~~Changes in cost of gas for 2013 and 2012 compared with the same prior periods are presented below.~~

Depreciation expense increased from ~~$102.8~~$112.2 million to ~~$112.2~~$128.7 million over the three-year period ~~2011~~2013 to ~~2013~~2015 primarily due to increases in plant in service, particularly related to major additions to serve new power generation customers ~~system~~and transmission integrity ~~and upgrades to our liquefied natural gas facilities.~~

2015 compared with ~~the same prior period are presented below.~~

~~Changes in General Taxes Expense - Increase (Decrease)~~


~~In millions~~	~~2012 vs.~~ ~~2011~~
~~Sales tax accrual~~	$	~~(2.5)~~
~~Gross receipts tax~~		~~(.8)~~
2014: Property taxes		.4
~~Other~~		~~(.6)~~

~~Total~~	$	~~(3.5)~~

~~2012 compared to 2011:~~

~~Sales tax accrual~~ – the ~~decrease~~increase is primarily due to ~~the accrual of a liability of $2.7 million~~increases in ~~2011 for sales~~property.

Franchise taxes ~~on certain customer accounts.~~

~~Gross receipts tax~~ – the ~~decrease~~increase is primarily due to ~~lower accruals~~changes in North Carolina tax laws and increases in property.

2014 compared with 2013:

Property taxes – the ~~current period for Tennessee gross receipts tax as a result of lower revenues.~~increase is primarily due to increases in property.

Franchise taxes – the increase is primarily due to increases in property.

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 warranty programs, subsidiary operations, interest income and other miscellaneous income. Non-operating expense is comprised of charitable contributions and miscellaneous expenses.

~~2013 compared with 2012:~~

Changes in Other Income (Expense) ~~increased $.9 million in 2013~~for 2015 and 2014 compared with ~~2012. The primary changes were an increase in income~~the same prior periods are presented below.



Changes in Other Income (Expense) - Increase (Decrease) to Income
	2015 vs.			2014 vs.
In millions	2014			2013
Income from equity method investments:
Constitution	$	3.4		$	1.7
SouthStar	(1.0		)	5.0
Other	(0.7		)	—
Total	1.7			6.7
Non-operating income	1.3			(1.0		)
Non-operating expense	0.6			0.8
Income Taxes	(1.6		)	(3.0		)
Total	$	2.0		$	3.5

2015 compared with 2014:

Income from equity method investments ~~and an~~from Constitution – the increase ~~in non-operating expenses. All other changes for~~is primarily due to higher capitalized interest associated with increased capital expenditures on the ~~year ended October 31, 2013 compared with 2012 were insignificant.~~

project.

Income from equity method investments from SouthStar ~~increased $1.3~~– the decrease is primarily due to a lower value of hedged derivatives and less usage in Georgia and Illinois due to warmer weather, partially offset by favorable margins in Georgia, Illinois and Ohio.

Non-operating income – the increase is primarily due to the $2 million write-off in ~~2013~~2014 of an investment that was accounted for on the cost basis as discussed below.

2014 compared with 2013:

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

Income from ~~colder weather compared~~equity method investments from SouthStar – the increase is primarily due to the ~~prior year, net~~expansion of ~~weather derivatives,~~ the ~~recording of a lower cost or market inventory adjustment in the~~

~~prior year and new margin from the~~business into Illinois ~~business that was contributed to the venture with our sharing~~markets beginning in September 2013, and favorable weather and customer usage in Georgia, partially offset by higher ~~gas costs, increased operating expenses~~general and lower retail price spreads. Beginning November 1, 2012 with our initial investment in Constitution, we recorded earnings of $1 million due to the allowance for funds used during construction (AFUDC), partially offset by operatingadministrative expenses. For further information on the contribution of the Illinois business ~~made~~ to SouthStar and our cash contribution in our equity method investment, see Note 1213 to the consolidated financial statements in this Form 10-K.

Non-operating ~~expense increased $3.3 million in 2013 compared with 2012~~income – the decrease is primarily due to ~~$1.8~~a $2 million write-off of ~~cumulative amortization of non-land costs related to~~an investment that we accounted for on the ~~allowed deferral of a regulatory asset for certain non-real estate costs, construction of which~~cost basis. This investment was ~~suspended~~presented in ~~March 2009, as included~~“Other noncurrent assets” in “Noncurrent Assets” 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.

~~2012 compared with 2011:~~

The primary change to Other Income (Expense) in 2012 compared with 2011 was income from equity method investments, primarily from SouthStar and Cardinal Pipeline Company, L.L.C. (Cardinal). All other changes for the year ended October 31, 2012 compared with 2011 were insignificant.

Income from equity method investments from SouthStar decreased $1.4 million in 2012 primarily due to lower customer usage related to warmer-than-normal weather, net of weather derivatives, partially offset by lower transportation and gas costs and higher commercial asset optimization.

The decrease from SouthStar was partially offset by a $1 million increase in earnings from Cardinal primarily due to higher capitalized interest from the AFUDC and increased revenues as a result of the expansion project to serve a subsidiary of Duke Energy Corporation, (DEC), the Duke Energy Progress, Inc. (DEP) Wayne County generation project, partially offset by higher depreciation and operating expenses.

Consolidated Balance Sheets.

Utility Interest Charges

Changes in utility interest charges for ~~2013~~2015 and ~~2012~~2014 compared with the same prior periods are presented below.

~~Changes in Utility Interest Charges - Increase (Decrease)~~

In millions
         2013 vs.
2012          2012 vs.
2011
Interest expense on long-term debt
   $ 12.7    $ (4.6)
Borrowed AFUDC
   (5.8)       (16.6)
Interest expense on short-term debt
   (1.5)       .8
Regulatory interest expense, net
   .1    (3.8)
Other
   (.7)       .3




  Total
   $ 4.8    $ (23.9)

~~2013~~



Changes in Utility Interest Charges - Increase (Decrease)
	2015 vs.			2014 vs.
In millions	2014			2013
Interest expense on long-term debt	$	9.1		$	7.4
Borrowed AFUDC	5.3			14.5
Regulatory interest expense, net	(0.5		)	8.1
Other	—			(0.3		)
Total	$	13.9		$	29.7

2015 compared to ~~2012:~~

2014:

Interest expense on long-term debt – the increase is primarily due to ~~the issuance~~higher amounts of debt outstanding in ~~2013 and a full year of interest expense on~~ the ~~debt issued in 2012.~~current period.

Borrowed ~~AFUDC~~allowance for funds used during construction (AFUDC) – the ~~decrease~~increase is due to ~~an increase~~a decrease in capitalized interest ~~primarily resulting from increased~~on a lower base of construction ~~expenditures.~~

~~Interest expense on short-term debt – the decrease is primarily due to lower balances outstanding during~~expenditures in the current period ~~at interest rates that are 34 basis points lower than~~resulting from the ~~prior year period. We paid down short-term debt as we issued long-term debt and equity securities during our fiscal year.~~timing of projects being placed into service.

~~2012~~

2014 compared to ~~2011:~~

2013:

Interest expense on long-term ~~debt – the decrease is primarily due to the replacement of higher rate debt with lower rate debt.~~

~~Borrowed AFUDC – the decrease is due to an increase in capitalized interest primarily as a result of increased project construction expenditures.~~

~~Interest expense on short-term~~ debt – the increase is primarily due to higher ~~balances~~amounts of debt outstanding ~~during~~in the current period.

Borrowed AFUDC – the increase is due to a decrease in capitalized interest on a lower base of construction expenditures in the current period ~~used for utility capital expenditures and other corporate purposes at interest rates that are 28 basis points lower than~~resulting from the ~~prior year period.~~timing of projects being placed into service.

Regulatory interest expense, net – the ~~decrease~~increase is primarily due to ~~an increase~~the recording of interest expense on amounts due to customers compared with the recording of interest income in ~~interest charged~~the prior year on amounts due from ~~customers, which is recorded as interest income.~~customers.

Financial Condition and Liquidity

Our ~~capital market~~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.

The Merger Agreement includes certain restrictions, limitations and prohibitions as to actions we may or may not take in the period prior to completion of the Acquisition. Among other restrictions, the Merger Agreement limits, beyond previously budgeted and planned amounts and allowed exceptions, our total capital spending, limits the extent to which we can obtain financing through long-term debt and equity, and caps our cash dividend to no more than the current annual per share dividend plus an increase of not more than $.04 per fiscal year, with record dates and payment dates consistent with our current dividend practices. At this time, as a result of the Acquisition, we do not anticipate modifying our 2016 strategy discussed below and do not expect a significant impact on our cash requirements and sources of liquidity.

For information on the issuance of long-term debt and equity securities, see Note 45 and Note 6,7, respectively, to the consolidated financial statements in this Form 10-K.

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~~provide the liquidity to fund our working capital, a portion of our capital expenditures and other cash needs.

Short-term debt is vital to meet the timing of our working capital needs, such as our seasonal requirements for gas supply, pipeline capacity, payment of dividends, general corporate liquidity, a portion of our capital expenditures and approved investments. 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, ~~construction~~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 ~~extension~~generation of federal net operating loss (NOL) carryforwards resulting from bonus depreciation, ~~legislation.~~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.”~~

Activities” in this Form 10-K.

Short-Term Debt. We have ~~a $650~~an $850 million five-year revolving syndicated credit facility that expires in October 2017 and has an option to request an expansion of up to $850 million. On November 1, 2013, we entered into an agreement with the lenders under the facility which increased our borrowing capacity to $850 million.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.

~~At October 31, 2013,~~

On December 14, 2015, we entered into an agreement with the lenders under our existing $850 million five-year revolving syndicated credit facility to amend and extend the facility. The amended facility has substantially similar terms to our existing facility and has an option to request an expansion of financing commitments by an additional $200 million. The amended facility extended the maturity of our facility to December 14, 2020. The amended facility expressly permits the Acquisition by Duke Energy. The CP program will continue to be backstopped by the new credit facility.

We have ~~a $650~~an $850 million unsecured CP program that is backstopped by the revolving syndicated credit facility. ~~Effective in November 2013, we exercised the expansion option under the revolving syndicated credit facility. With the exercise of the option, the~~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 ~~unsubordinated and~~ unsecured debt.

We did not have any borrowings under the revolving syndicated credit facility for the year ended October 31, 2015. Highlights for our short-term debt under our CP program as of October 31, ~~2013~~2015 and ~~2012~~2014 and for the quarter and year ended October 31, ~~2013~~2015 and ~~2012~~2014 are presented below.

In thousands
   Credit
        Facility               Commercial
Paper Total
    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
       $ -        $ 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 %
2012

End of period (October 31, 2012):

Amount outstanding
       $ -        $ 365,000     $ 365,000
Weighted average interest rate
   - % .42 % .42 %
During the period (August 1, 2012 - October 31, 2012):

Average amount outstanding
       $ -        $ 444,300     $ 444,300
Minimum amount outstanding
       $ -        $ 335,000     $ 335,000
Maximum amount outstanding
       $ -        $ 535,000     $ 535,000
Minimum interest rate
   - % .30 % .30 %
Maximum interest rate
   - % .45 % .45 %
Weighted average interest rate
   - % .39 % .39 %
Maximum amount outstanding during the month:

August 2012
       $ -        $ 450,000     $ 450,000
September 2012
   -    500,000 500,000
October 2012
   -    535,000 535,000
During the year ended October 31, 2012:

Average amount outstanding
       $ 144,700     $ 404,700     $ 416,300
Minimum amount outstanding⁽¹⁾
       $ -        $ -        $ 328,500
Maximum amount outstanding⁽¹⁾
       $     475,500     $ 535,000     $ 535,000
Minimum interest rate⁽²⁾
   1.15 % .22 % .22 %
Maximum interest rate
   1.20 % .45 % 1.20 %
Weighted average interest rate
   1.17 % .38 % .66 %
⁽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.



In thousands	2015
End of period (October 31, 2015):
Amount outstanding	$	340,000
Weighted average interest rate	.22		%

During the period (August 1, 2015 – October 31, 2015):
Average amount outstanding	$	372,600
Minimum amount outstanding	290,000
Maximum amount outstanding	445,000
Minimum interest rate	.16		%
Maximum interest rate	.25		%
Weighted average interest rate	.22		%

Maximum amount outstanding during the month:
August 2015	$	430,000
September 2015	445,000
October 2015	380,000

During the year ended October 31, 2015:
Average amount outstanding	$	361,100
Minimum amount outstanding	230,000
Maximum amount outstanding	580,000
Minimum interest rate	.15		%
Maximum interest rate	.30		%
Weighted average interest rate	.21		%



In thousands	2014
End of period (October 31, 2014):
Amount outstanding	$	355,000
Weighted average interest rate	.17		%

During the period (August 1, 2014 – October 31, 2014):
Average amount outstanding	$	420,900
Minimum amount outstanding	275,000
Maximum amount outstanding	535,000
Minimum interest rate	.10		%
Maximum interest rate	.25		%
Weighted average interest rate	.17		%

Maximum amount outstanding during the month:
August 2014	$	525,000
September 2014	535,000
October 2014	355,000

During the year ended October 31, 2014:
Average amount outstanding	$	441,500
Minimum amount outstanding	275,000
Maximum amount outstanding	625,000
Minimum interest rate	.10		%
Maximum interest rate	.43		%
Weighted average interest rate	.19		%

As of October 31, ~~2013,~~2015, we had $10 million available for letters of credit under our revolving syndicated credit facility, of which ~~$2.1~~$1.6 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, ~~2013,~~2015, unused lines of credit available under our revolving syndicated credit facility, including the issuance of the letters of credit, totaled ~~$247.9~~$508.4 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.as discussed above. 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~~increases 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~~as amounts due to or from 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, ~~are expected to~~ 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 $371.6 million in 2015, $430.6 million in 2014 and $313.2 million in ~~2013, $304.5 million in 2012 and $311.2 million in 2011.~~2013. Net cash provided by operating activities reflects a ~~$14.6~~$6.8 million ~~increase~~decrease in net income ~~for 2013~~in 2015 compared with ~~2012~~2014 primarily due to ~~increased margin, partially offset by~~ higher operating costs, costs resulting from the Acquisition and utility interest charges, ~~in 2013.~~partially offset by increased margin. The effect of changes in working capital on net cash provided by operating activities is described below:

Trade accounts receivable and unbilled utility revenues ~~increased $23.5~~decreased $10.2 million in the current period primarily due to ~~colder~~the decrease in amounts billed to customers reflecting lower gas costs. Volumes sold to weather-sensitive residential and commercial customers decreased .4 million dekatherms as compared with the same prior period primarily due to 2.7% warmer weather ~~and higher consumption of natural gas.~~

during the current period.

Volumes sold to weather-sensitive residential and commercial customers increased 17.3 million dekatherms as compared with the same prior period primarily due to 25% colder weather during the current period. Total throughput increased 63.3 million dekatherms as compared with the same prior period, largely from 39.2 million dekatherms, or 26%, increased deliveries to power generation customers, as well as increased sales to residential and commercial customers.

Net amounts due ~~from~~to customers decreased ~~$15.3~~$16.8 million in the current period primarily due to ~~margin decoupling~~a $45.5 million one-time bill credit to North Carolina customers and lower hedging costs, partially offset by deferred gas cost collections and refunds through ~~rates.~~rates, margin decoupling and WNA.

Gas in storage ~~increased $1.3~~decreased $15.8 million in the current period primarily due to ~~an increase~~a decrease in the weighted average cost of gas purchased for injections, offset slightly ~~offset~~ by ~~decreased~~increased volumes of gas in ~~storage from higher customer sales in 2013 due to colder weather.~~storage.

Prepaid gas costs ~~increased $4.7~~decreased $10.2 million in the current period primarily due to ~~an increase~~a decrease 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 increased$14.6 million in the current period primarily due to the timing of utility capital expenditures, partially offset by lower prices for natural gas purchases.

Primarily due to bonus depreciation, we generated federal NOLs in our tax years 2012, 2013 and 2014. 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 refundable income taxes from the carryback of theses NOLs in 2014. We are currently under audit by the Internal Revenue Service for our 2012 tax year. Due to the timing of the audit, we reclassified $26 million of current refundable income taxes to “Income taxes receivable” in “Noncurrent Assets” in the Consolidated Balance Sheets from the carryback of these NOLs in 2015.

The Tax Increase Prevention Act of 2014 (the Act), enacted December 19, 2014, retroactively extended the 50% bonus depreciation that expired December 2013 for a year to December 2014. Under the Act, we were entitled to additional tax depreciation deductions for 2014. These additional deductions resulted in generating a federal NOL in 2014. We utilized tax NOL carryforwards to offset our taxable income in 2015. We anticipate that we will generate future taxable income sufficient to utilize tax carryforwards prior to the expiration of the carryforward period. For further information on tax carryforwards as of October 31, 2015, see Note 12 to the consolidated financial statements in this Form 10-K.

The Protecting Americans from Tax Hikes Act of 2015, enacted in December 2015, retroactively extends bonus depreciation that expired in December 2014. Under this legislation, qualified property placed in service during 2015 is eligible for 50% bonus depreciation. This retroactive extension of bonus depreciation will increase our federal NOLs as of October 31, 2015 by approximately $135 million.

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 ~~which includes the additional months of April and October in 2013 and 2012 for Tennessee,~~ generated ~~charges~~credits to customers of $6.8 million and $8.4 million in 2015 and 2014, respectively, and charges of $3 million ~~and $13.3 million~~ in ~~2013 and 2012, respectively, and credits of $4.9 million in 2011.~~2013. 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”~~Liabilities,” as presented in Note 13 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 $27 million and $33.4 million in 2015 and 2014, respectively, and increased margin by $6 million ~~and $46.8 million~~ in ~~2013 and 2012, respectively, and reduced margin by $7 million in 2011.~~2013. Our gas costs are recoverable through purchased gas adjustment (PGA) procedures and are not affected by the WNA or the margin decoupling mechanisms.

The American Taxpayer Relief Act of 2012, enacted in January 2013, and The Tax Relief, Unemployment Insurance Reauthorization and Job Creation Act of 2010, enacted in December 2010 (the Acts), extended the 50% bonus depreciation that expired December 2009 and temporarily increased bonus depreciation for federal income tax purposes to 100% for certain qualified investments. These provisions are effective for our fiscal year tax returns for 2010 – 2015. Based on current capital projections and timelines, we anticipate that bonus depreciation will reduce cash needed to pay federal income taxes during fiscal years 2010 – 2015 by $165 – $180 million as compared with cash tax needs prior to the Acts. While reducing cash tax payments, bonus depreciation will increase deferred tax liabilities by a similar amount. Rate base generally consists of net utility plant in service less utility deferred income tax liabilities. Rate base upon which authorized revenue requirements are determined increased for 2013, but less than if bonus depreciation had not been in effect.

Primarily due to bonus depreciation, we generated a federal net operating loss (NOL) in our tax years 2012 and 2013. We will file 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 that we anticipate will be generated from the carryback of these NOLs. Any NOLs that are not carried back will be carried forward to offset future taxable income. From the carryforward of 2013 NOLs, we anticipate we will completely offset 2014 taxable income and will generate taxable income sufficient to utilize all NOLs prior to the expiration of the loss carryforward periods.

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~~

We face competition from 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. Competition for space heating and general household and small commercial energy needs generally occurs at the initial installation phase when the customer or builder makes decisions as to which types of equipment to install. Customers generally use the chosen energy source for the life of the equipment. 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 ~~price.~~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 $478.4 million in 2015, $504.4 million in 2014 and $663.5 million in ~~2013, $549.3 million in 2012 and $252.6 million in 2011.~~2013. Net cash used in investing activities was primarily for utility capital expenditures. Gross utility capital expenditures were ~~$600~~$443.7 million in ~~2013~~2015 as compared to ~~$529.6~~$460.4 million in ~~2012~~2014 primarily due to ~~increased expenditures for system~~lower spending on transmission integrity projects ~~partially offset by decreased expenditures for~~and the ~~construction~~completion of ~~power generation service delivery projects.~~early phases of the work and asset management system. Gross utility capital expenditures were ~~$529.6~~$460.4 million in ~~2012 as~~2014 compared to ~~$243.6~~$600 million in ~~2011~~2013 primarily due to ~~expending $284.3 million and $103.6 million, respectively, for the construction of~~lower power generation service delivery ~~projects.~~project expenditures and lower maintenance expenditures.

We have a substantial capital expansion program for construction of transmission and distribution facilities, purchase of equipment and other general improvements. Our program ~~primarily~~ supports our system infrastructure, ~~and~~ the growth in our customer ~~base. We are increasing our spending~~base and large amounts for pipeline integrity, safety and compliance programs, ~~and~~including systems and technology infrastructure to enhance our pipeline system and ~~integrity. To ensure safe pipeline operations, we are also deploying new technology~~integrity through ~~the development of~~ a ~~new~~comprehensive 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 ~~2014~~2016 – ~~2016~~2018 utility capital expenditures, including AFUDC, and our commitments to fund equity method investments is presented below. We intend to fund capital expenditures in a manner that maintains our targeted capitalization ratio of 4550 – ~~50%~~60% in ~~long-term~~total debt and 5040 – ~~55%~~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

2014

2015

2016

Customer growth and other
   $           200    $           190    $           190
System integrity
   250    225    215






Total forecasted utility capital expenditures
   $ 450    $ 415    $ 405

Our estimates for utility capital expenditures in 2014, particularly those associated with system integrity, have increased compared to previous estimates in prior years. These increases are primarily due to costs associated with the developmentdepreciation.



In millions	2016		2017		2018
Customer growth and other	$	290	$	310	$	385
System integrity	270		255		210
Total forecasted utility capital expenditures	560		$	565	595
Forecasted funding of construction in equity method investments	116		104		69
Total	$	676	$	669	$	664

During fiscal 2013, we placed into service natural gas pipeline 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 include retrofitting transmission lines to facilitate internal inspections, transmission line replacements, corrosion control, casing remediation and distribution integrity management. The increased expenditures in 2014 also include costs associated with the completion of a major transmission line replacement in Nashville, the construction of which began in 2013.

~~In October 2009, we reached an agreement with DEP, now a subsidiary of DEC,~~compression facilities to provide natural gas delivery service to a Duke Energy Progress, Inc., (now a subsidiary of Duke Energy) power generation facility ~~to be built~~ at their ~~Wayne County,~~Sutton

site near Wilmington, North ~~Carolina site requiring us to construct 38 miles of transmission~~Carolina. Our investment in the pipeline ~~along with additional~~and compression ~~facilities. Service began in June 2012 and is~~facilities was supported by a long-term service agreement with fixed monthly payments. We also executed an agreement with Cardinal to expand our firm capacity requirement on Cardinal 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, which began service in June 2012. As an equity venture partner of Cardinal, we made capital contributions of $9.8 million from January 2011 through June 2012 related to this system expansion. In June 2012, due to Cardinal obtaining permanent financing of the expansion, we received $5.4 million as a partial return of our capital investment. For further information regarding this agreement, see Note 12 to the consolidated financial statements in this Form 10-K.

~~In April 2010, we reached another agreement with DEP to provide natural gas delivery service to a power generation facility to be built at their existing~~

Our Sutton site near Wilmington, North Carolina. The agreement called for us to construct approximately 130 miles of transmission pipeline along with compression facilities to provide natural gas delivery service to the plant, which was placed into service as scheduled on June 1, 2013. Our investment in the pipeline and compression facilities is supported by a long-term service agreement with fixed monthly payments.

~~The 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~~In 2015, a special contracts credit, representing the depreciation of investments under our ~~2013 NCUC rate settlement provided for a portion of~~power generation contracts, reduced the IMR revenue requirement under the IMR mechanism.

In June 2014, we executed an agreement to construct approximately 1.5 miles of ~~this project~~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 ~~recovered through tariff rates~~$38 million, with expenditures occurring primarily in our fiscal year 2016, 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 and has a target in-service date of May 2017.

Also, in May 2015, we executed an agreement to ~~customers~~construct a delivery station and associated compression to provide additional service to Duke Energy’s power generation facility at their Sutton site as discussed above. Our total investment is estimated to be $13 million with expenditures occurring primarily in ~~North Carolina.~~

~~During~~our fiscal ~~2011, we placed into~~years 2016 and 2017, 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 and has a target in-service date of June 2017.

We are invested as equity members in two interstate natural gas pipeline and compression facilities to provide natural gas delivery service to a DEP power generation facility located in Richmond County, North Carolina. During fiscal 2011, we also placed into service natural gas pipeline facilities to provide natural gas delivery service to a DEC power generation facility located in Rowan County, North Carolina. In December 2011, we placed into service natural gas pipeline facilities to provide natural gas delivery service to a DEC power generation facility located in Rockingham County, North Carolina. Our investmentsprojects that are in the ~~pipeline facilities~~process of development. As a member of these limited liability companies, we are ~~supported by long-term service agreements with fixed monthly payments.~~

~~In July 2013, we acquired an incremental 5% membership interest~~committed to fund construction in ~~Pine Needle from Hess for $2.9 million, which increased~~proportion to our ~~membership interest from 40% to 45%.~~ownership interests. For further information regarding ~~this transaction,~~these investments, see Note 1213 to the consolidated financial statements in this Form 10-K.



	Constitution		ACP
In millions	(24% ownership interest)		(10% ownership interest)
Our anticipated contributions for total projects costs	$	200.2	$ 450 - 500
Anticipated in-service date	fourth quarter of 2016		late 2018
Our contributions:
For the year ended October 31, 2015	19.1		10.6
Over life of project to date	72.7		10.6

In ~~September 2013,~~connection with the ACP project, we ~~made an~~plan to make additional ~~$22.5 million~~utility capital ~~contribution to~~investments in our ~~existing SouthStar investment associated with our partner contributing retail~~ natural gas ~~marketing assets~~delivery system, predominately in fiscal 2017 and ~~related customer accounts located~~2018, of approximately $190 million in ~~Illinois. For further information regarding this transaction, see Note 12~~order 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 and operate approximately 120 miles of interstate natural gas pipeline and related facilities connecting shale naturalredeliver ACP 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~~local North Carolina markets we serve. Of that amount, ~~in proportion to our ownership interest for the development and construction of the new pipeline, which is expected to cost~~ approximately ~~$680 million. Our contributions through October 31, 2013 were $15.9~~$170 million ~~and we expect our total contributions~~ will be ~~an estimated $55 million and $92.1 million~~supported by third-party contracts. These expenditures are driving the increase in ~~our~~utility capital expenditures for fiscal ~~2014 and 2015 years, respectively. The target~~2018 for customer growth as shown above in ~~service date~~the schedule of ~~the project is March 2015. For further information regarding this agreement, see Note 12 to the consolidated financial statements in this Form 10-K.~~

forecasted capital expenditures.

Cash Flows from Financing Activities. Net cash provided by ~~(used in)~~ financing activities was $110.9 million in 2015, $75.4 million in 2014 and $356.3 million in ~~2013, $240 million in 2012 and ($57.5) million in 2011.~~2013. 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). ~~In recent years, bonus depreciation has been a source of funds in that it has decreased our federal income tax payments.~~ We may sell common stock and issue long-term debt when market and other conditions favor such long-term financing to maintain our target ~~long-term~~ capital structure of 5040 – ~~55%~~50% equity to total ~~long-term~~ capital. 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 when required to maintain target capital structure, pay quarterly dividends on our common stock and for other general corporate purposes.

Outstanding debt under our ~~revolving syndicated credit facility and~~ CP program ~~increased~~decreased from ~~$365~~$355 million as of October 31, ~~2012~~2014 to ~~$400~~$340 million as of October 31, ~~2013~~2015 primarily due to ~~increased utility capital expenditures and investments in our equity method investments, partially offset by the~~ net proceeds received from the issuance of long-term debt and our common ~~stock~~stock. As discussed above in “Short-Term Debt” in “Financial Condition and ~~long-term debt. Our~~Liquidity,” we amended and extended our existing $850 million five-year revolving syndicated credit facility, ~~had~~including an option to request an expansion of ~~up to $850~~financing commitments by an additional $200 million. In November 2013, we entered into an agreement with the lenders under the facility which increased our borrowing capacity to $850 million. Our unsecured CP program, which is backstopped by our credit facility, was established in March 2012. For further information on short-term debt, see Note 6 to the ~~previous discussion of “Short-Term Debt”~~consolidated financial statements 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.~~

~~We have an open~~10-K.

In June 2014, we filed a combined debt and equity shelf registration statement ~~filed~~ with the SEC ~~in July 2011~~ that ~~is available for future use until its expiration~~became effective on ~~July~~June 6, 2014. The NCUC approved debt and equity issuances under this shelf registration 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, including capital expenditures, additions to working capital and advances for our investments in our subsidiaries and for repurchases of shares of our common stock.~~purposes. Pending such use, we may temporarily invest any net proceeds that are not applied to the purposes mentioned above in ~~investment grade~~investment-grade securities. ~~We plan to issue new long-term debt and~~

Under this shelf registration statement, we established an ATM equity ~~capital over fiscal years 2014 and 2015, at such amounts to support our capital investment~~sales program, ~~and maintain our target capital structure of 45 – 50% in long-term debt and 50 – 55% in common equity.~~

including a forward sales component. On January ~~29, 2013,~~7, 2015, we entered into ~~an underwriting agreement under our open combined debt~~separate ATM Equity Offering Sales Agreements (Sales Agreements) with Merrill Lynch, Pierce, Fenner & Smith Incorporated and equity shelf registration statement to sell up to 4.6 million shares of our common stock. The offering for 3 million shares was settled on February 4, 2013, and we received net proceeds of $92.6 million from 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.

~~We have two FSAs totaling 1.6 million shares that must be settled no later than mid December 2013.~~J.P. Morgan Securities LLC, in their capacity as agents and/or principals (Agents). Under the terms of the ~~FSAs, at our election,~~Sales Agreements, we may ~~physically settle in shares, cash or net share settle for all or a portion~~issue and sell, through either of ~~our obligations under~~ the ~~agreements. On December 16, 2013, we physically settled by issuing 1.6 million~~Agents, shares of our common stock, up to an aggregate sales price of $170 million (subject to certain exceptions) during the period beginning January 2015 and ending October 31, 2016. Any such shares of our common stock would be offered and sold under our shelf registration statement and related prospectuses.

Our ability to sell our common stock up to the ~~forward counterparty~~specified $170 million limit will depend on a variety of circumstances, including equity market conditions, trading volume in our common stock and ~~received~~other factors outside our control. We cannot predict the timing of any such sales or the aggregate amount of shares that may be sold under the ATM program. In addition, the ATM program allows us, at our option, to sell shares pursuant to FSAs with affiliates of our sales agents (forward counterparties) under the related ATM program sales agreements. Shares sold pursuant to FSAs settle on dates specified by us, which may be substantially after the sales occur but not later than October 31, 2016, subject to certain exceptions. As of October 31, 2015, all FSAs have been settled in shares, and we intend to settle any future FSAs in shares. Under the terms of the Merger Agreement, we would need to obtain Duke Energy's prior consent to cash or net ~~proceeds of $47.3 million based on~~settle a FSA.

The table below presents equity transactions under the ~~net settlement price of $30.88 per share,~~open registration statements over the ~~original offering price, less certain adjustments.~~

three-year period ended October 31, 2015.



					Per share
Equity Issuance Transaction	Number of Shares	Settled	Net Proceeds Before Issuance Costs ⁽¹⁾ (In thousands)		Public Offering Price		Net Settlement Price			Underwriting Discount
Underwriting agreement, January 2013:
Issued	3,000,000	February 2013	$	92,640	$	32.00	$	30.88		$	1.12
FSAs physically settled in shares	1,600,000	December 2013	47,302				30.88
	4,600,000		$	139,942

ATM program, physically settled in shares:
FSA - executed March 2015	612,000	October 2015	$	21,729			35.50		⁽²⁾
FSA - executed June 2015	795,529	October 2015	28,230				35.49		⁽²⁾
FSA - executed September 2015	114,500	October 2015	4,125				36.03		⁽²⁾
Total ATM program	1,522,029		$	54,084
⁽¹⁾ Issuance costs incurred as follows: February 2013 shares - $370, December 2013 shares - $12, and October 2015 shares - $377.
⁽²⁾ Net of 1.5% commission plus other adjustments.

We used the net proceeds from the ~~January 2013 sale of our common stock~~equity transactions presented above to finance capital expenditures, repay outstanding ~~unsecured~~ notes under the unsecured CP program and for general corporate purposes. ~~We used~~As of October 31, 2015, we have approximately $114.1 million remaining under the ~~proceeds from the FSAs to finance capital expenditures, repay outstanding unsecured notes under our CP program and for general corporate purposes.~~ATM program. For further information on our common stock and for more details on these equity issuance transactions, see Note 67 to the consolidated financial statements in this Form 10-K.

As of October 31, 2015, we have $544.1 million remaining under the shelf registration statement for debt and equity issuances as approved by the NCUC. We plan to issue equity capital in our fiscal year 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 continue to issue common stock under our ATM program as described above through the end of fiscal 2016.

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. ~~In August 2013, we issued unsecured senior notes in~~The table below presents the amount of $300 million with an interest rate of 4.65% under our open debt and equity shelf registration statement. These notes will mature on August 1, 2043. The net proceeds of $297.2 million were used to finance capital expenditures, to repay the balance of $100 millionactivity of our ~~5% medium-term notes due December 19, 2013 at maturity, to repay outstanding short-term, unsecured notes under our CP program and for general corporate purposes.~~long-term debt during the three-year period ended October 31, 2015. For further information on our long-term debt instruments, see Note 45 to the consolidated financial statements in this Form 10-K.

In March 2012, we entered into an agreement to issue $300 million of notes in a private placement with a blended interest rate of 3.54%. In July 2012, we issued $100 million with an interest rate of 3.47%. In October 2012, we issued $200 million with an interest rate of 3.57%. Both issuances will mature in July 2027. These proceeds were used for general corporate purposes, including the repayment of short-term debt incurred in part for the funding of capital expenditures.



In millions	Issued (Redeemed)			Date Issued/Redeemed	Cash Impact
Senior Notes:
4.65%, due August 1, 2043 ⁽¹⁾	$	300		August 2013	$	299.9		⁽³⁾
4.10%, due September 18, 2034 ⁽²⁾	250			September 2014	249.6			⁽³⁾
3.60%, due August 15, 2025⁽²⁾	150			September 2015	149.9			⁽³⁾
Medium-Term Notes:
5.00%, due December 19, 2013	(100		)	December 2013	(100.0		)

⁽¹⁾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.
⁽²⁾ The net proceeds were used to finance capital expenditures, to repay outstanding short-term unsecured notes under our CP program and for general corporate purposes.
⁽³⁾ Net of debt discount.

From time to time, we have repurchased shares of common stock under our Common Stock Open Market Purchase Program as described in Note 67 to the consolidated financial statements in this Form 10-K. ~~During 2013, we~~We did not repurchase any ofor our common ~~stock. Under~~stock under our Common Stock Open Market Purchase Program during ~~2012 and 2011,~~the three-year period ended October 31, 2015, nor do we ~~repurchased and retired .8 million shares in each year for $26.5 million and $23 million, respectively. We do not~~ anticipate repurchasing our common stock in ~~our~~ fiscal year ~~2014.~~

2016. During ~~2013,~~the effectiveness of the Merger Agreement, we are prohibited from repurchasing our common stock.

During 2015, we issued ~~$24.6~~$27 million of common stock through DRIP and ESPP. During ~~2012~~2014 and ~~2011,~~2013, we issued ~~$22.1~~$25.6 million and ~~$20.2~~$24.6 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 ~~in 2013, 2012 and 2011.~~over the past three fiscal years. Dividends of $103.4 million, $99.2 million and $92.1 million ~~$85.7 million~~in 2015, 2014 and ~~$82.9 million for~~ 2013, ~~2012 and 2011,~~ respectively, were paid on common stock. Provisions contained in certain note agreements under which certain long-term debt was issued restrict the amount of cash dividends that may be paid. As of October 31, ~~2013,~~2015, our ~~retained earnings were~~ability to pay dividends was not ~~restricted.~~restricted by these note agreements. On December ~~12, 2013,~~11, 2015, the Board of Directors declared a quarterly dividend on common stock of ~~$.31~~$.33 per share, payable January 15, ~~2014~~2016 to shareholders of record at the close of business on December 24, ~~2013.~~2015. For further information on our long-term debt, see Note 45 to the consolidated financial statements in this Form 10-K.

Our ~~long-term debt~~ targeted capitalization ratio is 4550 – 60% in total debt and 40 – 50% in ~~long-term debt and 50 – 55% in~~ common equity. ~~As of October 31, 2013, our capitalization, excluding current maturities of long-term debt, if any, consisted of 50% in long-term debt and 50% in common equity.~~

The components of our total debt outstanding (short-term and ~~long-term)~~long-term, excluding unamortized discount and debt issuance costs) to our total capitalization as of October 31, ~~2013~~2015 and ~~2012~~2014 are summarized in the table below.

   October 31    October 31









In thousands
   2013    Percentage    2012    Percentage
Short-term debt
     $ 400,000    14 %         $ 365,000    16 %
Current portion of long-term debt
   100,000    3 %       -    - %
Long-term debt
   1,174,857    41 %       975,000    41 %








Total debt
   1,674,857    58 %       1,340,000    57 %
Common stockholders’ equity
   1,188,596    42 %       1,027,004    43 %









Total capitalization (including short-term debt)
     $   2,863,453    100 %         $   2,367,004    100 %



	October 31				October 31
In thousands	2015		Percentage		2014		Percentage
Short-term debt	$	340,000	10	%	$	355,000	12	%
Current portion of long-term debt	40,000		1	%	—		—	%
Long-term debt, principal	1,535,000		46	%	1,425,000		46	%
Total debt	1,915,000		57	%	1,780,000		58	%
Common stockholders’ equity	1,426,312		43	%	1,308,602		42	%
Total capitalization (including short-term debt)	$	3,341,312	100	%	$	3,088,602	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.

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, ~~2013.~~2015. 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, ~~2013,~~2015, all of our long-term debt was unsecured. Our long-term debt is rated ~~“A”~~ by two rating agencies, Standard & Poor’s Ratings Services (S&P) and ~~“A3” by~~ Moody’s Investors Service (Moody’s). Our current debt ratings are all considered investment grade and are as follows.



	S&P	Moody's
Unsecured long-term debt	A	A2
Commercial paper	A1	P1

Subsequent to the announcement of the Acquisition, S&P affirmed our A rating for our senior unsecured long-term debt but placed it on credit watch with negative implications. Currently, ~~with respect to~~Moody's has maintained its stable outlook for our long-term ~~debt, the credit agencies maintain their stable outlook. S&P and Moody’s have issued credit ratings on our CP program at “A1” and “P2”, respectively.~~debt. 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 ~~conservative~~constructive regulatory environments in which we operate, or 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 ~~our~~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, ~~2013,~~2015, 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 ~~4.6~~3.96 times as of October 31, ~~2013;~~2015;

Funded debt cannot exceed 70% of total capitalization. Funded debt was ~~59%~~57% of total capitalization as of October 31, ~~2013;~~2015;

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, ~~2013;~~2015;

Restrictions on permitted liens;

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

Restrictions on burdensome agreements.

The Acquisition would constitute a change in control under the note agreements under which our 2.02% Senior Notes due 2016, 4.24% Senior Notes due 2021, 3.47% Senior Notes due 2027 and 3.57% Senior Notes due 2027 were issued. While the Acquisition would not constitute an event of default, upon the closing of the Acquisition, we would be required to offer to prepay these notes to the noteholders at 100% of the principal amounts plus accrued interest.

Contractual Obligations and Commitments

We have incurred various contractual obligations and commitments in the normal course of business. As of October 31, ~~2013,~~2015, our estimated recorded and unrecorded contractual obligations are as follows.

   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)
     $ 100,000      $ 75,000      $ -         $ 1,100,000      $ 1,275,000
Short-term debt (2)
   400,000    -       -       -       400,000










Total recorded contractual obligations
   500,000    75,000    -       1,100,000    1,675,000










Unrecorded contractual obligations and commitments: (3)
Pipeline and storage capacity (4)
   170,430    453,445    276,550    647,982    1,548,407
Gas supply (5)
   6,356    -       -       -       6,356
Interest on long-term debt (6)
   62,191    178,387    111,311    648,294    1,000,183
Capital contributions to joint ventures (7)
   55,000    92,052    -       -       147,052
Telecommunications and information technology (8)
   11,045    5,436    -       -       16,481
Qualified and nonqualified pension plan funding (9)
   21,330    35,097    12,028    -       68,455
Postretirement benefits plan funding (9)
   1,500    4,000    1,300    -       6,800
Operating leases (10)
   4,543    13,380    8,362    27,359    53,644
Other purchase obligations (11)
   24,951    -       -       -       24,951
Letters of credit (12)
   2,078    -       -       -       2,078










Total unrecorded contractual obligations and commitments
   359,424    781,797    409,551    1,323,635    2,874,407










Total contractual obligations and commitments
     $       859,424      $       856,797      $       409,551      $   2,423,635      $   4,549,407

We have conditional asset retirement obligations for underground mains and services of $19.7 million that are not included in the table because we cannot reasonably estimate payments by periods.



	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⁾	$	40,000	$	35,000	$	160,000	$	1,340,000	$	1,575,000
Short-term debt ⁽²⁾	340,000		—		—		—		340,000
Total recorded contractual obligations	380,000		35,000		160,000		1,340,000		1,915,000

Unrecorded contractual obligations and
commitments: ⁽³⁾

Pipeline and storage capacity ⁽⁴⁾	178,594		439,793		228,134		402,599		1,249,120
Gas supply reservation fees ⁽⁵⁾	4,577		165		—		—		4,742
Gas supply purchase commitments ⁽⁶⁾	65,286		228,922		139,328		638,129		1,071,665
Interest on long-term debt ⁽⁷⁾	75,323		216,936		142,705		692,155		1,127,119
Capital contributions to joint ventures ⁽⁸⁾	115,835		234,269		1,172		—		351,276
Telecommunications and information
technology ⁽⁹⁾	6,164		2,918		—		—		9,082
Qualified and nonqualified pension plan
funding ⁽¹⁰⁾	12,170		37,946		13,141		—		63,257
Postretirement benefits plan funding ⁽¹⁰⁾	1,300		3,600		1,200		—		6,100
Operating leases ⁽¹¹⁾	5,052		13,748		9,060		19,830		47,690
Other purchase obligations ⁽¹²⁾	45,577		—		—		—		45,577
Surety bonds ⁽¹¹⁾	5,465		1,170		—		—		6,635
Letters of credit ⁽²⁾	1,641		—		—		—		1,641
Total unrecorded contractual obligations
and commitments	516,984		1,179,467		534,740		1,752,713		3,983,904
Total contractual obligations and
commitments	$	896,984	$	1,214,467	$	694,740	$	3,092,713	$	5,898,904


⁽¹⁾	See Note 5 to the consolidated financial statements in this Form 10-K.


⁽²⁾	See Note 46 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⁾	Base load gas supply commitments at market index pricing. For purposes of this table, payments above are calculated at the December 2015 price levels.


⁽⁷⁾	Includes accrued interest of $29.5 million as of October 31, 2015.


⁽⁸⁾	See Note 413 to the consolidated financial statements in this Form 10-K.

~~(7)~~

~~See Note 12 to the consolidated financial statements in this Form 10-K.~~

~~(8)~~

⁽⁹⁾

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)~~
⁽¹⁰⁾	Estimated funding beyond five years is not available. See Note 910 to the consolidated financial statements in this Form 10-K.

~~(10)~~
⁽¹¹⁾	See Note 89 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)~~
⁽¹²⁾	Consists primarily of pipeline products, vehicles, contractors and merchandise.

~~(12)~~

~~See Note 5 to the consolidated financial statements in this Form 10-K.~~

Off-balance Sheet Arrangements

~~We have no off-balance sheet arrangements other than~~

From time to time, we enter into letters of credit, surety bonds and operating ~~leases.~~leases, as well as credit support arrangements on behalf of a wholly-owned subsidiary that holds one of our equity-method investments. None of these existing arrangements are material to our results of operations, cash flows or financial position. The letters of credit ~~and operating leases~~ are discussed in

Note ~~5 and Note 8, respectively,~~6 to the consolidated financial statements in this Form ~~10-K~~10-K. The surety bonds and operating leases are ~~reflected~~discussed in Note 9 to the ~~table above.~~

consolidated financial statements in this Form 10-K. The credit support arrangement and indemnification agreement are discussed in Note 13 to the consolidated financial statements in this Form 10-K.

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 ~~WNA~~ 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 $33.8 million and $41.8 million in 2015 and 2014, respectively, and lower by $9 million 2013.

In 2014, the IMR 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 as initially approved, we file annually 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 $17.1 million for the period November 1, 2014 through October 31, 2015 and by ~~$60.1~~$.6 million for the period February 1, 2014 through October 31, 2014, respectively. Without the IMR in ~~2013~~Tennessee, our operating revenues and ~~2012,~~margin would have been lower by $18.2 million for the period November 1, 2014 through October 31, 2015 and by $10.1 million for the period January 1, 2014 through October 31, 2014, respectively.

The North Carolina IMR was revised in November 2015. As revised, filings are to be made semi-annually each October 31 and April 30 for certain costs closed to plant through September and March, respectively, with revised rates to be effective the following December 1 and ~~higher by $11.9 million in 2011.~~

June 1, respectively.

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 ~~in the~~as an adjustment to net income ~~statement~~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.

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 ~~deregulation legislation.~~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, ~~2013~~2015 and ~~2012~~2014 totaled ~~$246.3~~$207.7 million and ~~$293.1~~$202.1 million, respectively. Regulatory liabilities as of October 31, ~~2013~~2015 and ~~2012~~2014 totaled ~~$541.9~~$603.7 million and ~~$489.7~~$604.8 million, respectively. The detail of these regulatory assets and liabilities is presented in ~~“Rate-Regulated Basis of Accounting” in~~ Note 13 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 910 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 September 2015, we announced the replacement of the existing retiree medical and dental group coverage for eligible retirees with a tax-free Health Reimbursement Arrangement (HRA), effective January 1, 2016. Under the HRA, the retiree will receive a fixed subsidy that is assumed to not increase; therefore, our 2015 accumulated postretirement benefit obligation is not impacted by projected health care cost trend rates. For further information on this change in coverage, see Note 10 to the consolidated financial statements in this Form 10-K.

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~~The weighted average discount ~~rate~~rates used in the measurement of ~~the~~our plans' benefit obligation for the qualified pension plan changed from 3.51% in 2012 to 4.55% in 2013. For the nonqualified pension plans, the weighted average discount rate used in the measurement of the benefit obligation changed from 2.95% in 2012 to 3.98% in 2013. Similarly, the weighted average discount rate for postretirement benefits changed from 3.34% in 2012 to 4.44% in 2013.obligations are presented below. The higher discount rates ~~discussed above~~in 2015 reflect the higher yields found in the AA corporate bond market where the bond price has decreased together with the use of an above-mean yield curve. 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 7.5% in 2013 declining gradually to 5% by 2027.

decreased.



	2015		2014
Qualified pension plan	4.34	%	4.13	%
Nonqualified pension plans	3.85	%	3.69	%
Postretirement benefits	4.38	%	4.03	%

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 ~~50%~~55% equity securities and ~~50%~~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 ~~2011, 2012~~2013, decreasing to 7.75% in 2014, and ~~2013.~~further decreasing to 7.5% in 2015. Based on a fairly constant inflation trend, our age-related assumed rate of increase in future compensation levels was ~~3.78%~~3.76% in ~~2011,~~2013, decreasing to ~~3.76%~~3.72% in ~~2012~~2014, and ~~2013~~further decreasing to 3.68% in 2015 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.

During ~~2013,~~2015, we recorded costs of ~~$11.3~~$7.1 million related to our qualified pension plan and postretirement benefits plan. We estimate ~~2014~~2016 expenses for these two plans to be in the range of $6$3.5 to $7$4 million representing a decrease of ~~$4.3~~$3.1 to ~~$5.3~~$3.6 million from ~~2013.~~2015. These estimates reflect the higher discount rates and ~~assumed~~a 7.25% expected long-term rate of return on ~~the~~ plan ~~assets discussed above for each 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.

Actuarial Assumption
   Change in
Assumption Impact on 2013
Benefit Cost    Impact on Projected
Benefit Obligation

Increase (Decrease)
In thousands

Discount rate
   (.25 )% $ 629          $ 6,544
Rate of return on plan assets
   (.25 )% 660          N/A
Rate of increase in compensation
   .25 % 719             3,762



	Change in		Impact on 2015		Impact on Projected
Actuarial Assumption	Assumption		Benefit Cost		Benefit Obligation
			Increase (Decrease) In thousands
Discount rate	(0.25)%	$	674	$	7,472
Rate of return on plan assets	(0.25)%		787		N/A
Rate of increase in compensation	0.25%		791		3,740

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 2013    Impact on Accumulated
   Change in Postretirement    Postretirement Benefit
Actuarial Assumption    Assumption Benefit Cost    Obligation
   Increase (Decrease)

In thousands

Discount rate
   (.25 )% $ -          $ 840
Rate of return on plan assets
   (.25 )% 57          N/A
Health care cost trend rate
   .25 % 3          171



			Impact on 2015		Impact on Accumulated
	Change in		Postretirement		Postretirement Benefit
Actuarial Assumption	Assumption		Benefit Cost		Obligation
			Increase (Decrease)
			In thousands
Discount rate	(0.25)%	$	122	$	1,128
Rate of return on plan assets	(0.25)%		67		N/A
Health care cost trend rate	0.25%		34		N/A

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.

Beginning in 2016, we will change the method we use to estimate the service and interest cost components of net periodic benefit costs for our plans from using a developed zero-coupon spot rate yield curve as discussed above. We have elected to use a full yield curve approach in the estimation of these components of benefit costs by applying the specific spot rates along the yield curve used in the determination of the benefit obligations to the relevant projected cash flows. We will make this change to improve the correlation between projected benefit cash flows and the corresponding yield curve spot rates and to provide a more precise measurement of service and interest costs. This change will not affect the measurement of our total benefit obligations as the change in the service and interest costs is completely offset by the actuarial (gain) loss reported. We will account for this change as a change in estimate and, accordingly, will account for it prospectively beginning in 2016.

The expected impact in 2016 of the change in accounting estimate discussed above is presented below and is reflected in the 2016 estimated expense discussed above.



	Qualified			Nonqualified			Other
	Pension			Pension			Benefits
Discount rates used to measure benefit costs in 2016:
Service cost	4.46		%	N/A			4.67		%
Interest cost	3.25		%	2.98		%	3.51		%
Discount rate that would have been used to measure service and interest costs under prior actuarial methodology	4.34		%	3.85		%	4.38		%

Reduction in components of expected 2016 benefit costs using specific spot rates:	Impact in thousands
Service cost	$	153		N/A			$	11
Interest cost	3,280			$	45		320

The health care cost trend rate used in the prior actuarial calculations is not applicable under the 2016 methodology to measure either the benefit cost or the obligation for postretirement benefits. This is due to the new plan design where Piedmont's HRA contribution will be fixed as discussed above.

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~~late 2012, we ~~continued to diversify~~entered into long-term contracts that would provide diversification in 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~~The long-term contract with Cabot Oil & Gas (Cabot) to purchase firm, price-competitive Marcellus gas ~~supplies. We also signed a~~supplies and the 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~~markets began partial service in December ~~2012, we also signed a~~2015. Our long-term firm capacity contract with Williams – Transco under its Virginia Southside expansion ~~project that will also allow~~allowing us to further diversify our supply portfolio with Marcellus based natural ~~gas. These~~gas began service in September 2015. Also, in October 2014, we contracted for long-term pipeline capacity from diverse gas supply 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 ~~supply arrangements are scheduled to begin in late 2015, and we believe they~~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 ~~particularly to provide natural gas delivery service to power generation facilities located in North Carolina~~ as discussed in the preceding section of “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.~~10-K. For further information on our equity ~~venture with Cardinal that expanded~~ventures, particularly ACP's future service to our ~~firm capacity requirement in 2012 in order to serve a power generation facility in Wayne County, North Carolina,~~expanding markets, see Note 1213 to the consolidated financial statements in this Form 10-K.

~~Secondary~~

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 normally contribute smaller per-unit margins to earnings; however, the ~~program allows~~programs allow us to act as a wholesale marketer of natural gas and transportation capacity when market conditions permit and when the ~~capacity~~supply and ~~supply~~capacity are not required to serve our retail distribution system. For further information on secondary market transactions, see Note 23 to the consolidated financial statements in this Form 10-K.

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 23 to the consolidated financial statements in this Form 10-K.

Equity Method Investments

For information about our equity method investments, see Note 1213 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~~Manufactured Gas Plant 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 89 to the consolidated financial statements in this Form 10-K.

Accounting Guidance

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

~~Financial Accounting Standards Board and International Accounting Standards Board~~

With a goal to improve the U.S. financial accounting standards for the benefit of investors and other users of financial statements, the Financial Accounting Standards Board (FASB) has pursued convergence of select accounting standards with the International Accounting Standards Board (IASB) for the past ten years. The path toward convergence has been a collaborative effort by the FASB and the IASB to improve both U.S. GAAP and International Financial Reporting Standards and to eliminate or minimize the differences between them.

Over the next year and a half, the FASB plans to complete the open major convergence projects. By the first quarter of 2014, the final standard on revenue recognition should be released. In the first half of 2014, the FASB intends to issue final standards on the two financial instruments projects of classification and measurement as well as impairment. A final standard on leasing may be completed in 2014 followed by an insurance standard.

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 ~~also an~~our Enterprise Risk Management (ERM) program, ~~and with the direction of the~~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.

In fiscal 2014, 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 over which they have oversight responsibility. The Board of Directors approved risk tolerances for several major areas of risk exposure, namely strategic, commercial, market, financial, operational, regulatory and reputational risks, and receives 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.

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, ~~2013,~~2015, 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, ~~2013,~~2015, we had ~~$400~~$340 million of short-term debt outstanding as commercial paper at an interest rate of ~~.36%~~.22%. 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$3.6 million during ~~2013.~~

2015.

As of October 31, ~~2013,~~2015, information about our long-term debt is presented below.

   Fair Value as
   Expected Maturity Date of October 31,
In millions      2014     2015     2016     2017     2018     Thereafter     Total     2013
Fixed Rate Long-term Debt
   $         100 $         -    $ 40 $ 35 $         -    $         1,100 $         1,275 $         1,409.9
Average Interest Rate
   5 % - %         2.92 %         8.51 % - % 5.06 % 5.08 %



																						Fair Value as
	Expected Maturity Date																					of October 31,
In millions	2016			2017			2018			2019			2020			Thereafter			Total			2015
Fixed Rate Long-term Debt	$	40		$	35		$	—		$	—		$	—		$	1,500		$	1,575		$	1,720.6
Average Interest Rate	2.92		%	8.51		%	—		%	—		%	—		%	4.75		%	4.79		%

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 13 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 ~~and have used over-the-counter 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~~substantially all 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.

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.

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, ~~2013~~2015 and ~~2012,~~2014, 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, ~~2013.~~2015. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on ~~these~~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, ~~2013~~2015 and ~~2012,~~2014, and the results of their operations and their cash flows for each of the three years in the period ended October 31, ~~2013,~~2015, 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, ~~2013,~~2015, based on the criteria established inInternal Control—Integrated Framework ~~(1992)~~(2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated December 23, ~~2013~~2015 expressed an unqualified opinion on the Company’s internal control over financial reporting.

/s/ Deloitte & Touche LLP

Charlotte, North Carolina

December 23, ~~2013~~

2015

Consolidated Balance Sheets

October 31, ~~2013~~2015 and ~~2012~~

2014

ASSETS

In thousands    2013    2012
Utility Plant:

  Utility plant in service
   $ 4,421,937    $ 3,746,178
    Less accumulated depreciation
   1,088,331    1,036,814




      Utility plant in service, net
   3,333,606    2,709,364
  Construction work in progress
   297,717    388,979
  Plant held for future use
   3,155    6,743




      Total utility plant, net
       3,634,478        3,105,086




Other Physical Property, at cost (net of accumulated
  depreciation of $876 in 2013 and $843 in 2012)    382    415




Current Assets:

  Cash and cash equivalents    8,063    1,959
  Trade accounts receivable (less allowance for doubtful
    accounts of $1,604 in 2013 and $1,579 in 2012)
   79,210    56,700
  Income taxes receivable    31,065    31,606
  Other receivables    1,988    2,104
  Unbilled utility revenues    24,967    24,012
  Inventories:
    Gas in storage    73,929    72,661
    Materials, supplies and merchandise    1,725    934
  Gas purchase derivative assets, at fair value    1,834    3,153
  Regulatory assets    77,204    81,626
  Prepayments    35,038    30,600
  Deferred income taxes    12,695    -
  Other current assets    338    287




    Total current assets
   348,056    305,642




Noncurrent Assets:

  Equity method investments in non-utility activities
   128,469    87,867
  Goodwill
   48,852    48,852
  Regulatory assets
   169,102    211,478
  Marketable securities, at fair value
   2,995    2,131
  Overfunded postretirement asset
   28,258    -
  Other noncurrent assets
   8,017    8,468




      Total noncurrent assets
   385,693    358,796




      Total
   $ 4,368,609    $ 3,769,939

~~See notes to consolidated financial statements.~~



In thousands	2015		2014
Utility Plant:
Utility plant in service	$	5,426,584	$	5,011,497
Less accumulated depreciation	1,251,940		1,166,922
Utility plant in service, net	4,174,644		3,844,575
Construction work in progress	170,250		141,693
Plant held for future use	3,155		3,155
Total utility plant, net	4,348,049		3,989,423
Other Physical Property, at cost (net of accumulated depreciation of $926 in 2015 and $904 in 2014)	332		355
Current Assets:
Cash and cash equivalents	13,744		9,643
Trade accounts receivable ⁽¹⁾ (less allowance for doubtful accounts of $1,648 in 2015 and $2,152 in 2014)	59,248		65,260
Income taxes receivable	11,447		36,100
Other receivables	10,667		3,361
Unbilled utility revenues	17,422		21,093
Inventories:
Gas in storage	68,240		84,081
Materials, supplies and merchandise	1,251		1,652
Gas purchase derivative assets, at fair value	1,343		4,898
Regulatory assets	10,936		27,837
Prepayments	28,903		39,030
Deferred income taxes	32,392		53,418
Other current assets	344		326
Total current assets	255,937		346,699
Noncurrent Assets:
Equity method investments in non-utility activities	206,956		170,171
Goodwill	48,852		48,852
Regulatory assets	196,726		174,281
Income taxes receivable	26,023		—
Marketable securities, at fair value	4,666		3,727
Overfunded postretirement asset	17,770		33,757
Other noncurrent assets	5,439		7,042
Total noncurrent assets	506,432		437,830
Total	$	5,110,750	$	4,774,307

⁽¹⁾ See Note 13 for amounts attributable to affiliates.

See notes to consolidated financial statements.

Consolidated Balance Sheets

October 31, ~~2013~~2015 and ~~2012~~

2014

CAPITALIZATION AND LIABILITIES

In thousands    2013    2012
Capitalization:

  Stockholders’ equity:
    Cumulative preferred stock - no par value - 175 shares authorized    $ -    $ -
    Common stock - no par value - shares authorized: 200,000;
      shares outstanding: 76,099 in 2013 and 72,250 in 2012    561,644    442,461
    Retained earnings    627,236    584,848
    Accumulated other comprehensive loss    (284)       (305)




      Total stockholders’ equity    1,188,596    1,027,004
  Long-term debt    1,174,857    975,000




      Total capitalization    2,363,453    2,002,004




Current Liabilities:
  Current maturities of long-term debt    100,000    -
  Short-term debt    400,000    365,000
  Trade accounts payable    96,281    94,269
  Other accounts payable    43,855    47,699
  Accrued interest    28,205    21,450
  Customers’ deposits    19,831    21,739
  Current deferred taxes    -    13,542
  General taxes accrued    21,454    21,504
  Regulatory liabilities    -    28
  Other current liabilities    7,024    7,320




      Total current liabilities    716,650    592,551




Noncurrent Liabilities:
  Deferred income taxes    681,369    597,211
  Unamortized federal investment tax credits    1,402    1,669
  Accumulated provision for postretirement benefits    12,042    37,299
  Regulatory liabilities    �� 541,897    489,664
  Conditional cost of removal obligations    27,016    28,629
  Other noncurrent liabilities    24,780    20,912




      Total noncurrent liabilities    1,288,506    1,175,384




Commitments and Contingencies (Note 8)





      Total    $     4,368,609    $     3,769,939

~~See notes to consolidated financial statements.~~

~~Page Intentionally Blank~~



In thousands	2015			2014
Capitalization:
Stockholders’ equity:
Cumulative preferred stock - no par value - 175 shares authorized	$	—		$	—
Common stock – no par value – shares authorized: 200,000; shares outstanding: 80,883 in 2015 and 78,531 in 2014	721,419			636,835
Retained earnings	705,748			672,004
Accumulated other comprehensive loss	(855		)	(237		)
Total stockholders’ equity	1,426,312			1,308,602
Long-term debt, net	1,523,677			1,414,484
Total capitalization	2,949,989			2,723,086
Current Liabilities:
Current maturities of long-term debt	40,000			—
Short-term debt	340,000			355,000
Trade accounts payable ⁽¹⁾	99,895			85,299
Other accounts payable	52,149			54,349
Accrued interest	29,488			27,982
Customers’ deposits	20,896			19,994
General taxes accrued	27,940			23,828
Regulatory liabilities	13,367			46,231
Other current liabilities	11,861			9,303
Total current liabilities	635,596			621,986
Noncurrent Liabilities:
Deferred income taxes	861,615			809,467
Unamortized federal investment tax credits	1,027			1,193
Accumulated provision for postretirement benefits	14,975			15,471
Regulatory liabilities	590,301			558,598
Conditional cost of removal obligations	19,712			14,647
Other noncurrent liabilities	37,535			29,859
Total noncurrent liabilities	1,525,165			1,429,235
Commitments and Contingencies (Note 9)
Total	$	5,110,750		$	4,774,307

⁽¹⁾ See Note 13 for amounts attributable to affiliates.

See notes to consolidated financial statements.

Consolidated Statements of Comprehensive Income

For the Years Ended October 31, ~~2013, 2012~~2015, 2014 and ~~2011~~

      2013    2012    2011
In thousands except per share amounts
Operating Revenues    $     1,278,229    $     1,122,780    $     1,433,905
Cost of Gas    656,739    547,334    860,266






Margin    621,490    575,446    573,639






Operating Expenses:
  Operations and maintenance    253,120    242,599    225,351
  Depreciation    112,207    103,192    102,829
  General taxes    34,635    34,831    38,380
  Utility income taxes    77,334    69,101    64,068






    Total operating expenses    477,296    449,723    430,628






Operating Income    144,194    125,723    143,011






Other Income (Expense):
  Income from equity method investments    26,056    23,904    24,027
  Non-operating income    2,839    1,288    1,762
  Non-operating expense    (5,122)       (1,855)       (3,022)
  Income taxes    (8,612)       (9,116)       (8,218)






    Total other income (expense)    15,161    14,221    14,549






Utility Interest Charges:
  Interest on long-term debt    54,158    41,412    46,070
  Allowance for borrowed funds used during construction    (30,975)       (25,211)       (8,619)
  Other    1,755    3,896    6,541






    Total utility interest charges    24,938    20,097    43,992






Net Income    134,417    119,847    113,568






Other Comprehensive Income (Loss), net of tax:
  Unrealized loss from hedging activities of equity method
    investments, net of tax of ($69), ($530) and ($371) for the years
    ended October 31, 2013, 2012 and 2011, respectively.    (109)       (826)       (576)
  Reclassification adjustment of realized gain from hedging activities
    of equity method investments included in net income, net of tax of
    $85, $621 and $420 for the years ended October 31, 2013, 2012
    and 2011, respectively.
   130    973    654






    Total other comprehensive income    21    147    78






Comprehensive Income    $ 134,438    $ 119,994    $ 113,646






Average Shares of Common Stock:
  Basic    74,884    71,977    72,056
  Diluted    75,333    72,278    72,266
Earnings Per Share of Common Stock:
  Basic    $ 1.80    $ 1.67    $ 1.58
  Diluted    $ 1.78    $ 1.66    $ 1.57

~~See notes to consolidated financial statements.~~

2013



In thousands, except per share amounts	2015			2014			2013
Operating Revenues ⁽¹⁾	$	1,371,718		$	1,469,988		$	1,278,229
Cost of Gas ⁽¹⁾	644,424			779,780			656,739
Margin	727,294			690,208			621,490
Operating Expenses:
Operations and maintenance	294,517			270,877			253,120
Depreciation	128,704			118,996			112,207
General taxes	42,110			37,294			34,635
Utility income taxes	76,934			83,176			77,334
Total operating expenses	542,265			510,343			477,296
Operating Income	185,029			179,865			144,194
Other Income (Expense):
Income from equity method investments	34,461			32,753			26,056
Non-operating income	3,164			1,842			2,839
Non-operating expense	(3,724		)	(4,331		)	(5,122		)
Income taxes	(13,288		)	(11,642		)	(8,612		)
Total other income (expense)	20,613			18,622			15,161
Utility Interest Charges:
Interest on long-term debt	70,619			61,562			54,158
Allowance for borrowed funds used during construction	(11,106		)	(16,427		)	(30,975		)
Other	9,118			9,551			1,755
Total utility interest charges	68,631			54,686			24,938
Net Income	137,011			143,801			134,417
Other Comprehensive Income (Loss), net of tax:
Unrealized gain (loss) from hedging activities of equity method investments, net of tax of ($1,028), $225 and ($69) for the years ended October 31, 2015, 2014 and 2013, respectively	(1,601		)	355			(109		)
Reclassification adjustment of realized (gain) loss from hedging activities of equity method investments included in net income, net of tax of $652, ($177) and $85 for the years ended October 31, 2015, 2014 and 2013, respectively	1,018			(284		)	130
Net current period benefit activities of equity method investments, net of tax of ($23) and ($16) for the years ended October 31, 2015 and 2014, respectively	(35		)	(24		)
Total other comprehensive income (loss)	(618		)	47			21
Comprehensive Income	$	136,393		$	143,848		$	134,438

Average Shares of Common Stock:
Basic	78,942			77,883			74,884
Diluted	79,231			78,193			75,333

Earnings Per Share of Common Stock:
Basic	$	1.74		$	1.85		$	1.80
Diluted	$	1.73		$	1.84		$	1.78

⁽¹⁾ See Note 13 for amounts attributable to affiliates.

See notes to consolidated financial statements.

Consolidated Statements of Cash Flows

For the Years Ended October 31, ~~2013, 2012~~2015, 2014 and ~~2011~~

In thousands    2013    2012    2011
Cash Flows from Operating Activities:
  Net income    $       134,417    $       119,847    $       113,568
  Adjustments to reconcile net income to net
    cash provided by operating activities:
      Depreciation and amortization    120,797    109,230    107,046
  Allowance for doubtful accounts
   25    232    418
  Net gain on sale of property
   (349)       -    -
  Income from equity method investments
   (26,056)       (23,904)       (24,027)
  Distributions of earnings from equity method investments
   22,139    19,590    22,685
  Deferred income taxes, net
   57,637    99,159    76,821
  Changes in assets and liabilities:

    Gas purchase derivatives, at fair value
   1,319    (381)       47
    Receivables
   (23,327)       5,403    (3,019)
    Inventories
   (2,059)       18,897    13,789
    Settlement of legal asset retirement obligations
   (2,389)       (2,038)       (1,493)
    Overfunded postretirement asset
   (28,258)       22,879    (5,537)
    Other assets
   47,967    (95,582)       8,360
    Accounts payable
   2,381    4,283    (4,085)
    Provision for postretirement benefits
   (25,257)       22,628    (134)
    Other liabilities
   34,260    4,272    6,806






Net cash provided by operating activities    313,247    304,515    311,245






Cash Flows from Investing Activities:
  Utility capital expenditures    (599,999)       (529,576)       (243,641)
  Allowance for borrowed funds used during construction    (30,975)       (25,211)       (8,619)
  Contributions to equity method investments    (41,348)       (3,566)       (6,222)
  Distributions of capital from equity method investments    4,700    5,372    3,029
  Proceeds from sale of property    1,951    1,250    1,074
  Investments in marketable securities    (414)       (606)       (486)
  Other    2,609    3,044    2,292






Net cash used in investing activities    (663,476)       (549,293)       (252,573)

2013



In thousands	2015			2014			2013
Cash Flows from Operating Activities:
Net income	$	137,011		$	143,801		$	134,417
Adjustments to reconcile net income to net cash provided by
operating activities:
Depreciation and amortization	140,217			129,343			120,797
Provision for doubtful accounts	5,095			6,959			5,314
Impairment loss on investment	—			2,000			—
Net gain on sale of property	—			(817		)	(349		)
Income from equity method investments	(34,461		)	(32,753		)	(26,056		)
Distributions of earnings from equity method investments	24,875			24,843			22,139
Deferred income taxes, net	73,407			87,136			57,637
Changes in assets and liabilities:
Gas purchase derivatives, at fair value	3,555			(3,064		)	1,319
Receivables, net	(2,637		)	9,785			(28,616		)
Inventories	16,242			(10,079		)	(2,059		)
Settlement of legal asset retirement obligations	(5,563		)	(3,575		)	(2,389		)
Regulatory assets	(14,917		)	20,297			43,338
Other assets	16,220			(2,829		)	4,629
Accounts payable	(7,626		)	18			2,381
Contributions to benefit plans	(12,728		)	(22,516		)	(22,415		)
Accrued/deferred postretirement benefit costs	28,219			20,446			(31,100		)
Regulatory liabilities	(16,065		)	49,468			23,429
Other liabilities	20,791			12,149			10,831
Net cash provided by operating activities	371,635			430,612			313,247

Cash Flows from Investing Activities:
Utility capital expenditures	(443,654		)	(460,444		)	(599,999		)
Allowance for borrowed funds used during construction	(11,106		)	(16,427		)	(30,975		)
Contributions to equity method investments	(29,723		)	(37,642		)	(41,348		)
Distributions of capital from equity method investments	1,505			3,929			4,700
Proceeds from sale of property	717			1,883			1,951
Investments in marketable securities	(866		)	(454		)	(414		)
Other	4,707			4,708			2,609
Net cash used in investing activities	(478,420		)	(504,447		)	(663,476		)

Consolidated Statements of Cash Flows

For the Years Ended October 31, ~~2013, 2012~~2015, 2014 and ~~2011~~

In thousands    2013    2012    2011
Cash Flows from Financing Activities:
  Borrowings under credit facility    10,000               350,000            1,723,000
  Repayments under credit facility    (10,000)       (681,000)       (1,634,000)
  Net borrowings - commercial paper    35,000    365,000    -
  Proceeds from issuance of long-term debt, net of discount    299,856    300,000    200,000
  Retirement of long-term debt    -    -    (256,922)
  Expenses related to issuance of debt    (3,250)       (3,908)       (3,902)
  Proceeds from issuance of common stock, net of expenses    92,271    -    -
  Issuance of common stock through dividend reinvestment and employee stock plans
   24,610    22,123    20,233
  Repurchases of common stock    -    (26,528)       (23,004)
  Dividends paid    (92,146)       (85,693)       (82,913)
  Other    (8)       (34)       (6)






Net cash provided by (used in) financing activities    356,333    239,960    (57,514)






Net Increase (Decrease) in Cash and Cash Equivalents    6,104    (4,818)       1,158
Cash and Cash Equivalents at Beginning of Year    1,959    6,777    5,619






Cash and Cash Equivalents at End of Year        $ 8,063        $ 1,959        $ 6,777






Cash Paid During the Year for:
  Interest        $         50,275        $ 44,571        $ 50,136






  Income Taxes:
  Income taxes paid
       $ 5,760        $ 4,770        $ 5,649
  Income taxes refunded
   169    8,437    16,958






  Income taxes, net
       $ 5,591        $ (3,667)           $ (11,309)






Noncash Investing and Financing Activities:
  Accrued construction expenditures        $ 39,389        $ 43,643        $ 18,055

~~See notes to consolidated financial statements.~~

2013



In thousands	2015			2014			2013
Cash Flows from Financing Activities:
Borrowings under credit facility	$	—		$	—		$	10,000
Repayments under credit facility	—			—			(10,000		)
Net (repayments) borrowings - commercial paper	(15,000		)	(45,000		)	35,000
Proceeds from issuance of long-term debt, net of discount	149,902			249,565			299,856
Repayment of long-term debt	—			(100,000		)	—
Expenses related to issuance of debt	(1,330		)	(2,871		)	(3,250		)
Proceeds from issuance of common stock, net of expenses	53,707			47,290			92,271
Issuance of common stock through dividend reinvestment and employee stock plans	26,992			25,556			24,610
Dividends paid	(103,390		)	(99,151		)	(92,146		)
Other	5			26			(8		)
Net cash provided by financing activities	110,886			75,415			356,333
Net Increase in Cash and Cash Equivalents	4,101			1,580			6,104
Cash and Cash Equivalents at Beginning of Year	9,643			8,063			1,959
Cash and Cash Equivalents at End of Year	$	13,744		$	9,643		$	8,063

Cash Paid During the Year for:
Interest	$	71,519		$	64,276		$	50,275

Income Taxes:
Income taxes paid	$	3,680		$	10,840		$	5,760
Income taxes refunded	530			30			169
Income taxes, net	$	3,150		$	10,810		$	5,591

Noncash Investing and Financing Activities:
Accrued construction expenditures	$	58,868		$	38,869		$	39,389

See notes to consolidated financial statements.

Consolidated Statements of Stockholders’ Equity

For the Years Ended October 31, ~~2013, 2012~~2015, 2014 and ~~2011~~

In thousands except per share amounts    Common
Stock    Retained
Earnings
Accumulated
Other
Comprehensive
Income (Loss)
   Total
Balance, October 31, 2010
     $     445,640      $     519,831      $     (530)         $     964,941


Comprehensive Income:

  Net income
      113,568       113,568
  Other comprehensive income
         78    78


Total comprehensive income
            113,646
Common Stock Issued
   24,155          24,155
Common Stock Repurchased
   (23,004)             (23,004)
Costs of Rescission Offer
      (6)          (6)
Tax Benefit from Dividends Paid on ESOP Shares
      104       104
Dividends Declared ($1.15 per share)
      (82,913)          (82,913)








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

2013



In thousands, except per share amounts	Common Stock			Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total
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

Comprehensive Income:
Net income				137,011						137,011
Other comprehensive loss							(618		)	(618		)
Total comprehensive income										136,393
Common Stock Issued	84,966									84,966
Expenses from Issuance of Common Stock	(382		)							(382		)
Tax Benefit from Dividends Paid on ESOP Shares				123						123
Dividends Declared ($1.31 per share)				(103,390		)				(103,390		)
Balance, October 31, 2015	$	721,419		$	705,748		$	(855	)	$	1,426,312

See notes to consolidated financial statements.

The components of accumulated other comprehensive income (loss) (OCIL) as of October 31, ~~2013~~2015 and ~~2012~~2014 are as follows.

In thousands
2013 2012
Hedging activities of equity method investments
$ (284) $ (305)

~~See notes to consolidated financial statements.~~



In thousands	2015			2014
Hedging activities of equity method investments	$	(796	)	$	(213	)
Benefit activities of equity method investments	(59		)	(24		)

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 23 to the consolidated financial statements.

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). The consolidated financial statements reflect the accounts of Piedmont and its ~~wholly owned~~wholly-owned subsidiaries whose financial statements are prepared for the same reporting period as Piedmont using consistent accounting policies. 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.

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. ~~For further information on equity method investments, see Note 12 to the consolidated financial statements.~~ 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~~For further information on equity method investments and related party transactions, ~~have been eliminated in consolidation where appropriate; however, we have not eliminated inter-company profit on sales~~see Note 13 to ~~affiliates and costs from affiliates in accordance with accounting regulations prescribed under rate-based regulation.~~

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 1516 to the consolidated financial statements.

On October 24, 2015, we entered into an Agreement and Plan of Merger (Merger Agreement) with Duke Energy Corporation (Duke Energy). For further information, see Note 2 to the consolidated financial statements.

Use of Estimates

In accordance with GAAP, we make certain estimates and assumptions regarding reported amounts of assets, liabilities, revenues and ~~liabilities, disclosure~~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 ~~contingent~~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 ~~periods reported.~~reporting period. Actual results could differ ~~significantly~~ from these estimates and ~~assumptions.~~

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 ~~are evaluated~~is used regularly by the chief operating decision maker (CODM) in deciding how to allocate resources and in assessing performance. Our ~~chief operating decision maker~~CODM 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 our cash flows in the ventures.

We have ~~two~~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 ~~warranty programs,~~service agreements, with activities conducted by the utility. 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. 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~~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. Earnings or losses from equity method investments of the regulated and unregulated non-utility activities segments are included in “Income from equity method investments” in “Other Income (Expense)” in the Consolidated Statements of Comprehensive Income. All other revenues and expenses of the regulated and unregulated non-utility activities segments are included in “Non-operating income” in “Other Income (Expense)” in the Consolidated Statements of Comprehensive Income. See Note 1415 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.~~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, 2013 and 2012 are as follows.~~

In thousands

2013

2012

Regulatory Assets:

Unamortized debt expense
       $ 15,423        $ 13,583
Amounts due from customers
   66,321    81,626
Environmental costs
   9,416    10,202
Deferred operations and maintenance expenses
   6,376    7,050
Deferred pipeline integrity expenses
   19,449    13,691
Deferred pension and other retirement benefits costs
   20,736    20,139
Amounts not yet recognized as a component of pension and other retirement benefit costs
   80,604    123,290
Regulatory cost of removal asset
   22,974    21,129
Robeson LNG development costs
   1,808    -
Other
   3,199    2,394




Total
       $ 246,306        $ 293,104




Regulatory Liabilities:

Regulatory cost of removal obligations
       $ 493,111        $ 464,334
Amounts due to customers
   -    28
Deferred income taxes
   48,647    25,330
Amounts not yet recognized as a component of pension and other retirement costs
   139    -




Total
       $       541,897        $       489,692

As of October 31, 2013, we had regulatory assets totaling $.4 million on which we do not earn a return during the recovery period. The original amortization period for these assets is 15 years and the $.4 million will be fully amortized by 2018. We have $1.9 million related to unrealized mark-to-market amounts on which we do not earn a return until they are recorded in interest-bearing amounts due to/from customer accounts when realized and $80.6 million of regulatory postretirement assets, $23 million of asset retirement obligations (AROs) and $7.9 million of estimated environmental costs 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, ~~and~~ 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, ~~2013~~2015 and ~~2012~~2014 is presented below.

In thousands

2013

2012

Intangible plant
   $ 3,374    $ 3,374
Other storage plant
   171,349    118,277
Transmission plant
   1,403,829    866,000
Distribution plant
   2,505,160    2,422,988
General plant
   335,847    329,867
Asset retirement cost
   7,565    10,819
Contributions in aid of construction
   (5,187)       (5,147)




Total utility plant in service
   4,421,937    3,746,178
Less accumulated depreciation
   (1,088,331)       (1,036,814)




Total utility plant in service, net
   3,333,606    2,709,364
Construction work in progress
   297,717    388,979
Plant held for future use
   3,155    6,743




Total utility plant, net
   $       3,634,478    $       3,105,086



In thousands	2015			2014
Intangible plant	$	3,374		$	3,374
Other storage plant	180,960			180,058
Transmission plant	2,024,264			1,787,990
Distribution plant	2,766,871			2,623,560
General plant	452,301			421,763
Asset retirement cost	4,159			11
Contributions in aid of construction	(5,345		)	(5,259		)
Total utility plant in service	5,426,584			5,011,497
Less accumulated depreciation	(1,251,940		)	(1,166,922		)
Total utility plant in service, net	4,174,644			3,844,575
Construction work in progress	170,250			141,693
Plant held for future use	3,155			3,155
Total utility plant, net	$	4,348,049		$	3,989,423

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, ~~2013, 2012~~2015, 2014 and ~~2011,~~2013, all of our AFUDC was attributable to borrowed funds.

AFUDC for the years ended October 31, ~~2013, 2012~~2015, 2014 and ~~2011~~2013 is presented below.

In thousands

2013

2012

2011

AFUDC
   $ 30,975    $ 25,211    $ 8,619



In thousands	2015		2014		2013
AFUDC	$	11,106	$	16,427	$	30,975

In accordance with utility accounting practice, we classified real estate and development costs associated with a liquefied natural gas (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 ~~to be amortized~~that is recorded as a regulatory asset with amortization over 38 months beginning January 1, ~~2014. We~~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 was recorded ~~$1.2 million~~ as a regulatory asset ~~along~~ with ~~$.5 million of costs that we allocated to South Carolina operations.~~amortization over the 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 23 to the consolidated financial statements.

We compute depreciation expense using the straight-line method over periods ranging from 45 to 8880 years. The composite weighted-average depreciation rates were 2.48% for 2015, 2.54% for 2014 and 2.77% for ~~2013, 2.94% for 2012 and 3.19% for 2011.~~

2013.

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, ~~and~~ March 1, 2012 for ~~Tennessee. The new depreciation rates become effective~~Tennessee and January 1, 2014 infor North ~~Carolina under the settlement of the 2013 general rate proceeding.~~

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 1.3 to the consolidated financial statements. 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, ~~2013~~2015 and ~~2012.~~

2014.

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 ~~Public Service Commission of South Carolina (PSCSC)~~PSCSC and the ~~TRA,~~Tennessee Regulatory Authority (TRA), we are authorized to recover ~~all~~actual 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, ~~2013~~2015 and ~~2012,~~2014, our trade accounts receivable consisted of the following.

In thousands

2013

2012

Gas receivables
       $ 78,540        $ 55,956
Non-regulated merchandise and service work receivables
   2,274    2,323
Allowance for doubtful accounts
   (1,604)       (1,579)




Trade accounts receivable
       $       79,210        $       56,700



In thousands	2015			2014
Gas receivables	$	57,759		$	64,400
Non-regulated merchandise and service work receivables	3,137			3,012
Allowance for doubtful accounts	(1,648		)	(2,152		)
Trade accounts receivable	$	59,248		$	65,260

A reconciliation of the changes in the allowance for doubtful accounts for the years ended October 31, ~~2013, 2012~~2015, 2014 and ~~2011~~2013 is presented below.

In thousands

2013

2012

2011

Balance at beginning of year
   $ 1,579    $ 1,347    $ 929
Additions charged to uncollectibles expense
   5,314    4,584    4,842
Accounts written off, net of recoveries
   (5,289)       (4,352)       (4,424)






Balance at end of year
   $         1,604    $         1,579    $         1,347



In thousands	2015			2014			2013
Balance at beginning of year	$	2,152		$	1,604		$	1,579
Additions charged to uncollectibles expense	5,095			6,959			5,314
Accounts written off, net of recoveries	(5,599		)	(6,411		)	(5,289		)
Balance at end of year	$	1,648		$	2,152		$	1,604

For information on credit risk, see "Credit and Counterparty Risk" in Note 8 of the consolidated financial statements.

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 ~~transportation capacity, storage capacity~~ 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 ~~use by~~ our ~~customers~~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 ~~use by~~ our ~~customers~~use is reclassified on the Consolidated Balance Sheets as a current asset in “Prepayments,” and the inventory that is available for ~~use by~~ our ~~customers~~use remains in “Gas in storage.”

At October 31, ~~2013~~2015 and ~~2012,~~2014, such counterparties held natural gas storage assets as recorded in “Prepayments,” with a value of ~~$31.5~~$24.8 million and ~~$26.7~~$35 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, ~~2014.~~2017. For further information on the revenue sharing of secondary market transactions, see Note 23 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 ~~cash and cash equivalents,~~ 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 ~~financial~~nonfinancial assets and liabilities are recorded at fair value. They consist primarily of derivatives that are recorded in the Consolidated Balance Sheets in accordance with derivative accounting standards and marketable securities that are held in rabbi trusts established forinclude our ~~deferred compensation plans and are classified as trading securities. 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 a 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 78 to the consolidated financial statements. For the fair value measurements of our benefit plan assets, see Note 910 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. WeWhen we test goodwill, ~~using~~we use a fair value approach at a reporting unit level, generally equivalent to our operating segments as discussed in Note 1415 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, ~~2013,~~2015 was performed using a qualitative approach. As part of our qualitative assessment, we considered macroeconomic conditions such as general deterioration in economic condition, limitations on accessing capital and other developments in equity and credit markets. We evaluated industry and market considerations for any deterioration in the environment in which we operate, the increased competitive environment, a decline (both absolute and relative to our peers) in market-dependent multiples or metrics, any changes in the market for our products or services, and regulatory and political development. We assessed our overall financial performance and considered cost factors, such as increases in utility construction expenditures, labor or other costs, that would have a negative effect on earnings. We determined ~~that there was no impairment to~~the relevance of any entity-specific events or events affecting our regulated utility segment which would have a negative effect on the carrying value of the reporting unit.

Based on our ~~goodwill.~~qualitative assessment, we have determined that it is not necessary to perform a quantitative goodwill impairment test as of October 31, 2015. The annual goodwill impairment assessments performed have indicated that it is more likely than not that the fair value of the reporting unit is substantially in excess of carrying value and not at risk of failing step one of the quantitative goodwill impairment test. No impairment ~~has been~~was recognized during the years ended October 31, ~~2013, 2012~~2015, 2014 and ~~2011.~~2013. 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, 2012~~2015 and ~~2011~~2013 that resulted in any impairment charges. For further information on equity method investments, see Note 1213 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 910 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~~is 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, ~~2013~~2015 and ~~2012~~2014 is as follows.

In thousands
   2013    2012

Cost

Fair Value

Cost

Fair Value

Current trading securities:

Money markets
   $ -    $ -    $ -    $ -
Mutual funds
   134    199    134    157








Total current trading securities
   134    199    134    157








Noncurrent trading securities:

Money markets
   380    380    243    243
Mutual funds
   1,995    2,615    1,668    1,888








Total noncurrent trading securities
   2,375    2,995    1,911    2,131








Total trading securities
   $       2,509    $       3,194    $       2,045    $       2,288

~~Unamortized Debt Expense~~

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.



	2015				2014
In thousands	Cost		Fair Value		Cost		Fair Value
Current trading securities:
Money markets	$	51	$	51	$	22	$	22
Mutual funds	114		185		106		192
Total current trading securities	165		236		128		214
Noncurrent trading securities:
Money markets	465		465		447		447
Mutual funds	3,625		4,201		2,598		3,280
Total noncurrent trading securities	4,090		4,666		3,045		3,727
Total trading securities	$	4,255	$	4,902	$	3,173	$	3,941

Issuances and Repurchases of Common Stock

As discussed in Note 67 to the consolidated financial statements, from time to time we may repurchase shares on the open market and such shares are then ~~cancelled~~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~~asset retirement obligations (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 1.3 to the consolidated financial statements. 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 ~~4.61%~~4.62% to ~~5.87%~~5.89% with a time value weighted average of ~~5.73%~~5.69% for the twelve months ended October 31, ~~2013. The estimate was calculated using a time value weighted average credit adjusted risk-free rate.~~2015. 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, ~~2013~~2015 and ~~2012~~2014 are presented below.

In thousands

2013

2012

Regulatory non-legal AROs
   $ 493,111    $ 464,334
Conditional AROs
   27,016    28,629




Total cost of removal obligations
   $         520,127    $         492,963



In thousands	2015		2014
Regulatory non-legal AROs	$	521,478	$	506,574
Conditional AROs	19,712		14,647
Total cost of removal obligations	$	541,190	$	521,221

A reconciliation of the changes in conditional AROs for the year ended October 31, ~~2013~~2015 and ~~2012~~2014 is presented below.

In thousands

2013

2012

Beginning of period
     $ 28,629      $ 27,395
Liabilities incurred during the period
   2,052    1,705
Liabilities settled during the period
   (2,389)       (2,038)
Accretion
   1,641    1,570
Adjustment to estimated cash flows
   (2,917)       (3)




End of period
     $       27,016      $       28,629



In thousands	2015			2014
Beginning of period	$	14,647		$	27,016
Liabilities incurred during the period	4,663			2,108
Liabilities settled during the period	(5,563		)	(3,576		)
Accretion	924			1,548
Adjustment to estimated cash flows	5,041			(12,449		)
End of period	$	19,712		$	14,647

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. With the adoption of new accounting guidance in our fourth quarter of 2015 to present debt issuance costs as a direct deduction from the carrying amount of that debt, long-term debt is now presented net of unamortized debt expenses in the accompanying Consolidated Balance Sheets. For further information on the effects on regulatory assets and our long-term debt, see Note 3 and Note 5, respectively, to the consolidated financial statements.

We amortize bank debt expense over the life of the syndicated revolving credit facility, which is 5 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 as a regulatory asset or liability 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.

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 ~~rate stabilization adjustment (RSA) tariff~~RSA 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. Effective~~ March, ~~1, 2012, the WNA mechanism~~and in Tennessee, ~~was expanded to include~~ the ~~additional~~ months of April and ~~October in the winter heating season.~~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 ~~mechanisms.~~

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 initially approved in December 2013 in the settlement of our 2013 general rate case and subsequently revised in November 2015. Under the revised North Carolina IMR tariff, we will make filings semi-annually each October 31 and April 30 for certain costs closed to plant through September and March, respectively, with revised rates effective the following December 1 and June 1, respectively. Under the Tennessee IMR, we 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 3 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 23 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~~

“Regulatory Liabilities” as presented in “Rate-Regulated Basis of Accounting” in ~~this~~ Note 1.3 to the consolidated financial statements. 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.

Accounting Standards Update (ASU) - Guidance Adopted in Fiscal Year 2015



Guidance	Description	Effective date	Effect on the financial statements or other significant matters
ASU 2015-03, April 2015, Interest: Imputation of Interest - Simplifying the Presentation of Debt Issuance Costs (Subtopic 835-30)	The guidance is part of the Financial Accounting Standards Board's (FASB) simplification initiative to reduce complexity in accounting standards. The amendment requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by this amendment.	Annual periods beginning after December 15, 2015, and interim periods within those fiscal years, with early adoption permitted for financial statements that have not been previously issued. While the guidance would have been effective for us beginning November 1, 2016, we elected to adopt this guidance effective August 1, 2015.	The adoption of this guidance had no impact on our results of operations or cash flows. We retrospectively changed the presentation of the balance sheet line items current and noncurrent "Regulatory assets," "Other noncurrent assets" and "Long-term debt, net."
ASU 2015-15, August 2015, Interest - Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements - Amendments to SEC Paragraphs Pursuant to Staff Announcement at June 18, 2015 EITF Meeting	The guidance provides clarification to ASU 2015-03 for debt issuance costs for line-of-credit arrangements, specifically that the SEC would not object to an entity deferring and presenting debt issuance costs as an asset and subsequently amortizing deferred debt issuance costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement.	Effective upon adoption of ASU 2015-03, as adopted August 1, 2015.	The adoption of this guidance had no impact on our results of operations or cash flows.
ASU 2015-07, May 2015, Fair Value Measurement: Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent) (Topic 820)	The guidance amends the required disclosure of investments for which fair value is measured at NAV per share (or its equivalent). The amendments remove the requirement to make certain disclosures for all investments that are eligible to be measured at fair value using the NAV per share practical expedient.	Annual periods beginning after December 15, 2015, and interim periods within those fiscal years, with retrospective application to all periods presented and early adoption permitted. While the guidance would have been effective for us beginning November 1, 2016, we elected to adopt this guidance effective August 1, 2015.	The adoption of this guidance had no impact on our financial position, results of operations or cash flows. We have disclosed certain benefit plan assets under the new guidance.



Guidance	Description	Effective date	Effect on the financial statements or other significant matters
ASU 2015-12, July 2015, Plan Accounting: Defined Benefit Pension Plans (Topic 960), Defined Contribution Pension Plans (Topic 962) and Health and Welfare Benefit Plans (Topic 965)	The FASB issued a three-part standard providing guidance on certain aspects of the accounting by employee benefit plans. The ASU: (1) requires a pension plan to use contract value as the only measure for fully benefit-responsive investment contracts; (2) simplifies and increases the effectiveness of the investment disclosure requirements for employee benefit plans by grouping investments by general type; and (3) provides benefit plans with a measurement-date practical expedient on a month-end date nearest to the employer's fiscal year end.	Annual periods beginning after December 15, 2015 with early adoption permitted. The amendments in parts (1) and (2) are retrospectively applied to all periods presented, while the amendment in part (3) is applied prospectively. While the guidance would have been effective for us beginning November 1, 2016, we elected to adopt this guidance effective August 1, 2015.	The adoption of this guidance had no impact on our financial position, results of operations or cash flows. We have disclosed certain benefit plan assets under the new guidance of part (2). Parts (1) and (2) are applicable to our future Form 11-K filing; part (3) is not applicable to us.

Recently Issued Accounting Guidance

In December 2011, the Financial Accounting Standards Board (FASB) issued accounting guidance to improve disclosures and make information more comparable to International Financial Reporting Standards regarding the nature of an entity’s rights of offset and related arrangements associated with its financial instruments and derivative instruments. The guidance requires an entity to disclose information about offsetting and related arrangements in tabular format to enable users of financial statements to understand the effect of those arrangements on the entity’s financial position. The new disclosure requirements are effective for annual periods beginning after January 1, 2013 and interim periods within those periods, and require retrospective application in all periods presented. We will adopt this offsetting disclosure guidance for the first quarter of our fiscal year ending October 31, 2014. The adoption of this disclosure guidance will have no impact on our financial position, results of operations or cash flows.

In November 2012, the FASB finalized the presentation disclosures on items reclassified from accumulated other comprehensive income (OCI). We adopted this disclosure guidance for the second quarter of our fiscal year ending October 31, 2013. The adoption of this guidance did not have a material impact on our financial position, results of operations or cash flows.

In July 2013, the 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.



Guidance	Description	Effective date	Effect on the financial statements or other significant matters
ASU 2014-09, May 2014, Revenue from Contracts with Customers (Topic 606)	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. An entity may choose to adopt the new standard on either a full retrospective basis (practical expedients available) or through a cumulative effect adjustment to retained earnings as of the start of the first period of adoption.	Annual periods beginning after December 15, 2017 (beginning November 1, 2018 for us) and interim periods within that period, with early adoption permitted for annual periods beginning after December 15, 2016.	We are currently evaluating the effect on our financial position, results of operations and cash flows, as well as the transition approach we will take. The evaluation includes identifying revenue streams by like contracts to allow for ease of implementation. In our evaluation, we are following the efforts of an accounting utility subgroup and its issuance of a revenue implementation guide.
ASU 2014-15, August 2014, Presentation of Financial Statements - Going Concern (Subtopic 205-40)	The amendment provides 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."	Annual periods ending after December 15, 2016 (October 31, 2017 for us), and interim and annual periods thereafter; early adoption is permitted.	The adoption of this guidance will have no impact on our financial position, results of operations or cash flows. It will require establishing a going concern assessment process to meet the standard.



Guidance	Description	Effective date	Effect on the financial statements or other significant matters
ASU 2015-05, April 2015, Intangibles -Goodwill and Other - Internal-Use Software: Customer's Accounting for Fees Paid in a Cloud Computing Arrangement (Subtopic 350-40)	The guidance amends ASC 350-40 to provide customers with guidance on determining whether a cloud computing arrangement contains a software license that should be accounted for as internal-use software. The guidance applies only to hosting arrangements if both of the following criteria are met: (a) the customer has the contractual right to take possession of the software at any time during the hosting period without significant penalty and (b) it is feasible for the customer to run the software on its own hardware or contract with another party to host the software.	Annual periods (and interim periods within those periods) beginning after December 15, 2015 (November 1, 2016 for us), with early adoption permitted. Entities may adopt the guidance retrospectively or prospectively to arrangements entered into, or materially modified, after the effective date.	We are currently evaluating the effect on our financial position, results of operations and cash flows.
ASU 2015-17, November 2015, Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes	The guidance eliminates the current requirement to present deferred tax assets and liabilities as current and noncurrent amounts in a classified balance sheet. The new standard requires deferred tax liabilities and assets be classified as noncurrent. The current requirement that deferred tax liabilities and assets be presented as a single amount remains unchanged.	Annual periods (and interim periods within those periods) beginning after December 15, 2016, early adoption is permitted.	The adoption of this guidance will have no impact on our results of operations or cash flows. The reclassification of amounts from current to noncurrent will affect presentation of our financial position.

Reclassifications and Changes in Presentation

Reclassifications have been made to ~~certain~~the prior year ~~financial statements~~Consolidated Balance Sheets to conform with the current year presentation. We ~~have changed~~early adopted ASU 2015-03 requiring that issuance costs related to a long-term debt issuance be presented as a direct deduction from the carrying amount of that debt. In prior years, we presented unamortized debt expense as current and noncurrent regulatory assets. While these amounts are not regulatory assets under accounting guidance, they are a critical component of the embedded cost of debt financing and cost of capital utilized in rate proceedings in each of our ~~2012~~jurisdictions. With the adoption of the new pronouncement, unamortized debt expense associated with outstanding long-term debt has been reclassified from current and noncurrent regulatory assets to a reduction of the carrying value of long-term debt as of October 31, 2015 and 2014. For further information on the impact to our presentation of regulatory assets and ~~liabilities on the Consolidated Balance Sheets where regulatory assets~~long-term debt, see Note 3 and ~~liabilities were presented in various line items~~Note 5, respectively, to the ~~2013 presentation of a more cohesive presentation of~~consolidated financial statements.

Reclassifications have been made to the ~~regulatory balances in single “Regulatory assets” and “Regulatory liabilities” line items. The corresponding line items within “Cash Flows from Operating Activities” in the~~prior years Consolidated Statements of Cash Flows ~~were~~to conform with the current year presentation to provide additional detail and to present such information within separate line items. Within “Cash Flows from Operating Activities," we have changed the prior presentation of the cash flows line item "Allowance for doubtful accounts," comprised of the provision and the charge-offs. The provision is now presented on a separate line item "Provision for doubtful accounts" and the charges-offs are now included in the line item "Receivables, net." We have also changed the prior presentation of the cash flows line item "Provision for postretirement benefits, net" comprised of the contributions to ~~reflect this balance sheet presentation;~~benefit plans and other activity. The contributions are now presented on a separate line item "Contributions to benefit plans" and the remaining activity is now presented on a separate line item "Accrued/deferred postretirement benefit costs." The presentation for 2014 and 2013 have been changed to conform to the current year presentation. The reclassifications that provide additional detail had no effect on previously reported amounts for net cash flows from operating, investing or financing activities.

2. Proposed Acquisition by Duke Energy Corporation

On October 24, 2015, we entered into a Merger Agreement with Duke Energy and Forest Subsidiary, Inc. (Merger Sub), a new wholly owned subsidiary of Duke Energy. The ~~changes~~Merger Agreement provides for the merger of the Merger Sub with and into Piedmont, with Piedmont surviving as a wholly owned subsidiary of Duke Energy (the Acquisition). At the effective time of the Acquisition, subject to receipt of required shareholder and regulatory approvals and meeting specified customary closing conditions, each share of Piedmont common stock issued and outstanding immediately prior to the closing will be converted automatically into the right to receive $60 in ~~presentation had~~cash per share, without interest, less any applicable withholding taxes. Upon consummation of the Acquisition, Piedmont common stock will be delisted from the New York Stock Exchange (NYSE).

Completion of the Acquisition is subject to various closing conditions, including, among others (i) the approval of the Merger Agreement by an affirmative vote of the holders of a majority of the outstanding shares of our common stock, (ii) approval from the NCUC, and (iii) expiration or termination of any applicable waiting period under the federal Hart-Scott-Rodino Antitrust Improvements Act of 1976. The Merger Agreement may be terminated by us or by Duke Energy if the Acquisition is not consummated by October 31, 2016, subject to a six-month extension by either of us under certain circumstances. The Merger Agreement contains certain termination rights for both companies under certain circumstances, and provides that, upon termination of the Merger Agreement under specified circumstances, we would be required to pay Duke Energy a termination fee of $125 million, or Duke Energy would be required to pay us a termination fee of $250 million.

The Merger Agreement includes certain restrictions, limitations and prohibitions as to actions we may or may not take in the period prior to completion of the Acquisition. Among other restrictions, the Merger Agreement limits our total capital spending, limits the extent to which we can obtain financing through long-term debt and equity, and caps our cash dividend to no ~~effect~~more than the current annual per share dividend plus an increase of not more than $.04 per fiscal year, with record dates and payment dates consistent with our current dividend practices. Also, provision is made for a stub period dividend payment to holders of record of our shares of common stock immediately prior to consummation of the Acquisition.

In connection with this transaction, we recorded Acquisition-related expenses of $8.6 million for costs paid to outside parties in fiscal 2015, which are reflected in “Operations and maintenance” in “Operating Expenses” in the Consolidated Statements of Comprehensive Income. This amount does not include the cost of company personnel participating in Acquisition-related activities. We also recorded incremental share-based compensation expense of $7.2 million in "Operations and maintenance" as noted above for the end of period remeasurement to market value of the incentive compensation awards and the retention award of our President and Chief Executive Officer based upon the increase in the trading price of our common stock since the announcement of the Acquisition. We treated these costs as tax deductible since the requisite closing conditions to the Acquisition have not yet been satisfied. Upon completion of the Acquisition, we will evaluate the tax deductibility of these costs and reflect any non-deductible amounts in the effective tax rate at the Acquisition closing date. For further information on ~~total~~our employee share-based plans, see Note 11 to the consolidated financial statements.

3. Regulatory Matters

Rate-Regulated Basis of Accounting

Regulatory assets orand liabilities ~~reported~~ in the Consolidated Balance Sheets as of October 31, 2015 and 2014 are as follows.



In thousands	2015		2014
Regulatory Assets:
Current:
Unamortized debt expense on reacquired debt	$	238	$	239
Amounts due from customers	—		16,108
Environmental costs	1,513		1,568
Deferred operations and maintenance expenses	847		916
Deferred pipeline integrity expenses	3,470		3,470
Deferred pension and other retirement benefit costs	2,757		2,769
Robeson LNG development costs	381		917
Other	1,730		1,850
Total current	10,936		27,837

Noncurrent:
Unamortized debt expense on reacquired debt	4,666		4,904
Environmental costs	5,107		6,470
Deferred operations and maintenance expenses	3,997		4,721
Deferred pipeline integrity expenses	29,824		24,694
Deferred pension and other retirement benefits costs	17,861		18,799
Amounts not yet recognized as a component of pension and other retirement benefit costs	114,854		94,265
Regulatory cost of removal asset	19,087		18,275
Robeson LNG development costs	127		509
Other	1,203		1,644
Total noncurrent	196,726		174,281
Total	$	207,662	$	202,118



Regulatory Liabilities:
Current:
Amounts due to customers	$	13,367	$	46,231

Noncurrent:
Regulatory cost of removal obligations	521,478		506,574
Deferred income taxes	68,738		51,930
Amounts not yet recognized as a component of pension and other retirement benefit costs	85		94
Total noncurrent	590,301		558,598
Total	$	603,668	$	604,829

The 2014 presentation of unamortized debt expense has been changed to conform with the current year presentation in the table above. As discussed in Note 1 to the consolidated financial statements, we early adopted ASU 2015-03 requiring that issuance costs related to a recognized long-term debt liability be presented in the balance sheet as a direct deduction from the carrying value of that debt. Consequently, unamortized debt expense of $.9 million current and $9 million noncurrent presented in 2014 as regulatory assets have been reclassified as a reduction of $9.9 million to the carrying value of long-term debt. The amounts presented above in line items "Unamortized debt expense on reacquired debt" represent unamortized debt expense associated with the early retirement or ~~on any subtotals within~~the refunding of debt in accordance with established regulatory practice. Unamortized debt expenses related to short-term bank debt and unallocated expenses of our open debt and equity shelf registration are now presented in the line item "Other noncurrent assets" as "Noncurrent Assets" in the Consolidated Balance ~~Sheets, or~~

Sheets. See Note 1 with discussion of "Unamortized Debt Expense" and Note 5 to the consolidated financial statements for related discussion of these presentation changes.

As of October 31, 2015, we have $19.1 million of AROs and $117 million of other regulatory assets on ~~previously reported operating income, net income, comprehensive income, earnings per share (EPS) or stockholders’ equity.~~

2. 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 TRA on a deferred cash basis.

Regulatory ~~Matters~~

Oversight and Rate and Regulatory Actions

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 ~~a maximum deferral of $15 million. The~~the deferred amounts ~~accrued~~accruing interest ~~at a rate of 8.69%~~ 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. As a part of the 2005 general rate case proceeding, deferral ceased on October 31, 2005, and the balance in the deferred account as of June 30, 2005 of $7.9 million, including accrued interest, is being amortized over 15 years beginning November 1, 2005. Under the settlement of the 2008 general rate proceeding, the unamortized balance of the EasternNC deferred O&M expenses ~~was~~of $9 million at October 31, ~~2008. This balance is accruing interest at a rate of 7.84% per annum and is being~~2008 was to be amortized over a twelve year ~~period. As of October 31, 2013 and 2012, we had unamortized balances of $6.4 million and $7 million, respectively.~~

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 ~~will accrue~~is accruing interest at a rate of 6.55% per annum ~~and will be amortized~~ with amortization beginning January 1, 2014over an 82-month period ~~beginning January 1, 2014.~~

ending October 31, 2020. As of October 31, 2015 and 2014, we had unamortized balances, including accrued interest, of $4.8 million and $5.6 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 ~~all~~certain incremental pipeline integrity external expenditures beginning November 1, 2004. Under the settlement of the 2008 general rate proceeding, the pipeline integrity management costs incurred between July 1, 2005 and June 30, 2008 of $4.6 million were fully amortized over a three-year period beginning November 1, 2008. 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 ~~beginning~~from January 1, ~~2014.~~2014 through December 31, 2018. As of October 31, ~~2013,~~2015 and 2014, we ~~have recorded a~~had unamortized regulatory asset balances for deferred pipeline integrity expenses of ~~$19.4 million.~~$33.3 million and $28.2 million, respectively. The existing regulatory asset treatment for ongoing pipeline integrity management costs ~~continues~~is expected to continue until another recovery mechanism is established in a future rate proceeding.

~~Based on~~

With the approval of the settlement of the 2013 NCUC general rate proceeding discussed below, ~~future~~certain 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 ~~integrity management rider (IMR).~~IMR, as revised by a subsequent settlement approved by the NCUC in November

2015. The settlement also ~~would approve~~approved recovery of $6.3 million of deferred North Carolina environmental costs over a five-year period ~~beginning~~from January ~~2014.~~

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. ~~Costs~~Our gas costs have never been disallowed on the basis of prudence.

In January 2011, the NCUC approved our accounting of gas costs for the twelve months ended May 31, 2010, with adjustments agreed to by us as a result of the North Carolina Public Staff’s audit of the 2010 gas cost review period. We were deemed prudent on our gas purchasing policies and practices during this review period and allowed 100% recovery.

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 North Carolina 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.

In November 2015, the NCUC approved our accounting of gas costs for the twelve months ended May 31, 2015. 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%~~up 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 2011, January 2012,~~ November ~~2012~~2013, November 2014 and November ~~2013~~2015 found our hedging activities during the review periods to be reasonable and prudent.

In ~~October 2012,~~April 2013, we ~~filed~~withdrew a petition that had been filed with the NCUC ~~seeking~~in October 2012 requesting 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~~citing our intent to address the matter in a general rate application. The 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 to produce overall increased annual revenues of $79.8 million, or 9.3% above~~charges. In December 2013, the ~~current annual revenues. In October, we reached a~~NCUC approved our general rate case settlement agreement with the NCUC Public Staff ~~and intervening parties, in which~~with new rates effective January 2014. In its order, the ~~parties agreed to~~NCUC approved the following:

~~Adjusted~~

Updated and increased rates and charges ~~to provide incremental~~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 ~~total~~ 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.

~~An overall rate base~~Implementation of ~~$1.8 billion, an equity capital structure component of 50.7% and~~ a ~~return on common equity of 10%.~~

A new IMR designed to separately track and recover annually outside of general rate cases the costs associated with capital expenditures ~~that are made~~incurred to comply with federal pipeline safety and integrity ~~requirements outside~~requirements.

Implementation of ~~a general rate case. IMR filings will occur annually in November to capture costs closed to plant through October with revised rates effective in February, which will provide revised rates in 2014.~~

~~Lower~~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.

~~With~~

In January 2014, we filed a petition with the ~~approval~~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 provided 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. In February 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 ~~December 17, 2013~~$241.9 million of capital investments in integrity and safety projects over the twelve-month period ending October 31, 2014. In January 2015, the NCUC issued an order authorizing the requested IMR rate adjustments, subject to further review and determination of the reasonableness and prudence of the capital investments and associated costs reflected in the adjustments in our annual IMR adjustment proceedings or next general rate case, with any adjustments to be implemented through a prospective rate adjustment at or after the time such adjustment is approved by the NCUC. We subsequently engaged in discussions with the NCUC Public Staff regarding the completion of their review of the IMR costs and the development of a future procedural schedule for the IMR audit and rate approval process. In September 2015, we and the NCUC Public Staff filed an agreement with the NCUC seeking approval of the following stipulations regarding the operation of the IMR:

Semi-annual IMR rate adjustments each December 1 and June 1, starting December 1, 2015, based on eligible capital investments in integrity and safety projects closed to plant as of September 30 and March 31.

Extension of the IMR tariff from October 31, 2017 to October 31, 2019.

An established procedural process and time line for NCUC Public Staff’s annual review of our IMR filings.

Fixed percentages to quantify various classes of system integrity expenditures to be recovered through the IMR with the remaining to be recovered through a future rate case:

Transmission integrity: 85% IMR / 15% rate case.

Distribution integrity: 90% IMR / 10% rate case.

Right-of-way clearing for integrity projects: 15% IMR / 85% rate case.

Work and asset management system: 68% IMR / 32% rate case.

Tax-related adjustments.

An immaterial reduction in IMR margin, which we recorded in the fourth fiscal quarter of 2015.

Based on the IMR agreement, in November 2015, we filed a petition with the NCUC seeking authority to adjust rates to collect an additional $13.4 million in annual IMR margin revenues, effective December 1, 2015, based on $161.9 million of IMR-eligible capital investments in integrity and safety projects over the eleven-month period ended September 30, 2015. In November 2015, the NCUC approved the IMR settlement agreement and the requested December 2015 IMR rate increase.

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 ~~discussed above,~~included the ~~new rates will become effective~~granting of a waiver of the commodity index pricing mechanism for January ~~1, 2014.~~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 NCUC 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 ~~increase~~order further required us to engage in ~~annual total revenues~~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 ~~$30.7~~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 5 to the consolidated financial statements.

In March 2015, we filed a petition with the NCUC seeking authority for a one-time gas cost bill credit, including applicable sales taxes, for our retail sales and transportation customers in North Carolina. In March 2015, the NCUC issued an order approving our request. The bill credit of $45.5 million ~~represents a 3.58% increase~~was reflected on customers' April 2015 bills, reducing amounts due to customers in ~~total revenues, or .7% annual increase per year since the last general rate proceeding in 2008.~~

North Carolina.

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 2011, we filed with the PSCSC a quarterly monitoring report for the twelve months ended March 31, 2011 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 2010 order. In October 2011, the PSCSC issued an order approving a settlement between the Office of Regulatory Staff (ORS) and us that resulted in a $3.1 million annual decrease in margin based on a return on equity of 11.3% and a decrease of $1.9 million in depreciation rates for South Carolina utility plant in service, effective November 1, 2011.

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.~~2011. In October 2012, the PSCSC issued an order approving a settlement agreement between the ~~ORS~~Office of Regulatory Staff (ORS) and us that resulted in a $1.1 million annual decrease in margin based on a stipulated 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.~~2012. 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 stipulated 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 October 2013.

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 June 2015, we filed with the PSCSC a quarterly monitoring report for the twelve months ended March 31, 2015 and a cost and revenue study under the RSA requesting a change in rates from those approved by the PSCSC in the October 2014 order. In October 2015, the PSCSC issued an order approving a settlement agreement between the ORS and us that resulted in a $1.65 million annual increase in margin based on a stipulated allowed return on equity of 10.2%, effective November 1, 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%~~up 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 ~~our PGAs and found our gas purchasing policies to be prudent for the twelve months ended March 31, 2011. The settlement agreement also stipulated~~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.

~~Tennessee~~

In ~~February 2010,~~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 September 2015, the PSCSC approved our PGAs and found our gas purchasing policies to be prudent for the twelve months ended March 31, 2015.

In July 2014, we filed a petition with the ~~TRA~~PSCSC requesting a limited waiver of certain billing provisions of our tariff related to ~~adjust~~emergency service for customers in January 2014. In August 2014, the ~~applicable rate for~~PSCSC granted our request and ordered us to continue to collaborate with the ~~collection of~~ORS to revise our tariff to address the ~~Nashville franchise fee from certain customers. The proposed rate adjustment was calculated~~situation that led 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.

petition.

Tennessee

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

TIP includes procedures for asset management transactions and ~~provided~~provides for a triennial review of TIP operations by an independent consultant.

~~In September 2010,~~ Although the TIP replaced annual prudence reviews of our gas purchasing activities, we ~~filed~~undergo an annual ~~report~~compliance audit on the accuracy of our calculations and compliance with all TRA orders and directives regarding 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, 2010 under the TIP. In May 2011, the TRA issued an order approvingcalculation of our ~~TIP account balances.~~

In December 2010, we filed our report with the TRA for the eighteen months ended June 30, 2010 reflecting the transactions in the deferred gas cost account for the ACA mechanism. This one-time eighteen month audit period was designed to synchronize the ACA audit year with the TIP year in order to facilitate the audit process for future periods. In August 2011, the TRA approved the deferred gas cost account balances ~~and issued its written order.~~

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~~Actual Cost Adjustment (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 Utilities Division Audit Staff (Audit Staff) submitted their report with which we concurred. In March 2013, the TRA approved the TIP account ~~balances. The TRA~~balances and 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 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 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. In March 2015, the Audit Staff submitted their report with which we concurred. In April 2015, the TRA approved and adopted the Audit Staff's report. The TRA's written order was issued in May 2015.

In August 2015, 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, 2015 under the TIP. We are waiting on a ruling from the TRA at this time.

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 March 2013, the TRA approved the deferred gas cost account balances and issued its written order.

In August 2013, we filed ~~an ACA~~a 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. In January 2015, the TRA issued its written order approving the settlement agreement. In October 2015, the TRA approved the deferred gas cost account balances for the twelve-month period ended June 30, 2013 and issued its written order.

In November 2015, we filed an annual report for the twelve months ended June 30, 2014 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. ~~We intend to file our ACA annual report for the twelve months ended June 30, 2013 upon resolution of this petition.~~

In September 2011, we filed a general rate application with the TRA requesting authority for an increase to rates and charges, ~~for all customers~~proposed to ~~produce overall incremental revenues of $16.7 million annually, or 8.9% above then current annual revenues.~~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. ~~The changes were proposed to be effective March 1, 2012.~~ In December 2011, we and the ~~Consumer Advocate and Protection Division~~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 ~~then~~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~~TRA issued its 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 8eight years beginning March 1, ~~2012.~~

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 of $100.4 million 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. OnIn November ~~27,~~ 2013, we and the CAD filed ~~with the TRA a~~an IMR settlement with the ~~Tennessee Attorney General’s Consumer Advocate Division agreeing to the IMR.~~TRA. A hearing on this matter was held in December ~~18,~~ 2013, and the TRA approved the IMR settlement as ~~filed.~~

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 ended October 31, 2014. In January 2015, the TRA accepted and approved the requested IMR rate adjustment and issued its written order in February 2015. In November 2015, we filed a petition with the TRA seeking authority to collect an additional $1.7 million in annual margin revenue effective January 2016 based on $18.4 million of capital investments in integrity and safety projects over the twelve-month period ending October 31, 2015. In December 2015, the TRA approved the IMR rate increase to be effective January 2016. We are waiting on the TRA's written order 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. In November 2015, we filed a settlement agreement with the CAD stipulating that Piedmont refund the $4.7 million to customers over a twelve month period. In December 2015, the TRA approved the settlement agreement, and we will begin refunding the $4.7 million to customers through a rate decrement over the twelve month period beginning January 2016. We are waiting on the TRA's written order at this time.

In September 2014, we filed a petition with the TRA seeking authority to implement a compressed natural gas (CNG) 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. A hearing on this matter was held in January 2015. In February 2015, the TRA (1) denied approval of the proposed tariff rider, (2) ruled that our retail CNG motor fuel service should be unregulated and no longer provided under our regulated tariff, and (3) approved the proposed modification to our tariff providing natural gas for motor fuel purposes at customer premises. The TRA indicated that we may seek recovery of our prior investments in CNG equipment of $4.7 million since our last rate proceeding in utility rate base in our next general rate case proceeding as the investments were made in good faith under the assumption retail CNG motor fuel would be a regulated service. The TRA's written order was issued in October 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~~

This sharing mechanism 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~~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~~2015, 2014 and 2013 is allocated to customers as gas cost reductions and $9.7 million as margin allocated to us. In all three jurisdictions for the twelve months ended October 31, 2011, we generated $56.1 million of margin from secondary market activity, $42.1 million of which is allocated to customers as gas cost reductions and $14 million as margin allocated to us.

presented below.



In millions	2015		2014		2013
Allocated to customers as gas cost reductions	$	60.1	$	72.2	$	26.9
Margin allocated to us	21.1		25.4		9.0
Margin from secondary market activity	$	81.2	$	97.6	$	35.9

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.

4. Earnings Per Share

We compute basic ~~EPS~~earnings per share (EPS) using the daily weighted average number of shares of common stock outstanding during each period. ~~Shares~~In the calculation of fully diluted EPS, shares of common stock to be issued under approved incentive compensation plans and forward sale agreements (FSAs) are contingently issuable shares, as determined by applying the treasury stock method, and are ~~included~~added to average common shares outstanding, resulting in ~~our calculation of fully~~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 and FSAs settle, for the years ended October 31, ~~2013, 2012~~2015, 2014 and ~~2011~~2013 is presented below.

In thousands except per share amounts

2013

2012

2011

Net Income
     $     134,417      $     119,847      $     113,568






Average shares of common stock outstanding for basic earnings per share
   74,884    71,977    72,056
Contingently issuable shares under incentive compensation plans
   289    301    210
Contingently issuable shares under forward sale agreements
   160    -       -






Average shares of dilutive stock
   75,333    72,278    72,266






Earnings Per Share of Common Stock:

Basic
     $ 1.80      $ 1.67      $ 1.58
Diluted
     $ 1.78      $ 1.66      $ 1.57



In thousands, except per share amounts	2015		2014		2013
Net Income	$	137,011	$	143,801	$	134,417

Average shares of common stock outstanding for basic earnings per share	78,942		77,883		74,884
Contingently issuable shares under incentive compensation plans	289		310		289
Contingently issuable shares under forward sale agreements	—		—		160
Average shares of dilutive stock	79,231		78,193		75,333

Earnings Per Share of Common Stock:
Basic	$	1.74	$	1.85	$	1.80
Diluted	$	1.73	$	1.84	$	1.78

5. 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~~None of our debt is actively traded.

As of October 31, 2015, we early adopted the accounting standard requiring that issuance costs related to a recognized long-term debt liability be presented in the balance sheet as a direct deduction from the carrying value of that debt, consistent with the presentation of debt discounts. The tables below reflect the detail of this presentation for our long-term debt as of October 31, ~~2013~~2015 and ~~2012 is as follows.~~

In thousands            2013                    2012
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
  4.65%, due August 1, 2043
   300,000    -
Medium-Term Notes:

  5.00%, due December 19, 2013
   100,000    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
   1,275,000    975,000
Less current maturities
   100,000    -
Less discount on issuance of notes
   143    -




    Total
     $ 1,174,857      $ 975,000

2014.



	Long-Term Debt as of October 31, 2015
In thousands	Principal		Unamortized Debt Issuance Expenses and Discounts			Total
Senior Notes:
2.92%, due June 6, 2016	$	40,000	$	(40	)	$	39,960
8.51%, due September 30, 2017	35,000		—			35,000
4.24%, due June 6, 2021	160,000		(752		)	159,248
3.47%, due July 16, 2027	100,000		(638		)	99,362
3.57%, due July 16, 2027	200,000		(1,307		)	198,693
4.10%, due September 18, 2034	250,000		(2,644		)	247,356
4.65%, due August 1, 2043	300,000		(3,040		)	296,960
3.60%, due September 1, 2025	150,000		(1,382		)	148,618
Medium-Term Notes:
6.87%, due October 6, 2023	45,000		(115		)	44,885
8.45%, due September 19, 2024	40,000		(115		)	39,885
7.40%, due October 3, 2025	55,000		(171		)	54,829
7.50%, due October 9, 2026	40,000		(126		)	39,874
7.95%, due September 14, 2029	60,000		(273		)	59,727
6.00%, due December 19, 2033	100,000		(720		)	99,280
Total	1,575,000		(11,323		)	1,563,677
Less current maturities	40,000		—			40,000
Total	$	1,535,000	$	(11,323	)	$	1,523,677



	Long-Term Debt as of October 31, 2014
In thousands	Principal		Unamortized Debt Issuance Expenses and Discounts			Total
Senior Notes:
2.92%, due June 6, 2016	$	40,000	$	(107	)	$	39,893
8.51%, due September 30, 2017	35,000		—			35,000
4.24%, due June 6, 2021	160,000		(887		)	159,113
3.47%, due July 16, 2027	100,000		(693		)	99,307
3.57%, due July 16, 2027	200,000		(1,418		)	198,582
4.10%, due September 18, 2034	250,000		(2,644		)	247,356
4.65%, due August 1, 2043	300,000		(3,132		)	296,868
Medium-Term Notes:
6.87%, due October 6, 2023	45,000		(129		)	44,871
8.45%, due September 19, 2024	40,000		(127		)	39,873
7.40%, due October 3, 2025	55,000		(189		)	54,811
7.50%, due October 9, 2026	40,000		(138		)	39,862
7.95%, due September 14, 2029	60,000		(292		)	59,708
6.00%, due December 19, 2033	100,000		(760		)	99,240
Total	1,425,000		(10,516		)	1,414,484
Less current maturities	—		—			—
Total	$	1,425,000	$	(10,516	)	$	1,414,484

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

In thousands
2014
     $ 100,000
2015
   -
2016
   40,000
2017
   35,000
2018
   -
Thereafter
   1,100,000


  Total
     $     1,275,000

On July 16, 2012, we issued $100 million of senior notes with an interest rate of 3.47%. On October 15, 2012, we issued $200 million of senior notes with an interest rate of 3.57%. Both issuances mature on July 16, 2027. These proceeds were used for general corporate purposes, including the repayment of short-term debt incurred in part for the funding of capital expenditures.



In thousands
2016	$	40,000
2017	35,000
2018	—
2019	—
2020	—
Thereafter	1,500,000
Total	$	1,575,000

We ~~have~~had an open combined debt and equity shelf registration statement filed with the SEC in July 2011 that iswas 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 7 to the consolidated financial statements.

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. As of October 31, 2015, we have $544.1 million remaining for debt and equity issuances as approved by the NCUC. 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 commercial paper (CP) program, to refinance other indebtedness, to repurchase our common stock, to pay dividends and for general corporate purposes, including capital expenditures, additions to working capital, advances for or investments in our subsidiaries and for repurchases of shares of our common stock. 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.

purposes.

On ~~August 1, 2013,~~September 18, 2014, we issued ~~$300~~$250 million of ~~thirty-year,~~twenty-year, unsecured senior notes with an interest rate of ~~4.65%~~4.10% and at a discount of ~~.048%~~.174% or ~~$144,000, which we began to amortize ratably over the expected life of the notes,~~$435,000 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,~~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 ~~February 1, 2043,~~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 ~~$297.2~~$247.7 million from this issuance to finance capital expenditures, to repay ~~$100~~outstanding short-term, unsecured notes under our CP program and for general corporate purposes.

On September 14, 2015, we issued $150 million of ~~our 5% medium-term~~ten-year, unsecured senior notes ~~due December 19, 2013~~with an interest rate of 3.60% and at a discount of .065% or $97,500 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 June 1, 2025, 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 25 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 June 1, 2025, at 100% of the principal amount plus any accrued and unpaid interest to the date of redemption. We used the net proceeds of $148.9 million from this issuance to finance capital expenditures, to repay outstanding short-term, unsecured notes under our ~~commercial paper (CP)~~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, ~~2013,~~2015, our ~~retained~~net earnings ~~were not restricted as the amount~~ available for restricted payments ~~was greater than our actual retained earnings as presented below.~~

In thousands

Amount available for restricted payments
   $ 760,870
Retained earnings
   627,236

were $1.2 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, ~~2013,~~2015, 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 ~~4.6~~3.96 times as of October 31, ~~2013;~~2015;

Funded debt cannot exceed 70% of total capitalization. Funded debt was ~~59%~~57% of total capitalization as of October 31, ~~2013;~~2015;

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, ~~2013;~~2015;

Restrictions on permitted liens;

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

Restrictions on burdensome agreements.

6. Short-Term Debt Instruments

At October 31, 2015, we have ~~a $650~~an $850 million five-year revolving syndicated credit facility that expires on October 1, 2017. The facility has an option to request an expansion of up to $850 million. On November 1, 2013, we entered into an agreement with the lenders under the facility which increased our borrowing capacity to $850 million. 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 ~~$2.1~~$1.6 million and ~~$3.6~~$1.8 million were issued and outstanding at October 31, ~~2013~~2015 and ~~2012,~~2014, 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 45 to the consolidated financial statements for discussion of default provisions, including cross default provisions, in all of our debt agreements.

On December 14, 2015, we entered into an agreement with the lenders under our existing $850 million five-year revolving syndicated credit facility to amend and extend the facility at substantially similar terms to our existing facility. The amended facility extended the maturity of our facility to December 14, 2020. The amended facility expressly permits the Acquisition by Duke Energy. The CP program will continue to be backstopped by the new credit facility.

We have ~~a $650~~an $850 million unsecured CP program that is backstopped by the revolving syndicated credit facility. ~~In conjunction with the exercise of the option in November 2013, the~~The amounts outstanding under the revolving syndicated credit facility and the CP program, either individually or in the aggregate, ~~have been increased to, but~~ 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 ~~unsubordinated and~~ 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, ~~2013,~~2015, we ~~have $400~~had $340 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 17 to 3714 days from their dates of issuance at a weighted average interest rate of ~~.36%~~.22%. As of October 31, ~~2012,~~2014, our outstanding notes under the CP program, included in the Consolidated Balance Sheets as stated above, were ~~$365~~$355 million at a weighted average interest rate of ~~.42%~~.17%.

We did not have any borrowings under the revolving syndicated credit facility for the twelve months ended October 31, 2015. A summary of the short-term debt activity under our CP program for the twelve months ended October 31, ~~2013~~2015 is as follows.

~~Short-Term Debt Activity~~

           Credit                 Commercial                 Total
In thousands
           Facility                 Paper                 Borrowings
      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.



In thousands
Minimum amount outstanding	$	230,000
Maximum amount outstanding	$	580,000
Minimum interest rate	.15		%
Maximum interest rate	.30		%
Weighted average interest rate	.21		%

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 ~~59%~~57% at October 31, ~~2013.~~

6.2015.

7. Stockholders’ Equity

Capital Stock

Changes in common stock for the years ended October 31, ~~2013, 2012~~2015, 2014 and ~~2011~~2013 are as follows.

In thousands
       Shares              Amount
Balance, October 31, 2010
   72,282    $ 445,640
  Issued to participants in the Employee Stock Purchase Plan (ESPP)
   30    870
  Issued to the Dividend Reinvestment and Stock Purchase Plan (DRIP)
   657    18,834
  Issued to participants in the Incentive Compensation Plan (ICP)
   149    4,451
  Shares repurchased under Accelerated Share Repurchase (ASR) agreement
   (800)       (23,004)




Balance, October 31, 2011
   72,318    446,791
  Issued to ESPP
   30    894
  Issued to DRIP
   677    20,508
  Issued to ICP
   25    796
  Shares repurchased under 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



In thousands	Shares	Amount
Balance, October 31, 2012	72,250	$	442,461
Issued to participants in the Employee Stock Purchase Plan (ESPP)	33	1,056
Issued to the Dividend Reinvestment and Stock Purchase Plan (DRIP)	720	22,791
Issued to participants in the Incentive Compensation Plan (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
Issued to ESPP	31	1,239
Issued to DRIP	669	24,679
Issued to ICP	130	4,964
Issuance of common stock through forward sale agreements, net of expenses	1,522	53,702
Balance, October 31, 2015	80,883	$	721,419

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 ~~cancelled~~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~~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.

Under our effective combined debt and equity shelf registration statement, we established an at-the-market (ATM) equity sales program, including a forward sale component. On January 7, 2015, we entered into separate ATM Equity Offering Sales Agreements (Sales Agreements) with Merrill Lynch, Pierce, Fenner & Smith Incorporated (Merrill) and J.P. Morgan Securities LLC (JP Morgan), in their capacity as agents and/or as principals (Agents). Under the terms of the Sales Agreements,

we may issue and sell, through either of the Agents, shares of our common stock, up to an aggregate sales price of $170 million (subject to certain exceptions) during the period beginning January 7, 2015 and ending October 31, 2016.

In addition to the issuance and sale of shares by us through the Agents, we may also enter into FSAs with affiliates of the Agents as Forward Purchasers. In connection with each FSA, the Forward Purchasers will, at our request, borrow from third parties and, through the Agents, sell a number of shares of our common stock equal to the number of shares underlying the FSA as its hedge. We expect to enter into separate FSAs each fiscal quarter during the term of the Sales Agreements and have done so in our second, third and fourth quarters of 2015.

Under the Sales Agreements, we specify the maximum number of our shares to be sold and the minimum price per share. We will pay each Agent (or, in the case of a FSA, the Forward Purchaser through a reduced initial forward sale price) a commission of 1.5% of the sales price of all shares sold through it as sales agent under the applicable Sales Agreement. The shares offered under the Sales Agreements may be offered, issued and sold in ATM sales through the Agents or offered in connection with one or more FSAs.

Under a FSA that we executed with Merrill on March 10, 2015, 612,000 shares were borrowed from third parties and sold by Merrill, from March 10, 2015 to April 24, 2015, at a weighted average share price of $36.83, net of adjustments. Based on the weighted average share price at the end of the trading period, the initial forward price was $36.28.

Under a FSA that we executed with JP Morgan on June 8, 2015, 795,529 shares were borrowed from third parties and sold by JP Morgan, from June 10, 2015 to July 30, 2015, at a weighted average share price of $36.42, net of adjustments. Based on the weighted average share price at the end of the trading period, the initial forward price was $35.87.

Under a FSA that we executed with Merrill on September 8, 2015, 114,500 shares were borrowed from third parties and sold by Merrill, from September 9, 2015 to September 15, 2015, at a weighted average share price of $36.58, net of adjustments. Based on the weighted average share price at the end of the trading period, the initial forward price was $36.03.

Under the terms of these FSAs, at our election, we could physically settle in shares, cash or net settle for all or a portion of our obligation under the agreements any time prior to December 15, 2015.

On October 29, 2015, we issued 1.5 million shares of our common stock to the forward counterparties by physically settling all of the FSAs entered into during 2015 and received net proceeds of $54.1 million. 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.

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 ~~as follows.~~

~~Direct shares –~~of which 3 million direct shares were issued ~~by us~~ and ~~delivered directly to the underwriters with settlement~~settled on February 4, ~~2013. We received~~2013 with proceeds of $92.6 million ~~from the underwriters and recorded this amount in “Stockholders’ equity” as an addition to “Common stock” in the Consolidated Balance Sheets.~~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 ~~net proceeds from~~remaining 1.6 million shares under this ~~sale of our common stock~~same underwriting agreement were ~~used to repay outstanding short-term, unsecured notes~~ under ~~our CP program.~~

~~Forward shares –~~FSAs with 1 million shares ~~were~~ borrowed by a forward counterparty and sold to the underwriters for resale to the public on February 4, ~~2013. Under this initial forward sale agreement (FSA) that we executed with the forward counterparty on January 29,~~ 2013 ~~we agreed to sell 1 million shares to the forward counterparty~~ at the same price as the direct ~~shares to be settled no later than mid December 2013. Under~~shares; the ~~terms of this FSA, at our election, we may physically settle in shares, cash or net share settle for all or a portion of our obligation under the agreement.~~

~~Additional shares – Up to~~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 atwhere the net price described above of $30.88 per share with settlement on February 22, 2013. We elected to place the .6 million shares under an additional FSA having substantially similar terms as the original FSA, including settlement options at our election as described above. In connection with the additional FSA, the .6 million 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~~,accounting guidance, we ~~have~~ classified the FSAs as equity transactions because the forward sale transactions ~~are~~were indexed to our own stock and physical settlement iswas 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 34 to the consolidated financial statements for the dilutive effect of the FSAs on our EPS at October 31, 2013 with the inclusion of the 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 were accounted for in the same manner.

As of October 31, ~~2013, our~~2015, shares of common stock ~~were~~ reserved for future issuance under various plans are as follows.



In thousands
ESPP	145
~~ESPP~~ DRIP	171	~~210~~
~~DRIP~~ ICP	820	~~1,538~~
~~ICP~~ Total	1,136	~~1,050~~

~~Total~~		~~2,798~~

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 1213 to the consolidated financial statements. Changes in each component of accumulated OCIL are presented below for the years ended October 31, ~~2013~~2015 and ~~2012.~~


~~Changes in Accumulated OCIL~~⁽¹⁾
~~In thousands~~

~~Balance, October 31, 2011~~	$	~~(452)~~


~~OCIL before reclassifications, net of tax~~		~~(826)~~
~~Amounts reclassified from accumulated OCIL, net of tax~~		~~973~~

~~Total current period activity, net of tax~~		~~147~~


~~Balance, October 31, 2012~~		~~(305)~~


~~OCIL before reclassifications, net of tax~~		~~(109)~~
~~Amounts reclassified from accumulated OCIL, net of tax~~		~~130~~

~~Total current period activity, net of tax~~		21


~~Balance, October 31, 2013~~	$	~~(284)~~

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

2014.



Changes in Accumulated OCIL ⁽¹⁾

In thousands	2015			2014
Accumulated OCIL beginning balance, net of tax	$	(237	)	$	(284	)
Hedging activities of equity method investments:
OCIL before reclassifications, net of tax	(1,601		)	355
Amounts reclassified from accumulated OCIL, net of tax	1,018			(284		)
Total current period activity of hedging activities of equity method investments, net of tax	(583		)	71
Net current period benefit activities of equity method investments, net of tax	(35		)	(24		)
Accumulated OCIL ending balance, net of tax	$	(855	)	$	(237	)
⁽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, ~~2013~~2015 and ~~2012.~~

   Reclassifications Out of
   Accumulated OCIL⁽¹⁾
   Years Ended
   October 31,    Affected Line Items on Statement of
In thousands    2013    2012    Comprehensive Income
Hedging activities of equity method investments
   $ (215)       $ (1,594)       Income from equity method investments
Income tax expense
   85    621    Income taxes





  Total reclassification for the period, net of tax
   $ (130)       $ (973)

⁽¹⁾ ~~Amounts in parentheses indicate credits to accumulated OCIL.~~

7.2014.



	Reclassification Out of Accumulated OCIL⁽¹⁾
	Reclassification Out of Accumulated OCIL⁽¹⁾
	Years Ended
	October 31						Affected Line Items on Statement of Comprehensive Income
In thousands	2015			2014			Affected Line Items on Statement of Comprehensive Income
Hedging activities of equity method investments	$	1,670		$	(461	)	Income from equity method investments
Income tax expense	(652		)	177			Income taxes
Net hedging activities	1,018			$	(284	)
Net benefit activities of equity method investments	(58		)	(40		)	Income from equity method investments
Income tax expense	23			16			Income taxes
Net benefit activities	(35		)	(24		)
Total reclassification for the period, net of tax	$	983		$	(308	)
⁽¹⁾ Amounts in parentheses indicate debits to accumulated OCIL.

8. 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, ~~2013~~2015 and ~~2012,~~2014, we had long gas purchase options providing total coverage of ~~25.4~~34.7 million dekatherms and ~~35.8~~29.2 million dekatherms, respectively. The long gas purchase options held at October 31, ~~2013~~2015 are for the period from December ~~2013~~2015 through October ~~2014.~~

2016.

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 ~~and liabilities~~ that were accounted for at fair value on a recurring basis as of October 31, ~~2013~~2015 and ~~2012.~~2014. 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, ~~2013~~2015 and ~~2012.~~

Recurring Fair Value Measurements as of October 31, 2013
          Significant
       Quoted Prices            Other            Significant
       in Active            Observable            Unobservable            Total
       Markets            Inputs            Inputs            Carrying
In thousands        (Level 1)            (Level 2)            (Level 3)            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

Recurring Fair Value Measurements as of October 31, 2012
          Significant
       Quoted Prices            Other            Significant
       in Active            Observable            Unobservable            Total
       Markets            Inputs            Inputs            Carrying
In thousands        (Level 1)            (Level 2)            (Level 3)            Value
Assets:

Derivatives held for distribution operations
   $ 3,153    $ -       $ -       $ 3,153
Debt and equity securities held as trading securities:

  Money markets
   243    -    -    243
  Mutual funds
   2,045    -    -    2,045








  Total fair value assets
   $ 5,441    $ -       $ -       $ 5,441

2014. 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, 2015

			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	$	1,343	$	—	$	—	$	—	$	1,343
Debt and equity securities held as trading securities:
Money markets	516		—		—		—		516
Mutual funds	4,386		—		—		—		4,386
Total fair value assets	$	6,245	$	—	$	—	$	—	$	6,245



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

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 13 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.~~ratings. The ~~carrying amount~~principal 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, 2013
   $     1,275,000    $     1,409,892
As of October 31, 2012
   975,000    1,163,227



In thousands	Principal		Fair Value
As of October 31, 2015	$	1,575,000	$	1,720,586
As of October 31, 2014	1,425,000		1,617,453

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 ~~amounts are~~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 ~~do not reflect any netting of asset and liability amounts or~~we have posted no cash collateral ~~amounts~~nor received any cash collateral under our master netting ~~arrangements.~~

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, ~~2013~~2015 and ~~2012.~~


~~Fair Value of Derivative Instruments~~

~~In thousands~~	��~~2013~~		~~2012~~

~~Derivatives Not Designated as Hedging Instruments under Derivative Accounting Standards:~~

~~Asset Financial Instruments:~~
~~Current Assets - Gas purchase derivative assets (December 2013 - October 2014)~~	$	~~1,834~~

~~Current Assets - Gas purchase derivative assets (December 2012 - October 2013)~~			$	~~3,153~~

2014.



Fair Value of Derivative Instruments

In thousands	2015		2014
Derivatives Not Designated as Hedging Instruments under Derivative Accounting Standards:
Asset Financial Instruments:
Current Assets - Gas purchase derivative assets (December 2015 - October 2016)	$	1,343
Current Assets - Gas purchase derivative assets (December 2014 - November 2015)			$	4,898

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 isare to use these financial instruments to ~~provide some level of protection against significant price increases.~~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 ~~to/~~from customers included as “Regulatory Assets” or amounts due to customers included as “Regulatory Liabilities” as presented in Note 13 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, ~~2013~~2015 and ~~2012,~~2014, absent the regulatory treatment under our approved PGA procedures.

         Location of Loss
   Amount of Loss Recognized    Amount of Loss Deferred    Recognized through
In thousands    on Derivative Instruments    Under PGA Procedures    PGA Procedures
       Twelve Months Ended            Twelve Months Ended
   October 31        October 31
       2013             2012            2013             2012
Gas purchase options
   $         6,303         $         8       $         6,303         $         8       Cost of Gas



	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	2015			2014		2015			2014
Gas purchase options	$	(4,423	)	$	6,162	$	(4,423	)	$	6,162	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 as 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 as 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~~have historically occurred in the ~~eastern,~~ gulf coast and mid-west regions of the United ~~States. We believe that this geographic concentration does not contribute significantly to~~States, but our ~~overall exposure to credit risk.~~portfolio is being rebalanced and diversified by adding gas supply from northeastern United States gas supply basins. 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 ~~$13.4~~$2.9 million, or approximately ~~17%~~5% of our gross trade accounts receivable at October 31, ~~2013.~~2015. 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~~investment-grade or functionally equivalent credit ratings, our policy requires credit enhancements that include letters of credit or parental guaranties. In either circumstance, ~~the~~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.

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 anthe direction of the Treasurer and Chief Risk Officer and our Enterprise Risk Management ~~program. In addition, we have an~~program, including our Energy Price Risk Management ~~Committee that monitors compliance~~Committee. Risk management is guided by senior management with ~~our hedging programs,~~Board of Directors oversight, and senior management takes an active role in the development of policies and procedures.

9. 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, ~~2013, 2012~~2015, 2014 and ~~2011~~2013 are as follows.

In thousands 2013 2012 2011
Operating lease payments⁽¹⁾
$ 4,729 $ 3,712 $ 4,496

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



In thousands	2015		2014		2013
Operating lease payments ⁽¹⁾	$	5,024	$	4,701	$	4,729

⁽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

2014
   $ 4,543
2015
   4,592
2016
   4,491
2017
   4,297
2018
   4,225
Thereafter
   31,496


  Total
   $         53,644



In thousands
2016	$	5,052
2017	4,706
2018	4,609
2019	4,433
2020	4,477
Thereafter	24,413
Total	$	47,690

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-two~~twenty years. The time periods for fixed payments under gas supply contracts are up to ~~one year.~~two years. The time period for the gas supply purchase commitments is up to fifteen 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 ~~three~~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, ~~2013,~~2015, future unconditional purchase obligations for the next five years ending October 31 and thereafter are as follows.

       Pipeline and               Telecommunications
       Storage               and Information
In thousands            Capacity                Gas Supply            Technology            Other                Total
2014
     $ 170,430      $ 6,356      $ 11,045      $ 24,951      $ 212,782
2015
   157,407    -    4,676    -       162,083
2016
   150,544    -       760    -       151,304
2017
   145,494    -       -       -       145,494
2018
   142,983    -       -       -       142,983
Thereafter
   781,549    -       -       -       781,549










  Total
     $     1,548,407      $     6,356      $     16,481      $     24,951      $     1,596,195



	Pipeline		Gas Supply		Gas Supply		Telecommunications
	and Storage		Reservation		Purchase		and Information
In thousands	Capacity		Fees		Commitments		Technology		Other		Total
2016	$	178,594	$	4,577	$	65,286	$	6,164	$	45,577	$	300,198
2017	163,806		165		89,784		1,639		—		255,394
2018	143,728		—		69,569		669		—		213,966
2019	132,259		—		69,569		610		—		202,438
2020	114,400		—		69,759		—		—		184,159
Thereafter	516,333		—		707,698		—		—		1,224,031
Total	$	1,249,120	$	4,742	$	1,071,665	$	9,082	$	45,577	$	2,380,186

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 ~~$2.1~~$1.6 million in letters of credit that were issued and outstanding at October 31, ~~2013.~~2015. Additional information concerning letters of credit is included in Note 56 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, 2015, we had open surety bonds with a total contingent obligation of $6.6 million.

Environmental Matters

Our three regulatory commissions have authorized us to utilize deferral accounting in connection with costs for environmental ~~costs.~~assessments and cleanups. Accordingly, we have established regulatory assets for actual environmental costs incurred and ~~for~~have recorded estimated environmental liabilities, ~~recorded.~~

including those for our 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 ~~manufactured gas plant (MGP)~~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~~our 2003 North Carolina Natural Gas Corporation (NCNG) acquisition, several MGP sites owned by NCNG were transferred to a ~~wholly owned~~wholly-owned subsidiary of Progress Energy, Inc. (Progress), now a subsidiary of Duke Energy, ~~Corporation (DEC),~~ 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.

~~There are four other~~

As of October 31, 2015, our estimated undiscounted environmental liability totaled $1.2 million, and consisted of $1.1 million for MGP sites ~~located in Reidsville and Hickory, North Carolina, Nashville, Tennessee and Anderson, South Carolina that we have owned, leased or operated and~~ for which we ~~have an investigation~~retain responsibility and ~~remediation liability. In fiscal year 2012,~~$.1 million for the Huntersville LNG facility. The costs we ~~performed soil remediation work at our Reidsville site. In July 2012,~~reasonable expect to incur are estimated using assumptions based on actual costs incurred, the ~~North Carolina Department~~timing of ~~Environment~~future payments and Natural Resources (NCDENR) approved our proposed groundwater investigation work plan, which included installing five monitoring wells in September 2012. The NCDENR is no longer requiring the groundwater remedial action plan. We filed land use restrictions on the property with the NCDENR in the fourth quarter of our fiscal year 2013. Upon NCDENR’s completed review, we will file land use restrictions with the Register of Deeds for Reidsville, North Carolina.inflation factors, among others. We have incurred ~~$.6~~$2.2 million of remediation costs ~~at the Reidsville site through October 31, 2013.~~

~~As part of a voluntary agreement with the NCDENR, we conducted~~related to our MGP sites and completed soil remediation for the Hickory, North Carolina MGP site in 2010. A Phase II groundwater investigation was conducted in 2011. A groundwater remedial action plan was submitted and approved by NCDENR in 2012. We continue$4.8 million related to conduct quarterly groundwater monitoring at this site in accordance with our site remediation plan. NCDENR has approved land use restrictions on this site. Once we obtain the property owner’s signature, we will then file land use restrictions with the Register of Deeds for Hickory, North Carolina. We have incurred $1.5 million of remediation costs at this site through October 31, 2013.

In November 2008, we submitted our final report of the remediation of the Nashville MGP holding tank site to the Tennessee Department of Environment and Conservation (TDEC). Remediation has been completed, and a final consent order imposing land usage restrictions on the property was approved and signed by the TDEC in June 2010. The final consent order required two years of semi-annual groundwater monitoring, which has been completed. We have incurred $1.5 million of remediation costs at this site through October 31, 2013.

~~During 2008, we became aware of and began investigating soil and groundwater molecular sieve contamination concerns at~~ our Huntersville LNG facility. The molecular sieve and the related contaminated soil were removed and properly disposed, and in June 2010, we received a determination letter from the NCDENR that no further soil remediation would be required at the

~~site for this issue. In September 2011, we received a letter from the NCDENR indicating their desire~~

We continue to enter into an Administrative Consent Order (ACO) addressing the remaining groundwater issues at the site. On April 11, 2012, we entered into a no admit/no deny ACO that imposed a fine of $40,000, unpaid annual fees totaling $18,000 and investigative and administrative costs of $1,860. As part of the ACO, we are required to develop a site assessment plan to determine the extent of the groundwater contamination related to the sieve burial, a groundwater remediation strategy and a groundwater and surface water site-wide monitoring program. A site assessment plan was accepted by the NCDENR, and we began groundwaterexpand our sampling in July 2012. We performed an initial round of sampling in November and December 2012 which was inconclusive as to migration, and thus additional groundwater monitoring wells were installed during March 2013 to aid in determining the extent of the groundwater contamination. The groundwater sampling results were submitted to the NCDENR in October 2013, and based on their response, we may be required to submit additional plan(s) to remediate and/or monitor the groundwater.

The Huntersville LNG facility was originally coated with lead-based paint. To avoid lead-based paint exposure or ground contamination, removal of lead-based paint from the site was initiated in spring 2010. The last phase of the lead-based paint removal began in July 2012 on the LNG tank, and the remediation of rafters in a nearby building began in the fourth quarter of our ~~fiscal year 2013 with completion anticipated~~pipelines for ~~both projects by the end of fiscal 2014. We have incurred $4.6 million of remediation costs through October 31, 2013 for all issues at the Huntersville LNG plant site.~~

~~Our Nashville LNG facility was also originally coated with lead-based paint. We completed the remediation of the facility in May 2012 and incurred $.5 million of remediation costs.~~

We have transitioned away from owning and maintaining our own petroleum underground storage tanks (USTs) with the exception of our Charlotte, North Carolina resource center which continues to operate two USTs. During 2011, our Greenville, South Carolina and Greensboro and Salisbury, North Carolina resource centers had their tanks removed, and we do not anticipate significant environmental remediation with respect to those removals. The South Carolina Department of Health and Environmental Control (SCDHEC) requested that we conduct an initial groundwater assessment at our Greenville, South Carolina site to determine its current groundwater quality condition. This assessment was conducted in August 2012, and in November 2012, we received a determination letter from the SCDHEC that no further groundwater remediation would be required at the site for this issue.

In July 2005, we were notified by the NCDENR that we were named as a potentially responsible party for alleged environmental issues associated with a propane UST site in Clemmons, North Carolina. We owned and operated this site from March 1986 until June 1988 in connection with a non-utility venture. There have been at least four owners of the site. We contend that we contractually transferred any and all clean-up costs to the new owner of the site when we sold this venture in June 1988. However, the owners that purchased the property contend that we only transferred the clean-up costs associated with the gasoline pumps and not the USTs. It is unclear of the outcome of this case and how many of the former owners may ultimately be responsible for this site. Based on the uncertainty of the ultimate liability, we established an immaterial non-regulated environmental liability for one-fourth of the estimated cost to remediate the site.

~~One of our resource centers has~~ coatings containing ~~asbestos on some of their pipelines. We have educated~~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, which generally occur only in small increments.~~

For all the matters discussed above, as of October 31, 2013, our estimated undiscounted environmental liability totaled $1.3 million, and consisted of $1.1 million for the MGP sites for which we retain remediation responsibility, $.1 million for the groundwater remediation at the Huntersville LNG site, and $.1 million for the LNG facilities and USTs not yet remediated. The costs we reasonably expect to incur are estimated using assumptions based on actual costs incurred, the timing of future payments and inflation factors, among others.

pipeline.

As of October 31, ~~2013,~~2015, our regulatory assets for unamortized environmental costs in our three-state territory totaled ~~$9.4~~$6.6 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 ~~approves~~allowed recovery of $6.3 million of our deferred North Carolina environmental costs over a five-year period beginning January 2014. We received approval from the PSCSC to recover ~~$.2~~$.1 million of our deferred South Carolina environmental costs over a one-year period beginning November ~~2013,~~2014, pursuant to the annual rate stabilization order ~~dated~~issued in October ~~2013. For further information on regulatory matters, see Note 2 to the consolidated financial statements.~~

2014.

Further evaluation of the MGP, LNG and UST sites ~~and removal of lead-based paint at our LNG site~~ 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.

10. 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~~the following types of investments:

Fixed income ~~securities, including~~securities: includes U.S. treasuries, corporate bonds, high yield ~~bonds,~~debt (bank loans), 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~~

Equity securities: includes 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~~

Real estate: includes a diversified global real estate investment trust ~~(REIT)~~ fund. ~~The remaining 15% target allocation is for investments in other types of funds, including~~

Other investments: includes commodities, hedge funds and private equity funds that follow several diversified strategies.

The target and actual allocations of the qualified pension plan's assets are as follows:



	Target		Assets at October 31
Asset Allocations	Allocation		2015		2014
Fixed income securities	45	%	46	%	45	%
Equity securities	35	%	34	%	31	%
Real estate	5	%	5	%	5	%
Cash and cash equivalents	—	%	1	%	8	%
Other investments	15	%	14	%	11	%
Total	100	%	100	%	100	%

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, 2015, 2014 and 2013 we contributed $1.4 million, $.9 million and $.7 million, respectively, 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~~Employees hired after 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~~benefit of $15,000.

In September 2015, we announced the replacement of the existing retiree medical and dental group coverage for eligible retirees with a tax-free Health Reimbursement Arrangement (HRA), effective January 1, ~~2005, this benefit is $15,000.~~2016. Under the new HRA, participating eligible retirees and their dependents will receive a subsidy each year through the HRA account to help purchase medical and dental coverage available on public and private health care exchanges using a tax-advantaged account funded by us to pay for allowable medical expenses. The ~~life insurance amount for employees who retired prior~~impact of the amendment was not material to ~~this date was calculated as a percentage of their basic life insurance prior to retirement.~~

us.

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~~above, except the 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.portfolio does not include derivatives. We do not have a concentration of assets in a single entity, industry, country, commodity or class of investment fund.

The target and actual allocations of the OPEB plan's assets are as follows:



	Target			Assets at October 31
Asset Allocations	Allocation			2015		2014
Fixed income securities	45	%	⁽¹⁾	47	%	44	%
Equity securities	47	%		44	%	42	%
Real estate	5	%		5	%	5	%
Cash and cash equivalents	3	%		4	%	9	%
Total	100	%		100	%	100	%
⁽¹⁾Includes 5% target allocation to high yield fixed income.

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~~certain 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.contributions. 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 (VDP), 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~~VDP on a specified date that is at least two years from the date of deferral, a change in control, on separation of service or upon death.

~~The~~

Our funding to the DCR plan ~~accounts~~account for the years ended October 31, ~~2013~~2015 and ~~2012,~~2014, and the amounts recorded as liabilities for these two deferred compensation plans as of October 31, ~~2013~~2015 and ~~2012~~2014, are presented below.

In thousands        2013            2012
Funding
   $ 434    $ 422
Liability:

  Current
   199    160
  Noncurrent
   3,328    2,412



In thousands	2015		2014
Funding	$	548	$	524
Liability:
Current	236		214
Noncurrent	5,089		4,248

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        2013            2012            2011
Term life policies of certain officers at the vice president level and above
   $ 27    $ 43    $ 56
Officers and director-level employees
   28    25    24



In thousands	2015		2014		2013
Term life policies of certain officers at the vice president level and above	$	35	$	30	$	27
Officers and director-level employees	30		32		28

Actuarial Plan Information

A reconciliation of changes in the plans’ benefit obligations and fair value of assets for the years ended October 31, ~~2013~~2015 and ~~2012, and~~2014, a statement of the funded status and the amounts reflected in the Consolidated Balance Sheets for the years ended October 31, ~~2013~~2015 and ~~2012~~2014, and the weighted average assumptions used in the measurement of the benefit obligations as of October 31, 2015 and 2014 are presented below.

       Qualified Pension            Nonqualified Pension            Other Benefits
In thousands          2013                2012                2013                2012                2013                2012
Accumulated benefit obligation at year end
     $ 230,175      $     245,361      $ 4,736      $ 5,569        N/A            N/A












Change in projected benefit obligation:

  Obligation at beginning of year
     $ 293,327      $ 236,632      $ 5,569      $ 5,219      $ 34,830      $ 31,900
  Service cost
   12,005    9,573    -       39    1,327    1,387
  Interest cost
   9,946    10,640    157    203    1,130    1,347
  Actuarial (gain) loss
   (24,859)       54,852    (540)       629    (1,094)       2,630
  Participant contributions
   -       -       -       -       641    788
  Administrative expenses
   (534)       (420)       -       -       -       -
  Benefit payments
   (17,482)       (17,950)       (450)       (521)       (3,156)       (3,222)












  Obligation at end of year
       272,403    293,327    4,736    5,569    33,678    34,830












Change in fair value of plan assets:

  Fair value at beginning of year
   272,337    259,511    -       -       23,663    22,045
  Actual return on plan assets
   26,340    31,196    -       -       2,848    1,972
  Employer contributions
   20,000    -       450    521    1,965    2,080
  Participant contributions
   -       -       -       -       641    788
  Administrative expenses
   (534)       (420)       -       -       -       -
  Benefit payments
   (17,482)       (17,950)       (450)       (521)       (3,156)       (3,222)












  Fair value at end of year
   300,661    272,337    -       -       25,961    23,663












Funded status at year end - (under) over
     $ 28,258      $ (20,990)         $ (4,736)         $ (5,569)         $ (7,717)         $ (11,167)












  Noncurrent assets
     $ 28,258      $ -         $ -         $ -         $ -         $ -
  Current liabilities
   -       -       (445)       (502)       -       -
  Noncurrent liabilities
   -       (20,990)       (4,291)       (5,067)       (7,717)       (11,167)












  Net amount recognized
     $ 28,258      $ (20,990)       $ (4,736)         $ (5,569)         $ (7,717)         $ (11,167)












Amounts Not Yet Recognized as a Component of Cost and Recognized in a Deferred

  Regulatory Account:

    Unrecognized transition obligation
     $ -         $ -         $ -         $ -         $ -         $ (667)
    Unrecognized prior service (cost) credit
   17,243    19,441    (196)       (277)       -       -
    Unrecognized actuarial loss
   (96,338)       (137,633)       (820)       (1,521)       (354)       (2,633)












    Regulatory asset
   (79,095)       (118,192)       (1,016)       (1,798)       (354)       (3,300)
    Cumulative employer contributions in excess of cost
   107,353    97,202    (3,720)       (3,771)       (7,363)       (7,867)












    Net amount recognized
     $ 28,258      $ (20,990)         $     (4,736)         $     (5,569)         $     (7,717)         $     (11,167)



	Qualified Pension						Nonqualified Pension						Other Benefits
In thousands	2015			2014			2015			2014			2015			2014
Accumulated benefit obligation at year end	$	263,120		$	252,706		$	5,527		$	5,925		N/A			N/A

Change in projected benefit obligation:
Obligation at beginning of year	$	302,686		$	272,403		$	5,925		$	4,736		$	37,817		$	33,678
Service cost	11,403			10,865			—			—			1,182			1,109
Interest cost	12,018			11,781			209			200			1,475			1,448
Plan amendments	—			—			—			485			(1,877		)	—
Actuarial (gain) loss	3,524			23,646			(100		)	956			1,697			3,734
Participant contributions	—			—			—			—			611			805
Administrative expenses	(590		)	(465		)	—			—			—			—
Benefit payments	(17,504		)	(15,544		)	(507		)	(452		)	(3,348		)	(2,957		)
Obligation at end of year	311,537			302,686			5,527			5,925			37,557			37,817
Change in fair value of plan assets:
Fair value at beginning of year	336,443			300,661			—			—			27,747			25,961
Actual return on plan assets	958			31,791			—			—			315			1,874
Employer contributions	10,000			20,000			507			452			2,221			2,064
Participant contributions	—			—			—			—			611			805
Administrative expenses	(590		)	(465		)	—			—			—			—
Benefit payments	(17,504		)	(15,544		)	(507		)	(452		)	(3,348		)	(2,957		)
Fair value at end of year	329,307			336,443			—			—			27,546			27,747
Funded status at year end - over (under)	$	17,770		$	33,757		$	(5,527	)	$	(5,925	)	$	(10,011	)	$	(10,070	)

Noncurrent assets	$	17,770		$	33,757		$	—		$	—		$	—		$	—
Current liabilities	—			—			(520		)	(521		)	—			—
Noncurrent liabilities	—			—			(5,007		)	(5,404		)	(10,011		)	(10,070		)
Net amount recognized	$	17,770		$	33,757		$	(5,527	)	$	(5,925	)	$	(10,011	)	$	(10,070	)

Amounts Not Yet Recognized as a Component
of Cost and Recognized in a Deferred
Regulatory Account:
Unrecognized prior service credit (cost)	$	12,848		$	15,046		$	(208	)	$	(439	)	$	1,877		$	—
Unrecognized actuarial loss	(120,541		)	(103,038		)	(1,560		)	(1,745		)	(7,185		)	(3,995		)
Regulatory asset	(107,693		)	(87,992		)	(1,768		)	(2,184		)	(5,308		)	(3,995		)
Cumulative employer contributions in
excess of cost	125,463			121,749			(3,759		)	(3,741		)	(4,703		)	(6,075		)
Net amount recognized	$	17,770		$	33,757		$	(5,527	)	$	(5,925	)	$	(10,011	)	$	(10,070	)

Weighted average assumptions used in the measurement of
the benefit obligations:
Discount rate	4.34		%	4.13		%	3.85		%	3.69		%	4.38		%	4.03		%
Rate of compensation increase	4.07		%	3.68		%	N/A			N/A			N/A			N/A

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 as presented above instead of ~~OCIL as presented above.~~OCIL. The regulators have allowed future recovery of our pension and OPEB costs to this date.

Net periodic benefit cost components for the years ended October 31, 2015, 2014 and 2013 ~~2012~~ and ~~2011 includes~~ the ~~following components.~~

Qualified Pension

Nonqualified Pension

Other Benefits

In thousands

2013

2012

2011

2013

2012

2011

2013

2012

2011

Service cost
     $ 12,005      $ 9,573      $ 8,508      $ -         $ 39      $ 45      $ 1,327      $ 1,387      $ 1,398
Interest cost
   9,946    10,640    11,024    157    203        209    1,130    1,347    1,495
Expected return on plan assets
       (21,105)           (20,289)           (20,608)       -       -       -       (1,663)           (1,551)       (1,534)
Amortization of transition obligation
   -       -       -       -       -       -       667    667    667
Amortization of prior service cost (credit)
   (2,198)       (2,198)       (2,198)       81    81    20    -       -       -
Amortization of net loss
   11,202    5,966    3,547    161    49    41    -       -       -


















Net periodic benefit cost
   9,850    3,692    273    399    372    315    1,461    1,850    2,026


















Other changes in plan assets and benefit obligation recognized through regulatory asset or liability:

Prior service cost
   -       -       -       -       -       290    -       -       -
Net loss (gain)
   (30,094)       43,945    17,539        (540)           629    130    (2,278)       2,209    415
Amounts recognized as a component of net periodic benefit cost:

Transition obligation
   -       -       -       -       -       -       (667)       (667)       (667)
Amortization of net loss
   (11,202)       (5,966)       (3,547)       (161)       (49)       (41)       -       -       -
Prior service (cost) credit
   2,198    2,198    2,198    (81)       (81)       (20)       -       -       -


















Total recognized in regulatory asset (liability)
   (39,098)       40,177    16,190    (782)       499    359    (2,945)       1,542    (252)


















Total recognized in net periodic benefit cost and regulatory asset (liability)
     $ (29,248)         $ 43,869      $ 16,463      $ (383)         $ 871      $ 674      $     (1,484)         $ 3,392      $     1,774

weighted average assumptions used to determine net period benefit cost as of October 31, 2015, 2014 and 2013 are presented below.



	Qualified Pension									Nonqualified Pension									Other Benefits
In thousands	2015			2014			2013			2015			2014			2013			2015			2014			2013
Service cost	$	11,403		$	10,865		$	12,005		$	—		$	—		$	—		$	1,182		$	1,109		$	1,327
Interest cost	12,018			11,781			9,946			209			200			157			1,475			1,448			1,130
Expected return on plan assets	(23,614		)	(22,530		)	(21,105		)	—			—			—			(1,837		)	(1,782		)	(1,663		)
Amortization of transition obligation	—			—			—			—			—			—			—			—			667
Amortization of prior service cost
(credit)	(2,198		)	(2,198		)	(2,198		)	231			243			81			—			—			—
Amortization of net loss	8,676			7,685			11,202			85			31			161			29			—			—
Net periodic benefit cost	6,285			5,603			9,850			525			474			399			849			775			1,461
Other changes in plan assets and benefit
obligation recognized through
regulatory asset or liability:
Prior service cost (credit)	—			—			—			—			485			—			(1,877		)	—			—
Net loss (gain)	26,179			14,385			(30,094		)	(100		)	956			(540		)	3,219			3,641			(2,278		)
Amounts recognized as a component of
net periodic benefit cost:
Transition obligation	—			—			—			—			—			—			—			—			(667		)
Amortization of net loss	(8,676		)	(7,685		)	(11,202		)	(85		)	(31		)	(161		)	(29		)	—			—
Prior service (cost) credit	2,198			2,198			2,198			(231		)	(243		)	(81		)	—			—			—
Total recognized in regulatory asset
(liability)	19,701			8,898			(39,098		)	(416		)	1,167			(782		)	1,313			3,641			(2,945		)
Total recognized in net periodic benefit
and regulatory asset (liability)	$	25,986		$	14,501		$	(29,248	)	$	109		$	1,641		$	(383	)	$	2,162		$	4,416		$	(1,484	)

Weighted average assumptions used to determine the net periodic benefit cost:
Discount rate	4.13		%	4.55		%	3.51		%	3.69		%	3.98		%	2.95		%	4.03		%	4.44		%	3.34		%
Expected long-term rate of return on plan assets	7.50		%	7.75		%	8.00		%	N/A			N/A			N/A			7.50		%	7.75		%	8.00		%
Rate of compensation increase	3.68		%	3.72		%	3.76		%	N/A			N/A			N/A			N/A			N/A			N/A

The ~~2014~~2016 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.

In thousands
   Qualified Pension Nonqualified Pension    Other Benefits
Amortization of unrecognized prior service cost (credit)
   $ (2,198 ) $ 81    $ -
Amortization of unrecognized actuarial loss
   7,138 47    -



	Qualified			Nonqualified		Other
In thousands	Pension			Pension		Benefits
Amortization of unrecognized prior service (credit) cost	$	(2,198	)	$	208	$	(332	)
Amortization of unrecognized actuarial loss	8,164			81		459

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, ~~2013,~~2015, the benchmark by plan was as follows.



~~Pension~~Qualified pension plan	~~4.55~~4.34	%
NCNG SERP	~~3.89~~3.78	%
Directors’ SERP	~~4.09~~3.91	%
Piedmont SERP	~~3.31~~3.17	%
OPEB	~~4.44~~4.38	%

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~~

In addition to the assumptions ~~used~~ in the ~~measurement~~above table, we also use subjective factors such as withdrawal and mortality rates in determining benefit obligations for all of our benefit plans. Our assumed mortality rates incorporate the ~~benefit obligation as~~new set of mortality tables issued by the Society of Actuaries in October ~~31, 2013 and 2012 are presented below.~~

Qualified Pension

Nonqualified Pension

Other Benefits


2013

2012

2013

2012

2013

2012

Discount rate
   4.55%       3.51%       3.98%       2.95%       4.44%       3.34%
Rate of compensation increase
   3.72%       3.76%       N/A       N/A       N/A       N/A

~~The weighted average assumptions used to determine~~2014. We also applied the ~~net periodic benefit cost as~~updated projection scale issued by the Society of Actuaries in October ~~31, 2013, 2012 and 2011 are presented below.~~

Qualified Pension

Nonqualified Pension


2013

2012

2011

2013

2012

2011

Discount rate
   3.51 % 4.67 % 5.47 % 2.95 % 4.10 % 4.37 %
Expected long-term rate of return on plan assets
   8.00 % 8.00 % 8.00 % N/A    N/A    N/A
Rate of compensation increase
   3.76 % 3.78 % 3.87 % N/A    N/A    N/A

Other Benefits


2013

2012

2011

Discount rate
   3.34 % 4.36 % 4.85 %
Expected long-term rate of return on plan assets
   8.00 % 8.00 % 8.00 %
Rate of compensation increase
   N/A    N/A    N/A

2015.

We anticipate that we will contribute the following amounts to our plans in ~~2014.~~


~~In thousands~~

Qualified pension plan *	$	~~20,000~~
~~Nonqualified pension plans~~		~~444~~
~~MPP plan~~		~~885~~
~~OPEB plan~~		~~1,500~~

* Funded in November 2013.

2016.



In thousands
Qualified pension plan *	$	10,000
Nonqualified pension plans	520
MPP plan	1,650
OPEB plan	1,300

* Funded in November 2015.

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

the PPA.

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

2014
   $ 25,918    $ 444    $ 2,140
2015
   16,918    458    2,262
2016
   15,169    434    2,322
2017
   16,154    410    2,417
2018
   18,672    383    2,507
2019 - 2023
       106,226        1,890        13,640



	Qualified		Nonqualified		Other
In thousands	Pension		Pension		Benefits
2016	$	28,147	$	520	$	1,987
2017	19,911		504		2,145
2018	20,413		482		2,301
2019	21,348		510		2,421
2020	21,829		491		2,494
2021 - 2025	114,267		2,100		13,379

Based on the retiree medical and dental group coverage changing to a HRA where the retiree subsidy provided by Piedmont is fixed and assumed to not increase, we are no longer impacted by the health care cost component (projected health care cost trend rates) for our accumulated postretirement benefit obligation as of October 31, 2015.

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, ~~2013 and 2012 are~~2014 is presented below.

2013

2012

Health care cost trend rate assumed for next year
   7.40 % 7.50 %
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



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

The health care cost trend rate assumptions could have a significant effect on ~~the~~ amounts ~~reported.~~reported as benefit cost. 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, 2013
   $ 21    $ (27 )
Effect on the health care cost component of the accumulated postretirement benefit obligation as of October 31, 2013
   690    (699 )

effect.



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, 2015	$	34	$	(35	)

total benefit obligations as the change in the service and interest costs is completely offset by the actuarial (gain) loss reported. We will account for this change as a change in estimate and, accordingly, will account for it prospectively beginning in 2016.

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~~are valued at the market value of the shares held by the plan at the valuation date for a money market mutual fund.

Fixed income securities – These assets include:

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

~~Large cap core index~~

Equity securities – 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~~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 (and for 2012, international value)~~

Mutual funds – These are Level 1 assets valued at the publicly quoted NAV per share computed as of ~~mutual fund shares in managed equity funds.~~

the close of business on our balance sheet date. Mutual funds with a NAV per share that is not publicly available are classified as Level 2.

Common trust ~~funds – International growth and international value~~fund – These are Level 2 assets held in a common trust ~~funds~~fund 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 5%3.5% but is still being funded through capital calls; ~~$7.4~~$4 million of the original $12 million subscription remains unfunded. Until a 5%3.5% allocation can be achieved, the balance of the 5%3.5% allocation is invested in a low-cost equity index fund that tracks the ~~S&P~~Standard & Poor's 500 Stock Index. Our investment is in various funds that invests in North American ~~companies;~~companies, allocate capital to private equity ~~funds;~~funds, invest in venture capital ~~partnerships;~~partnerships and private equity partnerships in emerging markets.

The following investments are measured at NAV and are not classified in the fair value hierarchy, in accordance with accounting guidance.

Hedge fund of funds – 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.

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.

High yield debt (bank loans) – These assets are held in a common trust fund that invest in global bank loans. Currently, there are no restrictions on redemption for the fund.

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			~~Redemptions~~ Notice
Investment	Frequency		Other Redemption Restrictions	Period

Common trust fund - International growth	Monthly		None	30 days

~~Common trust fund -~~ ~~International value~~		~~Daily~~			~~None~~	~~5 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, ~~2013.~~ 2015.	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 atas of October 31, ~~2013~~2015 and ~~2012~~2014 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, 2013

    Quoted Prices
in Active
Markets

Significant
Other
Observable
Inputs

Significant
Unobservable
Inputs

Total
Carrying
   % of
In thousands
   (Level 1)    (Level 2)    (Level 3)    Value    Total
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      -%
Municipals
   -         -         -         -         -%
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%

      Qualified Pension Plan as of October 31, 2012
      Quoted Prices
in Active
Markets    Significant
Other
Observable
Inputs    Significant
Unobservable
Inputs    Total
Carrying    % of
In thousands
   (Level 1)    (Level 2)    (Level 3)    Value    Total
Cash and cash equivalents
     $ 5,346      $ -      $ -      $ 5,346    2%


Fixed Income Securities:
               45%


U.S. treasuries
   -    17,544    -    17,544    6%
Long duration bonds
   -    63,565    -    63,565    23%
Corporate bonds
   -    26,368    -    26,368    10%
High yield bonds
   13,777    -    -    13,777    5%
Collateralized mortgage obligations
   -    1,513    -    1,513    1%
Municipals
   -    345    -    345    -%
Derivatives
   (3)       (86)       -    (89)       -%


Equity Securities:
               36%


Large cap core index
   10,260    -    -    10,260    4%
Large cap value
   10,427    -    -    10,427    4%
Large cap growth
   15,252    -    -    15,252    6%
Small cap value
   26,335    -    -    26,335    10%
International value
   14,376    -    -    14,376    5%
Common trust fund - International growth
   -    18,678    -    18,678    7%


Real Estate:
               6%


Global REIT
   16,252    -    -    16,252    6%


Other Investments:
               11%


Hedge fund of funds
   -    16,995    -    16,995    6%
Private equity fund of funds
   -    -    3,522    3,522    1%
Commodities fund of funds
   -    11,871    -    11,871    4%










Total assets at fair value
     $     112,022      $     156,793      $       3,522      $     272,337        100%










Percent of fair value hierarchy
   41%       58%       1%       100%

In 2012, we transferred amounts from Level 3 to Level 2 for our investments in the hedge fund of funds and the commodities fund of funds because inputs became more observable. The international value fund that was classified as a Level 1 asset as of October 31, 2012 was sold, and the proceeds were invested in the common trust fund – international value during fiscal year 2013.



	Qualified Pension Plan as of October 31, 2015
In thousands	Quoted Prices In Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total Carrying Value
Cash and cash equivalents	$	2,782	$	89	$	—	$	2,871
Fixed income securities	—		84,135		—		84,135
Equity securities	44,738		—		—		44,738
Mutual funds	78,853		42,890		—		121,743
Common trust fund	—		23,571		—		23,571
Private equity fund of funds	—		—		8,344		8,344
Other Investments:
Hedge fund of funds							19,809		⁽¹⁾
Commodities fund of funds							7,688		⁽¹⁾
High yield debt (bank loans)							16,408		⁽¹⁾
Total assets at fair value	$	126,373	$	150,685	$	8,344	$	329,307



	Qualified Pension Plan as of October 31, 2014
In thousands	Quoted Prices In Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total Carrying Value
Cash and cash equivalents	$	27,932	$	435	$	—	$	28,367
Fixed income securities	48		78,026		—		78,074
Equity securities	51,266		—		—		51,266
Mutual funds	54,502		48,049		—		102,551
Common trust fund	—		22,877		—		22,877
Private equity fund of funds	—		—		7,158		7,158
Other Investments:
Hedge fund of funds							19,829		⁽¹⁾
Commodities fund of funds							10,134		⁽¹⁾
High yield debt (bank loans)							16,187		⁽¹⁾
Total assets at fair value	$	133,748	$	149,387	$	7,158	$	336,443

⁽¹⁾ In accordance with accounting guidance, certain investments that are measured at fair value using the NAV per share (or its equivalent) practical expedient have not been classified in the fair value hierarchy. The fair value amounts presented in these tables for these investments are intended to permit reconciliation of the fair value hierarchy to the amounts presented in the reconciliation of changes in the plans’ benefit obligations and fair value of plan assets above.

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

      Hedge Fund    Private
Equity Fund    Commodities
In thousands
   of Funds    of Funds    Fund of Funds    Total
Balance, October 31, 2011
     $     6,207         $     1,925         $     8,472         $     16,604
Actual return on plan assets:

Relating to assets still held at the reporting date
   -       13       -          13
Relating to assets sold during the period
   -          145       -          145
Purchases, sales and settlements (net)
   -          1,439       -          1,439
Transfer in/out of Level 3
   (6,207)         -          (8,472)         (14,679)








Balance, October 31, 2012
   -          3,522       -          3,522
Actual return on plan assets:

Relating to assets still held at the reporting date
   -          116       -          116
Relating to assets sold during the period
   -          61       -          61
Purchases, sales and settlements (net)
   -          960       -          960
Transfer in/out of Level 3
   -          -          -          -








Balance, October 31, 2013
     $ -            $ 4,659         $ -            $ 4,659



	Private
	Equity Fund
In thousands	of Funds
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
Actual return on plan assets:
Relating to assets still held at the reporting date	413
Relating to assets sold during the period	618
Purchases, sales and settlements (net)	155
Transfer in/out of Level 3	—
Balance, October 31, 2015	$	8,344

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.~~

plan.

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~~

Mutual funds – These are Level 1 assets valued at the publicly 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 a high yield bond fund.~~

~~Large cap value, large cap growth, small cap growth, small cap value – These are Level 1 assets valued at the quoted NAV~~per share computed 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~~close of ~~mutual fund shares in a managed equity fund that invests globally but primarily in the United States.~~

business on our balance sheet date.

The OPEB plan’s asset allocations by level within the fair value hierarchy atas of October 31, ~~2013~~2015 and ~~2012~~2014 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, 2013
      Quoted Prices
in Active
Markets    Significant
Other
Observable
Inputs    Significant
Unobservable
Inputs    Total Carrying    % of
In thousands

(Level 1)

(Level 2)

(Level 3)

Value

Total

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%

   Other Benefits as of October 31, 2012
      Quoted Prices
in Active
Markets    Significant
Other
Observable
Inputs    Significant
Unobservable
Inputs    Total
Carrying    % of
In thousands

(Level 1)

(Level 2)

(Level 3)

Value

Total

Cash and cash equivalents
     $ 926      $ -      $ -      $ 926    4%


Fixed Income Securities:
               46%


U.S. treasuries
   2,345    -    -    2,345    10%
Corporate bonds / Other fixed income securities
   8,474    -    -    8,474    36%


Equity Securities:
               45%


Large cap value
   1,221    -    -    1,221    5%
Large cap growth
   1,149    -    -    1,149    5%
Small cap value
   1,177    -    -    1,177    5%
Small cap growth
   1,155    -    -    1,155    5%
Large cap index
   2,148    -    -    2,148    9%
International blend
   3,907    -    -    3,907    16%


Real Estate:
               5%


Global REIT
   1,161    -    -    1,161    5%










Total assets at fair value
     $     23,663      $       -      $ -      $       23,663        100%










Percent of fair value hierarchy
   100%       -%       -%       100%



	Other Benefits as of October 31, 2015

In thousands	Quoted Prices In Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total Carrying Value
Cash and cash equivalents	$	1,164	$	—	$	—	$	1,164
Mutual funds	26,382		—		—		26,382
Total assets at fair value	$	27,546	$	—	$	—	$	27,546



	Other Benefits as of October 31, 2014

In thousands	Quoted Prices In Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total Carrying Value
Cash and cash equivalents	$	2,590	$	—	$	—	$	2,590
Mutual funds	25,157		—		—		25,157
Total assets at fair value	$	27,747	$	—	$	—	$	27,747

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, ~~2013, 2012~~2015, 2014 and ~~2011,~~2013, we made matching contributions to participant accounts as follows.

In thousands

2013

2012

2011

401(k) matching contributions
   $     5,688    $     5,400    $     5,203



In thousands	2015		2014		2013
401(k) matching contributions	$	6,584	$	6,134	$	5,688

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.~~

11. Employee Share-Based Plans

Liability 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, ~~2013, 2012~~2015, 2014 and ~~2011,~~2013, we recorded compensation expense, and as of October 31, ~~2013~~2015 and ~~2012,~~2014, 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 each quarter and at the settlement date.

We have granted three series of awards under the approved ~~incentive compensation plans, each~~ICP, one with a three-year performance period ~~(ending~~that ended October 31, ~~2013,~~2015 (2015 plan) and two other awards ending on October 31, ~~2014~~2016 (2016 plan) and October 31, ~~2015)~~2017 (2017 plan). For each of these performance periods, awards ~~will be~~are weighted and based on achievement relative to to:

a target annual compounded increase in basic EPS ~~and the achievement of~~ (37.5% weight),

total shareholder returns ~~relative~~compared 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 plan with the performance period ending October 31, 2015 (2015 plan) has~~ (37.5% weight), and

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 is based on EPS at 37.5%, total shareholder return at 37.5 % and return on equity at 25% of the total units awarded.~~

commissions (25% weight).

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 ~~will vest~~vested for participants who ~~have~~ met the retention requirements at the end of athe three-year period ending in December 2013 and settled in the same month with payment in the form of shares of our common stock and withholdings for payment of applicable taxes on the compensation. The Compensation Committee of our Board of Directors has the discretion to accelerate the vesting of all or a portion of a participant’s units. For the twelve months ended October 31, 2013, 2012 and 2011, we recorded compensation expense, and as of October 31, 2013 and 2012, 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.

Also under our approved ICP, 64,700 unvested retention stock units (RSUs) were granted to our President and Chief Executive Officer (CEO) 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~~RSUs 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 ~~vest~~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, ~~2013~~2015, 2014 and ~~2012,~~2013, we recorded compensation expense, and as of October 31, ~~2013~~2015 and ~~2012,~~2014, we accrued a liability for this award based on the fair market value of our common stock at the end of each quarter. The liability is re-measured to market value each quarter and at the settlement date.

The December 15, 2014 vesting covered 20% of the grant, including accrued dividends, for a total of 14,461 shares of our common stock. After withholdings of $.3 million for federal and state income taxes, our President and CEO received 7,231 shares of our common stock at the NYSE composite closing price on December 12, 2014 of $37.89 per share.

The December 15, 2015 vesting covers 30% of the grant, including accrued dividends, for a total of 22,434 shares of our common stock. After withholdings of $.6 million for federal and state income taxes, our President and CEO received 11,732 shares of our common stock at the NYSE composite closing price on December 14, 2015 of $56.85 per share.

At the time of distribution of ~~awards~~any award under the ICP, the number of shares of common stock 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~~the net shares issued in the Consolidated Statements of Stockholders’ ~~Equity.~~

Equity and in Note 7 to the consolidated financial statements.

The compensation expense related to the ~~incentive compensation plans~~awards under the ICP for the years ended October 31, ~~2013, 2012~~2015, 2014 and ~~2011,~~2013, 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, ~~2013~~2015 and ~~2012~~2014 are presented below.

In thousands    2013    2012    2011
Compensation expense
   $ 4,526    $ 5,730    $     2,604
Tax benefit
   1,538    2,080    673
Liability
       11,098        10,631

100



In thousands	2015		2014		2013
Compensation expense	$	14,173	$	8,496	$	4,526
Tax benefit	3,966		2,476		1,538
Liability	22,037		15,130

Based on current accrual assumptions as of October 31, ~~2013,~~2015, the expected payout for the approved incentive compensation awards at target will occur in the following fiscal ~~years.~~

In thousands 2014 2015 2016 2017
Amount of payout
$ 4,071 $ 4,290 $ 2,290 $ 446

years with the 2015 plan paying out in fiscal year 2016, the 2016 plan paying out in fiscal year 2017 and the 2017 plan paying out in fiscal year 2018. Payouts as currently accrued are presented net of estimated federal and state withholding payments.



In thousands	2016		2017		2018
Amount of payout	$	10,866	$	8,179	$	2,992

The Merger Agreement provides for the conversion of the shares subject to the RSUs and ICP awards at the performance level specified in the Merger Agreement into the right to receive $60 cash per share upon the closing of the transactions contemplated in the Merger Agreement. In November and December 2015, the Compensation Committee of our Board of Directors authorized the accelerated vesting, payment and taxation of the RSUs for our President and CEO (accelerated RSUs) and the ICP awards under the 2016 plan and the 2017 plan (accelerated ICP awards) at the target level of performance to participants, at his and their elections to accelerate, in the form of restricted shares of our common stock, net of shares withheld for applicable taxes. The acceleration of the vesting and payment of these awards will mitigate the effects of Section 280G of the Tax Code, including increasing the deductibility of such payments for the Company. The acceleration and payout of the ICP awards, at a 96% election rate by the participants, and the RSUs, per the election of our President and CEO, occurred on December 15, 2015.

In connection with the election to accelerate the ICP awards and the RSUs, each respective participant executed a share repayment agreement dated December 15, 2015. Under the share repayment agreements, each participant agreed to repay to the Company the net after-tax shares of common stock issued to him/her in connection with the acceleration, as well as shares of common stock resulting from the reinvestment of dividends paid with respect to these shares of common stock that are required to be reinvested in additional shares of common stock, to the extent the shares of common stock would not otherwise have been earned or payable absent the acceleration. Under the share repayment agreements, the shares of common stock delivered to the participants, including dividends paid by the Company and reinvested as discussed above, may not be transferred or encumbered until such shares of common stock are no longer subject to repayment under the applicable repayment agreement. The restricted shares of common stock and dividends earned on those shares of common stock are subject to full or partial cancellation if the Acquisition is not consummated or the participant leaves the Company prior to consummation of the Acquisition. The participants otherwise have all rights of shareholders with respect to the restricted shares of common stock.

The accelerated ICP awards and the accelerated RSUs were priced at the NYSE composite closing price of $56.85 on December 14, 2015. Under the accelerated ICP awards, 162,390 restricted shares of our common stock were issued to participants, net of shares withheld for applicable federal and state income taxes. The gross value of the shares issued for the accelerated ICP awards was $17.4 million, or $9.2 million net of federal and state tax withholdings. Under the accelerated RSUs, 19,554 restricted shares of our common stock were issued to our President and CEO, net of shares withheld for applicable federal and state income taxes. The gross value of the shares for the accelerated RSUs was $2.1 million, or $1.1 million net of federal and state tax withholdings.

Equity Plan

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 the fair ~~market~~ value is determined by calculating the mean average of the high and low trading prices on the purchase date.

~~11.~~

101

12. Income Taxes

The components of income tax expense for the years ended October 31, ~~2013, 2012~~2015, 2014 and ~~2011~~2013 are presented below.

   2013 2012 2011
In thousands
Federal State Federal State Federal State
Charged (Credited) to operating income:

Current
  $ (3,032)      $ 919   $ (29,062)      $ 1,857   $ (11,403)      $ 4,209
Deferred
67,885 11,829 86,496 10,144 64,806 6,597
Tax Credits:

Utilization
- - - - 184 -
Amortization
(267)    - (334)    - (325)    -

Total
64,586 12,748 57,100 12,001 53,262 10,806

Charged (Credited) to other income (expense):

Current
6,049 984 5,636 1,027 3,263 (36)
Deferred
2,225 (646)    2,214 239 4,167 824

Total
8,274 338 7,850 1,266 7,430 788

Total
  $     72,860   $     13,086 $     64,950   $     13,267   $     60,692   $     11,594



	2015						2014					2013
In thousands	Federal			State			Federal			State		Federal			State
Charged (Credited) to operating
income:
Current	$	(10,449	)	$	(289	)	$	(1,653	)	$	950	$	(3,032	)	$	919
Deferred ^{(1) (2)}	75,644			12,195			70,654			13,434		67,885			11,829
Tax Credits:
Amortization	(167		)	—			(209		)	—		(267		)	—
Total	65,028			11,906			68,792			14,384		64,586			12,748

Charged (Credited) to other income
(expense):
Current	9,709			1,449			4,233			870		6,049			984
Deferred ^{(1) (2)}	2,249			(119		)	5,811			728		2,225			(646		)
Total	11,958			1,330			10,044			1,598		8,274			338
Total	$	76,986		$	13,236		$	78,836		$	15,982	$	72,860		$	13,086
⁽¹⁾Includes benefits from net operating loss (NOL) and tax carryforwards of $64.3 million and $62.3 million for the years ended October 31, 2015 and 2013, respectively.
⁽²⁾ Includes the utilization of NOL carryforwards of $19.8 million and $28.6 million for the years ended October 31, 2015 and 2014, respectively.

The Tax Increase Prevention Act of 2014 (the Act), enacted December 19, 2014, retroactively extended the 50% bonus depreciation that expired December 2013 for a year to December 2014. Under the Act, we were able to claim additional depreciation deductions on our tax return for the year ended October 31, 2014. As a result of this additional depreciation, we generated a NOL for our tax year ended October 31, 2014. Prior to the Act's retroactive extension to 2014, we had anticipated utilizing NOL carryforwards to offset taxable income generated in our fiscal year 2014. The benefit from NOL and tax carryforwards for the year ended October 31, 2015 includes $61.1 million to record the retroactive impact of the Act.

A reconciliation of income tax expense at the federal statutory rate to recorded income tax expense for the years ended October 31, ~~2013, 2012~~2015, 2014 and ~~2011~~2013 is presented below.

In thousands

2013

2012

2011

Federal taxes at 35%
     $     77,127   $     69,322   $     65,049
State income taxes, net of federal benefit
   8,506 8,624 7,536
Amortization of investment tax credits
   (267 ) (334 ) (325 )
Other, net
   580 605 26


Total
     $ 85,946   $ 78,217   $ 72,286



In thousands	2015			2014			2013
Federal taxes at 35%	$	79,532		$	83,517		$	77,127
State income taxes, net of federal benefit	8,604			10,389			8,506
Amortization of investment tax credits	(167		)	(209		)	(267		)
Other, net	2,253			1,121			580
Total	$	90,222		$	94,818		$	85,946

102

As of October 31, ~~2013~~2015 and ~~2012,~~2014, deferred income taxes consisted of the following temporary differences.

In thousands

2013

2012

Deferred tax assets:

Benefit of loss carryforwards
   $ 66,087    $ 3,092
Employee benefits and compensation
   13,834    22,286
Revenue requirement
   19,062    10,148
Utility plant
   10,386    11,285
Other
   12,796    9,173




Total deferred tax assets
   122,165    55,984
Valuation allowance
   (505)       (505)




Total deferred tax assets, net
   121,660    55,479




Deferred tax liabilities:

Utility plant
   652,822    523,232
Revenues and cost of gas
   21,257    26,816
Equity method investments
   38,710    34,092
Deferred costs
   59,221    73,744
Other
   18,324    8,348




Total deferred tax liabilities
   790,334    666,232




Net deferred income tax liabilities
   $ 668,674    $ 610,753



In thousands	2015			2014
Deferred tax assets:
Benefit of loss carryforwards	$	84,025		$	39,532
Revenues and cost of gas	3,495			4,960
Employee benefits and compensation	22,134			16,547
Revenue requirement	26,088			20,320
Utility plant	7,481			5,631
Other	10,461			12,869
Total deferred tax assets	153,684			99,859
Valuation allowance	(848		)	(505		)
Total deferred tax assets, net	152,836			99,354
Deferred tax liabilities:
Utility plant	849,835			724,172
Revenues and cost of gas	—			4,340
Equity method investments	44,778			42,998
Deferred costs	73,903			65,828
Other	13,543			18,065
Total deferred tax liabilities	982,059			855,403
Net deferred income tax liabilities	$	829,223		$	756,049

As of October 31, ~~2013~~2015 and ~~2012,~~2014, 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~~wholly-owned subsidiaries file a consolidated federal income tax return and various state income tax returns. As of October 31, ~~2013,~~2015 and 2014, we have a federal NOL ~~carryforward~~carryforwards of ~~$178.1~~$219.7 million and $97 million, respectively, which ~~expires~~expire in ~~2033.~~2033 through 2034. We also have $5.9 million of federal NOL carryforwards as of October 31, ~~2013~~2015 and ~~2012~~2014 that expire in ~~2021~~2023 through 2025 and are subject to an annual limitation of $.3 million.

As of October 31, ~~2013~~2015, we have a capital loss carryforward of $1 million which expires in 2019. We believe that it is more likely than not that the benefit from the capital loss carryforward will not be realized. Due to the uncertainty of realizing a benefit from the deferred tax asset recorded for the capital loss carryforward, we recorded a valuation allowance of $.3 million during fiscal year ended October 31, 2015. As of October 31, 2015, we have a $1.1 million alternative minimum tax credit carryforward.

As of October 31, 2015 and ~~2012,~~2014, we have state NOL carryforwards of ~~$6.4~~$115.1 million and ~~$6.8~~$7.2 million, respectively, ~~that~~which expire from ~~2020~~2018 through ~~2028.~~2030. We may use the carryforwards to offset taxable income.

~~We have federal charitable contribution carryforwards as of October 31, 2013 and 2012 of $4.2 million and $2.3 million, respectively, that expire from 2016 through 2018.~~

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, ~~2013, 2012~~2015, 2014 and ~~2011~~2013 is presented below.

In thousands

2013

2012

2011

Balance at beginning of year
     $       505      $       505      $       1,324
Credited to income tax expense
   -    -    (819)






Balance at end of year
     $ 505      $ 505      $ 505



In thousands	2015		2014		2013
Balance at beginning of year	$	505	$	505	$	505
Charged to income tax expense	343		—		—
Balance at end of year	$	848	$	505	$	505

There were no unrecognized tax benefits for the years ended October 31, ~~2013~~2015 and ~~2012.~~

2014.

In July 2013, legislation was passed in North Carolina affecting corporate taxation. The legislation ~~reduces~~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

103

after January 1, 2015. It also ~~provides~~provided for two additional 1% rate reductions if the state’s tax collections exceed certain thresholds. In July 2015, the provision for a 1% state income tax rate reduction based on state tax collections exceeding certain thresholds under the North Carolina tax statutes was announced. Accordingly, the statutory income tax rate for North Carolina will decrease to 4% for our fiscal year 2017. 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 state income tax rate reductions announced in July 2015, we adjusted our noncurrent deferred income tax balances ~~at October 31, 2013~~during fiscal year 2015 by approximately ~~$25~~$17.5 million for temporary differences expected to reverse at athe lower ~~rate than under the prior law and~~future rate. We recognized a tax benefit ~~of approximately $1 million~~ in net income ~~the majority~~ of ~~which relates~~approximately $.5 million, largely related to our regulated non-utility activities segment, ~~with~~and recorded the ~~balance~~remainder of approximately ~~$24~~$17 million ~~recorded in~~as regulatory deferred income taxes as presented in ~~“Regulatory Liabilities”~~noncurrent "Regulatory Liabilities" in Note 13 to the consolidated financial statements, reflecting a future benefit to our ~~customers;~~customers. During fiscal 2014, we recorded an additional $3 million for the difference in the tax rate included in our ~~state commissions~~customers' rates and the rate at which the deferred taxes are expected to reverse. As of October 31, 2015, we have approximately $44 million related to the North Carolina tax rate change included in our deferred income taxes recorded in “Regulatory Liabilities,” which would have been an increase to net income predominately in fiscal years 2013 and 2015 without our utility regulation. The NCUC will determine the recovery period of this regulatory liability in future proceedings.

~~12.~~ In fiscal 2013, we recognized a tax benefit in net income of approximately $1 million related to the corporate income tax reduction.

13. Equity Method Investments

The consolidated financial statements include the accounts of ~~wholly owned~~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, ~~2013,~~2015, 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.~~

Ownership Interests

We ~~own 21.49% of~~have the following membership interests in these companies as of October 31, 2015 and 2014.



Entity Name	Interest	Activity
Cardinal Pipeline Company, LLC (Cardinal)	21.49%	Intrastate pipeline located in North Carolina; regulated by the NCUC
Pine Needle LNG Company, LLC (Pine Needle)	45%	Interstate LNG storage facility located in North Carolina; regulated by the FERC
SouthStar Energy Services, LLC (SouthStar)	15%	Energy services company primarily selling natural gas in the unregulated retail gas market to residential, commercial and industrial customers in the eastern United States, primarily Georgia and Illinois
Hardy Storage Company (Hardy Storage)	50%	Underground interstate storage facility located in Hardy and Hampshire Counties, West Virginia; regulated by the FERC
Constitution Pipeline Company LLC (Constitution)	24%	To develop, construct, own and operate 124 miles of interstate natural gas pipeline and related facilities connecting shale natural gas supplies and gathering systems in Susquehanna County, Pennsylvania, to Iroquois Gas Transmission and Tennessee Gas Pipeline systems in New York; regulated by the FERC
Atlantic Coast Pipeline, LLC (ACP)	10%	To develop, construct, own and operate 564 miles of interstate natural gas pipeline with associated compression from West Virginia through Virginia into eastern North Carolina in order to provide interstate natural gas transportation services of Marcellus and Utica gas supplies into southeastern markets; regulated by the FERC

104

Accumulated Other Comprehensive Income (Loss)

As an equity method investor, we record the effect of certain transactions in our accumulated OCIL. Cardinal ~~Pipeline Company, L.L.C. (Cardinal)~~and Pine Needle enter into interest-rate swap agreements to modify the interest expense characteristics of their unsecured long-term debt which is nonrecourse to its members. SouthStar uses financial contracts in the form of futures, options and swaps, all considered to be derivatives, to moderate the effect of price and weather changes on the timing of its earnings; fair value of these financial contracts is based on selected market indices. Retirement benefits are allocated to SouthStar by its majority member with the activity of prescribed benefit expense items reflected in accumulated OCIL. For these transactions with these equity method investees, we record our share of movements in the market value of these hedged agreements and contracts and retirement benefit items in “Accumulated other comprehensive loss” in “Stockholders’ equity” in the Consolidated Balance Sheets; the detail of our share of the market value of the various financial instruments and the retirement benefits are presented in “Other Comprehensive Income (Loss), net of tax” in the Consolidated Statements of Comprehensive Income.

Related Party Transactions

We have related party transactions as a customer of our investments. For the years ended October 31, 2015, 2014 and 2013, these gas costs and the amounts we owed to our equity method investees, as of October 31, 2015 and 2014, are as follows.



Related Party	Type of Expense	Cost of Gas ⁽¹⁾						Trade accounts payable ⁽²⁾
In thousands		2015		2014		2013		2015		2014
Cardinal	Transportation costs	$	8,763	$	8,825	8,775		$	744	$	747
Pine Needle	Gas storage costs	11,441		11,364		11,098		955		989
Hardy Storage	Gas storage costs	9,290		9,461		9,702		774		774
Totals		$	29,494	$	29,650	$	29,575	$	2,473	$	2,510

⁽¹⁾In the Consolidated Statements of Comprehensive Income.
⁽²⁾ In the Consolidated Balance Sheets.

We have related party transactions as we sell wholesale gas supplies to SouthStar. For the years ended October 31, 2015, 2014 and 2013, our operating revenues from these sales and the amounts SouthStar owed us as of October 31, 2015 and 2014, are as follows.



	Operating Revenues ⁽¹⁾						Trade accounts receivable ⁽²⁾
In thousands	2015		2014		2013		2015		2014
Operating revenues	$	1,568	$	3,541	$	3,291	$	183	$	460
⁽¹⁾ In the Consolidated Statements of Comprehensive Income.
⁽²⁾In the Consolidated Balance Sheets.

Information on Our Equity Method Investments

Cardinal

Cardinal is 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.

To provide natural gas delivery service to Duke Energy Progress, Inc. (DEP), now a subsidiary of DEC, for a power generation facility at their Wayne County, North Carolina site, we executed an agreement with Cardinal, which was approved by the NCUC in May 2010, to expand our firm capacity requirement on Cardinal to serve DEP. Cardinal invested in a compressor station and expanded meter stations in order to increase the capacity of its system for us and another customer. We made capital contributions totaling $9.8 million related to this system expansion from January 2011 through June 2012. Cardinal’s expansion service for the project and our natural gas delivery service for DEP’s Wayne County site were placed into service on June 1, 2012.

The charges we incur as transportation costs from Cardinal are passed through to DEP under the terms of our natural gas delivery service agreement with DEP. Cardinal issued $45 million of long-term debt on June 22, 2012, and we received a distribution of $5.4 million in June 2012 as a partial return of our capital contributions.

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, 2013, 2012 and 2011, these transportation costs and the amounts we owed Cardinal as of October 31, 2013 and 2012 are as follows.

In thousands

2013

2012

2011

Transportation costs
   $         8,775    $         6,613    $         4,104
Trade accounts payable
   755    855

Summarized financial information provided to us by Cardinal for 100% of Cardinal as of September 30, ~~2013~~2015 and ~~2012,~~2014, and for the twelve months ended September 30, ~~2013, 2012~~2015, 2014 and ~~2011~~2013, is presented below.

In thousands

2013

2012

2011

Current assets
   $ 15,179    $ 9,179
Noncurrent assets
       116,414        120,437
Current liabilities
   2,637    1,786
Noncurrent liabilities
   45,273    45,702
Revenues
   17,649    16,165    $     13,633
Gross profit
   17,649    16,165    13,633
Income before income taxes
   9,361    10,433    6,473

105



In thousands	2015		2014		2013
Current assets	$	9,451	$	8,856
Noncurrent assets	106,444		111,881
Current liabilities	1,228		1,468
Noncurrent liabilities	45,446		45,402
Revenues	16,629		16,705		$	17,649
Gross profit	16,629		16,705		17,649
Income before income taxes	7,742		8,042		9,361

Pine Needle

Pine Needle ~~LNG Company, L.L.C.~~

~~Pine Needle LNG Company, L.L.C. (Pine Needle),~~is a North Carolina limited liability ~~company, owns an interstate LNG storage facility~~company. The other members are the Municipal Gas Authority of Georgia, and subsidiaries of The Williams Companies, Inc. and SCANA Corporation. Effective July 1, 2013, we acquired Hess Corporation’s 5% membership interest in ~~North Carolina and is regulated by the FERC.~~Pine Needle for $2.9 million, increasing our membership interest from 40% to 45%. Pine Needle has firm, long-term service agreements for 100% of the storage capacity of the facility, of which Piedmont subscribes to approximately 64%. ~~In June 2013, we entered into an agreement with Hess Corporation (Hess) to acquire their 5% membership interest in Pine Needle. Effective July 1, 2013, we acquired Hess’ 5% membership interest~~We are dependent on the Williams – Transco pipeline system for $2.9 million. With the purchase of this additional 5% membership interest, our membership interest in Pine Needle increased from 40% to 45%. As of October 31, 2013, 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~~redelivery 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, 2013, 2012 and 2011, these gas storage costs and the amounts we owed Pine Needle as of October 31, 2013 and 2012 are as follows.

In thousands

2013

2012

2011

Gas storage costs
   $         11,098    $         10,410    $         10,677
Trade accounts payable
   940    914

volumes to our system for service to our customers.

Summarized financial information provided to us by Pine Needle for 100% of Pine Needle as of September 30, ~~2013~~2015 and ~~2012,~~2014, and for the twelve months ended September 30, ~~2013, 2012~~2015, 2014 and ~~2011~~2013, is presented below.

In thousands

2013

2012

2011

Current assets
   $ 9,225    $ 11,937
Noncurrent assets
         74,710          77,463
Current liabilities
   3,531    4,278
Noncurrent liabilities
   35,391    35,851
Revenues
   16,810    16,390    $       17,666
Gross profit
   16,810    16,390    17,666
Income before income taxes
   5,804    5,832    5,763



In thousands	2015		2014		2013
Current assets	$	9,863	$	8,812
Noncurrent assets	71,586		70,837
Current liabilities	5,377		38,029
Noncurrent liabilities	35,112		—
Revenues	16,913		18,025		$	16,810
Gross profit	16,913		18,025		16,810
Income before income taxes	6,002		6,011		5,804

SouthStar

SouthStar ~~Energy Services LLC~~

~~We own 15% of the membership interests in SouthStar Energy Services LLC (SouthStar),~~is a Delaware limited liability company. The other member is Georgia Natural Gas Company (GNGC), a wholly-owned subsidiary of AGL Resources, Inc. (AGL). who is subject to being acquired by The Southern Company. On September 4, 2015, under the terms of the SouthStar ~~primarily sells natural gas~~limited liability company agreement (SSE LLC Agreement) regarding GNGC's change in control, we affirmed our election by written notice to ~~residential, commercial and industrial customers~~remain a member of SouthStar.

In accordance with the SSE LLC Agreement, upon the announcement of the Acquisition, we delivered a notice of change of control to GNGC. On December 9, 2015, GNGC delivered to us a written notice electing to purchase our entire 15% interest in the southeastern United States, including Illinois, Ohio, New York, Maryland, North Carolina, South Carolina and Tennessee, with most of its business being conducted in the unregulated retail gas market in Georgia. We account forSouthStar. GNGC’s election to purchase our ~~investment~~entire 15% interest in SouthStar ~~using~~is subject to and effective with 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~~consummation of the ~~operations of SouthStar.~~

Acquisition.

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. Our share of movements in the~~

market value of these contracts 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 these contracts 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.

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, 2013, 2012 and 2011, our operating revenues from these sales and the amounts SouthStar owed us as of October 31, 2013 and 2012 are as follows.

In thousands

2013

2012

2011

Operating revenues
   $     3,291    $     2,442    $     4,961
Trade accounts receivable
   441    473

106

Summarized financial information provided to us by SouthStar for 100% of SouthStar as of September 30, ~~2013~~2015 and ~~2012,~~2014, and for the twelve months ended September 30, ~~2013, 2012~~2015, 2014 and ~~2011~~2013, is presented below.

In thousands

2013

2012

2011

Current assets
   $ 194,793    $ 152,422
Noncurrent assets
   136,753    9,803
Current liabilities
   76,304    42,197
Noncurrent liabilities
   53    1
Revenues
         639,426          585,291    $       733,987
Gross profit
   174,993    161,122    176,010
Income before income taxes
   103,146    94,631    103,704



In thousands	2015		2014*		2013
Current assets	$	204,237	$	192,151
Noncurrent assets	132,315		143,958
Current liabilities	45,953		47,923
Noncurrent liabilities	—		—
Revenues	769,295		845,695		$	639,426
Gross profit	224,612		234,581		174,993
Income before income taxes	129,340		136,569		102,805

* Balance sheet amounts have been changed to reflect SouthStar's reclassification of cash collateral under accounting guidance.

Hardy Storage

Hardy Storage ~~Company, LLC~~

~~We own 50% of the membership interests in Hardy Storage Company, LLC (Hardy Storage),~~is 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~~are dependent on Columbia Pipeline Group and the Williams – Transco pipeline system for redelivery 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, 2013, 2012 and 2011, these gas storage costs and the amounts we owed Hardy Storage as of October 31, 2013 and 2012 are as follows.

In thousands

2013

2012

2011

Gas storage costs
   $     9,702    $     9,702    $     9,702
Trade accounts payable
   808    808

volumes to our system for service to our customers.

Summarized financial information provided to us by Hardy Storage for 100% of Hardy Storage as of October 31, ~~2013~~2015 and ~~2012,~~2014, and for the twelve months ended October 31, ~~2013, 2012~~2015, 2014 and ~~2011~~2013, is presented below.

In thousands

2013

2012

2011

Current assets
   $ 7,641    $ 10,302
Noncurrent assets
       161,282        164,374
Current liabilities
   12,378    14,534
Noncurrent liabilities
   87,184    95,061
Revenues
   24,375    24,359    $       24,378
Gross profit
   24,375    24,359    24,378
Income before income taxes
   10,582    9,939    9,657



In thousands	2015		2014		2013
Current assets	$	11,658	$	12,644
Noncurrent assets	156,803		157,861
Current liabilities	19,078		17,316
Noncurrent liabilities	69,971		78,830
Revenues	23,350		23,804		$	24,375
Gross profit	23,350		23,804		24,375
Income before income taxes	10,403		10,497		10,582

Constitution

Constitution ~~Pipeline Company, LLC~~

~~We own 24% of the membership interests of Constitution Pipeline Company, LLC (Constitution),~~is a Delaware limited liability company. ~~In May 2013, through one~~The other members are subsidiaries of ~~its subsidiaries, WGL Holdings, Inc. became a member of the joint venture along with existing members~~ The Williams Companies, Inc. ~~and~~, Cabot Oil & Gas ~~Corporation.~~Corporation and WGL Holdings, Inc. A subsidiary of The Williams Companies iswill be the operator of the project. The purpose of the joint venture 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.pipeline. 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~~$834 million, excluding AFUDC, in total. Our total anticipated contributions are approximately $200.2 million. As of October 31, ~~2013,~~2015, our fiscal year contributions were ~~$15.9~~$19.1 million, ~~and we expect~~with our total equity contributions ~~will be an estimated $55~~for the project totaling $72.7 million to date. On December 2, 2014, the FERC issued a certificate of public convenience and ~~$92.1 million in our fiscal 2014 and 2015 years, respectively.~~necessity approving construction of the Constitution pipeline. The target in-service date of the project is ~~March 2015.~~the fourth quarter of 2016, which has been extended due to a longer than expected regulatory and permitting process. The capacity of the pipeline is 100% subscribed under ~~fifteen year~~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, ~~2013,~~2015 and 2014, and for the twelve months ended September 30, 2015, 2014 and 2013, is presented below.

~~In thousands~~ ~~2013~~
⁽¹⁾
~~Current assets~~
~~$ 10,944~~
~~Noncurrent assets~~
~~62,438~~
~~Current liabilities~~
~~7,960~~
~~Noncurrent liabilities~~
-
~~Revenues~~
-
~~Gross profit~~
-
~~Income before income taxes~~
~~3,459~~

⁽¹⁾	Presented is 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.

~~13.~~

107



In thousands	2015		2014		2013
Current assets	$	6,163	$	11,273
Noncurrent assets	330,152		219,208
Current liabilities	4,398		7,667
Noncurrent liabilities	—		—
Revenues	—		—		$	—
Gross profit	—		—		—
Income before income taxes	24,604		10,091		3,459

ACP

On September 2, 2014, Piedmont, Duke Energy, Dominion Resources, Inc. (Dominion), and AGL announced the formation of ACP, a Delaware limited liability company. A Dominion subsidiary will be the operator of the pipeline. The pipeline will be designed with an initial capacity of 1.5 billion cubic feet per day with a target in-service date of late 2018, subject to state and other federal approvals. The capacity of ACP is substantially subscribed by the members of ACP, other utilities and related companies under twenty-year contracts.

The total cost for the project is expected to be between $4.5 billion to $5 billion, excluding financing costs. Members anticipate obtaining project financing for 60% of the total costs during the construction period, and a project capitalization ratio of 50% debt and 50% equity when operational. As of October 31, 2015, our fiscal year contributions were $10.6 million, with contributions to the project beginning November 2014.

In November 2014, the FERC authorized the ACP pre-filing process under which environmental review for the natural gas pipeline will commence. In February 2015, ACP, along with Dominion Transmission, Inc. (DTI), filed a notice of intent to prepare its environmental impact statement for the project and DTI’s supply header project affecting ACP. ACP filed its FERC application in September 2015 and expects to receive the FERC certificate of public convenience and necessity in the summer of 2016 and begin construction thereafter.

On March 2, 2015, ACP entered into a Precedent Agreement with DTI for supply header transportation services. Under the Precedent Agreement, ACP is required to provide assurance of its ability to meet its financial obligations to DTI. DTI has informed ACP that ACP, independent of its members, is not currently creditworthy as required by DTI’s FERC Gas Tariff. ACP requested that its members provide proportionate assurance of ACP’s ability to meet its financial obligations under the Precedent Agreement, which the Piedmont member provided through an Equity Contribution Agreement between Piedmont and ACP where Piedmont committed to make funds available to the Piedmont member for it to pay and perform its obligations under the ACP Limited Liability Company Agreement. This commitment is capped at $15.2 million. This commitment ceases when DTI acknowledges that ACP is independently creditworthy in accordance with the Precedent Agreement, termination or expiration of the Precedent Agreement, or when we are no longer a member of ACP.

On July 13, 2015, the parent companies of the members of ACP entered into an indemnification agreement with an insurance company to secure surety bonds in connection with preparatory and pre-construction activities on the ACP project. Liability under the indemnification agreement is several and is capped at each member’s proportionate share, based on its membership interest in ACP, of losses, if any, incurred by the insurance company.

On October 24, 2015, Piedmont entered into a Merger Agreement with Duke Energy. The ACP limited liability company agreement includes provisions to allow Dominion an option to purchase additional ownership interests in ACP to maintain a majority ownership percentage relative to all other members. After consummation of the Acquisition, Duke, together with our ownership, would have a 50% membership interest unless Dominion exercises its option.

Summarized financial information provided to us by ACP for 100% of ACP as of September 30, 2015, and for the twelve months ended September 30, 2015, is presented below. Information for 2014 is not applicable as ACP was formed on September 2, 2014.

108



In thousands	2015
Current assets	$	23,422
Noncurrent assets	86,109
Current liabilities	9,105
Noncurrent liabilities	—
Revenues	—
Gross profit	—
(Loss) before income taxes	(5,205		)

14. Variable Interest Entities

~~Under accounting guidance,~~

On a quarterly basis, we evaluate our variable interests in other entities, primarily ownership interests, to determine if they represent a variable interest entity (VIE) ~~is a legal entity that conducts a business or holds property whose equity,~~as defined 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 obligationsauthoritative guidance on consolidation, and ~~that interest changes as the entity’s net assets change. The consolidating investor~~if so, which party 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.

primary beneficiary. As of October 31, ~~2013,~~2015, we have determined that we are not the primary beneficiary ~~as defined by the authoritative~~under VIE accounting guidance ~~related to consolidations,~~ in any of our equity method investments, as discussed in Note 1213 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,~~performance, and we will continue to apply equity method accounting to these ~~investments, as discussed in Note 12 to the consolidated financial statements.~~ investments.

Our maximum loss exposure related to these equity method investments is limited to our equity investment in each ~~entity.~~entity included in “Equity method investments in non-utility activities” in “Noncurrent Assets” in the Consolidated Balance Sheets. As of October 31, ~~2013~~2015 and ~~2012,~~2014, our investment balances are as follows.

   October 31,    October 31,
In thousands
   2013    2012
Cardinal
   $ 18,207    $ 17,969
Pine Needle
   20,270    19,239
SouthStar
   38,372    18,118
Hardy Storage
   34,681    32,541
Constitution
   16,939    -




Total equity method investments in non-utility activities
   $     128,469    $     87,867



	October 31,		October 31,
In thousands	2015		2014
Cardinal	$	15,083	$	16,073
Pine Needle	18,396		18,689
SouthStar	41,325		40,965
Hardy Storage	39,706		37,179
Constitution	82,403		57,255
ACP	10,043		10
Total equity method investments in non-utility activities	$	206,956	$	170,171

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.

~~14.~~

109

15. Business Segments

We have ~~two~~three reportable business ~~segments,~~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 ~~warranty programs,~~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. 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~~wholly-owned subsidiaries.

Operations of ~~the regulated utility segment are reflected in “Operating Income” in the Consolidated Statements of Comprehensive Income. Operations of the~~our unregulated non-utility activities segment are ~~included in the Consolidated Statements~~comprised primarily of ~~Comprehensive Income in “Other Income (Expense)” in “Income from~~our equity method ~~investments” and “Non-operating income.”~~ 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.

All of our operations are within the United States. No single customer accounts for more than 10% of our consolidated revenues.

We evaluate the performance of the regulated utility segment based on margin, O&M expenses and operating income. We evaluate the performance of the non-utility activities segment based on earnings from and our cash flows in the ventures.

Operations by segment for the years ended October 31, ~~2013, 2012~~2015, 2014 and ~~2011,~~2013, and as of October 31, ~~2013, 2012~~2015, 2014 and ~~2011~~2013, are presented below.

      Regulated    Non-Utility
In thousands

Utility
   Activities
Total

2013

Revenues from external customers
   $     1,278,229    $ - $     1,278,229
Margin
   621,490    -    621,490
Operations and maintenance expenses
   253,120    181 253,301
Depreciation
   112,207    18 112,225
Income from equity method investments
   -       26,056 26,056
Interest expense
   24,938    -    24,938
Operating income (loss) before income taxes
   221,528    (352 ) 221,176
Income before income taxes
   194,659    25,704 220,363
Total assets
   4,053,591      128,832 4,182,423
Equity method investments in non-utility activities
   -       128,469 128,469
Construction expenditures
   599,999    -    599,999
      Regulated    Non-Utility
In thousands

Utility

Activities

Total

2012

Revenues from external customers
   $ 1,122,780    $ - $ 1,122,780
Margin
   575,446    -    575,446
Operations and maintenance expenses
   242,599    102 242,701
Depreciation
   103,192    18 103,210
Income from equity method investments
   -       23,904 23,904
Interest expense
   20,097    -    20,097
Operating income (loss) before income taxes
   194,824    (264 ) 194,560
Income before income taxes
   174,424    23,640 198,064
Total assets
   3,475,640    88,247 3,563,887
Equity method investments in non-utility activities
   -       87,867 87,867
Construction expenditures
   529,576    -    529,576
      Regulated    Non-Utility
In thousands

Utility

Activities

Total

2011

Revenues from external customers
   $ 1,433,905    $ - $ 1,433,905
Margin
   573,639    -    573,639
Operations and maintenance expenses
   225,351    109 225,460
Depreciation
   102,829    28 102,857
Income from equity method investments
   -       24,027 24,027
Interest expense
   43,992    -    43,992
Operating income (loss) before income taxes
   207,079    (120 ) 206,959
Income before income taxes
   161,925    23,929 185,854
Total assets
   2,968,574    85,519 3,054,093
Equity method investments in non-utility activities
   -       85,121 85,121
Construction expenditures
   243,641    -    243,641

110



			Regulated			Unregulated
	Regulated		Non-Utility			Non-Utility
In thousands	Utility		Activities			Activities			Total
2015
Revenues from external customers	$	1,371,718	$	—		$	—		$	1,371,718
Margin	727,294		—			—			727,294
Operations and maintenance expenses	294,517		81			105			294,703
Depreciation	128,704		—			18			128,722
Operating income (loss) before income taxes	261,963		(152		)	(217		)	261,594
Income from equity method investments	—		15,060			19,401			34,461
Interest charges	68,631		—			—			68,631
Income before income taxes	193,140		14,909			19,184			227,233
Total assets	4,742,284		165,630			41,682			4,949,596
Equity method investments in non-utility activities	—		165,630			41,326			206,956
Construction expenditures	443,654		—			—			443,654

			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 charges	54,686		—			—			54,686
Income before income taxes	206,253		12,135			20,231			238,619
Total assets ⁽¹⁾	4,432,239		129,206			41,309			4,602,754
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 charges	24,938		—			—			24,938
Income before income taxes	194,659		10,434			15,270			220,363
Total assets ⁽¹⁾	4,045,259		90,097			38,735			4,174,091
Equity method investments in non-utility activities	—		90,097			38,372			128,469
Construction expenditures	599,999		—			—			599,999

⁽¹⁾ Regulated utility total assets have been adjusted in 2014 and 2013 to reflect the netting of debt issuance costs with its debt carrying value in accordance with the 2015 adoption of new accounting guidance related to this balance sheet presentation.

111

Reconciliations to the consolidated financial statements for the years ended October 31, ~~2013, 2012~~2015, 2014 and ~~2011,~~2013, and as of October 31, ~~2013~~2015 and ~~2012~~2014 are as follows.

In thousands

2013

2012

2011

Operating Income:

Segment operating income before income taxes
     $ 221,176      $ 194,560      $ 206,959
Utility income taxes
   (77,334)       (69,101)       (64,068)
Non-utility activities operating loss before income taxes
   352    264    120






Total
     $ 144,194      $ 125,723      $ 143,011






Net Income:

Income before income taxes for reportable segments
     $ 220,363      $ 198,064      $ 185,854
Income taxes
   (85,946)       (78,217)       (72,286)






Total
     $ 134,417      $ 119,847      $     113,568






In thousands

2013

2012


Consolidated Assets:

Total assets for reportable segments
     $   4,182,423      $   3,563,887
Eliminations/Adjustments
   186,186    206,052





Total
     $ 4,368,609      $ 3,769,939

~~15.~~



In thousands	2015			2014			2013
Operating Income:
Segment operating income before income taxes	$	261,594		$	262,655		$	221,176
Utility income taxes	(76,934		)	(83,176		)	(77,334		)
Regulated non-utility activities operating loss before income taxes	152			183			150
Unregulated non-utility activities operating loss before income taxes	217			203			202
Total	$	185,029		$	179,865		$	144,194

Net Income:
Income before income taxes for reportable segments	$	227,233		$	238,619		$	220,363
Income taxes	(90,222		)	(94,818		)	(85,946		)
Total	$	137,011		$	143,801		$	134,417



In thousands	2015		2014
Consolidated Assets:
Total assets for reportable segments	$	4,949,596	$	4,602,754
Eliminations/Adjustments	161,154		171,553
Total	$	5,110,750	$	4,774,307

16. 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, ~~stockholders’~~short-term debt instruments, employee share-based plans and equity ~~and environmental matters,~~method investments, see Note 2,3, Note 6, Note 11 and Note 8,13, respectively, to the consolidated financial statements.

~~16.~~

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

      Operating       Operating
Income
Net
Income

Earnings (Loss)
Per Share of
Common Stock


Revenues

Margin

(Loss)

(Loss)

Basic

Diluted

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 )
Fiscal Year 2012

January 31
   $ 471,840    $ 220,237    $ 79,819 $ 76,227 $ 1.06 $ 1.05
April 30
   308,432    171,951    48,782 50,192 0.70 0.70
July 31
   161,123    86,460    (2,513 ) (4,613 ) (0.06 ) (0.06 )
October 31
   181,385    96,798    (365 ) (1,959 ) (0.03 ) (0.03 )



											Earnings (Loss)
					Operating			Net			Per Share of
	Operating				Income			Income			Common Stock
	Revenues		Margin		(Loss)			(Loss)			Basic			Diluted
Fiscal Year 2015
January 31	$	607,271	$	270,070	$	105,758		$	92,978		$	1.18		$	1.18
April 30	424,924		225,621		75,123			66,402			0.84			0.84
July 31	158,266		111,572		5,233			(8,260		)	(0.10		)	(0.10		)
October 31	181,257		120,031		(1,085		)	(14,109		)	(0.18		)	(0.18		)

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		)

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.

112

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 ~~2013~~2015 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

113

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

December 23, ~~2013~~

2015

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)~~(2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based upon such evaluation, our management concluded that as of October 31, ~~2013,~~2015, 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, ~~2013.~~

2015.



			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

114

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, ~~2013,~~2015, based on ~~the~~ criteria established inInternal Control—Integrated Framework ~~(1992)~~(2013) 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, ~~2013,~~2015, based on the criteria established inInternal Control—Integrated Framework ~~(1992)~~(2013) 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, ~~2013~~2015 of the Company and our report dated December 23, ~~2013~~2015 expressed an unqualified opinion on those financial statements.

/s/ Deloitte & Touche LLP

Charlotte, North Carolina

December 23, ~~2013~~

2015

115

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 ~~2014~~2016 Annual Meeting of Shareholders ~~(2014~~(2016 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 ~~2014~~2016 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 ~~2014~~2016 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 atwww.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 ~~2014~~2016 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 ~~2014~~2016 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 ~~2014~~2016 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 ~~2014~~2016 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 ~~2014”~~2016” in our ~~2014~~2016 Proxy Statement, which section is incorporated in this annual report on Form 10-K by reference.

116

PART IV

Item 15. Exhibits, Financial Statement Schedules




(a)	1.	Financial Statements

The following consolidated financial statements for the year ended October 31, ~~2013,~~2015, are included in Item 8 of this report as follows:

Consolidated Balance Sheets – October 31, ~~2013~~2015 and ~~2012~~ 2014 Consolidated Statements of Comprehensive Income – Years Ended October 31, ~~2013, 2012~~2015, 2014 and ~~2011~~ 2013 Consolidated Statements of Cash Flows – Years Ended October 31, ~~2013, 2012~~2015, 2014 and ~~2011~~ 2013 Consolidated Statements of Stockholders’ Equity – Years Ended October 31, ~~2013, 2012~~2015, 2014 and ~~2011~~ 2013 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 ~~10.20~~10.17 are management contracts or compensatory plans or arrangements.

	2.1	Agreement and Plan of Merger, dated as of October 24, 2015, by and among Duke Energy Corporation, Forest Subsidiary, Inc. and Piedmont Natural Gas Company, Inc. (incorporated by reference to Exhibit 2.1, Form 8-K dated October 26, 2015).

	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).

117




		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).

		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 5% Medium-Term Note, Series E, dated as of December 19, 2003 (incorporated by reference to Exhibit 99.1, Form 8-K, dated December 23, 2003).~~

~~4.14~~ 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).
~~4.15~~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).
~~4.16~~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).
~~4.17~~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).
~~4.18~~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).
~~4.19~~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).

118



		~~4.20~~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).

		~~4.21~~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).

		~~4.22~~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).

		~~4.23~~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).

		~~4.24~~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).

~~4.25~~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).
~~4.26~~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).

~~4.27~~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 (incorporated by reference to Exhibit 4.29, Form 10-K for the fiscal year ended October 31, 2014).
4.30 Seventh Supplemental Indenture, dated September 14, 2015, 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 14, 2015).
4.31 Form of 3.60% Senior Notes due 2025 (incorporated by reference to Exhibit 4.2, Form 8-K dated September 14, 2015).
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).

119



		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).

		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).~~Agreement.

		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~~10.7 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~~10.8 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~~ Employment Agreement between Piedmont Natural Gas Company, Inc. and Jane R. Lewis-Raymond, dated as of August 1, 2011 (incorporated by reference to Exhibit 10.19, Form 10-K for the fiscal year ended October 31, 2011).
~~10.13~~ ~~Form of 2013 Retention Award Agreement, dated as of December 15, 2010 (incorporated by reference to Exhibit 10.2, Form 10-Q for the quarter ended January 31, 2011).~~
~~10.14~~10.9 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).
~~10.15~~10.10 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).
~~10.16~~ Employment Agreement, dated February 1, 2012, between Piedmont Natural Gas Company, Inc. and Victor M. Gaglio (incorporated by reference to Exhibit 10.1, Form 10-Q for the quarter ended April 30, 2012).
~~10.17~~10.11 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).

~~10.18~~10.12 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).
~~10.19~~10.13 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).
~~10.20~~10.14 ~~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~~Resolution of Board of Directors, June 6, 2014, establishing compensation for ~~the fiscal year ended October 31, 2012).~~
~~Other Contracts:~~
~~10.21~~ ~~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~~non-management directors (incorporated by reference to Exhibit 10.1, Form 10-Q for the quarter ended ~~April 30, 2004)~~July 31, 2014).
~~10.22~~10.15 ~~First Amendment to~~Piedmont Natural Gas Company Employee Stock Purchase Plan Amended and Restated ~~Limited Liability Company Agreement~~as of ~~SouthStar Energy Services LLC,~~November 1, 2014, 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).~~
~~10.23~~ 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).
~~10.24~~ 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).
~~10.25~~ ~~Equity Contribution Agreement, dated as of November 12, 2004, between Columbia Gas Transmission Corporation and Piedmont Natural Gas Company~~January 30, 2015 (incorporated by reference to Exhibit 10.1, Form ~~8-K dated November 16, 2004)~~10-Q for the quarter ended January 31, 2015).

120




		~~10.26~~10.16		~~Operating Agreement of Hardy Storage~~Piedmont Natural Gas Company, ~~LLC,~~Inc. Voluntary Deferral Plan, amended and restated effective March 31, 2015, dated ~~as of November 12, 2004~~May 1, 2015 (incorporated by reference to Exhibit ~~10.3,~~10.1, Form ~~8-K dated November 16, 2004)~~10-Q for the quarter ended July 31, 2015).

		~~10.27~~10.17		~~Second Amendment to Amended and Restated Limited Liability Company Agreement~~Resolution of ~~SouthStar Energy Services LLC by and between Georgia Natural Gas Company and Piedmont Energy Company, dated July 2, 2009~~Board of Directors, June 5, 2015, establishing compensation for non-management directors (incorporated by reference to Exhibit 10.2, Form 10-Q for the quarter ended July 31, ~~2009)~~2015).

		~~10.28~~		~~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).~~Other Contracts:

		~~10.29~~		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).

		~~10.30~~10.18		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).

		~~10.31~~10.19		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.~~Lender (incorporated by reference to Exhibit 10.34, Form 10-K for the fiscal year ended October 31, 2012).

		~~10.32~~10.20		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).

		~~10.33~~10.21		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).

~~10.34~~ 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).
~~10.35~~ Underwriting Agreement dated January 29, 2013, among Piedmont Natural Gas Company, Inc., Morgan Stanley & Co. LLC, J.P. Morgan Securities LLC and Wells Fargo Securities, LLC, individually and acting as representatives of each of the other underwriters named in Schedule II thereto, and Morgan Stanley & Co. LLC, as forward counterparty (incorporated by reference to Exhibit 1.1, Form 8-K filed February 4, 2013).
~~10.36~~ 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).
~~10.37~~10.22 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).
~~10.38~~ Underwriting Agreement dated July 29, 2013, among the Company, Merrill Lynch, Pierce, Fenner & Smith Incorporated, U.S. Bancorp Investments, Inc., individually and acting as representatives of each of the other underwriters named in Schedule A thereto (incorporated by reference to Exhibit 1.1, Form 8-K filed August 1, 2013).
~~10.39~~10.23 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).
10.24 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).

10.25 * 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. (incorporated by reference to Exhibit 10.35, Form 10-K for the fiscal year ended October 31, 2014).
10.26 ATM Equity Offering Sales Agreement dated January 7, 2015 between the Company and Merrill Lynch, Pierce, Fenner & Smith Incorporated (incorporated by reference to Exhibit 1.1, Form 8-K dated January 7, 2015).

121



		10.27		ATM Equity Offering Sales Agreement dated January 7, 2015 between the Company and J.P. Morgan Securities LLC (incorporated by reference to Exhibit 1.2, Form 8-K dated January 7, 2015).

		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.
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 as of October 31, 2015 and 2014; (3) Consolidated Statements of Comprehensive Income for the years ended October 31, 2015, 2014 and 2013; (4) Consolidated Statements of Cash Flows for the years ended October 31, 2015, 2014 and 2013; (5) Consolidated Statements of Stockholders’ Equity for the years ended October 31, 2015, 2014 and 2013; and Notes to Consolidated Financial Statements.

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, 2013 and 2012; (3) Consolidated Statements of Comprehensive Income for the years ended October 31, 2013, 2012 and 2011; (4) Consolidated Statements of Cash Flows for the years ended October 31, 2013, 2012 and 2011; (5) Consolidated Statements of Stockholders’ Equity for the years ended October 31, 2013, 2012 and 2011; and Notes to Consolidated Financial Statements.

122

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, ~~2013~~2015

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~~
Signature		Title

/s/ Thomas E. Skains		Chairman of the Board, President and
Thomas E. Skains		Chief Executive Officer
		(Principal Executive Officer)

Date: December 23, ~~2013~~2015

/s/ Karl W. Newlin		Senior Vice President and
Karl W. Newlin		Chief Financial Officer
		(Principal Financial Officer)

Date: December 23, ~~2013~~2015

/s/ Jose M. Simon		Vice President and Controller
Jose M. Simon		(Principal Accounting Officer)

Date: December 23, ~~2013~~2015

123



~~Signature~~		~~Title~~
Signature		Title

/s/ E. James Burton		Director
E. James Burton

/s/ Malcolm E. Everett III		Director
Malcolm E. Everett III

/s/ ~~John W. Harris~~ Gary A. Garfield		Director
~~John W. Harris~~Gary A. Garfield

~~/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 W. McElreath		Director
Vicki W. McElreath

/s/ Thomas M. Pashley		Director
Thomas M. Pashley

/s/ Minor M. Shaw		Director
Minor M. Shaw

/s/ ~~Muriel W. Sheubrooks~~ Jo Anne Sanford		Director
~~Muriel W. Sheubrooks~~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

~~Piedmont Natural Gas Company, Inc.~~

~~Form 10-K~~

~~For the Fiscal Year Ended October 31, 2013~~

~~Exhibits~~

124



~~10.39~~		~~Second Amended and Restated Limited Liability Company Agreement of SouthStar Energy Services LLC, dated as of September 1, 2013, by and between Georgia~~Piedmont Natural Gas Company, ~~and Piedmont Energy Company~~Inc.
		Form 10-K
		For the Fiscal Year Ended October 31, 2015

		Exhibits

10.5		Form of Performance Unit Award Agreement

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

125



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)



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



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



Class		Outstanding at December ~~13, 2013~~ 11, 2015
Common Stock, no par value		~~76,116,503~~80,985,282



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


				~~Page~~

~~Part I.~~

~~Item 1.~~Piedmont Natural Gas Company, Inc.

~~Business~~
2015 FORM 10-K ANNUAL REPORT
TABLE OF CONTENTS
		1
~~Item 1A.~~		~~Risk Factors~~ Page
Part I.			11
~~Item 1B.~~		~~Unresolved Staff Comments~~
19Item 1.	Business	1
Item 1A.	Risk Factors	9
Item 1B.	Unresolved Staff Comments	16
Item 2.	Properties	17
Item 3.	Legal Proceedings	17
Item 4.	Mine Safety Disclosures	17

Part II.
~~Item 2.~~		~~Properties~~			19
~~Item 3.~~		~~Legal Proceedings~~			20
~~Item 4.~~		~~Mine Safety Disclosures~~			20

~~Part II.~~

Item 5.		Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities			21	18
Item 6.		Selected Financial Data			24	21
Item 7.		Management’s Discussion and Analysis of Financial Condition and Results of Operations			24	21
Item 7A.		Quantitative and Qualitative Disclosures about Market Risk			56	47
Item 8.		Financial Statements and Supplementary Data			58	48
Item 9.		Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	113
Item 9A.	Controls and Procedures	113
Item 9B.	Other Information	116

~~134~~Part III.
~~Item 9A.~~		~~Controls and Procedures~~			~~134~~
~~Item 9B.~~		~~Other Information~~			~~137~~

~~Part III.~~

Item 10.		Directors, Executive Officers and Corporate Governance			~~137~~	116
Item 11.		Executive Compensation			~~137~~	116
Item 12.		Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters			~~137~~	116
Item 13.		Certain Relationships and Related Transactions, and Director Independence			~~138~~	116
Item 14.		Principal Accounting Fees and Services	116

~~138~~Part IV.

~~Part IV.~~

Item 15.		Exhibits, Financial Statement Schedules	117
			~~139~~

		Signatures			~~148~~	123


	Assets		Earnings Before Taxes

Regulated Utility		97%		88%


Non-utility Activities:
Regulated non-utility activities		2%		5%
Unregulated non-utility activities		1%		7%

Total non-utility activities		3%		12%



			Earnings
	Assets		Before Taxes
Regulated Utility	96	%	85	%
Non-utility Activities:
Regulated non-utility activities	3	%	7	%
Unregulated non-utility activities	1	%	8	%
Total non-utility activities	4	%	15	%


	2013		2012
Residential customers		46 %		48 %
Commercial customers		26 %		27 %
Large volume customers, including industrial, power generation and resale customers		15 %		12 %
Secondary market activities		12 %		12 %
Other sources		1 %		1 %

Total		100 %		100 %


	2013		2012		2011
Fixed margin (from margin decoupling in North Carolina, facilities charges to our customers and fixed-rate contracts)		73 %		72 %		70 %
Semi-fixed margin (RSA in South Carolina and WNA in South Carolina and Tennessee)		16 %		17 %		18 %
Volumetric or periodic renegotiation		11 %		11 %		12 %
Total		100 %		100 %		100 %


	2013		2012
Residential new home construction		10,299		7,939
Residential conversion		2,463		3,789	*
Commercial		1,512		1,546

Total new customers		14,274		13,274



~~Williams-Transco~~ Williams – Transco	632,100	~~632,200~~
~~El Paso-Tennessee~~Kinder Morgan – Tennessee Pipeline	37,000	~~74,100~~
~~Spectra-Texas~~Spectra – Texas Eastern (partially through East Tennessee and Transco)	11,700	~~36,700~~
~~Oneok-Midwestern (through either Tennessee, Columbia Gulf,~~Spectra – East Tennessee or(through Transco)	44,800	~~120,000~~
~~NiSource-Columbia~~Oneok – Midwestern (through East Tennessee)	25,000
Columbia Pipeline Group – Columbia Gas (through Transco and Columbia Gulf)		42,800
~~NiSource-Columbia~~Columbia Pipeline Group – Columbia Gulf	41,000	~~15,000~~
Total	834,400
~~Total~~		~~920,800~~



Piedmont Liquefied Natural Gas (LNG)	270,000	~~250,000~~
Pine Needle LNG (through Transco)		263,400
~~Williams-Transco~~Williams – Transco Storage		86,100
~~NiSource-Columbia~~Columbia Pipeline Group – Columbia Gas Storage		96,400
Hardy Storage (through Columbia Gas and Transco)		68,800
~~Dominion~~Kinder Morgan – Tennessee Pipeline Storage ~~(through Transco)~~	55,900	~~13,200~~
~~Kinder Morgan-Tennessee Pipeline Storage~~ Total	840,600	~~55,900~~

~~Total~~		~~833,800~~


2013	High		Low		2012	High		Low

Quarter ended:					Quarter ended:
January 31		$ 33.10	$	28.51	January 31	$	34.74	$	29.90
April 30		34.92		31.73	April 30		34.00		29.05
July 31		35.53		32.39	July 31		33.03		28.90
October 31		35.05		31.56	October 31		33.72		31.03


	2013		2012		2011		2010		2009
Operating Revenues (in thousands):
Sales and Transportation:
Residential	$	588,546	$	534,321	$	658,892	$	743,346	$	787,994
Commercial		331,831		301,013		379,846		428,085		462,160
Industrial		113,182		95,177		104,774		116,122		126,855
Power Generation		64,109		36,027		28,969		21,708		19,609
For Resale		9,549		9,512		9,692		11,061		11,746

Total		1,107,217		976,050		1,182,173		1,320,322		1,408,364
Secondary Market Sales		164,130		140,380		244,824		224,973		221,300
Miscellaneous		6,882		6,350		6,908		7,000		8,452

Total	$	1,278,229	$	1,122,780	$	1,433,905	$	1,552,295	$	1,638,116


Gas Volumes - Dekatherms
(in thousands):
System Throughput:
Residential		55,283		43,788		57,778		58,327		55,298
Commercial		39,602		33,774		40,749		39,994		38,526
Industrial		95,019		89,234		90,842		82,805		74,363
Power Generation		190,862		151,675		83,522		63,024		39,639
For Resale		6,834		5,829		6,870		8,465		9,048

Total		387,600		324,300		279,761		252,615		216,874


Secondary Market Sales		41,605		48,373		48,835		46,823		46,057


Number of Customers Billed
(12-month average):
Residential		890,887		878,851		871,401		864,205		855,670
Commercial		96,009		95,100		94,485		94,287		94,404
Industrial		2,271		2,265		2,265		2,273		2,358
Power Generation		24		22		22		20		20
For Resale		15		15		15		16		17



	2015		2014			2013			2012		2011
Operating Revenues (in thousands):
Sales and Transportation:
Residential	$	656,182	$	683,848		$	588,546		$	534,321	$	658,892
Commercial	370,339		397,004			331,831			301,013		379,846
Industrial	106,986		115,515			113,182			95,177		104,774
Power Generation	85,650		85,902			64,109			36,027		28,969
For Resale	10,208		9,587			9,549			9,512		9,692
Total	1,229,365		1,291,856			1,107,217			976,050		1,182,173
Secondary Market Sales	134,322		169,543			164,130			140,380		244,824
Miscellaneous	8,031		8,589			6,882			6,350		6,908
Total	$	1,371,718	$	1,469,988		$	1,278,229		$	1,122,780	$	1,433,905

Gas Volumes - Dekatherms (in thousands)
System Throughput:
Residential	61,004		61,782			55,283			43,788		57,778
Commercial	44,616		44,259			39,602			33,774		40,749
Industrial	96,380		95,780			95,019			89,234		90,842
Power Generation	262,161		201,707			190,862			151,675		83,522
For Resale	7,362		7,174			6,834			5,829		6,870
Total	471,523		410,702			387,600			324,300		279,761

Secondary Market Sales	30,759		20,516			41,605			48,373		48,835

Number of Customers Billed (12-month average):
Residential	916,719		903,067			890,887			878,851		871,401
Commercial	98,544		97,288			96,009			95,100		94,485
Industrial	2,283		2,279			2,271			2,265		2,265
Power Generation	25		25			24			22		22
For Resale	15		16			15			15		15
Total	1,017,586		1,002,675			989,206			976,253		968,188

Cost of Gas (in thousands):
Natural Gas Commodity Costs	$	450,100	$	621,604		$	526,703		$	379,145	$	666,930
Capacity Demand Charges	131,196		144,313			151,369			129,090		136,139
Natural Gas Withdrawn From
(Injected Into) Storage, net	25,715		(13,578		)	(5,867		)	27,580		11,362
Regulatory Charges (Credits), net	37,413		27,441			(15,466		)	11,519		45,835


	~~Dividends Paid~~		~~Dividends Paid~~
~~2013~~	~~Per Share~~	~~2012~~	~~Per Share~~

~~Quarter ended:~~		~~Quarter ended:~~
~~January 31~~	~~30¢~~	~~January 31~~	~~29¢~~
~~April 30~~	~~31¢~~	~~April 30~~	~~30¢~~
~~July 31~~	~~31¢~~	~~July 31~~	~~30¢~~
~~October 31~~	~~31¢~~	~~October 31~~	~~30¢~~


Margin by Customer Class

In thousands	2013				2012				2011
Sales and Transportation:
Residential	$	331,920	54	%	$	321,056	56	%	$	319,675	56	%
Commercial		155,065	25	%		150,306	26	%		150,681	26	%
Industrial		52,268	8	%		46,993	8	%		47,176	8	%
Power Generation		56,312	9	%		32,289	6	%		23,970	4	%
For Resale		7,477	1	%		7,465	1	%		8,550	2	%

Total		603,042	97	%		558,109	97	%		550,052	96	%
Secondary Market Sales		8,979	1	%		9,681	2	%		14,016	2	%
Miscellaneous		9,469	2	%		7,656	1	%		9,571	2	%

Total	$	621,490	100	%	$	575,446	100	%	$	573,639	100	%



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/~~13 -~~15 – 8/31/13 15	-—	$ —	-	-—	2,910,074
9/1/~~13 -~~15 – 9/30/13 15	-—	$ —	-	-—	2,910,074
10/1/~~13 -~~15 – 10/31/13 15	-—	$ —	-	-—	2,910,074

Total	—	—	—


	2008		2009		2010		2011		2012		2013
Piedmont	$	100	$	74	$	97	$	112	$	113	$	126
LDC Peer Group		100		104		132		156		167		205
S&P 500 Index		100		110		128		138		159		203


In thousands except per share amounts	2013		2012		2011		2010		2009

Operating Revenues	$	1,278,229	$	1,122,780	$	1,433,905	$	1,552,295	$	1,638,116
Margin (operating revenues less cost of gas)	$	621,490	$	575,446	$	573,639	$	552,592	$	561,574
Net Income	$	134,417	$	119,847	$	113,568	$	141,954	$	122,824
Earnings per Share of Common Stock:
Basic	$	1.80	$	1.67	$	1.58	$	1.96	$	1.68
Diluted	$	1.78	$	1.66	$	1.57	$	1.96	$	1.67
Cash Dividends per Share of Common Stock	$	1.23	$	1.19	$	1.15	$	1.11	$	1.07
Total Assets	$	4,368,609	$	3,769,939	$	3,242,541	$	3,053,275	$	3,118,819
Long-Term Debt (less current maturities)	$	1,174,857	$	975,000	$	675,000	$	671,922	$	732,512


							Percent Change
							2013 vs.			2012 vs.
In thousands except per share amounts	2013		2012		2011		2012			2011

Operating Revenues	$	1,278,229	$	1,122,780	$	1,433,905		13.8	%		(21.7	)%
Cost of Gas		656,739		547,334		860,266		20.0	%		(36.4	)%

Margin		621,490		575,446		573,639		8.0	%		0.3	%

Operations and Maintenance		253,120		242,599		225,351		4.3	%		7.7	%
Depreciation		112,207		103,192		102,829		8.7	%		0.4	%
General Taxes		34,635		34,831		38,380		(0.6	)%		(9.2	)%
Utility Income Taxes		77,334		69,101		64,068		11.9	%		7.9	%

Total Operating Expenses		477,296		449,723		430,628		6.1	%		4.4	%

Operating Income		144,194		125,723		143,011		14.7	%		(12.1	)%
Other Income (Expense), net of tax		15,161		14,221		14,549		6.6	%		(2.3	)%
Utility Interest Charges		24,938		20,097		43,992		24.1	%		(54.3	)%

Net Income	$	134,417	$	119,847	$	113,568		12.2	%		5.5	%


Average Shares of Common Stock:
Basic		74,884		71,977		72,056		4.0	%		(0.1	)%
Diluted		75,333		72,278		72,266		4.2	%		-	%

Earnings per Share of Common Stock:
Basic	$	1.80	$	1.67	$	1.58		7.8	%		5.7	%
Diluted	$	1.78	$	1.66	$	1.57		7.2	%		5.7	%



Comprehensive Income Statements Components

							Percent Change
							2015 vs.		2014 vs.
In thousands, except per share amounts	2015		2014		2013		2014		2013
Operating Revenues	$	1,371,718	$	1,469,988	$	1,278,229	(6.7	)%	15.0	%
Cost of Gas	644,424		779,780		656,739		(17.4	)%	18.7	%
Margin	727,294		690,208		621,490		5.4	%	11.1	%
Operations and Maintenance	294,517		270,877		253,120		8.7	%	7.0	%
Depreciation	128,704		118,996		112,207		8.2	%	6.1	%
General Taxes	42,110		37,294		34,635		12.9	%	7.7	%
Utility Income Taxes	76,934		83,176		77,334		(7.5	)%	7.6	%
Total Operating Expenses	542,265		510,343		477,296		6.3	%	6.9	%
Operating Income	185,029		179,865		144,194		2.9	%	24.7	%
Other Income (Expense), net of tax	20,613		18,622		15,161		10.7	%	22.8	%
Utility Interest Charges	68,631		54,686		24,938		25.5	%	119.3	%
Net Income	$	137,011	$	143,801	$	134,417	(4.7	)%	7.0	%

Average Shares of Common Stock:
Basic	78,942		77,883		74,884		1.4	%	4.0	%
Diluted	79,231		78,193		75,333		1.3	%	3.8	%

Earnings per Share of Common Stock:
Basic	$	1.74	$	1.85	$	1.80	(5.9	)%	2.8	%
Diluted	$	1.73	$	1.84	$	1.78	(6.0	)%	3.4	%



Gas Deliveries, Customers, Weather Statistics and Number of Employees

							Percent Change
							2015 vs.		2014 vs.
	2015		2014		2013		2014		2013
Deliveries in Dekatherms (in thousands):
Residential	61,004		61,782		55,283		(1.3	)%	11.8	%
Commercial	44,616		44,259		39,602		0.8	%	11.8	%
Industrial	96,380		95,780		95,019		0.6	%	0.8	%
Power Generation	262,161		201,707		190,862		30.0	%	5.7	%
For Resale	7,362		7,174		6,834		2.6	%	5.0	%
Throughput	471,523		410,702		387,600		14.8	%	6.0	%
Secondary Market Volumes	30,759		20,516		41,605		49.9	%	(50.7	)%

Customers Billed (at period end)	1,011,959		992,551		979,909		2.0	%	1.3	%
Gross Residential, Commercial and Industrial Customer Additions	17,017		16,251		14,293		4.7	%	13.7	%
Degree Days
Actual	3,449		3,543		3,336		(2.7	)%	6.2	%
Normal	3,257		3,265		3,276		(0.2	)%	(0.3	)%
Percent colder than normal	5.9	%	8.5	%	1.8	%	n/a		n/a
Number of Employees (at period end)	1,943		1,879		1,795		3.4	%	4.7	%


Changes in Operating Revenues- Increase (Decrease)

	2013 vs.		2012 vs.
In millions	2012		2011
Residential and commercial customers	$	136.2	$	(275.4)
Industrial customers		18.0		(9.8)
Power generation customers		28.1		7.1
Secondary market		23.8		(104.4)
Margin decoupling mechanism		(40.8)		53.7
WNA mechanisms		(10.4)		18.2
Other		.5		(.5)

Total	$	155.4	$	(311.1)



Changes in Operating Revenue - Increase (Decrease)
	2015 vs.			2014 vs.
In millions	2014			2013
Residential and commercial customers	$	(85.2	)	$	201.5
Industrial customers	(9.6		)	1.4
Power generation customers	(0.3		)	21.8
Secondary market	(35.2		)	5.4
Margin decoupling mechanism	6.4			(39.4		)
WNA mechanisms	1.6			(11.4		)
IMR mechanisms	24.6			10.7
Other	(0.6		)	1.8
Total	$	(98.3	)	$	191.8



Changes in Cost of Gas - Increase (Decrease)
	2015 vs.			2014 vs.
In millions	2014			2013
Commodity gas costs passed through to sales customers	$	(125.8	)	$	137.5
Commodity gas costs in secondary market transactions	(31.0		)	(11.0		)
Pipeline demand charges	(13.1		)	(7.1		)
Regulatory approved gas cost mechanisms	34.5			3.6
Total	$	(135.4	)	$	123.0


Changes in Cost of Gas- Increase (Decrease)
In millions	2013 vs. 2012		2012 vs. 2011
Commodity gas costs passed through to sales customers	$	96.8	$	(194.3)
Commodity gas costs in secondary market transactions		24.5		(100.1)
Pipeline demand charges		22.3		(7.0)
Regulatory approved gas cost mechanisms		(34.2)		(11.5)

Total	$	109.4	$	(312.9)



Regulatory Mechanism	North Carolina	South Carolina	Tennessee
WNA mechanism*		X	X
Margin decoupling mechanism *	X
Natural gas rate stabilization mechanism		X
Secondary market programs **	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- Increase (Decrease)
	2013 vs.		2012 vs.
In millions	2012		2011
Residential and commercial customers	$	15.6	$	1.0
Industrial customers		5.3		(1.3)
Power generation customers		24.0		8.3
Secondary market activity		(.7)		(4.3)
Net gas cost adjustments		1.8		(1.9)

Total	$	46.0	$	1.8



Changes in Margin - Increase (Decrease)
	2015 vs.			2014 vs.
In millions	2014			2013
Residential and commercial customers	$	39.9		$	31.2
Industrial customers	2.7			—
Power generation customers	(0.3		)	21.3
Secondary market activity	(4.3		)	16.4
Net gas cost adjustments	(0.9		)	(0.2		)
Total	$	37.1		$	68.7



Changes in Operations and Maintenance Expenses - Increase (Decrease)
	2015 vs.			2014 vs.
In millions	2014			2013
Contract labor	$	13.4		$	1.9
Payroll	7.9			9.6
Employee benefits	2.5			(0.3		)
Regulatory	1.0			4.2
Bad debt	(1.8		)	2.1
Other	0.6			0.3
Total	$	23.6		$	17.8



Changes in General Taxes - Increase (Decrease)
	2015 vs.		2014 vs.
In millions	2014		2013
Property taxes	$	3.1	$	1.5
Franchise taxes	1.3		0.9
Other	0.4		0.3
Total	$	4.8	$	2.7


In thousands	Credit Facility			Commercial Paper			Total 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	$	-		$	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	%

2012
End of period (October 31, 2012):
Amount outstanding	$	-		$	365,000		$	365,000
Weighted average interest rate		-	%		.42	%		.42	%

During the period (August 1, 2012 - October 31, 2012):
Average amount outstanding	$	-		$	444,300		$	444,300
Minimum amount outstanding	$	-		$	335,000		$	335,000
Maximum amount outstanding	$	-		$	535,000		$	535,000
Minimum interest rate		-	%		.30	%		.30	%
Maximum interest rate		-	%		.45	%		.45	%
Weighted average interest rate		-	%		.39	%		.39	%

Maximum amount outstanding during the month:
August 2012	$	-		$	450,000		$	450,000
September 2012		-			500,000			500,000
October 2012		-			535,000			535,000

During the year ended October 31, 2012:
Average amount outstanding	$	144,700		$	404,700		$	416,300
Minimum amount outstanding⁽¹⁾	$	-		$	-		$	328,500
Maximum amount outstanding⁽¹⁾	$	475,500		$	535,000		$	535,000
Minimum interest rate⁽²⁾		1.15	%		.22	%		.22	%
Maximum interest rate		1.20	%		.45	%		1.20	%
Weighted average interest rate		1.17	%		.38	%		.66	%

⁽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.


Actuarial Assumption	Change in Assumption			Impact on 2013 Benefit Cost		Impact on Projected Benefit Obligation
				Increase (Decrease) In thousands
Discount rate		(.25	)%	$	629	$	6,544
Rate of return on plan assets		(.25	)%		660		N/A
Rate of increase in compensation		.25	%		719		3,762


				Impact on 2013		Impact on Accumulated
	Change in			Postretirement		Postretirement Benefit
Actuarial Assumption	Assumption			Benefit Cost		Obligation
				Increase (Decrease)
				In thousands
Discount rate		(.25	)%	$	-	$	840
Rate of return on plan assets		(.25	)%		57		N/A
Health care cost trend rate		.25	%		3		171


In thousands

Amount available for restricted payments	$	760,870
Retained earnings		627,236


	Credit			Commercial			Total
In thousands	Facility			Paper			Borrowings

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.