatory Staff October 2013 [Member]
Public Utilities, Rate Matters, Approved [Abstract]
Public Utilities, Approved Return on Equity, Percentage	11.30%
PSCSC [Member] | Settlement With Office Of Regulatory Staff October 2013 [Member] | Margin [Member]
Public Utilities, Rate Matters, Approved [Abstract]
Public Utilities, Approved Rate Increase (Decrease), Amount	(100,000)
PSCSC [Member] | Settlement With Office of Regulatory Staff October 2014 [Member]
Public Utilities, Rate Matters, Approved [Abstract]
Public Utilities, Approved Return on Equity, Percentage	10.20%
PSCSC [Member] | Settlement With Office of Regulatory Staff October 2014 [Member] | Margin [Member]
Public Utilities, Rate Matters, Approved [Abstract]
Public Utilities, Approved Rate Increase (Decrease), Amount	(2,900,000)
PSCSC [Member] | Environmental costs | Settlement With Office Of Regulatory Staff October 2013 [Member]
Public Utilities, Rate Matters, Approved [Abstract]
Amortization Time Period For Specified Expenses	1 year
Regulatory Noncurrent Asset, End Date for Recovery	Oct. 31, 2014
Public Utilities, Rate Matters, Requested [Abstract]
Regulatory Assets, Current		200,000
PSCSC [Member] | Environmental costs | Settlement With Office of Regulatory Staff October 2014 [Member]
Public Utilities, Rate Matters, Approved [Abstract]
Amortization Time Period For Specified Expenses	1 year
Regulatory Noncurrent Asset, End Date for Recovery	Oct. 31, 2015
Public Utilities, Rate Matters, Requested [Abstract]
Regulatory Assets	100,000
Regulatory Assets, Current	100,000
PSCSC [Member] | Robeson LNG Development Cost [Member] | Settlement With Office of Regulatory Staff October 2014 [Member]
Public Utilities, Rate Matters, Approved [Abstract]
Amortization Time Period For Specified Expenses	12 months
Regulatory Noncurrent Asset, End Date for Recovery	Oct. 31, 2015
Public Utilities, Rate Matters, Requested [Abstract]
Regulatory Assets, Current	500,000
Tennessee Regulatory Authority [Member]
Public Utilities, Rate Matters, Requested [Abstract]
Percentage Of Net Secondary Market Margins Flowed Through To Customers	75.00%
Percentage Of Net Secondary Market Margins Retained	25.00%
Annual Incentive Cap On Gains And Losses	1,600,000.0
Tennessee Regulatory Authority [Member] | Collection Nashville Franchise Fee [Member]
Public Utilities, Rate Matters, Approved [Abstract]
Denied Franchise Fees												1,500,000
Public Utilities, Rate Matters, Requested [Abstract]
Public Utilities, Requested Rate Increase (Decrease), Amount	2,900,000
Operations and maintenance											(500,000)	1,500,000
Tennessee Regulatory Authority [Member] | Actual Cost Adjustment [Member] | Subsequent Event [Member]
Public Utilities, Rate Matters, Requested [Abstract]
Public Utilities, Disclosure of Rate Matters										In December 2014, we filed an annual report for the twelve months ended June 30, 2013 with the TRA that reflected the transactions in the deferred gas cost account for the ACA mechanism. We are waiting on a ruling from the TRA at this time.
Tennessee Regulatory Authority [Member] | Adjustment Filed August 2013 [Member]
Public Utilities, Rate Matters, Requested [Abstract]
Public Utilities, Requested Rate Increase (Decrease), Amount	3,700,000
Expense Related to Actual Cost Adjustment													1,700,000
Tennessee Regulatory Authority [Member] | TRA Settlement December 2014 [Member] | Subsequent Event [Member]
Public Utilities, Rate Matters, Approved [Abstract]
Public Utilities, Approved Rate Increase (Decrease), Amount														2,000,000
Public Utilities, Rate Matters, Requested [Abstract]
Public Utilities, Disclosure of Rate Matters														In November 2014, we filed a joint settlement agreement with the TRA and the Tennessee Attorney General's Consumer Advocate and Protection Division (CAD) in which the parties agreed that we may include in our next ACA filing prior period adjustments totaling $2 million in lieu of the $3.7 million as originally petitioned. In December 2014, the TRA approved the settlement agreement, and we included the stipulated $2 million of prior period adjustments in the filed ACA annual report for the twelve-month period ended June 30, 2013.
Tennessee Regulatory Authority [Member] | General Rate Application Settlement 2012 [Member]
Public Utilities, Rate Matters, Approved [Abstract]
Public Utilities, Approved Return on Equity, Percentage	10.20%
Public Utilities, Rate Matters, Requested [Abstract]
Recovery Of Fixed Charges Cost Allocations																			37.00%	29.00%
Recovery Of Volumetric Charges Cost Allocations																			63.00%	71.00%
Tennessee Regulatory Authority [Member] | General Rate Application Settlement 2012 [Member] | Sales [Member]
Public Utilities, Rate Matters, Approved [Abstract]
Public Utilities, Approved Rate Increase (Decrease), Amount	11,900,000
Public Utilities, Approved Rate Increase (Decrease), Percentage	6.30%
Tennessee Regulatory Authority [Member] | Tennessee IMR Petition August 2013 [Member]
Public Utilities, Rate Matters, Requested [Abstract]
Public Utilities, Requested Rate Increase (Decrease), Amount	13,100,000
Tennessee Regulatory Authority [Member] | Tennessee IMR Settlement 2013 [Member]
Public Utilities, Rate Matters, Approved [Abstract]
Public Utilities, Approved Rate Increase (Decrease), Amount	13,100,000
Tennessee Regulatory Authority [Member] | TRA IMR Rate Adjustment Petition Filed December 2014 [Member] | Subsequent Event [Member]
Public Utilities, Rate Matters, Requested [Abstract]
Public Utilities, Requested Rate Increase (Decrease), Amount										6,500,000
Public Utilities, Disclosure of Rate Matters										In December 2014, we filed a petition with the TRA seeking authority to collect an additional $6.5 million in annual IMR margin revenues effective January 2015 based on $54 million of capital investments in integrity and safety projects over the twelve-month period ending October 31, 2014. We are waiting on a ruling from the TRA at this time.
Tennessee Regulatory Authority [Member] | TRA Petition to Amortize and Refund Customers for Excess Deferred Taxes [Member]
Public Utilities, Rate Matters, Requested [Abstract]
Public Utilities, Requested Rate Increase (Decrease), Amount	(4,700,000)
Tennessee Regulatory Authority [Member] | Tennessee CNG Rider Petition September 2014 [Member] | Subsequent Event [Member]
Public Utilities, Rate Matters, Requested [Abstract]
Public Utilities, Disclosure of Rate Matters									In September 2014, we filed a petition with the TRA seeking authority to implement a compressed natural gas infrastructure rider to recover the costs of our capital investments in infrastructure and equipment associated with this alternative motor vehicle transportation fuel. We proposed that the tariff rider be effective October 1, 2014 with an initial rate adjustment on November 1, 2014 based on capital expenditures incurred through June 2014 and for rates to be updated annually outside of general rate cases for the return of and on these capital investments. In November 2014, the TRA consolidated this docket with a separate petition we filed seeking modifications to our tariff regarding service to customers using natural gas as a motor fuel. The TRA suspended the proposed tariffs through February 9, 2015. A hearing on this matter has been scheduled for January 12, 2015.
Tennessee Regulatory Authority [Member] | Environmental costs | General Rate Application Settlement 2012 [Member]
Public Utilities, Rate Matters, Approved [Abstract]
Amortization Time Period For Specified Expenses	8 years
Public Utilities, Rate Matters, Requested [Abstract]
Regulatory Assets																			2,000,000
Tennessee Regulatory Authority [Member] | Other Regulatory Assets (Liabilities) [Member] | General Rate Application Settlement 2012 [Member]
Public Utilities, Rate Matters, Approved [Abstract]
Amortization Time Period For Specified Expenses	8 years
Regulatory Noncurrent Asset, End Date for Recovery	Feb. 28, 2020
Public Utilities, Rate Matters, Requested [Abstract]
Regulatory Assets																			1,000,000

XML

Consolidated Statements of Comprehensive Income (Parentheticals) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Oct. 31, 2014	Oct. 31, 2013	Oct. 31, 2012
Statement of Comprehensive Income [Abstract]
Unrealized gain (loss) from hedging activities of equity method investments arising during period tax	$ 225	$ (69)	$ (530)
Reclassification adjustment of realized gain (loss) from hedging activities of equity investments included in net income, tax	(177)	85	621
Net current period benefit activities of equity method investments, tax	$ (16)

XML

Regulatory Matters

12 Months Ended

Oct. 31, 2014

Public Utilities, Rate Matters [Abstract]

Public Utilities Disclosure [Text Block]

Regulatory Matters

Our utility operations are regulated by the NCUC, PSCSC and TRA as to rates, service area, adequacy of service, safety standards, extensions and abandonment of facilities, accounting and depreciation. We are also regulated by the NCUC as to the issuance of long-term debt and equity securities.

The NCUC and the PSCSC regulate our gas purchasing practices under a standard of prudence and audit our gas cost accounting practices. The TRA regulates our gas purchasing practices under a gas supply incentive program which compares our actual costs to market pricing benchmarks. As part of this jurisdictional oversight, all three regulatory commissions address our gas supply hedging activities. Additionally, all three regulatory commissions allow for recovery of uncollectible gas costs through the PGA. The portion of uncollectibles related to gas costs is recovered through the deferred account and only the non-gas costs, or margin, portion of uncollectibles is included in base rates and uncollectibles expense.

North Carolina

The North Carolina General Assembly enacted the Clean Water and Natural Gas Critical Needs Act of 1998 which provided for the issuance of $200 million of general obligation bonds of the state for the purpose of providing grants, loans or other financing for the cost of constructing natural gas facilities in unserved areas of North Carolina. In 2000, the NCUC issued an order awarding Eastern North Carolina Natural Gas Company (EasternNC) an exclusive franchise to provide natural gas service to 14 counties in the eastern-most part of North Carolina that had not been able to obtain gas service because of the relatively small population of those counties and the resulting economic infeasibility of providing service and granted $38.7 million in state bond funding. In 2001, the NCUC issued an order granting EasternNC an additional $149.6 million, for a total of $188.3 million. With the 2003 acquisition and subsequent merger of EasternNC into our regulated utility segment, we are required to provide an accounting of the operational feasibility of this area to the NCUC every two years. Should this operational area become economically feasible and generate a profit, which we believe is unlikely, we would begin to repay the state bond funding.

The NCUC had allowed EasternNC to defer its O&M expenses during the first eight years of operation or until the first rate case order, whichever occurred first, with the deferred amounts accruing interest per annum. In December 2003, the NCUC confirmed that these deferred expenses should be treated as a regulatory asset for future recovery from customers to the extent they are deemed prudent and proper. Under the settlement of the 2008 general rate proceeding, the unamortized balance of the EasternNC deferred O&M expenses of $9 million at October 31, 2008 was to be amortized over a twelve year period beginning November 1, 2008, with interest accruing at 7.84% per annum. Under the settlement of the 2013 general rate proceeding discussed below, the unamortized balance of the EasternNC deferred O&M expenses was $6.3 million as of December 31, 2013. This balance is accruing interest at a rate of 6.55% per annum with amortization beginning January 1, 2014over an 82-month period ending October 31, 2020. As of October 31, 2014 and 2013, we had unamortized balances, including accrued interest, of $5.6 million and $6.4 million, respectively.

We incur certain pipeline integrity management costs in compliance with the Pipeline Safety Improvement Act of 1992 and certain regulations of the United States Department of Transportation. The NCUC approved deferral treatment of the O&M costs applicable to certain incremental pipeline integrity external expenditures beginning November 1, 2004. The approved balance for recovery of actual pipeline integrity management O&M costs incurred between July 1, 2008 through August 31, 2013 as established in the settlement of the 2013 general rate proceeding discussed below was $17.3 million to be amortized over a five-year period from January 1, 2014 through December 31, 2018. As of October 31, 2014 and 2013, we had unamortized regulatory asset balances for deferred pipeline integrity expenses of $28.2 million and $19.4 million, respectively. The existing regulatory asset treatment for ongoing pipeline integrity management costs will continue until another recovery mechanism is established in a future rate proceeding.

With the approval of the settlement of the 2013 NCUC general rate proceeding discussed below, future capital expenditures that are incurred to comply with federal pipeline safety and integrity requirements will be separately tracked and recovered on an annual basis through an IMR. The settlement also approved recovery of $6.3 million of deferred North Carolina environmental costs over a five-year period from January 2014 through December 2018.

In North Carolina, our recovery of gas costs is subject to annual gas cost proceedings to determine the prudence of our gas purchases. Our gas costs have never been disallowed on the basis of prudence.

In January 2012, the NCUC approved our accounting of gas costs for the twelve months ended May 31, 2011, with adjustments agreed to by us as a result of the NCUC Public Staff’s audit of the 2011 gas cost review period. We were deemed prudent on our gas purchasing policies and practices during this review period and allowed 100% recovery.

In November 2012, the NCUC approved our accounting of gas costs for the twelve months ended May 31, 2012. We were deemed prudent on our gas purchasing policies and practices during this review period and allowed 100% recovery.

In November 2013, the NCUC approved our accounting of gas costs for the twelve months ended May 31, 2013. We were deemed prudent on our gas purchasing policies and practices during this review period and allowed 100% recovery.

In November 2014, the NCUC approved our accounting of gas costs for the twelve months ended May 31, 2014. We were deemed prudent on our gas purchasing policies and practices during this review period and allowed 100% recovery.

Our gas cost hedging plan for North Carolina is designed to provide a level of protection against significant price increases, targets a percentage range of 22.5% to 45% of annual normalized sales volumes for North Carolina and operates using historical pricing indices that are tied to future projected gas prices as traded on a national exchange. Unlike South Carolina as discussed below, recovery of costs associated with the North Carolina hedging plan is not pre-approved by the NCUC, and the costs are treated as gas costs subject to the annual gas cost prudence review. Any gain or loss recognition under the hedging program is a reduction in or an addition to gas costs, respectively, which, along with any hedging expenses, are flowed through to North Carolina customers in rates. The gas cost review orders issued January 2012, November 2012, November 2013 and November 2014 found our hedging activities during the review periods to be reasonable and prudent.

In October 2012, we filed a petition with the NCUC seeking authority to transfer the total balance of $6.7 million of capital costs held in “Plant held for future use” in “Utility Plant” in the Consolidated Balance Sheets to a deferred regulatory asset account, effective November 1, 2012. This balance in “Plant held for future use” was comprised of real estate and non-real estate costs and related to the development of a LNG facility in Robeson County, North Carolina, construction of which was suspended by Piedmont in March 2009. In April 2013, we withdrew the petition, citing our intent to address the matter in a general rate application. The appropriate treatment of the Robeson County LNG costs was addressed in the general rate settlement discussed below.

In May 2013, we filed a general rate application with the NCUC requesting an increase in rates and charges. In December 2013, the NCUC approved our general rate case settlement agreement with the NCUC Public Staff with new rates effective January 2014. In its order, the NCUC approved the following:

• Updated and increased rates and charges based on an overall rate base of $1.8 billion, an equity capital structure component of 50.7% and a return on common equity of 10% and an overall rate of return of 7.51%.

• Increased total annual revenues of $30.7 million, a 3.58% increase in total revenues, or .7% annual increase, including $16.8 million related to gas utility margin and $13.8 million related to increased fixed gas costs, and annual pre-tax income of $24.2 million after taking into account revised depreciation rates and changes to regulatory asset amortizations.

• Implementation of a new IMR designed to separately track and recover annually outside of general rate cases the costs associated with capital expenditures incurred to comply with federal pipeline safety and integrity requirements.

• Implementation of lower depreciation rates that provide increased annual pre-tax income of $10.9 million. These new lower rates reflect the most recent study conducted in 2009, as discussed in Note 1 to the consolidated financial statements.

• Amortization and collection of $1.2 million of certain non-real estate costs associated with the initial development of the Robeson County LNG facility as discussed above.

• Amortization and collection of certain environmental expenses and pipeline safety and integrity compliance expenses through August 31, 2013 that had been deferred since our last general rate case in 2008.

• Provision for ongoing increased annual contributions to fund pipeline safety and integrity research.

• Future adjustments to rates to recognize the lower state corporate income taxes from North Carolina legislation for fiscal years beginning November 1, 2014 and November 1, 2015.

In January 2014, we filed a petition with the NCUC seeking authority to adjust rates effective February 1, 2014 under the IMR mechanism approved in the general rate case settlement agreement in December 2013 discussed above. The IMR provides for annual adjustments to our rates every February 1 for capital investments in integrity and safety projects as of October 31 of the preceding year. On February 5, 2014, the NCUC approved as filed the initial IMR adjustment totaling $.8 million in annual margin revenues that we reflected in our rates to customers beginning that month. In December 2014, we filed a petition with the NCUC seeking authority to adjust rates to collect an additional $26.6 million in annual IMR margin revenues effective February 1, 2015 based on $241.9 million of capital investments in integrity and safety projects over the twelve-month period ending October 31, 2014. We are waiting on a ruling from the NCUC at this time.

In April 2014, we filed a petition with the NCUC for a limited waiver of certain billing provisions of our tariff related to emergency service and unauthorized gas taken by customers in January 2014. In August 2014, we and the NCUC Public Staff filed a joint stipulation of settlement. The terms of the settlement included the granting of a waiver of the commodity index pricing mechanism for January 2014, that we should not be penalized for our conduct in varying from the tariff in this instance as that conduct was solely for the benefit of our customers, and that we and the Public Staff would work together to develop mutually agreeable revisions to our tariff to address the situation that led to this petition. In October 2014, the NCUC issued an order rejecting the joint stipulation of settlement, finding that we must bill our customers for the higher commodity cost of gas pursuant to tariffs and assessing a $65,000 penalty against us for failure to bill and collect according to the commission-approved tariffs. The order further requires us to engage in discussions with each customer served under an interruptible rate schedule to explain the service and obligation under that rate schedule and to conduct an investigation to determine if customers are receiving service under the appropriate tariff.

In April 2014, the NCUC issued an order granting us the authority to issue up to $1 billion in the aggregate of senior or subordinated debt securities or equity securities under our open shelf registration statement. This request was made by us to allow flexibility to access the capital markets as needed for business purposes, including for capital investments and to fund the operations of our subsidiaries. For further information on this shelf registration statement, see Note 4 to the consolidated financial statements.

South Carolina

We currently operate under the Natural Gas Rate Stabilization Act of 2005 in South Carolina. If a utility elects to operate under this act, the annual cost and revenue filing will provide that the utility’s rate of return on equity will remain within a 50-basis point band above or below the last approved allowed rate of return on equity.

In June 2012, we filed with the PSCSC a quarterly monitoring report for the twelve months ended March 31, 2012 and a cost and revenue study as permitted by the RSA requesting a change in rates from those approved by the PSCSC in the October 2011 order. In October 2012, the PSCSC issued an order approving a settlement agreement between the Office of Regulatory Staff (ORS) and us that resulted in a $1.1 million annual decrease in margin based on a return on equity of 11.3%, effective November 1, 2012.

In June 2013, we filed with the PSCSC a quarterly monitoring report for the twelve months ended March 31, 2013 and a cost and revenue study as permitted by the RSA requesting a change in rates from those approved by the PSCSC in the October 2012 order. In October 2013, the PSCSC issued an order approving a settlement agreement between the ORS and us that resulted in a $.1 million annual decrease in margin based on a return on equity of 11.3%, effective November 1, 2013. The PSCSC also approved the recovery of $.2 million of our deferred South Carolina environmental costs over a one-year period beginning November 2013 and ending October 2014.

In June 2014, we filed with the PSCSC a quarterly monitoring report for the twelve months ended March 31, 2014 and a cost and revenue study under the RSA requesting a change in rates from those approved by the PSCSC in the October 2013 order. In October 2014, the PSCSC issued an order approving a settlement agreement between the ORS and us that resulted in a $2.9 million annual decrease in margin based on a stipulated allowed return on equity of 10.2%, effective November 1, 2014. Also in this proceeding, the PSCSC approved the recovery of $.1 million of our deferred South Carolina environmental costs and $.5 million of certain non-real estate costs associated with the initial development of the Robeson County LNG facility located in North Carolina as discussed above, both with amortization periods of one year beginning November 2014 and ending October 2015.

In South Carolina, our recovery of gas costs is subject to annual gas cost proceedings to determine the prudence of our gas purchases. Costs have never been disallowed on the basis of prudence.

The PSCSC has approved a gas cost hedging plan for the purpose of cost stabilization for South Carolina customers. The plan targets a percentage range of 22.5% to 45% of annual normalized sales volumes for South Carolina and operates using historical pricing indices tied to future projected gas prices as traded on a national exchange. All properly accounted for costs incurred in accordance with the plan are deemed to be prudently incurred and recovered in rates as gas costs. Any gain or loss recognized under the hedging program is a reduction in or an addition to gas costs, respectively, and flows through to South Carolina customers in rates. In an August 2011 order, the PSCSC approved a stipulation that our hedging program should no longer have a required minimum volume of hedging.

In August 2012, the PSCSC approved our PGAs and found our gas purchasing policies to be prudent for the twelve months ended March 31, 2012.

In August 2013, the PSCSC approved our PGAs and found our gas purchasing policies to be prudent for the twelve months ended March 31, 2013.

In August 2014, the PSCSC approved our PGAs and found our gas purchasing policies to be prudent for the twelve months ended March 31, 2014.

In July 2014, we filed a petition with the PSCSC requesting a limited waiver of certain billing provisions of our tariff related to emergency service for customers in January 2014. In August 2014, the PSCSC granted our request and ordered us to continue to collaborate with the ORS to revise our tariff to address the situation that led to this petition.

Tennessee

In February 2010, we filed a petition with the TRA to adjust the applicable rate for the collection of the Nashville franchise fee from certain customers. The proposed rate adjustment was calculated to recover the net $2.9 million of under-collected Nashville franchise fee payments as of May 31, 2009. In April 2010, the TRA passed a motion approving a new Nashville franchise fee rate designed to recover only the net under-collections that have accrued since June 1, 2005, which would have denied recovery of $1.5 million. In October 2011, the TRA issued an order denying us the recovery of $1.5 million of franchise fees consistent with its April 2010 motion, and we recorded $1.5 million in “Operating Expenses” as “Operations and maintenance” in the Consolidated Statements of Comprehensive Income. In November 2011, we filed for reconsideration, which was granted that month. In February 2012, a hearing on this matter was held before the TRA. In May 2012, the TRA approved the recovery of an additional $.5 million in under-collected Nashville franchise fees covering years 2002 through May 2005, which we recorded as a reduction in O&M expenses. The written order was issued by the TRA in June 2012.

In Tennessee, the Tennessee Incentive Plan (TIP) replaced annual prudence reviews under the Actual Cost Adjustment (ACA) mechanism in 1996 by benchmarking gas costs against amounts determined by published market indices and by sharing secondary market (capacity release and off-system sales) activity performance. In 2007, the TRA modified our TIP to clarify and simplify the calculation of allocating secondary marketing gains and losses to ratepayers and shareholders by adopting a uniform 75/25 sharing ratio. The TRA also maintained the $1.6 million annual incentive cap for us on gains and losses, improved the transparency of plan operations by an agreed to request for proposal procedures for asset management transactions and provided for a triennial review of TIP operations by an independent consultant.

In August 2011, we filed an annual report with the TRA reflecting the shared gas cost savings from gains and losses derived from gas purchase benchmarking and secondary market transactions for the twelve months ended June 30, 2011 under the TIP. In March 2012, the TRA approved our TIP account balance. The TRA issued its written order approving the deferred gas cost balances in April 2012.

In September 2011, we filed an annual report for the twelve months ended June 30, 2011 with the TRA that reflected the transactions in the deferred gas cost account for the ACA mechanism. In March 2012, the TRA approved the deferred gas cost account balances. The TRA issued its written order approving the deferred gas cost balances in April 2012.

In August 2012, we filed an annual report with the TRA reflecting the shared gas cost savings from gains and losses derived from gas purchase benchmarking and secondary market transactions for the twelve months ended June 30, 2012 under the TIP. In February 2013, the TRA approved the TIP account balances. The TRA issued its written order approving our TIP account balances in March 2013.

In September 2012, we filed an annual report for the twelve months ended June 30, 2012 with the TRA that reflected the transactions in the deferred gas cost account for the ACA mechanism. In February 2013, the TRA approved the deferred gas cost account balances. The TRA issued its written order approving the deferred gas cost balances in March 2013.

In December 2014, we filed an annual report for the twelve months ended June 30, 2013 with the TRA that reflected the transactions in the deferred gas cost account for the ACA mechanism. We are waiting on a ruling from the TRA at this time.

In August 2013, we filed an annual report with the TRA reflecting the shared gas cost savings from gains and losses derived from gas purchase benchmarking and secondary market transactions for the twelve months ended June 30, 2013 under the TIP. In February 2014, the TRA Utilities Division Audit Staff (Audit Staff) submitted their report with which we concurred. In March 2014, the TRA approved and adopted the Audit Staff’s report. The TRA’s written order was issued in April 2014.

In August 2014, we filed an annual report with the TRA reflecting the shared gas cost savings from gains and losses derived from gas purchase benchmarking and secondary market transactions for the twelve months ended June 30, 2014 under the TIP. We are waiting on a ruling from the TRA at this time.

In August 2013, we filed an ACA petition with the TRA to authorize us to make an adjustment to the deferred gas cost account reporting for prior periods in the amount of a $3.7 million under collection. In November 2014, we filed a joint settlement agreement with the TRA staff and the Tennessee Attorney General's Consumer Advocate and Protection Division (CAD) in which the parties agreed that we may include in our next ACA filing prior period adjustments totaling $2 million in lieu of the $3.7 million as originally petitioned. In September 2014, we recorded as expense $1.7 million in the Consolidated Statements of Comprehensive Income. In December 2014, the TRA approved the settlement agreement, and we included the stipulated $2 million of prior period adjustments in the ACA annual report filed in December 2014 for the twelve-month period ended June 30, 2013, as described above.

In September 2011, we filed a general rate application with the TRA requesting authority for an increase to rates and charges, proposed to be effective March 1, 2012. In addition, the petition also requested modifications of the cost allocation and rate designs underlying our existing rates, including shifting more of our cost recovery to our fixed charges and expanding the period of the WNA to October through April. We also sought approval to implement a school-based energy education program with appropriate cost recovery mechanisms, amortization of certain regulatory assets and deferred accounts, revised depreciation rates for plant and changes to the existing service regulations and tariffs. In December 2011, we and the CAD reached a stipulation and settlement agreement resolving all issues in this proceeding, including an increase in rates and charges to all customers effective March 1, 2012 designed to produce overall incremental revenues of $11.9 million annually, or 6.3% above the current annual revenue, based upon an approved rate of return on equity of 10.2%. The new cost allocation and rate designs shifted recovery of fixed charges from 29% to 37% with a resulting decrease of volumetric charges from 71% to 63%. The stipulation and settlement agreement did not include a cost recovery mechanism for a school-based energy education program. In January 2012, a hearing on this matter was held by the TRA. The TRA approved the settlement agreement at the January 2012 hearing. The TRA’s written order was issued in April 2012.

As a part of the rate case settlement mentioned above, the TRA approved the recovery of $1 million incurred as a result of our response to severe flooding in Nashville in May 2010. These direct incremental expenses had been approved for deferred accounting treatment in October 2010. These deferred expenses are being amortized over eight years beginning March 1, 2012 through February 2020.

In August 2013, we filed a petition with the TRA seeking authority to implement an IMR to recover the costs of our capital investments that are made in compliance with federal and state safety and integrity management laws or regulations. We proposed that the rider be effective October 1, 2013 with an initial adjustment on January 1, 2014 of $13.1 million in annual margin revenue from tariff customers based on capital expenditures incurred through October 2013 and for rates to be updated annually outside of general rate cases for the return of and on these capital investments. In September 2013, the TRA issued an order suspending this proposed tariff through December 30, 2013. In November 2013, we and the CAD filed an IMR settlement with the TRA. A hearing on this matter was held in December 2013, and the TRA approved the IMR settlement as filed for $13.1 million with the IMR rate adjustments beginning January 2014. A written order was issued in May 2014. In December 2014, we filed a petition with the TRA seeking authority to collect an additional $6.5 million in annual IMR margin revenues effective January 2015 based on $54 million of capital investments in integrity and safety projects over the twelve-month period ending October 31, 2014. We are waiting on a ruling from the TRA at this time.

In February 2014, we filed a petition with the TRA to authorize us to amortize and refund $4.7 million to customers for recorded excess deferred taxes. We proposed to refund this amount to customers over three years. We are waiting on a ruling from the TRA at this time.

In September 2014, we filed a petition with the TRA seeking authority to implement a compressed natural gas infrastructure rider to recover the costs of our capital investments in infrastructure and equipment associated with this alternative motor vehicle transportation fuel. We proposed that the tariff rider be effective October 1, 2014 with an initial rate adjustment on November 1, 2014 based on capital expenditures incurred through June 2014 and for rates to be updated annually outside of general rate cases for the return of and on these capital investments. In November 2014, the TRA consolidated this docket with a separate petition we filed seeking modifications to our tariff regarding service to customers using natural gas as a motor fuel. The TRA suspended the proposed tariffs through February 9, 2015. A hearing on this matter has been scheduled for January 12, 2015.

All States

Due to the seasonal nature of our business, we contract with customers in the secondary market to sell supply and capacity assets when market conditions permit. In North Carolina and South Carolina, we operate under sharing mechanisms approved by the NCUC and the PSCSC for secondary market transactions where 75% of the net margins are flowed through to jurisdictional customers in rates and 25% is retained by us. In Tennessee, we operate under the amended TIP where gas purchase benchmarking gains and losses are combined with secondary market transaction gains and losses and shared 75% by customers and 25% by us. Our share of net gains or losses in Tennessee is subject to an overall annual cap of $1.6 million. In all three jurisdictions for the twelve months ended October 31, 2014, we generated $97.6 million of margin from secondary market activity, $72.2 million of which is allocated to customers as gas cost reductions and $25.4 million as margin allocated to us. In all three jurisdictions for the twelve months ended October 31, 2013, we generated $35.9 million of margin from secondary market activity, $26.9 million of which is allocated to customers as gas cost reductions and $9 million as margin allocated to us. In all three jurisdictions for the twelve months ended October 31, 2012, we generated $38.7 million of margin from secondary market activity, $29 million of which is allocated to customers as gas cost reductions and $9.7 million as margin allocated to us.

We currently have commission approval in all three states that place tighter credit requirements on the retail natural gas marketers that schedule gas for transportation service on our system in order to mitigate the risk exposure to the financial condition of the marketers.

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Selected Quarterly Financial Data (Details) (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended								12 Months Ended
	Oct. 31, 2014	Jul. 31, 2014	Apr. 30, 2014	Jan. 31, 2014	Oct. 31, 2013	Jul. 31, 2013	Apr. 30, 2013	Jan. 31, 2013	Oct. 31, 2014	Oct. 31, 2013	Oct. 31, 2012
Quarterly Financial Data [Abstract]
Operating Revenues	$ 185,821	$ 164,187	$ 462,247	$ 657,733	$ 200,000	$ 162,943	$ 399,411	$ 515,875	$ 1,469,988	$ 1,278,229	$ 1,122,780
Margin	112,326	104,847	211,523	261,512	109,011	97,000	183,856	231,623	690,208	621,490	575,446
Operating Income	6,993	3,254	67,299	102,319	5,886	591	51,504	86,213	179,865	144,194	125,723
Net income (loss)	$ (8,967)	$ (7,344)	$ 62,540	$ 97,572	$ (5,003)	$ (2,293)	$ 55,790	$ 85,923	$ 143,801	$ 134,417	$ 119,847
Earnings Per Share of Common Stock:
Basic (usd per share)	$ (0.11)	$ (0.09)	$ 0.80	$ 1.27	$ (0.07)	$ (0.03)	$ 0.74	$ 1.19	$ 1.85	$ 1.80	$ 1.67
Diluted (usd per share)	$ (0.11)	$ (0.09)	$ 0.80	$ 1.26	$ (0.07)	$ (0.03)	$ 0.74	$ 1.18	$ 1.84	$ 1.78	$ 1.66

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Earnings Per Share (Tables)

12 Months Ended

Oct. 31, 2014

Earnings Per Share [Abstract]

Schedule of Earnings Per Share, Basic and Diluted [Table Text Block]

A reconciliation of basic and diluted EPS, which includes contingently issuable shares that could affect EPS if performance units ultimately vest or stock agreements settle, for the years ended October 31, 2014, 2013 and 2012 is presented below.

In thousands, except per share amounts	2014		2013		2012
Net Income	$	143,801	$	134,417	$	119,847
Average shares of common stock outstanding for basic earnings per share	77,883		74,884		71,977
Contingently issuable shares under incentive compensation plans	310		289		301
Contingently issuable shares under forward sale agreements	—		160		—
Average shares of dilutive stock	78,193		75,333		72,278
Earnings Per Share of Common Stock:
Basic	$	1.85	$	1.80	$	1.67
Diluted	$	1.84	$	1.78	$	1.66

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Business Segments (Tables)

12 Months Ended

Oct. 31, 2014

Segment Reporting [Abstract]

Schedule of Segment Reporting Information, by Segment [Table Text Block]

Operations by segment for the years ended October 31, 2014, 2013 and 2012, and as of October 31, 2014, 2013 and 2012 are presented below. The information provided for fiscal years 2013 and 2012 have been restated to align with management's view of the non-utility activities.

			Regulated			Unregulated
	Regulated		Non-Utility			Non-Utility
In thousands	Utility		Activities			Activities			Total
2014
Revenues from external customers	$	1,469,988	$	—		$	—		$	1,469,988
Margin	690,208		—			—			690,208
Operations and maintenance expenses	270,877		132			92			271,101
Depreciation	118,996		—			18			119,014
Operating income (loss) before income taxes	263,041		(183		)	(203		)	262,655
Income from equity method investments	—		12,318			20,435			32,753
Interest expense	54,686		—			—			54,686
Income before income taxes	206,253		12,135			20,231			238,619
Total assets	4,442,185		129,206			41,309			4,612,700
Equity method investments in non-utility activities	—		129,206			40,965			170,171
Construction expenditures	460,444		—			—			460,444
			Regulated			Unregulated
	Regulated		Non-Utility			Non-Utility
In thousands	Utility		Activities			Activities			Total
2013
Revenues from external customers	$	1,278,229	$	—		$	—		$	1,278,229
Margin	621,490		—			—			621,490
Operations and maintenance expenses	253,120		103			78			253,301
Depreciation	112,207		—			18			112,225
Operating income (loss) before income taxes	221,528		(150		)	(202		)	221,176
Income from equity method investments	—		10,584			15,472			26,056
Interest expense	24,938		—			—			24,938
Income before income taxes	194,659		10,434			15,270			220,363
Total assets	4,053,591		90,097			38,735			4,182,423
Equity method investments in non-utility activities	—		90,097			38,372			128,469
Construction expenditures	599,999		—			—			599,999
			Regulated			Unregulated
	Regulated		Non-Utility			Non-Utility
In thousands	Utility		Activities			Activities			Total
2012
Revenues from external customers	$	1,122,780	$	—		$	—		$	1,122,780
Margin	575,446		—			—			575,446
Operations and maintenance expenses	242,599		31			71			242,701
Depreciation	103,192		—			18			103,210
Operating income (loss) before income taxes	194,824		(78		)	(186		)	194,560
Income from equity method investments	—		9,709			14,195			23,904
Interest expense	20,097		—			—			20,097
Income before income taxes	174,424		9,631			14,009			198,064
Total assets	3,475,640		69,749			18,498			3,563,887
Equity method investments in non-utility activities	—		69,749			18,118			87,867
Construction expenditures	529,576		—			—			529,576

Reconciliation of Operating Profit (Loss) from Segments to Consolidated [Table Text Block]

Reconciliations to the consolidated financial statements for the years ended October 31, 2014, 2013 and 2012, and as of October 31, 2014 and 2013 are as follows.

In thousands	2014			2013			2012
Operating Income:
Segment operating income before income taxes	$	262,655		$	221,176		$	194,560
Utility income taxes	(83,176		)	(77,334		)	(69,101		)
Regulated non-utility activities operating loss before income taxes	183			150			78
Unregulated non-utility activities operating loss before income taxes	203			202			186
Total	$	179,865		$	144,194		$	125,723
Net Income:
Income before income taxes for reportable segments	$	238,619		$	220,363		$	198,064
Income taxes	(94,818		)	(85,946		)	(78,217		)
Total	$	143,801		$	134,417		$	119,847

Reconciliation of Assets from Segment to Consolidated [Table Text Block]

In thousands	2014		2013
Consolidated Assets:
Total assets for reportable segments	$	4,612,700	$	4,182,423
Eliminations/Adjustments	171,553		186,186
Total	$	4,784,253	$	4,368,609

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Equity Method Investments

12 Months Ended

Oct. 31, 2014

Equity Method Investments and Joint Ventures [Abstract]

Equity Method Investments and Joint Ventures Disclosure [Text Block]

Equity Method Investments

The consolidated financial statements include the accounts of wholly-owned subsidiaries whose investments in joint venture, energy-related businesses are accounted for under the equity method. Our ownership interest in each entity is included in “Equity method investments in non-utility activities” in “Noncurrent Assets” in the Consolidated Balance Sheets. Earnings or losses from equity method investments are included in “Income from equity method investments” in “Other Income (Expense)” in the Consolidated Statements of Comprehensive Income.

As of October 31, 2014, there were no amounts that represented undistributed earnings of our 50% or less owned equity method investments in our retained earnings.

Cardinal Pipeline Company, L.L.C.

We own 21.49% of the membership interests in Cardinal Pipeline Company, L.L.C. (Cardinal), a North Carolina limited liability company. The other members are subsidiaries of The Williams Companies, Inc., and SCANA Corporation. Cardinal owns and operates an intrastate natural gas pipeline in North Carolina and is regulated by the NCUC. Cardinal has firm, long-term service agreements with local distribution companies for 100% of the firm transportation capacity on the pipeline, of which Piedmont subscribes to approximately 53%. Cardinal is dependent on the Williams – Transco pipeline system to deliver gas into its system for service to its customers.

Cardinal enters into interest-rate swap agreements to modify the interest expense characteristics of its unsecured long-term debt. Our share of movements in the market value of these agreements are recorded as a hedge in “Accumulated other comprehensive loss” in “Stockholders’ equity” in the Consolidated Balance Sheets; the detail of our share of the market value of the swap agreements is combined with our other equity method investments and presented in “Other Comprehensive Income (Loss), net of tax” in the Consolidated Statements of Comprehensive Income. Cardinal’s long-term debt is nonrecourse to the members.

We have related party transactions as a transportation customer of Cardinal, and we record the transportation costs charged by Cardinal in “Cost of Gas” in the Consolidated Statements of Comprehensive Income. For each of the years ended October 31, 2014, 2013 and 2012, these transportation costs and the amounts we owed Cardinal as of October 31, 2014 and 2013 are as follows.

In thousands	2014		2013		2012
Transportation costs	$	8,825	$	8,775	$	6,613
Trade accounts payable	747		755

Summarized financial information provided to us by Cardinal for 100% of Cardinal as of September 30, 2014 and 2013, and for the twelve months ended September 30, 2014, 2013 and 2012 is presented below.

In thousands	2014		2013		2012
Current assets	$	8,856	$	15,179
Noncurrent assets	111,881		116,414
Current liabilities	1,468		2,637
Noncurrent liabilities	45,402		45,273
Revenues	16,705		17,649		$	16,165
Gross profit	16,705		17,649		16,165
Income before income taxes	8,042		9,361		10,433

Pine Needle LNG Company, L.L.C.

We own 45% of the membership interests in Pine Needle LNG Company, L.L.C. (Pine Needle), a North Carolina limited liability company that owns an interstate LNG storage facility in North Carolina regulated by the FERC. Pine Needle has firm, long-term service agreements for 100% of the storage capacity of the facility, of which Piedmont subscribes to approximately 64%. Effective July 1, 2013, we acquired Hess Corporation’s 5% membership interest in Pine Needle for $2.9 million,which increased our membership interest from 40% to 45%. The other members are the Municipal Gas Authority of Georgia and subsidiaries of The Williams Companies, Inc. and SCANA Corporation.

Pine Needle enters into interest-rate swap agreements to modify the interest expense characteristics of its long-term debt. Our share of movements in the market value of these agreements are recorded as a hedge in “Accumulated other comprehensive loss” in “Stockholders’ equity” in the Consolidated Balance Sheets; the detail of our share of the market value of the swap agreements is combined with our other equity method investments and presented in “Other Comprehensive Income (Loss), net of tax” in the Consolidated Statements of Comprehensive Income. Pine Needle’s long-term debt is nonrecourse to the members.

We have related party transactions as a customer of Pine Needle, and we record the storage costs charged by Pine Needle in “Cost of Gas” in the Consolidated Statements of Comprehensive Income. For the years ended October 31, 2014, 2013 and 2012, these gas storage costs and the amounts we owed Pine Needle as of October 31, 2014 and 2013 are as follows.

In thousands	2014		2013		2012
Gas storage costs	$	11,364	$	11,098	$	10,410
Trade accounts payable	989		940

Summarized financial information provided to us by Pine Needle for 100% of Pine Needle as of September 30, 2014 and 2013, and for the twelve months ended September 30, 2014, 2013 and 2012 is presented below.

In thousands	2014		2013		2012
Current assets	$	8,812	$	9,225
Noncurrent assets	70,837		74,710
Current liabilities	38,029		3,531
Noncurrent liabilities	—		35,391
Revenues	18,025		16,810		$	16,390
Gross profit	18,025		16,810		16,390
Income before income taxes	6,011		5,804		5,832

SouthStar Energy Services LLC

We own 15% of the membership interests in SouthStar, a Delaware limited liability company. The other member is Georgia Natural Gas Company (GNGC), a wholly-owned subsidiary of AGL Resources, Inc. (AGL). SouthStar primarily sells natural gas in the unregulated retail gas market to residential, commercial and industrial customers in the eastern United States, primarily in Georgia and Illinois. We account for our investment in SouthStar using the equity method, as we have board representation with equal voting rights on significant governance matters and policy decisions, and thus, exercise significant influence over the operations of SouthStar.

In September 2013, GNGC contributed its retail natural gas marketing assets and customer accounts located in Illinois. AGL acquired these retail assets and customers from Nicor Inc. in December 2011 and additional retail natural gas assets and customer accounts in a separate transaction in June 2013. We made an additional $22.5 million capital contribution to SouthStar, maintaining our 15% equity ownership, related to this transaction.

SouthStar’s business is seasonal in nature as variations in weather conditions generally result in greater revenue and earnings during the winter months when weather is colder and natural gas consumption is higher. Also, because SouthStar is not a rate-regulated company, the timing of its earnings can be affected by changes in the wholesale price of natural gas. While SouthStar uses financial contracts to moderate the effect of price and weather changes on the timing of its earnings, wholesale price and weather volatility can cause variations in the timing of the recognition of earnings.

These financial contracts, in the form of futures, options and swaps, are considered to be derivatives and fair value is based on selected market indices. Beginning in 2014, retirement benefits were allocated to SouthStar by its majority member with the activity of prescribed benefit expense items reflected in accumulated OCIL. Our share of movements in the market value of these derivative contracts are recorded as a hedge and the activity of the retirement benefit items are reflected in “Accumulated other comprehensive loss” in “Stockholders’ equity” in the Consolidated Balance Sheets; the detail of our share of the market value of these contracts and the retirement benefits are combined with our other equity method investments and presented in “Other Comprehensive Income (Loss), net of tax” in the Consolidated Statements of Comprehensive Income.

We have related party transactions as we sell wholesale gas supplies to SouthStar, and we record the amounts billed to SouthStar in “Operating Revenues” in the Consolidated Statements of Comprehensive Income. For the years ended October 31, 2014, 2013 and 2012, our operating revenues from these sales and the amounts SouthStar owed us as of October 31, 2014 and 2013 are as follows.

In thousands	2014		2013		2012
Operating revenues	$	3,541	$	3,291	$	2,442
Trade accounts receivable	460		441

Summarized financial information provided to us by SouthStar for 100% of SouthStar as of September 30, 2014 and 2013, and for the twelve months ended September 30, 2014, 2013 and 2012 is presented below.

In thousands	2014		2013*		2012
Current assets	$	196,286	$	199,425
Noncurrent assets	143,420		147,571
Current liabilities	51,435		76,346
Noncurrent liabilities	83		31
Revenues	845,695		639,426		$	585,291
Gross profit	234,581		174,993		161,122
Income before income taxes	136,569		102,805		94,631

* Amounts have been changed to reflect restatement of AGL's Form 10-K for the year ended December 31, 2013. The restatement had an immaterial impact on SouthStar's results.

Hardy Storage Company, LLC

We own 50% of the membership interests in Hardy Storage Company, LLC (Hardy Storage), a West Virginia limited liability company. The other owner is a subsidiary of Columbia Gas Transmission Corporation, a subsidiary of NiSource Inc. Hardy Storage owns and operates an underground interstate natural gas storage facility located in Hardy and Hampshire Counties, West Virginia, that is regulated by the FERC. Hardy Storage has firm, long-term service agreements for 100% of the storage capacity of the facility, of which Piedmont subscribes to approximately 40%.

We have related party transactions as a customer of Hardy Storage, and we record the storage costs charged by Hardy Storage in “Cost of Gas” in the Consolidated Statements of Comprehensive Income. For the years ended October 31, 2014, 2013 and 2012, these gas storage costs and the amounts we owed Hardy Storage as of October 31, 2014 and 2013 are as follows.

In thousands	2014		2013		2012
Gas storage costs	$	9,461	$	9,702	$	9,702
Trade accounts payable	774		808

Summarized financial information provided to us by Hardy Storage for 100% of Hardy Storage as of October 31, 2014 and 2013, and for the twelve months ended October 31, 2014, 2013 and 2012 is presented below.

In thousands	2014		2013		2012
Current assets	$	12,644	$	7,641
Noncurrent assets	157,861		161,282
Current liabilities	17,316		12,378
Noncurrent liabilities	78,830		87,184
Revenues	23,804		24,375		$	24,359
Gross profit	23,804		24,375		24,359
Income before income taxes	10,497		10,582		9,939

Constitution Pipeline Company, LLC

We own 24% of the membership interests of Constitution Pipeline Company, LLC (Constitution), a Delaware limited liability company. The other members are subsidiaries of The Williams Companies, Inc., Cabot Oil & Gas Corporation and WGL Holdings, Inc. A subsidiary of The Williams Companies is the operator of the project. The purpose of the joint venture is to develop, construct, own and operate approximately 120 miles of interstate natural gas pipeline and related facilities connecting shale natural gas supplies and gathering systems in Susquehanna County, Pennsylvania, to the Iroquois Gas Transmission and Tennessee Gas Pipeline systems in New York. We have committed to fund an amount in proportion to our ownership interest for the development and construction of the new pipeline, which is expected to cost approximately $730 million at the project level. As of October 31, 2014, our fiscal year contributions were $37.6 million, with our total equity contributions for the project totaling $53.5 million to date. On December 2, 2014, the FERC issued a certificate of public convenience and necessity approving construction of the Constitution pipeline. The target in-service date of the project is late 2015 or 2016. The capacity of the pipeline is 100% subscribed under fifteen year service agreements with two Marcellus producer-shippers with a negotiated rate structure.

Summarized financial information provided to us by Constitution for 100% of Constitution as of September 30, 2014 and 2013, and for the twelve months ended September 30, 2014 and 2013 is presented below.

In thousands	2014		2013 (1)
Current assets	$	11,273	$	10,944
Noncurrent assets	219,208		62,438
Current liabilities	7,667		7,960
Noncurrent liabilities	—		—
Revenues	—		—
Gross profit	—		—
Income before income taxes	10,091		3,459
(1) Presented in the period in which we have a membership interest in Constitution, and not prior periods when we had no membership interest in Constitution. Our membership in Constitution began in November 2012.

Atlantic Coast Pipeline, LLC

On September 2, 2014, Piedmont, Duke Energy, Dominion Resources, Inc. (Dominion), and AGL announced the formation of Atlantic Coast Pipeline, LLC (ACP), a Delaware limited liability company. ACP intends to construct, operate and maintain a 550 mile natural gas pipeline, with associated compression, from West Virginia through Virginia into eastern North Carolina. The pipeline is proposed to provide interstate natural gas transportation services for Marcellus and Utica gas supplies into southeastern markets. ACP, which is regulated by the FERC, will be designed with an initial capacity of 1.5 billion cubic feet per day with a target in-service date of late 2018. The capacity of ACP is substantially subscribed by the members of ACP, other utilities and related companies under twenty-year contracts.

We entered into an agreement through a wholly-owned subsidiary to become a 10% equity member of ACP. The other members are subsidiaries of Duke Energy, Dominion and AGL. A Dominion subsidiary will be the operator of the pipeline. The cost for the development and construction of the pipeline is expected to be between $4.5 billion to $5 billion, excluding financing costs. Members anticipate obtaining project financing for 70% of the total costs during the construction period. As of October 31, 2014, we have made no contributions to ACP.

In October 2014, ACP requested approval from the FERC to utilize the pre-filing process under which environmental review for the natural gas pipeline will commence. ACP expects to file its FERC application in the third quarter of 2015, receive the FERC certificate in the summer of 2016 and begin construction thereafter. The project is subject to FERC, state and other federal approvals.