These decreases were partially offset by$2.3 million in other miscellaneous expenses primarily due to a recovery disallowance of some prior years’ franchise fees in one of our jurisdictions and higher bank fees from increased activity and unused amounts of the following increases:revolving syndicated credit facility.
$1.5 million in materials.
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| • | $3.6 million in payroll expense primarily due to an increase in long-term incentive plan accruals in 2008 because of a higher share price and performance levels, partially offset by the impact of fewer employees. |
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| • | $2.3 million in contract labor primarily due to contract billing services, telecom and financial, gas accounting and compliance systems. |
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| • | $.5 million in utilities primarily due to increased charges for measurement systems. |
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| • | $.5 million in advertising. |
Operations and maintenance expenses decreased $4.9increased $11.7 million in 20072010 compared with 20062009 primarily due to the following decreases:increases:
$4.2 million in payroll expense primarily from increases in long-term incentive plan accruals priced as a higher current stock price and merit wage increases for non-officer employees.
$3.3 million in employee benefits expense due primarily to increases in pension expense from a lower discount rate used to determine periodic benefit cost and group insurance expense from higher claims.
| | |
| • | $11 million in payroll primarily related to the management restructuring program in 2006, including impacts on short-term and long-term incentive plan accruals. For further information, see Note 12 to the consolidated financial statements. |
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| • | $.6 million in transportation costs primarily due to fewer vehicles being used as a result of our automated meter reading initiative and continuous business process improvements. |
$2.4 million in contract labor for contract billing services, telecom and activity related to a new corporate rebranding campaign.
These decreases were partially offset by the following increases:$.9 million in advertising and sales promotion related to a new corporate rebranding campaign.
| | |
| • | $3.2 million in outside services primarily due to increased telephony services and our gas accounting, financial close and record retention projects. |
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| • | $2 million in employee benefits primarily due to pension and postretirement health care costs and health initiative programs and adjustments in group insurance expense. |
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| • | $1.3 million in regulatory expense primarily due to consulting related to gas cost accounting reviews. |
Depreciation expense increased from $89.7$97.4 million to $93.1$102.8 million over the three-year period 20062009 to 20082011 primarily due to increases in plant in service.
General taxes increased $.8$4.5 million in 20082011 compared with 20072010 primarily due to the following changes:increases:
$2.5 million from the accrual and payment of a liability for sales tax on certain customer accounts that were not exempt from sales tax.
$1.8 million in property taxes related to a larger property base and property value reassessments by taxing authorities.
| | |
| • | $.6 million increase in property taxes related to a refund for South Carolina taxes in the prior year. |
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| • | $.4 million increase in gross receipts taxes in Tennessee. |
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| • | $.2 million decrease in payroll taxes primarily related to organizational restructuring and process improvement initiatives that began in 2007, partially offset by an increase in the social security wage limit. |
General taxes decreased $.7 millionby an insignificant amount in 20072010 compared with 2006 primarily due to the following changes:
| | |
| • | $1.2 million decrease in property taxes related to lower assessments in South Carolina and Tennessee as well as refunds from South Carolina for prior years. |
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| • | $.5 million decrease in payroll taxes. |
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| • | $.9 million increase in gross receipts taxes in Tennessee. |
2009.Other Income (Expense)
Other Income (Expense) is comprised of income from equity method investments, gain on sale of interest in equity method investment, non-operating income, charitable contributions, non-operating expense and income taxes related to these items. Non-operating income
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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 other miscellaneous expenses.
The primary changes to Other Income (Expense) in 2011 compared with 2010 were in income from equity method investments, the gain on the sale of half of our ownership interest in SouthStar Energy Services LLC (SouthStar) in 2010 and non-operating income discussed below. All other changes were not significant.
insignificant.On January 1, 2010, we sold half of our 30% membership interest in SouthStar to the other member of the joint venture and retained a 15% earnings and membership interest after the sale. The pre-tax gain on the sale was $49.7 million. The after-tax gain was $30.3 million, or $.42 per diluted earnings per share, for 2010.
Income from equity method investments decreased $9.4$4.8 million in 20082011 compared with 20072010 primarily due to a decrease of $4.5 million in earnings from SouthStar due to a full year of recording earnings at the following changes:
| | |
| • | $9.9 million decrease in earnings from SouthStar primarily due to lower of cost or market inventory adjustments, lower contributions from the management of storage and transportation assets, a loss on weather derivatives and a Georgia Public Service Commission consent agreement related to retail pricing. |
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| • | $.9 million increase in earnings from Hardy Storage primarily due to its first full year of operations, partially offset by higher operations and maintenance expenses, depreciation and general taxes. |
lower 15% ownership interest and unfavorable changes in SouthStar’s average customer usage due to warmer weather and retail pricing plan mix which were partially offset by decreases in operating expenses.Non-operating income increased $1.1 million in 2011 compared with 2010 primarily due to increased revenues under our non-regulated home service warranty program, interest earned on installment loans made to our natural gas customers under our third party financing program and a state tax refund on behalf of a joint venture.
Income from equity method investments increased $7.2decreased $4.6 million in 20072010 compared with 20062009 due to a $4.5 million decrease in earnings from SouthStar primarily due to the following changes:
| | |
| • | $5.3 million increase in earnings from SouthStar primarily due to hedging activities and retail price spreads. |
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| • | $2.8 million increase in earnings from Hardy Storage primarily due to storage revenues in 2007 as phase one service to customers began in April 2007. |
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| • | $.6 million decrease in earnings from Pine Needle due to reduced rates approved by the FERC in Pine Needle’s 2007 rate proceeding. |
recording of earnings at the new 15% ownership interest as of January 1, 2010 and a change in the retail pricing mix chosen by SouthStar customers with a decrease in the average number of customers, losses on weather derivatives and a decreased contribution from storage and transportation asset management due to higher transportation and commodity prices, partially offset by increased average customer usage due to colder weather, favorable changes in the lower of cost or market storage inventory adjustments and higher retail price spreads.Utility Interest Charges
Utility interest charges increased $2$.3 million in 20082011 compared with 20072010 primarily due to the following changes:
$3.7 million increase in net interest expense due to a decrease in interest charged on amounts due from customers (receivable), which earned a carrying charge, as those balances were lower in the current period.
$1.4 million increase in interest expense due to a decrease in interest in the borrowed allowance for funds used during construction (AFUDC), which is recorded as income, primarily due to the closing of approximately half of our construction expenditures to utility plant in service in the first half of the current year as compared with the prior year.
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| • | $2.7 million increase in regulatory interest expense primarily due to interesttrue-ups related to amounts due to customers. |
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| • | $.3 million increase in interest on short-term debt due to higher balances outstanding. |
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| • | $.9 million decrease in interest expense related to a federal tax audit settlement in 2007. |
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| • | $.3 million decrease in interest on regulatory treatment of certain components of deferred income taxes. |
$1.1 million increase in interest expense on short-term debt primarily due to average interest rates during the current period that were 44 basis points higher than the prior year period due to higher spreads under the new revolving syndicated credit facility that was put into place in January 2011.
$6.6 million decrease in interest on long-term debt primarily due to lower amounts of debt outstanding during the current period.
Utility interest charges increased $5decreased $3 million in 20072010 compared with 20062009 primarily due to the following changes:
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| • | $5.5 million increase in interest on long-term debt due to the issuance on June 20, 2006 of $200 million of insured quarterly notes due June 1, 2036, which was partially offset by the retirement on July 30, 2006 of $35 million of senior notes. |
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| • | $.9$9.1 million increase in net interest expense on regulatory treatment of certain components of deferred income taxes. |
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| • | $.9 million increase in interest expense related to a tax audit settlement. |
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| • | $2.1 million decrease in interest on short-term debt due to a decrease in interest charged on amounts due from customers (receivable), which earned a carrying charge, as those balances were lower balances outstanding in 2007 than in 2006 even though rates were slightly higher in the current period. |
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| • | $.4 million decrease in net interest expense on amounts due to/from customers due to higher net receivables in 2007. |
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$7.7 million decrease in interest expense due to an increase in the borrowed AFUDC, which is recorded as income, primarily due to increased construction expenditures.$2.4 million decrease in interest expense on long-term debt primarily due to lower amounts of debt outstanding.
$1.8 million decrease in interest expense on short-term debt primarily due to lower levels of borrowing in the current period combined with an average interest rate for the current period approximately 35 basis points lower than the prior period.
Financial Condition and Liquidity
To meet our capital and liquidity requirements, we rely on certain resources, including cash flows from operating activities, access to capital markets, cash generated from our investments in joint ventures and short-term bank borrowings. Our capital market 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.
We access ourbelieve that the capacity of short-term credit facility to finance our working capital needs and growth. Recent adverse developments in financial and credit markets have made it more difficult and more expensive to access the short-term capital market to meet our liquidity needs. Although the credit markets tightened in the latter half of 2008, we believe that these sources, including amounts available to us under our existingrevolving syndicated credit facility and seasonal facilities,the issuance of debt and equity securities, together with cash provided by operating activities, will continue to allow us to meet our needs for working capital, construction expenditures, investments in joint ventures, anticipated debt redemptions, dividend payments, employee benefit plan contributions, common share repurchases and dividend payments.
other cash needs.Short-Term Borrowings. On January 25, 2011, we replaced our existing $450 million five-year revolving syndicated credit facility with a new $650 million three-year revolving syndicated credit facility. The new facility expires in January 2014 and has an option to expand up to $850 million. The three-year revolving syndicated credit facility has the same financial covenant as our previous syndicated credit facility and has additional provisions regarding defaulting lenders and replacement of lenders. We pay an annual fee of $30,000 plus fifteen basis points for any unused amount up to $650 million. During the three months ended October 31, 2011, short-term borrowing ranged from $165.5 million to $342.5 million, and interest rates ranged from 1.10% to 1.15%. During the twelve months ended October 31, 2011, short-term borrowings ranged from $73.5 million to $426 million, and interest rates ranged from .51% to 1.17%.
Our short-term borrowings, which consist only of the revolving syndicated credit facility as included in “Bank debt” in the consolidated balance sheets, are vital in order to meet working capital needs, such as our seasonal requirements for gas supply, general corporate liquidity, capital expenditures and approved investments. We rely on short-term borrowings along 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 capital expenditures, which are fundamental to support our system infrastructure and the growth in our customer base. We believe that our revolving syndicated credit facility, along with our access to capital markets, will allow us to meet the increased capital requirements anticipated to be spent over the next two years.
Highlights for our bank borrowings as of October 31, 2011 and for the quarter and year ended October 31, 2011 are presented below.
Bank Borrowings
| | | | |
In thousands | | | |
End of period (October 31, 2011): | | | | |
Amount outstanding | | $ | 331,000 | |
Weighted average interest rate | | | 1.15 | % |
During the period (August 1, 2011 - October 31, 2011): | | | | |
Average amount outstanding | | $ | 236,000 | |
Weighted average interest rate | | | 1.14 | % |
Maximum amount outstanding during the month: | | | | |
August | | $ | 269,500 | |
September | | | 288,500 | |
October | | | 342,500 | |
During the year ended October 31, 2011: | | | | |
Average amount outstanding | | $ | 203,500 | |
Weighted average interest rate | | | .94 | % |
Maximum amount outstanding | | $ | 426,000 | |
The level of short-term bank borrowings 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.
As of October 31, 2011, we had $10 million available for letters of credit under our three-year revolving syndicated credit facility, of which $3.5 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, 2011, unused lines of credit available under our three-year revolving syndicated credit facility, including the issuance of the letters of credit, totaled $315.5 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 resulting from suchoperations. The major factors asthat 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 bank borrowings to meet seasonal working capital needs. During our first and second quarters, we generally experience overall positive cash flows from the sale of flowing gas and gas inwithdrawal from storage and the collection of amounts billed to customers during the November through March winter heating season (November through March).season. Cash requirements generally increase during the third and fourth quarters due to increases in natural gas purchases forinjected into storage, paying down short-term debt, seasonal construction activity and decreases in receipts from customers.
During the winter heating season, our accounts payable increase to reflect amounts due to our natural gas suppliers for commodity and pipeline capacity. The cost of the natural gas can vary significantly from period to period due to volatilitychanges in the price of natural gas, which is a function of market fluctuations in the pricecommodity cost of natural gas, along with our changing requirements for storage volumes. Differences between natural gas costs that we have paid to suppliers and amounts that we have collected from customers are included in regulatory deferred accounts and in amounts due to/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. 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.
Because of the economic recession in 2008,weak economy, including continued high unemployment, we may incur additional bad debt expense during the winter heating season, as well as experience increased customer conservation. We may incur more short-term debt to pay for gas supplies and other operating costs since collections from customers could be slower and some customers may not be able to pay their bills. Regulatory margin stabilizing and cost recovery mechanisms, such as those that allow us to recover the gas cost portion of bad debt expense, willare expected to mitigate the impact these factors may have on our results of operations.
Net cash provided by operating activities was $69.2$311.2 million in 2008, $233.52011, $360.5 million in 20072010 and $103.8$344.3 million in 2006.2009. Net cash provided by operating activities reflects a $5.6$28.4 million increasedecrease in net income for 2008,2011 compared with 2007.2010, which included the gain on the sale of half our interest in SouthStar as discussed in “Results of Operations” above in Item 7 of this Form 10-K in Management’s Discussion and Analysis of Financial Condition and Results of Operations. The effect of changes in working capital on net cash provided by operating activities is described below:
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| • | Trade accounts receivable and unbilled utility revenues increased $12.9 million in the current period primarily due to amounts billed to customers reflecting higher gas costs in 2008 as compared with 2007 and weather in the current period being 7% colder than the same prior period. Volumes sold to residential and commercial customers increased 5 million dekatherms as compared with the same prior period primarily due to the colder weather and customer growth. Total throughput increased 4.2Trade accounts receivable and unbilled utility revenues increased $2.5 million in the current period primarily due to total throughput which increased 27.1 million dekatherms as compared with the same prior period, largely from the transportation of gas for industrial customers and for power generation along with an increase in unbilled volumes, slightly offset by amounts billed to customers reflecting lower gas costs in 2011 as compared with 2010. Weather during the current period was 3.6% colder than the same prior period. Volumes sold to residential and commercial customers increased .2 million dekatherms as compared with the same prior period. |
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Net amounts due from customers decreased $26.3 million in the current period primarily due to the collection of deferred gas costs through rates.Gas in storage decreased $10.6 million in the current period primarily due to a decrease in the weighted average cost of gas purchased for injections as well as decreased volumes in storage in 2011 as compared with 2010.
Prepaid gas costs decreased $.8 million in the current period primarily due to lower average cost of gas in prepaid storage. Under some gas supply 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 $1.6 million in the current period primarily due to gas purchases for storage to meet customer demand for the next winter heating season.
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| • | Net amounts due from customers increased $105.9 million in the current period primarily due to the under-recovery of deferred gas and hedging costs. Included in the amounts due from customers were increased hedging costs from the extension of our hedging transactions over a longer term horizon and the expansion of those transactions to a greater percentage of sales quantities due to lower forward market prices. |
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| • | Gas in storage increased $58.8 million in the current period primarily due to a higher average cost of gas in storage as well as increased volumes in storage in 2008 as compared with 2007. |
|
| • | Prepaid gas costs increased $20.5 million in the current period primarily due to the higher average cost of gas in prepaid storage. Prepaid gas costs represent purchases of gas during the summer months under gas supply contracts that are not available for sale, and therefore not recorded in inventory, until the winter heating season. |
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| • | Trade accounts payable decreased $7.4 million in the current period primarily due to gas purchases at lower costs during the fourth quarter. |
Our three state regulatory commissions approve rates that are designed to give us the opportunity to generate revenues to cover our gas costs, and fixed and variable non-gas costs and to earn a fair return for our shareholders. We have a WNA mechanism in South Carolina and Tennessee that partially offsets the impact of colder- or warmer-than-normal weather on bills rendered in November through March for residential and commercial customers. The WNA in South Carolina and Tennessee generated chargescredits to customers of $6.8$4.9 million in 2008, $6.42011, $8.8 million in 20072010 and $4.1$1.2 million in 2006.2009. In Tennessee, adjustments are made directly to individual customer bills. In South Carolina, the adjustments are calculated at the individual customer level but are recorded in a deferred account“Amounts due from customers” or “Amounts due to customers” in the consolidated balance sheets 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 consumption patterns. The margin decoupling mechanism providedreduced margin of $25.4by $7 million in 20082011 and $32.7$5.9 million in 20072010 and $30.4increased margin by $6 million in 2006.2009. Our gas costs are recoverable through PGA procedures and are not affected by the WNA or the margin decoupling mechanism.
The financial condition of the natural gas marketers and pipelines that supply and deliver natural gas to our distribution system can increase our exposure to supply and price fluctuations. We believe our risk exposure to the financial condition of the marketers and pipelines is not significant based on our receipt of the products and services prior to payment and the availability of other marketers of natural gas to meet our firm supply needs if necessary.
We have regulatory commission approval in North Carolina, South Carolina and Tennessee that places tighter credit requirements on the retail natural gas marketers that schedule gas for transportation service on our system.
The regulated utility competes with other energy products, such as electricity and propane, in the residential and commercial customer markets. The most significant product competition is with electricity for space heating, water heating and cooking. Numerous factors can influence customer demand for natural gas, including price, value, availability, environmental attributes, 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 relationship between supply and demand has the greatest impact on the price of natural gas. With a tighter balance between domestic supply and demand, the cost of natural gas from non-domestic sources may play a greater role in establishing the future market 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.organizations, as well as the value of the US dollar versus other currencies. Our liquidity could be impacted, either positively or negatively, as a result of alternate fuel decisions made by industrial customers.
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In an effort to keep customer rates competitive by holding downand to maximize earnings, we continue to implement business process improvement and operations and maintenance costs and as part of an ongoing effort aimed at improving business processes, capturingcost management programs to capture operational and organizational efficiencies andwhile improving customer service we are continuing the process of standardizing our customer payment and collection processes, streamlining business operationsmaintaining a safe and further consolidating our call centers. These specific initiatives were largely completed during 2008. For further information, see Note 12 to the consolidated financial statements.
reliable system.Cash Flows from Investing Activities. Net cash used in investing activities was $177.4$252.6 million in 2008, $148.22011, $128.6 million in 20072010 and $167.6$129.6 million in 2006.2009. Net cash used in investing activities was primarily for utility construction expenditures. Gross utility construction expenditures were $181$243.6 million in 2008,2011, a 34%22% increase from the $135.2$199.1 million in 2007,2010, primarily due to system infrastructure investments.
$103.6 million and $52.3 million, respectively, of investments in plant to serve power generation customers. Gross utility construction expenditures were $129 million in 2009 with $2.6 million of investments in plant to serve power generation customers.We have a substantial capital expansion program for construction of transmission and distribution facilities, purchase of equipment and other general improvements. This program primarily supports our system infrastructure and the growth in our customer base. Gross utility construction expenditures totaling $246.2 million, primarily to serve future customer growth, are budgeted for 2009. We are not contractually obligated to expend capital until the work is completed. Even though we are seeing a slower pace of customer growth in our service territory due to the downturn in the housing market and other economic factors, significantSignificant utility construction expenditures are expected to continue to meet long-term growth, including the power generation market, 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.We anticipate making capital expenditures, including AFUDC, of $240 - 280 million and $80 - 90 million in our fiscal years 2012 and 2013, respectively, to provide natural gas service in the power generation market. These expenditures are significantly higher than we have traditionally expended. We intend to fund expenditures related to these projects in a manner that maintains our targeted capitalization ratio of 45-50% in long-term debt and 50-55% in common equity. Additional detail for the anticipated capital expenditures follows.
| | | | | | | | | | | | |
In millions | | 2012 | | | 2013 | | | 2014 | |
Utility capital expenditures | | $ | 300 - 320 | | | $ | 270 - 300 | | | $ | 200 - 250 | |
Power generation related capital expenditures | | | 240 - 280 | | | | 80 - 90 | | | | — | |
| | | | | | | | | | | | |
Total forecasted capital expenditures | | $ | 540 - 600 | | | $ | 350 - 390 | | | $ | 200 - 250 | |
| | | | | | | | | | | | |
In October 2009, we reached an agreement with Progress Energy Carolinas to provide natural gas delivery service to a power generation facility to be built at their Wayne County, North Carolina site. The agreement, approved by the NCUC in May 2010, calls for us to construct approximately 38 miles of 20-inch transmission pipeline along with compression facilities to provide natural gas delivery service to the plant by June 2012. We began construction in February 2010. Our investment in the pipeline and compression facilities is supported by a long-term service agreement. To provide the additional delivery service, we have executed an agreement with Cardinal Pipeline Company, LLC (Cardinal) to expand our firm capacity requirement by 149,000 dekatherms per day to serve this facility. This will require Cardinal to spend an estimated $48 million to expand its system. As a 21.49% equity venture partner of Cardinal, we will invest an estimated $10.3 million in Cardinal’s system expansion. Capital contributions related to this system expansion began in January 2011 and will continue on a periodic basis through September 2012. As of October 31, 2011, our contributions to date related to this system expansion were $6.2 million. For further information regarding this agreement, see Note 12 to the consolidated financial statements.
In April 2010, we reached another agreement with Progress Energy Carolinas to provide natural gas delivery service to a power generation facility to be built at their existing Sutton site near Wilmington, North Carolina. The agreement, also approved by the NCUC in May 2010, calls for us to construct approximately 130 miles of transmission pipeline along with compression facilities to provide natural gas delivery service to the plant by June 2013. We began construction in May 2010. Our service to Progress Energy Carolinas is supported by a long-term service agreement. We anticipate that a portion of the cost of this project will be included in our North Carolina utility rate base.
The Sutton facilities will also create cost effective expansion capacity that we will use to help serve the growing natural gas requirements of our customers in the eastern part of North Carolina. At the present time with the timing and design scope of the Sutton facilities, there is no current need to proceed with our plan to provide safe, reliablepreviously announced Robeson liquefied natural gas distribution service tostorage project. The timing and design scope of the expansion of our growing customer base and manage our seasonal demand growth, we intend to design, construct, own and operate a LNG peak storage facility as a regulated utility projectfacilities in Robeson County will be determined as our system infrastructure and market supply growth requirements in North Carolina withdictate.
During the capacity to store approximately 1.25 billion cubic feetfirst quarter of fiscal 2011, we placed into service natural gas for use during times of peak demand. The LNG facility is plannedpipeline and compression facilities to be inprovide natural gas delivery service for the2012-2013 winter heating season. Preliminary estimates place the cost of the facility in the $300 million to $350 million range, with $1.5 million incurred in fiscal year 2008.
During 2007, $2.2 million of supplier refunds was recorded as restricted cash. In 2008, restrictions on cash totaling $2.2 million were removed pursuant to a
2007 NCUC order,Progress Energy Carolinas power generation facility located in Richmond County, North Carolina.During the first quarter of fiscal 2011, we also placed into service natural gas pipeline facilities to provide natural gas delivery service to a Duke Energy Carolinas power generation facility located in Rowan County, North Carolina. In a second agreement with Duke Energy Carolinas, we placed into service in December 2011 natural gas pipeline facilities we constructed to provide natural gas delivery service to their Rockingham County, North Carolina power generation facility.
On January 1, 2010, we sold half of our 30% membership interest in SouthStar to Georgia Natural Gas Company (GNGC) and retained a 15% earnings and membership share in SouthStar after the sale. At closing, we liquidated all certificates of deposit and similar investments that held any supplier refunds due to customers and transferred these funds upon maturityreceived $57.5 million from GNGC. For further information regarding the sale, see Note 12 to the North Carolina deferred account. During 2006, the restrictions on cash totaling $13.2 million were removed in connection with implementing the NCUC order in a general rate proceeding.
consolidated financial statements.In 2008,2009, we contributed $10.9$.9 million to our Hardy Storage Company, LLC (Hardy Storage) joint venture as part of our equity contribution for construction of the FERC regulated interstate storage facility.
During 2008, we sold various properties located We made no contributions in
Burlington2010 and
High Point, North Carolina, Spartanburg, South Carolina and Nashville, Tennessee for $13.2 million, net of expenses. In accordance with utility plant accounting, we recorded the disposition of the land from these sales2011 as
a pre-tax gain of $1.2 million with a deferral of $.5 million relatedHardy Storage converted its construction interim notes in March 2010 into long-term project-financed debt. For further information on Hardy Storage, see Note 12 to the
Nashville sale. The net pre-tax gain of $.7 million was recorded in “Other Income (Expense)” in the consolidated
statements of income. We recorded a gain of $3.1 million on the disposition of the buildings as a charge to “Accumulated depreciation” in the consolidated balance sheets. We entered into a sale-leaseback agreement on the Nashville property for a lease of 18financial statements.1/2 months, where the $.5 million deferred gain will be amortized on a straight-line basis over the life of the lease and recorded to “Other Income (Expense)” in the consolidated statements of income. During 2008, we recorded $38,636 of deferred gain.
Cash Flows from Financing Activities. Net cash provided by (used in)used in financing activities was $107.7$57.5 million in 2008, $(86.6)2011, $233.9 million in 20072010 and $65.6$214.1 million in 2006.2009. Funds are primarily provided from bank borrowings and the issuance of common stock through dividend reinvestment and stock purchase and employee stock plans, net of purchases under the common stock repurchase program.purchase plans. We may sell common stock and long-term debt when market and other conditions favor such long-term financing. Funds are primarily used to retire long-term debt, pay down outstanding short-term bank borrowings, to repurchase common stock under the common stock repurchase program and to pay quarterly dividends on our common stock. As of October 31, 2008,2011, our current assets
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were $600.8$286 million and our current liabilities were $681.5$534.1 million, primarily due to seasonal requirements as discussed above.
As of October 31, 2008, we had committed lines of credit under our senior credit facility of $450 million with the ability to expand up to $600 million, for which we pay an annual fee of $35,000 plus six basis points for any unused amount up to $450 million. Outstanding short-term bank borrowings increased from $195.5$242 million as of October 31, 20072010 to $406.5$331 million as of October 31, 2008,2011 primarily due to higher storage inventory costs, costs associated withcapital expenditures and long-term debt maturities. Over the hedging programs,three-year period from 2009 to 2011, our short-term borrowings have included the purchasereplacement of shares under the ASR program and payments for interest on short-term debt and property taxes, partially offset by the collections of amounts that had been billed to customers during the winter months. During the twelve months ended October 31, 2008, short-term bank borrowings ranged from $9 million to $426 million, and interest rates ranged from 2.63% to 5.51% (weighted average of 3.79%).
On October 27 and 29, 2008, we entered into two short-term credit facilities with banks for unsecured commitments totaling $75 million expiring on December 1, 2008. On December 1, 2008, these commitments were extended to December 3, 2008. Advances under each short-term facility bear interest at a rate based on the30-day LIBOR rate plus from .75% to 1.75%, based on our credit ratings. We entered into these short-term facilities to provide lines of credit in addition to the seniorfive-year revolving syndicated credit facility discussed above in order to have additional resources to meet seasonal cash flow requirements, including support forwith our gas supply procurement program as well as general corporate needs. No borrowings were outstanding at October 31, 2008.
Effective December 3, 2008, we entered intocurrent three-year revolving syndicated credit facility and a syndicated seasonal credit facility
with aggregate commitments totaling $150 million. Advances under this seasonal facility bear interest at a rate based on the30-day LIBOR rate plusin existence from
.75% to 1.75%, based on our credit ratings. Any borrowings under this agreement are due byDecember 3, 2008 through March 31, 2009.
For further information on bank borrowings, see the previous discussion of “Short-Term Borrowings” 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 entered into this facility to provide lines of creditretired our $60 million 6.55% medium-term notes, $60 million 7.8% medium-term notes and $30 million 7.35% medium-term notes in addition to the senior revolving credit facility discussed above in order to have additional resources to meet seasonal cash flow requirementsSeptember 2011, September 2010 and general corporate needs.
As of October 31, 2008, under our senior credit facility,September 2009, respectively, as they became due. On June 1, 2011, we had available letters of credit of $5 million of which $1.9 million was issued and outstanding. The letters of credit are used to guarantee claims fromself-insurance under our general liability policies. As of October 31, 2008, unused lines of credit available under our credit facilities, including the issuanceredeemed all of the letters6.25% insured quarterly notes with an aggregate principal balance of credit, totaled $116.6 million.
The level of$196.8 million with short-term bank borrowings
can vary significantly dueunder the revolving syndicated credit facility. On June 6, 2011, we issued $40 million of unsecured senior notes maturing in 2016 at an interest rate of 2.92% and $160 million of unsecured senior notes maturing in 2021 at an interest rate of 4.24%. We used the proceeds from the sale of the senior notes to
changesreduce our short-term borrowings as well as for other general corporate purposes and working capital needs. The replacement of this higher rate debt with lower rate debt will provide annual interest savings of $4.3 million.On July 7, 2011, we filed with the SEC a combined debt and equity shelf registration statement that became effective on the same date. Unless otherwise specified at the time such securities are offered for sale, the net proceeds from the sale of the securities will be used for general corporate purposes, including capital expenditures, additions to working capital and advances for or investments in the wholesale pricesour subsidiaries, and for repurchases of natural gas andshares of our common stock. Pending such use, we may temporarily invest any net proceeds that are not applied to the level of purchases of natural gas supplies and hedging transactionspurposes mentioned above in investment grade securities.
We plan to serve customer demand and for storage. Short-term debt may increase when wholesale prices for natural gas increase because we must pay suppliers for the gas before we collect our costs from customers through their monthly bills. Gas prices could continue to fluctuate. If wholesale gas prices increase, we may incur more short-term debt for natural gas supplies 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.
In September 2009, the balance of $30issue approximately $300 million of
our 7.35% Medium-Term Notes is due. We anticipate issuing up to $125 million in long-term debt in our
fiscal 2012 third quarter for general corporate purposes, including the funding of capital expenditures to serve new power generation projects. We continually monitor customer growth trends and opportunities in our markets along with the economic recovery of our service area for the timing of any infrastructure investments that would require the need for additional long-term debt.From time to time, we have repurchased shares of common stock under our Common Stock Open Market Purchase Program and our ASR program as described in Note 6 to the consolidated financial statements. During 2011, we repurchased and retired .8 million shares for $23 million under our Common Stock Open Market Purchase Program, leaving a balance of 3,710,074 shares available for repurchase under the program. During 2010 and 2009, we repurchased 1.8 million shares and .7 million shares for $47.3 million and $17.9 million, respectively. We anticipate repurchasing .8 million shares of common stock through an ASR agreement in the first quarter of our fiscal year 2012 with no permanent reduction in shares outstanding for general operating purposes. The timing of this issuance has not yet been determined.
We had a shelf registration statement filed with the SEC that expired on December 1, 2008 that could have been used for the issuance of either debt or equity. The remaining balance of unused long-term financing available under this shelf registration statement as of October 31, 2008 was $109.4 million.
fiscal year 2012.During 2008,2011, we issued $15.6$20.2 million of common stock through dividend reinvestment and stock purchase and employee stock purchase plans. On November 2, 2007,During 2010 and 2009, we issued $19.1 million and $14.4 million, respectively, through an ASR agreement, we repurchased and retired 1 million shares of common stock for $24.8 million. On January 15, 2008, we settled the transaction and paid an additional $1.3 million. Under the ASR agreement and the Common Stock Open Market Purchase Program discussed in Note 4 to the consolidated financial statements, we paid $42.7 million during 2008 for 1.6 million shares of common stock that are available for reissuance to these plans. During 2007, 2 million shares were repurchased for $54.2 million. During 2006, 2.1 million shares were repurchased for $50.2 million.
25
Through the ASR program, we may repurchase and subsequently retire up to approximately four million shares of common stock by no later than December 31, 2010. Through the ASR agreements, we have repurchased 3,850,000 shares as follows.
| | | | |
April 2006 | | | 1,000,000 | |
November 2006 | | | 1,000,000 | |
March 2007 | | | 850,000 | |
November 2007 | | | 1,000,000 | |
| | | | |
Total | | | 3,850,000 | |
| | | | |
These shares are in addition to shares that are repurchased on a normal basis through the open market program. During 2009, we do not intend to repurchase any shares under an ASR agreement or the Common Stock Open Market Purchase Program.
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 2008, $.04 per share in 20072011, 2010 and $.05 per share in 2006.2009. Dividends of $75.5$82.9 million, $73.6$80.3 million and $72.1$78.4 million for 2008, 20072011, 2010 and 2006,2009, respectively, were paid on common stock. Provisions contained in certain note agreements under which long-term debt was issued restrict the amount of cash dividends that may be paid. As of October 31, 2008,2011, our retained earnings were not restricted. On December 18, 2008,16, 2011, the Board of Directors declared a quarterly dividend on common stock of $.26$.29 per share, payable January 15, 200913, 2012 to shareholders of record at the close of business on December 26, 2008.27, 2011. For further information, see Note 34 to the consolidated financial statements.
Our long-term targeted capitalization ratio is45-50% in long-term debt and50-55% in common equity. Accomplishing this capital structure objective and maintaining sufficient cash flow are necessary to maintain attractive credit ratings. As of October 31, 2008,2011, our capitalization, including current maturities of long-term debt, if any, consisted of 48%40% in long-term debt and 52%60% in common equity.
The components of our total debt outstanding (short-term and long-term) to our total capitalization as of October 31, 20082011 and 20072010 are summarized in the table below.
| | | | | | | | | | | | | | | | | |
| | | October 31 | | | October 31 | |
| | | 2008 | | | Percentage | | | 2007 | | | Percentage | |
| | | In thousands | |
| |
| Short-term debt | | $ | 406,500 | | | | 19 | % | | $ | 195,500 | | | | 10 | % |
| Current portion of long-term debt | | | 30,000 | | | | 1 | % | | | — | | | | 0 | % |
| Long-term debt | | | 794,261 | | | | 38 | % | | | 824,887 | | | | 44 | % |
| | | | | | | | | | | | | | | | | |
| Total debt | | | 1,230,761 | | | | 58 | % | | | 1,020,387 | | | | 54 | % |
| Common stockholders’ equity | | | 887,244 | | | | 42 | % | | | 878,374 | | | | 46 | % |
| | | | | | | | | | | | | | | | | |
| Total capitalization (including short-term debt) | | $ | 2,118,005 | | | | 100 | % | | $ | 1,898,761 | | | | 100 | % |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
| | | October 31 | | | October 31 | |
In thousands | | 2011 | | | Percentage | | | 2010 | | | Percentage | |
Short-term debt | | $ | 331,000 | | | | 16 | % | | $ | 242,000 | | | | 12 | % |
Current portion of long-term debt | | | — | | | | — | % | | | 60,000 | | | | 3 | % |
Long-term debt | | | 675,000 | | | | 34 | % | | | 671,922 | | | | 35 | % |
| | | | | | | | | | | | | | | | |
Total debt | | | 1,006,000 | | | | 50 | % | | | 973,922 | | | | 50 | % |
Common stockholders’ equity | | | 996,923 | | | | 50 | % | | | 964,941 | | | | 50 | % |
| | | | | | | | | | | | | | | | |
Total capitalization (including short-term debt) | | $ | 2,002,923 | | | | 100 | % | | $ | 1,938,863 | | | | 100 | % |
| | | | | | | | | | | | | | | | |
Credit ratings impact our ability to obtain short-term and long-term financing and the cost of such financings. 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. In determining our credit ratings, the rating agencies consider various factors. The more significant quantitative factors include:
| | |
| • | Ratio of total debt to total capitalization, including balance sheet leverage, |
|
| • | Ratio of net cash flows to capital expenditures, |
|
| • | Funds from operations interest coverage, |
|
| • | Ratio of funds from operations to average total debt, |
|
| • | Pension liabilities and funding status, and |
|
| • | Pre-tax interest coverage. |
26
Ratio of net cash flows to capital expenditures,Funds from operations interest coverage,
Ratio of funds from operations to average total debt,
Pension liabilities and funding status, and
Pre-tax interest coverage.
Qualitative factors include, among other things:
Stability of regulation in the jurisdictions in which we operate,
Consistency of our earnings over time,
| | |
| • | Stability of regulation in the jurisdictions in which we operate, |
|
| • | Consistency of our earnings over time, |
|
| • | Risks and controls inherent in the distribution of natural gas, |
|
| • | Predictability of cash flows, |
|
| • | Quality of business strategy and management, |
|
| • | Corporate governance guidelines and practices, |
|
| • | Industry position, and |
|
| • | Contingencies. |
Risks and controls inherent in the distribution of natural gas,
Predictability of cash flows,
Quality of business strategy and management,
Corporate governance guidelines and practices,
As of October 31, 2008,2011, all of our long-term debt was unsecured. Our long-term debt is rated “A” by Standard & Poor’s Ratings Services and “A3” by Moody’s Investors Service (Moody’s).Service. Currently, with respect to our long-term debt, the credit agencies maintain their stable outlook. Credit ratings and outlooks are opinions of the rating agency and are subject to their ongoing review. A significant decline in our operating performance, capital structure, or a significant reduction in our liquidity could trigger a negative change in our ratings outlook or even a reduction in our credit ratings by our 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.
giving rise to acceleration of our debt.The default provisions of some or all of our senior notes are:debt include:
Failure to make principal or interest payments,
Bankruptcy, liquidation or insolvency,
| | |
| • | Failure to make principal, interest or sinking fund payments, |
|
| • | Interest coverage of 1.75 times, |
|
| • | TotalFinal 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, Failure to observe or perform covenants, including: Interest coverage of at least 1.75 times. Interest coverage was 5.78 times as of October 31, 2011; Funded debt cannot exceed 70% of total capitalization. Funded debt was 51% of total capitalization as of October 31, 2011; Funded debt of all subsidiaries in the aggregate cannot exceed 15% of total capitalization. There is no funded debt cannot exceed 70% of total capitalization, |
|
| • | Funded debt of all subsidiaries in the aggregate cannot exceed 15% of total company capitalization, |
|
| • | Failure to make payments on any capitalized lease obligation, |
|
| • | Bankruptcy, liquidation or insolvency, and |
|
| • | Final judgment against us in excess of $1 million that after 60 days is not discharged, satisfied or stayed pending appeal. |
The default provisions of our medium-term notes are:subsidiaries as of October 31, 2011;
Restrictions on permitted liens;
| | |
| • | Failure to make principal, interest or sinking fund payments, |
|
| • | Failure after the receipt of a90-day notice to observe or perform for any covenant or agreement in the notes or in the indenture under which the notes were issued, and |
|
| • | Bankruptcy, liquidation or insolvency. |
27
Restrictions on paying dividends, on or repurchasing our stock or making investments in subsidiaries; and
Restrictions on burdensome agreements.
Contractual Obligations and Commitments
We have incurred various contractual obligations and commitments in the normal course of business. As of October 31, 2008,2011, our estimated future recorded and unrecorded contractual obligations are as follows.
| | | | | | | | | | | | | | | | | | | | | |
| | | Payments Due by Period | |
| | | Less than
| | | 1-3
| | | 4-5
| | | After
| | | | |
| | | 1 Year | | | Years | | | Years | | | 5 Years | | | Total | |
| | | In thousands | |
| |
Recorded contractual obligations | | | | | | | | | | | | | | | | | | | | |
| Long-term debt(1) | | $ | 30,000 | | | $ | 120,000 | | | $ | 100,000 | | | $ | 574,261 | | | $ | 824,261 | |
| Short-term debt | | | 406,500 | | | | — | | | | — | | | | — | | | | 406,500 | |
| | | | | | | | | | | | | | | | | | | | | |
| Total | | $ | 436,500 | | | $ | 120,000 | | | $ | 100,000 | | | $ | 574,261 | | | $ | 1,230,761 | |
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | |
| | | Payments Due by Period | |
In thousands | | Less than
1 year | | | 1-3
Years | | | 4-5
Years | | | After
5 Years | | | Total | |
Recorded contractual obligations: | | | | | | | | | | | | | | | | | | | | |
Long-term debt (1) | | $ | — | | | $ | 100,000 | | | $ | 75,000 | | | $ | 500,000 | | | $ | 675,000 | |
Short-term debt (2) | | | 331,000 | | | | — | | | | — | | | | — | | | | 331,000 | |
| | | | | | | | | | | | | | | | | | | | |
Total | | $ | 331,000 | | | $ | 100,000 | | | $ | 75,000 | | | $ | 500,000 | | | $ | 1,006,000 | |
| | | | | | | | | | | | | | | | | | | | |
| | |
| (1) | | See Note 34 to the consolidated financial statements. |
| | | | | | | | | | | | | | | | | | | | | |
| | | Less than
| | | 1-3
| | | 4-5
| | | After
| | | | |
| | | 1 Year | | | Years | | | Years | | | 5 Years | | | Total | |
| | | In thousands | |
| |
Unrecorded contractual obligations and commitments(1) | | | | | | | | | | | | | | | | | | | | |
| Pipeline and storage capacity(2) | | $ | 148,907 | | | $ | 453,595 | | | $ | 168,998 | | | $ | 335,306 | | | $ | 1,106,806 | |
| Gas supply(3) | | | 23,340 | | | | 369 | | | | — | | | | — | | | | 23,709 | |
| Interest on long-term debt(4) | | | 56,115 | | | | 149,655 | | | | 86,917 | | | | 626,733 | | | | 919,420 | |
| Telecommunications and information technology(5) | | | 18,555 | | | | 17,106 | | | | — | | | | — | | | | 35,661 | |
| Qualified and nonqualified pension plan funding(6) | | | 11,618 | | | | 34,714 | | | | 11,480 | | | | — | | | | 57,812 | |
| Postretirement benefits plan funding(6) | | | 3,400 | | | | 5,600 | | | | 1,500 | | | | — | | | | 10,500 | |
| Operating leases(7) | | | 6,232 | | | | 12,866 | | | | 7,887 | | | | 5,956 | | | | 32,941 | |
| Other purchase obligations(8) | | | 32,093 | | | | — | | | | — | | | | — | | | | 32,093 | |
| Letters of credit | | | 2,335 | | | | 7,005 | | | | 4,670 | | | | — | | | | 14,010 | |
| FIN 48 obligations | | | 202 | | | | 305 | | | | — | | | | — | | | | 507 | |
| | | | | | | | | | | | | | | | | | | | | |
| Total | | $ | 302,797 | | | $ | 681,215 | | | $ | 281,452 | | | $ | 967,995 | | | $ | 2,233,459 | |
| | | | | | | | | | | | | | | | | | | | | |
| (2) | | See Note 5 to the consolidated financial statements. |
| | | | | | | | | | | | | | | | | | | | |
In thousands | | Less than
1 year | | | 1-3
Years | | | 4-5
Years | | | After
5 Years | | | Total | |
Unrecorded contractual obligations and commitments: (1) | | | | | | | | | | | | | | | | | | | | |
Pipeline and storage capacity (2) | | $ | 151,456 | | | $ | 254,299 | | | $ | 112,774 | | | $ | 281,147 | | | $ | 799,676 | |
Gas supply (3) | | | 6,974 | | | | 11 | | | | — | | | | — | | | | 6,985 | |
Interest on long-term debt (4) | | | 40,181 | | | | 113,198 | | | | 69,423 | | | | 289,479 | | | | 512,281 | |
Telecommunications and information technology (5) | | | 11,055 | | | | 14,921 | | | | — | | | | — | | | | 25,976 | |
Qualified and nonqualified pension plan funding (6) | | | 1,052 | | | | 19,140 | | | | 6,731 | | | | — | | | | 26,923 | |
Postretirement benefits plan funding (6) | | | 1,600 | | | | 4,000 | | | | 1,300 | | | | — | | | | 6,900 | |
Operating leases (7) | | | 3,560 | | | | 11,775 | | | | 7,291 | | | | 31,853 | | | | 54,479 | |
Other purchase obligations (8) | | | 5,912 | | | | — | | | | — | | | | — | | | | 5,912 | |
Letters of credit (9) | | | 3,459 | | | | — | | | | — | | | | — | | | | 3,459 | |
| | | | | | | | | | | | | | | | | | | | |
Total | | $ | 225,249 | | | $ | 417,344 | | | $ | 197,519 | | | $ | 602,479 | | | $ | 1,442,591 | |
| | | | | | | | | | | | | | | | | | | | |
| (1) | | In accordance with generally accepted accounting principles (GAAP), these items are not reflected in our consolidated balance sheets. |
|
| (2) | | Recoverable through PGA procedures. |
|
| (3) | | Reservation fees are recoverable through PGA procedures. |
|
| (4) | | See Note 34 to the consolidated financial statements. |
|
| (5) | | 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. |
|
| (6) | | Estimated funding beyond five years is not available. See Note 79 to the consolidated financial statements. |
|
| (7) | | See Note 68 to the consolidated financial statements. |
|
| (8) | | Consists primarily of pipeline products, vehicles, contractors and merchandise. |
| (9) | See Note 5 to the consolidated financial statements. |
Off-balance Sheet Arrangements
We have no off-balance sheet arrangements other than operating leases and letters of credit and operating leases. The letters of credit and operating leases are discussed in Note 65 and Note 5,8, respectively, to the consolidated financial statements thatand are reflected in the table above.
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Piedmont Energy Partners, Inc., a wholly owned subsidiary of Piedmont, has entered into a guaranty in the normal course of business. The guaranty involves some levels of performance and credit risk that are not included on our consolidated balance sheets. We have recorded an estimated liability of $1.2 million and $1.3 million as of October 31, 2008 and 2007, respectively. The possibility of having to perform on the guaranty is largely dependent upon the future operations of Hardy Storage, third parties or the occurrence of certain future events. For further information on this guaranty, see Note 10 to the consolidated financial statements.
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.
Regulatory Accounting. Our regulated utility segment is subject to regulation by certain state and federal authorities. Our accounting policies conform to Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation” (Statement 71),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 income statement 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. 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, 20082011 and 2007,2010 totaled $263.2$200.1 million and $134$197.8 million, respectively. Regulatory liabilities as of October 31, 20082011 and 2007,2010 totaled $383.7$467 million and $374$439.1 million, respectively. The detail of these regulatory assets and liabilities is presented in “Rate-Regulated Basis of Accounting” in Note 1.B1 to the consolidated financial statements.
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 revenues against warmer-than-normal weather as deviations from normal weather can affect our financial performance and liquidity. The WNA also serves 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 formerly known as the CUT, provides for the recovery of our approved margin from residential and commercial customers independent of consumption patterns. The margin earned monthly under the margin decoupling mechanism will resultresults in semi-annual rate adjustments to refund anyover-collection or
29
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 mechanism. Without the WNA orand margin decoupling mechanism,mechanisms, our operating revenues in 2008, 20072011 and 20062010 would have been higher by $11.9 million and $14.7 million, respectively, and lower by $32.2$4.8 million $39.1 million and $34.6 million, respectively.
in 2009.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 approximate30-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 mechanism, as applicable. Secondary market revenues are recognized when the physical sales are delivered based on contract or market prices.
Pension and Postretirement Benefits. For eligible full-time employees hired on or before December 31, 2007 (December 31, 2008 for employees covered under the bargaining unit contract in Nashville, Tennessee), we We have a traditional defined benefit pension plan which was amended to close the plan to employees hired after December 31, 2007 and to modify how benefits are accrued.(qualified pension plan) covering eligible employees. We also provide certain other postretirement health care and life insurance benefits to eligible full-time employees. For further information and our reported costs of providing these benefits, see Note 79 to the consolidated financial statements. The costs of providing these benefits are impacted by numerous factors, including the provisions of the plans, changing employee demographics and various actuarial calculations, assumptions and accounting mechanisms. Because of the complexity of these calculations, the long-term nature of these obligations and the importance of the assumptions used, our estimate of these costs is a critical accounting estimate.
Several statistical and other factors, which attempt to anticipate future events, are used in calculating the expenses and liabilities related to the plans. These factors include assumptions about the discount rate used in determining future benefit obligations, projected health care cost trend rates, expected long-term return on plan assets and rate of future compensation increases, within certain guidelines. In addition, we also use subjective factors such as withdrawal and mortality rates to estimate projected benefit obligations. The actuarial assumptions used may differ materially from actual results due to changing market and economic conditions, higher or
lower withdrawal rates or longer or shorter life spans of participants. These differences may result in a significant impact on the amount of pension expense or other postretirement benefit costs recorded in future periods.
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 Moody’s Investors Service’s AA or better-rated non-callable bonds. Based on this approach, the weighted average discount rate used in the measurement of the benefit obligation for the qualified pension plan changed from 6.43%5.47% in 20072010 to 8.15%4.67% in 2008.2011. For the nonqualified pension plans, the weighted average discount rate used in the measurement of the benefit obligation changed from 6.06%4.37% in 20072010 to 8.46%4.10% in 2008.2011. Similarly, based on this approach, the weighted average discount rate for postretirement benefits changed from 6.25%4.85% in 20072010 to 8.5%4.36% in 2008.2011. The lower discount rates discussed above reflect the lower yields found in the AA corporate bond market where the bond price has increased. Based on our review of actual cost trend rates and projected future trends in establishing health care cost trend rates, we maintained the sameinitial health care cost trend rate of 8.25%was assumed to be 7.80% in 2008 and 2007,2011 declining gradually to 5% in 2017.
by 2027.In determining our expected long-term rate of return on plan assets, we review past long-term performance, asset allocations and long-term inflation assumptions. We target our asset allocations for qualified pension plan assets and other postretirement benefit assets to be approximately 60%50% equity securities and 40%50% 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 8.5% in 2006 and 2007, and 8% in 2008.2009, 2010 and 2011. Based on a fairly stagnantconstant inflation trend, our age-related assumed rate of increase in future compensation levels was 4.01%3.92% in 2006,2009, decreasing to 3.99%3.87% in 20072010 and further decreasing to 3.97%3.78% in 20082011 due to changes in the demographics of the participants.
30
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 2011, we recorded cost of $2.3 million related to our qualified pension plan and postretirement benefits plan. We estimate 2012 expenses for these two plans to be in the range of $5 to $6 million representing an increase of $3 to $4 million over 2011. These estimates reflect the discount rates and assumed rate of return on the plan assets discussed above for each plan.
The following reflects the sensitivity of pension cost to changes in certain actuarial assumptions for our qualified pension plan, assuming that the other components of the calculation are constant.
| | | | | | | | | | | | | |
| | | Change in
| | | Impact on 2008
| | | Impact on Projected
| |
Actuarial Assumption | | Assumption | | | Pension Cost | | | Benefit Obligation | |
| | | Increase (Decrease)
| |
| | | In thousands | |
| |
| Discount rate | | | (.25 | )% | | $ | 715 | | | $ | 3,023 | |
| Rate of return on plan assets | | | (.25 | )% | | | 528 | | | | N/A | |
| Rate of increase in compensation | | | .25 | % | | | 381 | | | | 1,207 | |
| | | | | | | | | | | | |
Actuarial Assumption | | Change in
Assumption | | | Impact on 2011
Benefit Cost | | | Impact on Projected
Benefit Obligation | |
| | | | | | Increase (Decrease)
In thousands | |
Discount rate | | | (.25 | )% | | $ | 515 | | | $ | 5,973 | |
Rate of return on plan assets | | | (.25 | )% | | | 644 | | | | N/A | |
Rate of increase in compensation | | | .25 | % | | | 560 | | | | 3,162 | |
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 2008
| | | Impact on Accumulated
| |
| | | Change in
| | | Postretirement
| | | Postretirement Benefit
| |
Actuarial Assumption | | Assumption | | | Benefit Cost | | | Obligation | |
| | | Increase (Decrease)
| |
| | | In thousands | |
| |
| Discount rate | | | (.25 | )% | | $ | 5 | | | $ | 511 | |
| Rate of return on plan assets | | | (.25 | )% | | | 51 | | | | N/A | |
| Health care cost trend rate | | | .25 | % | | | 21 | | | | 179 | |
| | | | | | | | | | | | |
Actuarial Assumption | | Change in
Assumption | | | Impact on 2011
Postretirement
Benefit Cost | | | Impact on Accumulated
Postretirement Benefit
Obligation | |
| | | | | | Increase (Decrease)
In thousands | |
Discount rate | | | (.25 | )% | | $ | 13 | | | $ | 796 | |
Rate of return on plan assets | | | (.25 | )% | | | 52 | | | | N/A | |
Health care cost trend rate | | | .25 | % | | | 9 | | | | 177 | |
We utilize a number of accounting methods consistently applied that are allowed under generally accepted accounting principles (GAAP) thatGAAP which reduce the volatility of reported pension costs. Differences between actuarial assumptions and actual plan results are deferred and amortized into cost when the accumulated differences exceed 10% of the greater of the projected benefit obligation or the market-related value of the plan assets. If necessary, the excess is amortized over the average remaining service period of active employees.
Gas Supply and Regulatory Proceedings
We continue to pursue the diversificationThe source of our gas supply portfolio through pipeline capacity arrangements that access new sourceswe distribute to our customers comes primarily from the Gulf Coast production region where it is purchased primarily from major and independent producers and marketers. As part of supply and market-area storage and thatour long-term plan to diversify supply concentrationour reliance away from the Gulf Coast region. In January 2008,region, we began receiving 120,000 dekatherms per day ofhave contracted for firm, long-term market area storage service in West Virginia from Hardy Storage, a venture in which we have a 50% equity interest, which is more fully discussed in Note 12 to the consolidated financial statements. We have also contracted for firm, long-term transportation contract service from Midwestern that provides access to Canadian and Rocky Mountain gas supplies via the Chicago hub, primarily to serve our Tennessee markets. In April 2007, we began receiving firm, long-term market-area storage
Natural gas demand is continuing to grow in our service from Hardy Storage in West Virginia. Hardy Storage willarea, particularly to provide us 58,700 dekatherms per day of storage withdrawalnatural gas delivery service during the winter of2008-2009,to existing and that service level is planned to increase to 68,800 dekatherms per day for the winter of2009-2010. We have a 50% equity interest in this project which is more fullyfuture power generation facilities 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. For further information on our equity venture with Cardinal to expand our firm capacity requirement in order to serve a power generation facility in Wayne County, North Carolina, see Note 1012 to the consolidated financial statements.
As part of our plan to provide safe, reliable gas distribution service to our growing customer base and manage our seasonal demand, we intend to design, construct, own and operate a LNG peak storage facility in Robeson County, North Carolina with the capacity to store approximately 1.25 billion cubic feet of natural gas for use during times of peak demand. The LNG facility will be a part of our regulated utility segment and is planned to be in service for the2012-2013 winter heating season.
Secondary market transactions permit us to market gas supplies and transportation services by contract with wholesale or off-system customers. These sales contribute smallerper-unit margins to earnings; however, the program allows us to act as a wholesale marketer of natural gas and transportation capacity in order to generate operating margin from sources not restricted by the capacity of our retail distribution system. A sharing mechanism is in effect where 75% of any margin is passed through to customers in all of our jurisdictions. However,For further information on secondary market transactions, in Tennessee are included in the TIP discussed insee Note 2 to the consolidated financial statements.
We have been in discussionscontinue to work with FERC’s Officeour regulatory commissions to earn a fair rate of Enforcement (OE) regarding certain instances of possible non-compliance with FERC’s capacity release regulations regarding postingreturn for our shareholders and bidding requirements for short-term releases. We have provided relevant informationprovide safe, reliable natural gas distribution service to FERC OE Staff and are cooperating with
31
FERC in its investigation. We are continuing to meet with FERC’s OE staff to resolve this matter. We are unable to predict the outcome of the investigation at this time; however, we do not believe this matter will have a material effect on our earnings.
In October 2008, the NCUC approved a settlement in our general rate case proceeding that provides an annual revenue increase of $15.7 million and the continuation of the margin decoupling mechanism. The new rates become effective November 1, 2008. Also in October 2008, the PSCSC issued an order approving a settlement that provides for an annual decrease of $1.5 million in margin under the Natural Gas Rate Stabilization Act (RSA) mechanism based on a return on equity of 11.2%, effective November 1, 2008.customers. For further information about regulatory proceedings and other regulatory information, see Note 2 to the consolidated financial statements.
Equity Method Investments
For information about our equity method investments, see Note 1012 to the consolidated financial statements.
We have developed an environmental self-assessment plan to assess our facilities and program areas for compliance with federal, state and local environmental regulations and to correct any deficiencies identified. As a member of the North Carolina MGP Initiative Group, we, along with other responsible parties, work directly with the North Carolina Department of Environment and Natural Resources to set priorities for manufactured gas plant (MGP) site remediation. For additional information on environmental matters, see Note 68 to the consolidated financial statements.
Accounting Pronouncements
GuidanceFor further information regarding recently issued accounting guidance, see Note 1 to the consolidated financial statements.
International Financial Reporting Standards (IFRS)
In September 2006,early 2010, the SEC expressed its commitment to the development of a single set of high quality globally accepted accounting standards and directed its staff to execute a work plan addressing specific areas of concern regarding the potential incorporation of IFRS for the U.S. In October 2010, the SEC staff issued its first public progress report on the work plan. Additionally, in December 2010, the SEC chairman publicly stated that companies would be allowed a minimum of four years to implement IFRS if it is mandated. In May 2011, an SEC Staff Paper was issued outlining a possible endorsement approach for incorporation of IFRS into the U.S. financial reporting system if the SEC were to decide that incorporation of IFRS is in the best interest of U.S. investors. Under this possible framework, IFRS would be incorporated into U.S. GAAP during a transition period of five to seven years with the Financial Accounting Standards Board (FASB) issued SFAS No. 157, “Fair Value Measurements” (Statement 157). Statement 157 provides enhanced guidance for using fair value to measure assets and liabilities and applies whenever other standards require (or permit)remaining as the measurement of assets or liabilities at fair value, but does not expand the use of fair value measurement to any new circumstances. Under Statement 157, 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. Statement 157 clarifies that fair value should be based on the assumptions market participants would use when pricing the asset or liability. Statement 157 establishes a fair value hierarchy for valuation inputs that prioritizes the information used to develop those assumptions into three levels as follows:
| | |
| • | Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that the entity has the ability to access as of the reporting date. |
|
| • | Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly, through corroboration with observable data. |
|
| • | Level 3 inputs are unobservable inputs, such as internally developed pricing models for the asset or liability due to little or no market activity for the asset or liability. |
Under Statement 157, we anticipate fair value measurements would be disclosed by level for gas purchase options under our gas hedging plans.
U.S. accounting standard setter.In November 2007,2011, the FASB delayedSEC released two more Staff Papers as part of their work plan. The first paper was the implementation of Statement 157 for one year only for other nonfinancial assets and liabilities. Statement 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years, with earlier application encouraged for financial assets and liabilities, as well as for any other assets and liabilities that are carried at fair value on a recurring basis. Accordingly, we will adopt Statement 157 for our fiscal year beginning November 1, 2008 with the exception ofSEC Staff’s observations regarding the application of IFRS in practice based on an analysis of 183 companies across 36 industries. The Staff found that company financial statements generally appeared to comply with IFRS requirements. Two observations made were: (1) Companies did not always provide relevant accounting policy disclosures or there was not
sufficient detail or clarity in the provision related to nonfinancial assetsaccounting policy disclosures; and liabilities. The
32
adoption(2) Diversity in the application of Statement 157 will not have a material impact on our financial position, results of operations or cash flows.
In April 2007, the FASB issued FSPFIN 39-1 to amend paragraph 3 of FIN 39, “Offsetting of Amounts Related to Certain Contracts,” to replace the terms conditional contracts and exchange contractsIFRS made comparability challenging with the term derivative instruments as defined in SFAS 133, “Accounting for Derivative Instrumentsdiversity attributed to be standard driven where options were permitted by IFRS or there was an absence of IFRS guidance or just noncompliance with IFRS. The second paper provided an assessment of a comparison of U.S. GAAP and Hedging Activities” (Statement 133). The FSP amends paragraph 10 of FIN 39 to permit a reporting entity to offset fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral against fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting arrangement. This FSP is effective for fiscal years beginning after November 15, 2007, with early application permitted. Accordingly, we have evaluated the impacts of the right to offset fair value amounts pursuant to amended paragraph 10 of FIN 39 for our fiscal year beginning November 1, 2008. Our policy has been to present our positions, exclusive of any receivable or payable, with the same counterparty on a net basis; however, we will elect “not to net” under FSPFIN 39-1 and will reflect minor reclassifications on our statement of financial position.
In December 2007, the FASB issued SFAS No. 141(R), “Business Combinations” (Statement 141(R)). Statement 141(R) establishes principles and requirements for how the acquirer in a business combination recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed and any noncontrolling interest in the acquiree at the acquisition date at fair value. Statement 141(R) changes the accounting for business combinations in various areas, including contingency consideration, preacquistion contingencies, transaction costs and restructuring costs. In addition, changes in the acquired entity’s deferred tax assets and uncertain tax positions after the measurement period will impact income tax expense. We will apply the provisions of Statement 141(R) to any acquisitions we may complete after November 1, 2009.
In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities — Including an Amendment of FASB Statement No. 115” (Statement 159). Statement 159 provides companiesIFRS with an optioninventorying of areas in which IFRS provides less or no guidance than U.S. GAAP. The fundamental differences noted were that IFRS contains broad principles to report selected financial assetsaccount for transactions across industries with limited specific guidance and liabilities at fair value. Its objective is to reducestated exceptions and that fundamental differences exist between conceptual frameworks, including the complexity in accounting for financial instrumentslevel of authority and to mitigate the volatility in earnings caused by measuring related assetsdefinition and liabilities differently. Although Statement 159 does not eliminate disclosure requirements included in other accounting standards, it does establish additional presentation and disclosure requirements designed to facilitate comparisons between companies that choose different measurement attributes for similar typesrecognition of assets and liabilities. Statement 159 is effective for financial statements issued for fiscal years beginning after November 15, 2007, with early adoption permitted forThe Staff Paper provided a broad comparison of the requirements of both accounting standards, highlighting notable differences, but did not provide an entity that has elected also to apply Statement 157 early. Accordingly, we will adopt Statement 159 for our fiscal year beginning November 1, 2008. We have evaluated Statement 159, and we do not intend to electanalysis of the option to measure any applicable financial assets or liabilities at fair value pursuant toimpact of those differences on the provisionsquality of Statement 159.
In March 2008,IFRS.Although the FASB issued SFAS No. 161, “Disclosures About Derivative Instruments and Hedging Activities” (Statement 161). Statement 161 amends Statement 133, by requiring expanded qualitative, quantitative and credit-risk disclosures about derivative instruments and hedging activities, but does not change the scope or accounting under Statement 133 and its related interpretations. Statement 161 requires specific disclosures regarding how and why an entity uses derivative instruments; how derivative instruments and related hedged items are accounted for; and how derivative instruments and related hedged items affect an entity’s financial position, results of operations and cash flows. Statement 161 also amended SFAS 107, “Disclosures about Fair Value of Financial Instruments” (Statement 107), to clarify that derivative instruments are subject to Statement 107’s concentration-of-credit-risk disclosures. Statement 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early adoption permitted. Since Statement 161 only requires additional disclosures concerning derivatives and hedging activities, this standard is notSEC was expected to have a material impact on our financial position, results of operations, or cash flows. We will adopt Statement 161 on February 1, 2009.
In May 2008, the FASB issued SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles” (Statement 162). Statement 162 identifies the sources of accounting principles and the framework for selecting the principles used in the preparation of financial statements that are presented in conformity
33
with GAAP for nongovernmental entities. Statement 162 was issued to include the GAAP hierarchy in the accounting literature establishedvote by the
FASB. Statement 162end of 2011 on whether to require the use of IFRS and by what method, they have further delayed their decision to 2012 in order to complete a comprehensive work plan.In late 2010 and early 2011, we completed a preliminary assessment of IFRS to understand the key accounting and reporting differences compared to U.S. GAAP and to assess potential organizational, process and system impacts that would be required. The accounting differences between U.S. GAAP and IFRS are complex and significant in many areas, and conversion to IFRS would have broad impacts to us. In addition to financial statement and disclosure changes, converting to IFRS would involve changes to processes and controls, regulatory and management reporting, financial reporting systems and other areas of the company. As a part of the IFRS assessment project, a preliminary conversion roadmap was created for reporting IFRS. This IFRS conversion roadmap and our strategy for addressing a potential mandate of IFRS will be effective sixty days followingre-assessed when the SecuritiesSEC makes its final determination on the use of IFRS.
Item 7A. Quantitative and Exchange Commission (SEC) approval of the Public Company Accounting Oversight Board amendments to AU Section 411, “The Meaning of Present Fairly in Conformity With Generally Accepted Accounting Principles.” We do not expect this statement to have any impact on our financial position, results of operations or cash flows. We will adopt Statement 162 when it becomes effective.
| |
Item 7A. | Quantitative and Qualitative Disclosures about Market Risk |
Qualitative Disclosures about Market RiskWe 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 market risk and credit riskall of these risks in accordance with defined policies and procedures under an Enterprise Risk Management Policy.program and with the direction of the 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.
We hold all financial instruments discussed below for purposes other than trading.
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. TheIn situations where counterparties do not have investment grade 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. The policy is also designed to mitigaterating and/or credit risks through a requirement for credit enhancements that include letters of credit or parent guaranties.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 anyour 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 North Carolina and South Carolina, gas costs related to uncollectible accounts are recovered through PGA procedures. In Tennessee, the gas cost portion of net write-offs for a fiscal year that exceed the gas cost portion included in base rates is 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 thoseour high risk customers that do not satisfy our predetermined credit standards.standards until a satisfactory payment history has been established. Significant increases in the price of natural gas can also slow our collection efforts as customers experience increased difficulty in paying their gas bills, leading to higher than normal accounts receivable.
We are exposed to interest rate risk as a result of changes in interest rates on short-term debt. As of October 31, 2008,2011, 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, 2008,2011, we had $406.5$331 million of short-term debt outstanding under our syndicated revolving credit facility at a weighted averagean interest rate of 2.84%1.15%. 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 $1.9$2 million during 2008.
34
As of October 31, 2008,2011, information about our long-term debt is presented below.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | Fair Value as
| |
| | | Expected Maturity Date | | | of October 31,
| |
| | | 2009 | | | 2010 | | | 2011 | | | 2012 | | | 2013 | | | Thereafter | | | Total | | | 2008 | |
| | | | | | | | | | | | In millions | | | | | | | | | | |
| |
| Fixed Rate Long-term Debt | | $ | 30 | | | $ | 60 | | | $ | 60 | | | $ | — | | | $ | — | | | $ | 674.3 | | | $ | 824.3 | | | $ | 798.1 | |
| Average Interest Rate | | | 7.35 | % | | | 7.80 | % | | | 6.55 | % | | | — | | | | — | | | | 6.64 | % | | | 6.72 | % | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | Fair Value as
of October 31,
2011 | |
| | | Expected Maturity Date | | | | | |
In millions | | 2012 | | | 2013 | | | 2014 | | | 2015 | | | 2016 | | | Thereafter | | | Total | | |
Fixed Rate Long-term Debt | | $ | — | | | $ | — | | | $ | 100 | | | $ | — | | | $ | 40 | | | $ | 535.0 | | | $ | 675.0 | | | $ | 831.3 | |
Average Interest Rate | | | — | % | | | — | % | | | 5 | % | | | — | % | | | 2.92 | % | | | 6.38 | % | | | 5.97 | % | | | | |
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. WeAs such, we face regulatory recovery risk associated with the purchase of natural gas.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” or any over-recoveries are included in “Amounts due to customers” in our consolidated balance sheets 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 the New York Mercantile Exchange (NYMEX) exchange-tradedexchange traded instruments and have used over-the-counter instruments of various durations for the forward purchase of a portion of our natural gas requirements, subject to regulatory review and approval.
We purchase firm gas from a diverse portfolio of suppliers at liquid exchange points. For term suppliers whose performance is greater than one month, we evaluate and monitor their creditworthiness and maintain the ability to require additional financial assurances, including deposits, letters of credit or surety bonds, in case a supplier defaults. Since most of our commodity supply contracts are at market index prices tied to liquid exchange points and with our significant storage flexibility, we believe that it is unlikely that a supplier default would have a material effect on our financial position, results of operations or cash flows.
Our gas purchasing practices are subject to regulatory reviews in all three states in which we operate. We are responsible for following competitive and reasonable practices in purchasing gas for our customers. Costs have never been disallowed on the basis of prudence in any jurisdiction.
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. In these states, this risk is mitigated by WNA mechanisms that partiallyare designed to offset the impact of colder-than-normal or warmer-than-normal weather.weather during the months of November through March in our residential and commercial markets. In North Carolina, we manage our weather risk through a year around margin decoupling mechanism that allows us to recover our approved margin from residential and commercial customers independent of volumes sold.
Additional information concerning market risk is set forth in “Financial Condition and Liquidity” in Item 7 of thisForm 10-K.10-K in Management’s Discussion and Analysis of Financial Condition and Results of Operations.
Item 8. Financial Statements and Supplementary Data
| |
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 thisForm 10-K.
35
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, 20082011 and 2007,2010, and the related consolidated statements of income, stockholders’ equity, and cash flows for each of the three years in the period ended October 31, 2008.2011. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these 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, 20082011 and 2007,2010, and the results of their operations and their cash flows for each of the three years in the period ended October 31, 2008,2011, 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, 2008,2011, based on the criteria established inInternal Control — Control—Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated December 29, 200823, 2011 expressed an unqualified opinion on the Company’s internal control over financial reporting.
/s/ Deloitte & Touche LLP
Charlotte, North Carolina
3623, 2011
Piedmont Natural Gas Company, Inc.
October 31, 20082011 and 2007
| | | | | | | | | |
| | | 2008 | | | 2007 | |
| | | In thousands | |
| |
ASSETS |
| Utility Plant: | | | | | | | | |
| Utility plant in service | | $ | 2,997,186 | | | $ | 2,833,286 | |
| Less accumulated depreciation | | | 813,822 | | | | 752,977 | |
| | | | | | | | | |
| Utility plant in service, net | | | 2,183,364 | | | | 2,080,309 | |
| Construction work in progress | | | 57,470 | | | | 61,228 | |
| | | | | | | | | |
| Total utility plant, net | | | 2,240,834 | | | | 2,141,537 | |
| | | | | | | | | |
| Other Physical Property, at cost (net of accumulated depreciation of $2,351 in 2008 and $2,197 in 2007) | | | 864 | | | | 1,007 | |
| | | | | | | | | |
| Current Assets: | | | | | | | | |
| Cash and cash equivalents | | | 6,991 | | | | 7,515 | |
| Restricted cash | | | — | | | | 2,211 | |
| Trade accounts receivable (less allowance for doubtful accounts of $1,066 in 2008 and $544 in 2007) | | | 82,346 | | | | 97,625 | |
| Income taxes receivable | | | 731 | | | | 15,699 | |
| Other receivables | | | 393 | | | | 649 | |
| Unbilled utility revenues | | | 51,819 | | | | 24,121 | |
| Inventories: | | | | | | | | |
| Gas in storage | | | 190,275 | | | | 131,439 | |
| Materials, supplies and merchandise | | | 6,525 | | | | 5,222 | |
| Gas purchase options, at fair value | | | — | | | | 13,725 | |
| Amounts due from customers | | | 181,745 | | | | 76,035 | |
| Prepayments | | | 79,831 | | | | 61,007 | |
| Other | | | 96 | | | | 96 | |
| | | | | | | | | |
| Total current assets | | | 600,752 | | | | 435,344 | |
| | | | | | | | | |
| Investments, Deferred Charges and Other Assets: | | | | | | | | |
| Equity method investments in non-utility activities | | | 99,214 | | | | 95,193 | |
| Goodwill | | | 48,852 | | | | 48,852 | |
| Overfunded postretirement asset | | | 6,797 | | | | 36,256 | |
| Regulatory asset for postretirement benefits | | | 28,732 | | | | 1,865 | |
| Gas purchase options, at fair value | | | 10,257 | | | | — | |
| Unamortized debt expense | | | 9,915 | | | | 10,565 | |
| Regulatory cost of removal asset | | | 6,398 | | | | 11,939 | |
| Other | | | 40,965 | | | | 37,760 | |
| | | | | | | | | |
| Total investments, deferred charges and other assets | | | 251,130 | | | | 242,430 | |
| | | | | | | | | |
| Total | | $ | 3,093,580 | | | $ | 2,820,318 | |
| | | | | | | | | |
| |
CAPITALIZATION AND LIABILITIES |
| Capitalization: | | | | | | | | |
| Stockholders’ equity: | | | | | | | | |
| Cumulative preferred stock — no par value — 175 shares authorized | | $ | — | | | $ | — | |
| Common stock — no par value — shares authorized: 200,000; shares outstanding: 73,246 in 2008 and 74,208 in 2007 | | | 471,565 | | | | 497,570 | |
| Paid-in capital | | | 763 | | | | 402 | |
| Retained earnings | | | 414,246 | | | | 379,682 | |
| Accumulated other comprehensive income | | | 670 | | | | 720 | |
| | | | | | | | | |
| Total stockholders’ equity | | | 887,244 | | | | 878,374 | |
| Long-term debt | | | 794,261 | | | | 824,887 | |
| | | | | | | | | |
| Total capitalization | | | 1,681,505 | | | | 1,703,261 | |
| | | | | | | | | |
| Current Liabilities: | | | | | | | | |
| Current maturities of long-term debt | | | 30,000 | | | | — | |
| Notes payable | | | 406,500 | | | | 195,500 | |
| Trade accounts payable | | | 91,142 | | | | 97,156 | |
| Other accounts payable | | | 45,148 | | | | 46,411 | |
| Income taxes accrued | | | 4,414 | | | | 1,224 | |
| Accrued interest | | | 22,777 | | | | 21,811 | |
| Customers’ deposits | | | 23,881 | | | | 22,930 | |
| Deferred income taxes | | | 6,878 | | | | 16,422 | |
| General taxes accrued | | | 18,932 | | | | 18,980 | |
| Gas purchase options, at fair value | | | 19,561 | | | | — | |
| Amounts due to customers | | | — | | | | 162 | |
| Other | | | 12,300 | | | | 3,915 | |
| | | | | | | | | |
| Total current liabilities | | | 681,533 | | | | 424,511 | |
| | | | | | | | | |
| Deferred Credits and Other Liabilities: | | | | | | | | |
| Deferred income taxes | | | 305,362 | | | | 267,479 | |
| Unamortized federal investment tax credits | | | 2,626 | | | | 2,983 | |
| Regulatory liability for postretirement benefits | | | 372 | | | | 13,876 | |
| Accumulated provision for postretirement benefits | | | 16,257 | | | | 17,469 | |
| Cost of removal obligations | | | 367,450 | | | | 351,738 | |
| Other | | | 38,475 | | | | 39,001 | |
| | | | | | | | | |
| Total deferred credits and other liabilities | | | 730,542 | | | | 692,546 | |
| | | | | | | | | |
| Commitments and Contingencies (Note 6) | | | — | | | | — | |
| | | | | | | | | |
| Total | | $ | 3,093,580 | | | $ | 2,820,318 | |
| | | | | | | | | |
2010ASSETS
| | | | | | | | |
In thousands | | 2011 | | | 2010 | |
Utility Plant: | | | | | | | | |
Utility plant in service | | $ | 3,377,310 | | | $ | 3,176,312 | |
Less accumulated depreciation | | | 974,631 | | | | 917,300 | |
| | | | | | | | |
Utility plant in service, net | | | 2,402,679 | | | | 2,259,012 | |
Construction work in progress | | | 217,832 | | | | 171,901 | |
Plant held for future use | | | 6,751 | | | | 6,751 | |
| | | | | | | | |
Total utility plant, net | | | 2,627,262 | | | | 2,437,664 | |
| | | | | | | | |
Other Physical Property, at cost (net of accumulated depreciation of $806 in 2011 and $729 in 2010) | | | 452 | | | | 528 | |
| | | | | | | | |
Current Assets: | | | | | | | | |
Cash and cash equivalents | | | 6,777 | | | | 5,619 | |
Trade accounts receivable (less allowance for doubtful accounts of $1,347 in 2011 and $929 in 2010) | | | 57,035 | | | | 62,370 | |
Income taxes receivable | | | 15,966 | | | | 24,856 | |
Other receivables | | | 2,547 | | | | 2,289 | |
Unbilled utility revenues | | | 28,715 | | | | 21,337 | |
Inventories: | | | | | | | | |
Gas in storage | | | 91,124 | | | | 101,734 | |
Materials, supplies and merchandise | | | 1,368 | | | | 4,547 | |
Gas purchase derivative assets, at fair value | | | 2,772 | | | | 2,819 | |
Amounts due from customers | | | 38,649 | | | | 62,336 | |
Prepayments | | | 39,128 | | | | 39,832 | |
Deferred income taxes | | | 1,793 | | | | — | |
Other current assets | | | 147 | | | | 101 | |
| | | | | | | | |
Total current assets | | | 286,021 | | | | 327,840 | |
| | | | | | | | |
Noncurrent Assets: | | | | | | | | |
Equity method investments in non-utility activities | | | 85,121 | | | | 80,287 | |
Goodwill | | | 48,852 | | | | 48,852 | |
Marketable securities, at fair value | | | 1,439 | | | | 997 | |
Overfunded postretirement asset | | | 22,879 | | | | 17,342 | |
Regulatory asset for postretirement benefits | | | 81,073 | | | | 64,775 | |
Unamortized debt expense | | | 11,315 | | | | 8,576 | |
Regulatory cost of removal asset | | | 19,336 | | | | 17,825 | |
Other noncurrent assets | | | 58,791 | | | | 48,589 | |
| | | | | | | | |
Total noncurrent assets | | | 328,806 | | | | 287,243 | |
| | | | | | | | |
Total | | $ | 3,242,541 | | | $ | 3,053,275 | |
| | | | | | | | |
See notes to consolidated financial statements.
37
Consolidated Balance Sheets
October 31, 2011 and 2010
Piedmont Natural Gas Company, Inc.
CAPITALIZATION AND LIABILITIES | | | | | | | | |
In thousands | | 2011 | | | 2010 | |
Capitalization: | | | | | | | | |
Stockholders’ equity: | | | | | | | | |
Cumulative preferred stock - no par value - 175 shares authorized | | $ | — | | | $ | — | |
Common stock - no par value - shares authorized: 200,000; shares outstanding: 72,318 in 2011 and 72,282 in 2010 | | | 446,791 | | | | 445,640 | |
Retained earnings | | | 550,584 | | | | 519,831 | |
Accumulated other comprehensive loss | | | (452 | ) | | | (530 | ) |
| | | | | | | | |
Total stockholders’ equity | | | 996,923 | | | | 964,941 | |
Long-term debt | | | 675,000 | | | | 671,922 | |
| | | | | | | | |
Total capitalization | | | 1,671,923 | | | | 1,636,863 | |
| | | | | | | | |
Current Liabilities: | | | | | | | | |
Current maturities of long-term debt | | | — | | | | 60,000 | |
Bank debt | | | 331,000 | | | | 242,000 | |
Trade accounts payable | | | 85,721 | | | | 66,019 | |
Other accounts payable | | | 43,959 | | | | 49,645 | |
Accrued interest | | | 20,038 | | | | 20,134 | |
Customers’ deposits | | | 25,462 | | | | 25,631 | |
Deferred income taxes | | | — | | | | 4,933 | |
General taxes accrued | | | 21,262 | | | | 20,100 | |
Amounts due to customers | | | 2,617 | | | | — | |
Other current liabilities | | | 4,073 | | | | 10,098 | |
| | | | | | | | |
Total current liabilities | | | 534,132 | | | | 498,560 | |
| | | | | | | | |
Noncurrent Liabilities: | | | | | | | | |
Deferred income taxes | | | 512,961 | | | | 429,225 | |
Unamortized federal investment tax credits | | | 2,004 | | | | 2,145 | |
Accumulated provision for postretirement benefits | | | 14,671 | | | | 14,805 | |
Cost of removal obligations | | | 466,000 | | | | 436,072 | |
Other noncurrent liabilities | | | 40,850 | | | | 35,605 | |
| | | | | | | | |
Total noncurrent liabilities | | | 1,036,486 | | | | 917,852 | |
| | | | | | | | |
Commitments and Contingencies (Note 8) | | | | | | | | |
| | | | | | | | |
Total | | $ | 3,242,541 | | | $ | 3,053,275 | |
| | | | | | | | |
See notes to consolidated financial statements.
Page Intentionally Blank
Consolidated Statements of Income
For the Years Ended October 31, 2008, 20072011, 2010 and 2006
| | | | | | | | | | | | | |
| | | 2008 | | | 2007 | | | 2006 | |
| | | In thousands except per share amounts | |
| |
| Operating Revenues | | $ | 2,089,108 | | | $ | 1,711,292 | | | $ | 1,924,628 | |
| Cost of Gas | | | 1,536,135 | | | | 1,187,127 | | | | 1,401,149 | |
| | | | | | | | | | | | | |
| Margin | | | 552,973 | | | | 524,165 | | | | 523,479 | |
| | | | | | | | | | | | | |
| Operating Expenses: | | | | | | | | | | | | |
| Operations and maintenance | | | 210,757 | | | | 214,442 | | | | 219,353 | |
| Depreciation | | | 93,121 | | | | 88,654 | | | | 89,696 | |
| General taxes | | | 33,170 | | | | 32,407 | | | | 33,138 | |
| Income taxes | | | 62,814 | | | | 51,315 | | | | 50,543 | |
| | | | | | | | | | | | | |
| Total operating expenses | | | 399,862 | | | | 386,818 | | | | 392,730 | |
| | | | | | | | | | | | | |
| Operating Income | | | 153,111 | | | | 137,347 | | | | 130,749 | |
| | | | | | | | | | | | | |
| Other Income (Expense): | | | | | | | | | | | | |
| Income from equity method investments | | | 27,718 | | | | 37,156 | | | | 29,917 | |
| Non-operating income | | | 1,320 | | | | 2,218 | | | | 1,147 | |
| Charitable contributions | | | (1,327 | ) | | | (587 | ) | | | (321 | ) |
| Non-operating expense | | | (864 | ) | | | (164 | ) | | | (106 | ) |
| Income taxes | | | (10,678 | ) | | | (14,311 | ) | | | (11,887 | ) |
| | | | | | | | | | | | | |
| Total other income (expense), net of tax | | | 16,169 | | | | 24,312 | | | | 18,750 | |
| | | | | | | | | | | | | |
| Utility Interest Charges: | | | | | | | | | | | | |
| Interest on long-term debt | | | 55,449 | | | | 55,440 | | | | 49,915 | |
| Allowance for borrowed funds used during construction | | | (4,002 | ) | | | (3,799 | ) | | | (3,893 | ) |
| Other | | | 7,826 | | | | 5,631 | | | | 6,288 | |
| | | | | | | | | | | | | |
| Total utility interest charges | | | 59,273 | | | | 57,272 | | | | 52,310 | |
| | | | | | | | | | | | | |
| Net Income | | $ | 110,007 | | | $ | 104,387 | | | $ | 97,189 | |
| | | | | | | | | | | | | |
| Average Shares of Common Stock: | | | | | | | | | | | | |
| Basic | | | 73,334 | | | | 74,250 | | | | 75,863 | |
| Diluted | | | 73,612 | | | | 74,472 | | | | 76,156 | |
| Earnings Per Share of Common Stock: | | | | | | | | | | | | |
| Basic | | $ | 1.50 | | | $ | 1.41 | | | $ | 1.28 | |
| Diluted | | $ | 1.49 | | | $ | 1.40 | | | $ | 1.28 | |
2009 | | | | | | | | | | | | |
| | | 2011 | | | 2010 | | | 2009 | |
In thousands except per share amounts | | | | | | | | | | | | |
Operating Revenues | | $ | 1,433,905 | | | $ | 1,552,295 | | | $ | 1,638,116 | |
Cost of Gas | | | 860,266 | | | | 999,703 | | | | 1,076,542 | |
| | | | | | | | | | | | |
Margin | | | 573,639 | | | | 552,592 | | | | 561,574 | |
| | | | | | | | | | | | |
Operating Expenses: | | | | | | | | | | | | |
Operations and maintenance | | | 225,351 | | | | 219,829 | | | | 208,105 | |
Depreciation | | | 102,829 | | | | 98,494 | | | | 97,425 | |
General taxes | | | 38,380 | | | | 33,909 | | | | 34,590 | |
Utility income taxes | | | 64,068 | | | | 62,082 | | | | 70,079 | |
| | | | | | | | | | | | |
Total operating expenses | | | 430,628 | | | | 414,314 | | | | 410,199 | |
| | | | | | | | | | | | |
Operating Income | | | 143,011 | | | | 138,278 | | | | 151,375 | |
| | | | | | | | | | | | |
Other Income (Expense): | | | | | | | | | | | | |
Income from equity method investments | | | 24,027 | | | | 28,854 | | | | 33,464 | |
Gain on sale of interest in equity method investment | | | — | | | | 49,674 | | | | — | |
Non-operating income | | | 1,762 | | | | 659 | | | | 32 | |
Charitable contributions | | | (1,818 | ) | | | (1,363 | ) | | | (2,011 | ) |
Non-operating expense | | | (1,204 | ) | | | (643 | ) | | | (1,558 | ) |
Income taxes | | | (8,218 | ) | | | (29,794 | ) | | | (11,803 | ) |
| | | | | | | | | | | | |
Total other income (expense) | | | 14,549 | | | | 47,387 | | | | 18,124 | |
| | | | | | | | | | | | |
Utility Interest Charges: | | | | | | | | | | | | |
Interest on long-term debt | | | 46,070 | | | | 52,666 | | | | 55,105 | |
Allowance for borrowed funds used during construction | | | (8,619 | ) | | | (9,981 | ) | | | (2,298 | ) |
Other | | | 6,541 | | | | 1,026 | | | | (6,132 | ) |
| | | | | | | | | | | | |
Total utility interest charges | | | 43,992 | | | | 43,711 | | | | 46,675 | |
| | | | | | | | | | | | |
Net Income | | $ | 113,568 | | | $ | 141,954 | | | $ | 122,824 | |
| | | | | | | | | | | | |
Average Shares of Common Stock: | | | | | | | | | | | | |
Basic | | | 72,056 | | | | 72,275 | | | | 73,171 | |
Diluted | | | 72,266 | | | | 72,525 | | | | 73,461 | |
Earnings Per Share of Common Stock: | | | | | | | | | | | | |
Basic | | $ | 1.58 | | | $ | 1.96 | | | $ | 1.68 | |
Diluted | | $ | 1.57 | | | $ | 1.96 | | | $ | 1.67 | |
See notes to consolidated financial statements.
38
Piedmont Natural Gas Company, Inc.
For the Years Ended October 31, 2008, 20072011, 2010 and 2006
| | | | | | | | | | | | | |
| | | 2008 | | | 2007 | | | 2006 | |
| | | In thousands | |
| |
| Cash Flows from Operating Activities: | | | | | | | | | | | | |
| Net income | | $ | 110,007 | | | $ | 104,387 | | | $ | 97,189 | |
| | | | | | | | | | | | | |
| Adjustments to reconcile net income to net cash provided by operating activities: | | | | | | | | | | | | |
| Depreciation and amortization | | | 97,637 | | | | 93,355 | | | | 94,111 | |
| Amortization of investment tax credits | | | (358 | ) | | | (434 | ) | | | (534 | ) |
| Allowance for doubtful accounts | | | 522 | | | | (695 | ) | | | 51 | |
| Gain on sale of land | | | (711 | ) | | | — | | | | — | |
| Allowance for funds used during construction | | | — | | | | — | | | | (3,893 | ) |
| Income from equity method investments | | | (27,718 | ) | | | (37,156 | ) | | | (29,917 | ) |
| Distributions of earnings from equity method investments | | | 34,060 | | | | 27,884 | | | | 28,442 | |
| Deferred income taxes | | | 28,370 | | | | 23,854 | | | | 22,021 | |
| Stock-based compensation expense | | | 338 | | | | 336 | | | | — | |
| Changes in assets and liabilities: | | | | | | | | | | | | |
| Receivables | | | (12,685 | ) | | | 14,892 | | | | 19,395 | |
| Inventories | | | (60,139 | ) | | | 7,743 | | | | 12,791 | |
| Amounts due from customers | | | (105,710 | ) | | | 13,599 | | | | (37,474 | ) |
| Settlement of legal asset retirement obligations | | | (1,358 | ) | | | (1,660 | ) | | | — | |
| Overfunded postretirement asset | | | 29,459 | | | | (36,256 | ) | | | — | |
| Regulatory asset for postretirement benefits | | | (26,867 | ) | | | (1,786 | ) | | | — | |
| Other assets | | | (5,469 | ) | | | (351 | ) | | | 7,581 | |
| Accounts payable | | | (8,617 | ) | | | 13,069 | | | | (94,095 | ) |
| Amounts due to customers | | | (162 | ) | | | 39 | | | | (17,001 | ) |
| Regulatory liability for postretirement benefits | | | (13,504 | ) | | | 13,876 | | | | — | |
| Accumulated provision for postretirement benefits | | | (1,212 | ) | | | 17,469 | | | | — | |
| Other liabilities | | | 33,319 | | | | (18,664 | ) | | | 5,146 | |
| | | | | | | | | | | | | |
| Total adjustments | | | (40,805 | ) | | | 129,114 | | | | 6,624 | |
| | | | | | | | | | | | | |
| Net cash provided by operating activities | | | 69,202 | | | | 233,501 | | | | 103,813 | |
| | | | | | | | | | | | | |
| Cash Flows from Investing Activities: | | | | | | | | | | | | |
| Utility construction expenditures | | | (181,001 | ) | | | (135,231 | ) | | | (204,116 | ) |
| Allowance for funds used during construction | | | (4,002 | ) | | | (3,799 | ) | | | — | |
| Reimbursements from bond fund | | | — | | | | — | | | | 15,955 | |
| Contributions to equity method investments | | | (10,917 | ) | | | (12,914 | ) | | | (23,696 | ) |
| Distributions of capital from equity method investments | | | 98 | | | | 344 | | | | 28,968 | |
| Proceeds from sale of land and buildings | | | 13,159 | | | | — | | | | — | |
| Decrease (increase) in restricted cash | | | 2,196 | | | | (2,211 | ) | | | 13,108 | |
| Other | | | 3,090 | | | | 5,576 | | | | 2,227 | |
| | | | | | | | | | | | | |
| Net cash used in investing activities | | | (177,377 | ) | | | (148,235 | ) | | | (167,554 | ) |
| | | | | | | | | | | | | |
| Cash Flows from Financing Activities: | | | | | | | | | | | | |
| Increase in notes payable, net of expenses of $405 in 2006 | | | 211,000 | | | | 25,500 | | | | 11,095 | |
| Proceeds from issuance of long-term debt, net of expenses | | | — | | | | — | | | | 193,360 | |
| Retirement of long-term debt | | | (626 | ) | | | (113 | ) | | | (35,000 | ) |
| Expenses related to the issuance of long-term debt | | | (10 | ) | | | (5 | ) | | | — | |
| Expenses related to expansion of the short-term facility | | | (113 | ) | | | — | | | | — | |
| Issuance of common stock through dividend reinvestment and employee stock plans | | | 15,591 | | | | 15,782 | | | | 18,377 | |
| Repurchases of common stock | | | (42,678 | ) | | | (54,240 | ) | | | (50,163 | ) |
| Dividends paid | | | (75,513 | ) | | | (73,561 | ) | | | (72,107 | ) |
| | | | | | | | | | | | | |
| Net cash provided by (used in) financing activities | | | 107,651 | | | | (86,637 | ) | | | 65,562 | |
| | | | | | | | | | | | | |
| Net Increase (Decrease) in Cash and Cash Equivalents | | | (524 | ) | | | (1,371 | ) | | | 1,821 | |
| Cash and Cash Equivalents at Beginning of Year | | | 7,515 | | | | 8,886 | | | | 7,065 | |
| | | | | | | | | | | | | |
| Cash and Cash Equivalents at End of Year | | $ | 6,991 | | | $ | 7,515 | | | $ | 8,886 | |
| | | | | | | | | | | | | |
| Cash Paid During the Year for: | | | | | | | | | | | | |
| Interest | | $ | 63,769 | | | $ | 63,703 | | | $ | 54,669 | |
| Income taxes | | | 29,281 | | | | 27,423 | | | | 56,615 | |
| | | | | | | | | | | | | |
| Noncash Investing and Financing Activities: | | | | | | | | | | | | |
| Accrued construction expenditures | | $ | 1,340 | | | $ | 741 | | | $ | 2,837 | |
| Guaranty | | | 101 | | | | 485 | | | | 1,820 | |
See notes to consolidated financial statements.
39
| | | | | | | | | | | | |
In thousands | | 2011 | | | 2010 | | | 2009 | |
Cash Flows from Operating Activities: | | | | | | | | | | | | |
Net income | | $ | 113,568 | | | $ | 141,954 | | | $ | 122,824 | |
Adjustments to reconcile net income to net cash provided by operating activities: | | | | | | | | | | | | |
Depreciation and amortization | | | 107,046 | | | | 102,776 | | | | 102,592 | |
Amortization of investment tax credits | | | (141 | ) | | | (277 | ) | | | (204 | ) |
Allowance for doubtful accounts | | | 418 | | | | (61 | ) | | | (76 | ) |
Gain on sale of interest in equity method investment, net of tax | | | — | | | | (30,286 | ) | | | — | |
Net gain on sale of property | | | — | | | | (89 | ) | | | (495 | ) |
Income from equity method investments | | | (24,027 | ) | | | (28,854 | ) | | | (33,464 | ) |
Distributions of earnings from equity method investments | | | 22,685 | | | | 28,834 | | | | 23,954 | |
Deferred income taxes, net | | | 76,962 | | | | 21,831 | | | | 81,468 | |
Changes in assets and liabilities: | | | | | | | | | | | | |
Gas purchase derivatives, at fair value | | | 47 | | | | (30,863 | ) | | | 18,741 | |
Receivables | | | (3,019 | ) | | | 23,493 | | | | 25,018 | |
Inventories | | | 13,789 | | | | 2,565 | | | | 87,953 | |
Amounts due from/to customers | | | 26,304 | | | | 133,794 | | | | (14,385 | ) |
Settlement of legal asset retirement obligations | | | (1,493 | ) | | | (1,141 | ) | | | (1,480 | ) |
Overfunded postretirement asset | | | (5,537 | ) | | | (17,342 | ) | | | 6,797 | |
Regulatory asset for postretirement benefits | | | (16,298 | ) | | | 12,130 | | | | (48,173 | ) |
Other assets | | | 972 | | | | 18,184 | | | | (13,573 | ) |
Accounts payable | | | (4,085 | ) | | | (3,007 | ) | | | (22,154 | ) |
Regulatory liability for postretirement benefits | | | — | | | | — | | | | (372 | ) |
Provision for postretirement benefits | | | (134 | ) | | | (16,836 | ) | | | 15,384 | |
Other liabilities | | | 4,188 | | | | 3,706 | | | | (6,085 | ) |
| | | | | | | | | | | | |
Net cash provided by operating activities | | | 311,245 | | | | 360,511 | | | | 344,270 | |
| | | | | | | | | | | | |
Cash Flows from Investing Activities: | | | | | | | | | | | | |
Utility construction expenditures | | | (243,641 | ) | | | (199,059 | ) | | | (129,006 | ) |
Allowance for funds used during construction | | | (8,619 | ) | | | (9,981 | ) | | | (2,298 | ) |
Contributions to equity method investments | | | (6,222 | ) | | | — | | | | (862 | ) |
Distributions of capital from equity method investments | | | 3,029 | | | | 18,260 | | | | 32 | |
Proceeds from sale of interest in equity method investment | | | — | | | | 57,500 | | | | — | |
Proceeds from sale of property | | | 1,074 | | | | 1,653 | | | | 748 | |
Investments in marketable securities | | | (486 | ) | | | (498 | ) | | | (380 | ) |
Other | | | 2,292 | | | | 3,554 | | | | 2,154 | |
| | | | | | | | | | | | |
Net cash used in investing activities | | | (252,573 | ) | | | (128,571 | ) | | | (129,612 | ) |
| | | | | | | | | | | | |
Piedmont Natural Gas Company, Inc.
Cash FlowsFor the Years Ended October 31, 2008, 20072011, 2010 and 2006
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | Accumulated
| | | | |
| | | | | | | | | | | | Other
| | | | |
| | | Common
| | | Paid-in
| | | Retained
| | | Comprehensive
| | | | |
| | | Stock | | | Capital | | | Earnings | | | Income (Loss) | | | Total | |
| | | In thousands except per share amounts | |
| |
| Balance, October 31, 2005 | | $ | 562,880 | | | $ | — | | | $ | 323,565 | | | $ | (2,253 | ) | | $ | 884,192 | |
| | | | | | | | | | | | | | | | | | | | | |
| Comprehensive Income: | | | | | | | | | | | | | | | | | | | | |
| Net income | | | | | | | | | | | 97,189 | | | | | | | | 97,189 | |
| Other comprehensive income: | | | | | | | | | | | | | | | | | | | | |
| Minimum pension liability, net of tax of ($51) | | | | | | | | | | | | | | | (78 | ) | | | | |
| Unrealized gain from hedging activities of equity method investments, net of tax of $3,013 | | | | | | | | | | | | | | | 4,644 | | | | | |
| Reclassification adjustment of realized gain from hedging activities of equity method investments included in net income, net of tax of ($665) | | | | | | | | | | | | | | | (973 | ) | | | 3,593 | |
| | | | | | | | | | | | | | | | | | | | | |
| Total comprehensive income | | | | | | | | | | | | | | | | | | | 100,782 | |
| Common Stock Issued | | | 20,047 | | | | | | | | | | | | | | | | 20,047 | |
| Common Stock Repurchased | | | (50,163 | ) | | | | | | | | | | | | | | | (50,163 | ) |
| Share-Based Compensation Expense | | | | | | | 56 | | | | | | | | | | | | 56 | |
| Tax Benefit from Dividends Paid on ESOP Shares | | | | | | | | | | | 118 | | | | | | | | 118 | |
| Dividends Declared ($.95 per share) | | | | | | | | | | | (72,107 | ) | | | | | | | (72,107 | ) |
| | | | | | | | | | | | | | | | | | | | | |
| Balance, October 31, 2006 | | | 532,764 | | | | 56 | | | | 348,765 | | | | 1,340 | | | | 882,925 | |
| | | | | | | | | | | | | | | | | | | | | |
| Comprehensive Income: | | | | | | | | | | | | | | | | | | | | |
| Net income | | | | | | | | | | | 104,387 | | | | | | | | 104,387 | |
| Other comprehensive income: | | | | | | | | | | | | | | | | | | | | |
| Minimum pension liability, net of tax of $18 | | | | | | | | | | | | | | | 24 | | | | | |
| Unrealized gain from hedging activities of equity method investments, net of tax of $314 | | | | | | | | | | | | | | | 578 | | | | | |
| Reclassification adjustment of realized gain from hedging activities of equity method investments included in net income, net of tax of ($762) | | | | | | | | | | | | | | | (1,276 | ) | | | (674 | ) |
| | | | | | | | | | | | | | | | | | | | | |
| Total comprehensive income | | | | | | | | | | | | | | | | | | | 103,713 | |
| Adjustment to initially apply Statement 158, net of tax | | | | | | | | | | | | | | | 54 | | | | 54 | |
| Common Stock Issued | | | 19,046 | | | | | | | | | | | | | | | | 19,046 | |
| Common Stock Repurchased | | | (54,240 | ) | | | | | | | | | | | | | | | (54,240 | ) |
| Share-Based Compensation Expense | | | | | | | 336 | | | | | | | | | | | | 336 | |
| Dividends — Incentive Compensation Plan | | | | | | | 10 | | | | (10 | ) | | | | | | | — | |
| Tax Benefit from Dividends Paid on ESOP Shares | | | | | | | | | | | 101 | | | | | | | | 101 | |
| Dividends Declared ($.99 per share) | | | | | | | | | | | (73,561 | ) | | | | | | | (73,561 | ) |
| | | | | | | | | | | | | | | | | | | | | |
| Balance, October 31, 2007 | | | 497,570 | | | | 402 | | | | 379,682 | | | | 720 | | | | 878,374 | |
| | | | | | | | | | | | | | | | | | | | | |
| Comprehensive Income: | | | | | | | | | | | | | | | | | | | | |
| Net income | | | | | | | | | | | 110,007 | | | | | | | | 110,007 | |
| Other comprehensive income: | | | | | | | | | | | | | | | | | | | | |
| Unrealized gain from hedging activities of equity method investments, net of tax of $891 | | | | | | | | | | | | | | | 1,399 | | | | | |
| Reclassification adjustment of realized gain from hedging activities of equity method investments included in net income, net of tax of ($922) | | | | | | | | | | | | | | | (1,449 | ) | | | (50 | ) |
| | | | | | | | | | | | | | | | | | | | | |
| Total comprehensive income | | | | | | | | | | | | | | | | | | | 109,957 | |
| Common Stock Issued | | | 16,673 | | | | | | | | | | | | | | | | 16,673 | |
| Common Stock Repurchased | | | (42,678 | ) | | | | | | | | | | | | | | | (42,678 | ) |
| Share-Based Compensation Expense | | | | | | | 338 | | | | | | | | | | | | 338 | |
| Dividends — Incentive Compensation Plan | | | | | | | 23 | | | | (23 | ) | | | | | | | — | |
| Tax Benefit from Dividends Paid on ESOP Shares | | | | | | | | | | | 93 | | | | | | | | 93 | |
| Dividends Declared ($1.03 per share) | | | | | | | | | | | (75,513 | ) | | | | | | | (75,513 | ) |
| | | | | | | | | | | | | | | | | | | | | |
| Balance, October 31, 2008 | | $ | 471,565 | | | $ | 763 | | | $ | 414,246 | | | $ | 670 | | | $ | 887,244 | |
| | | | | | | | | | | | | | | | | | | | | |
2009 | | | | | | | | | | | | |
In thousands | | 2011 | | | 2010 | | | 2009 | |
Cash Flows from Financing Activities: | | | | | | | | | | | | |
Borrowings under bank debt | | | 1,723,000 | | | | 1,058,000 | | | | 1,075,000 | |
Repayments under bank debt | | | (1,634,000 | ) | | | (1,122,000 | ) | | | (1,175,500 | ) |
Proceeds from issuance of long-term debt | | | 200,000 | | | | — | | | | — | |
Retirement of long-term debt | | | (256,922 | ) | | | (60,590 | ) | | | (31,749 | ) |
Expenses related to issuance and reacquiring of debt | | | (3,902 | ) | | | (46 | ) | | | — | |
Issuance of common stock through dividend reinvestment and employee stock plans | | | 20,233 | | | | 19,099 | | | | 14,435 | |
Repurchases of common stock | | | (23,004 | ) | | | (47,295 | ) | | | (17,857 | ) |
Dividends paid | | | (82,913 | ) | | | (80,255 | ) | | | (78,370 | ) |
Other | | | (6 | ) | | | (792 | ) | | | (50 | ) |
| | | | | | | | | | | | |
Net cash used in financing activities | | | (57,514 | ) | | | (233,879 | ) | | | (214,091 | ) |
| | | | | | | | | | | | |
Net Increase (Decrease) in Cash and Cash Equivalents | | | 1,158 | | | | (1,939 | ) | | | 567 | |
Cash and Cash Equivalents at Beginning of Year | | | 5,619 | | | | 7,558 | | | | 6,991 | |
| | | | | | | | | | | | |
Cash and Cash Equivalents at End of Year | | $ | 6,777 | | | $ | 5,619 | | | $ | 7,558 | |
| | | | | | | | | | | | |
Cash Paid During the Year for: | | | | | | | | | | | | |
Interest | | $ | 50,136 | | | $ | 56,554 | | | $ | 61,050 | |
Income Taxes: | | | | | | | | | | | | |
Income taxes paid | | | 5,649 | | | | 32,305 | | | | 51,132 | |
Income taxes refunded | | | 16,958 | | | | 1,845 | | | | 345 | |
| | | | | | | | | | | | |
Income taxes, net | | $ | (11,309 | ) | | $ | 30,460 | | | $ | 50,787 | |
| | | | | | | | | | | | |
Noncash Investing and Financing Activities: | | | | | | | | | | | | |
Accrued construction expenditures | | $ | 18,055 | | | $ | 3,225 | | | $ | 1,305 | |
Guaranty | | | — | | | | 1,234 | | | | — | |
See notes to consolidated financial statements.
Consolidated Statements of Stockholders’ Equity
For the Years Ended October 31, 2011, 2010 and 2009
| | | | | | | | | | | | | | | | | | | | |
In thousands except per share amounts | | Common
Stock | | | Paid-in
Capital | | | Retained
Earnings | | | Accumulated
Other
Comprehensive
Income (Loss) | | | Total | |
Balance, October 31, 2008 | | $ | 471,565 | | | $ | 763 | | | $ | 414,246 | | | $ | 670 | | | $ | 887,244 | |
| | | | | | | | | | | | | | | | | | | | |
Comprehensive Income: | | | | | | | | | | | | | | | | | | | | |
Net income | | | | | | | | | | | 122,824 | | | | | | | | 122,824 | |
Other comprehensive income: | | | | | | | | | | | | | | | | | | | | |
Unrealized gain from hedging activities of equity method investments, net of tax of ($3,886) | | | | | | | | | | | | | | | (6,032 | ) | | | (6,032 | ) |
Reclassification adjustment of realized gain from hedging activities of equity method investments included in net income, net of tax of $1,879 | | | | | | | | | | | | | | | 2,915 | | | | 2,915 | |
| | | | | | | | | | | | | | | | | | | | |
Total comprehensive income | | | | | | | | | | | | | | | | | | | 119,707 | |
Common Stock Issued | | | 17,861 | | | | | | | | | | | | | | | | 17,861 | |
Common Stock Repurchased | | | (17,857 | ) | | | | | | | | | | | | | | | (17,857 | ) |
Share-Based Compensation Expense | | | | | | | (730 | ) | | | | | | | | | | | (730 | ) |
Dividends - Incentive Compensation Plan | | | | | | | (33 | ) | | | 33 | | | | | | | | — | |
Tax Benefit from Dividends Paid on ESOP Shares | | | | | | | | | | | 93 | | | | | | | | 93 | |
Dividends Declared ($1.07 per share) | | | | | | | | | | | (78,370 | ) | | | | | | | (78,370 | ) |
| | | | | | | | | | | | | | | | | | | | |
Balance, October 31, 2009 | | | 471,569 | | | | — | | | | 458,826 | | | | (2,447 | ) | | | 927,948 | |
| | | | | | | | | | | | | | | | | | | | |
Comprehensive Income: | | | | | | | | | | | | | | | | | | | | |
Net income | | | | | | | | | | | 141,954 | | | | | | | | 141,954 | |
Other comprehensive income: | | | | | | | | | | | | | | | | | | | | |
Unrealized gain from hedging activities of equity method investments, net of tax of ($52) | | | | | | | | | | | | | | | (88 | ) | | | (88 | ) |
Reclassification adjustment of realized gain from hedging activities of equity method investments included in net income, net of tax of $1,291 | | | | | | | | | | | | | | | 2,005 | | | | 2,005 | |
| | | | | | | | | | | | | | | | | | | | |
Total comprehensive income | | | | | | | | | | | | | | | | | | | 143,871 | |
Common Stock Issued | | | 21,366 | | | | | | | | | | | | | | | | 21,366 | |
Common Stock Repurchased | | | (47,276 | ) | | | | | | | | | | | | | | | (47,276 | ) |
Rescission Offer | | | (19 | ) | | | | | | | | | | | | | | | (19 | ) |
Costs of Rescission Offer | | | | | | | | | | | (792 | ) | | | | | | | (792 | ) |
Tax Benefit from Dividends Paid on ESOP Shares | | | | | | | | | | | 98 | | | | | | | | 98 | |
Dividends Declared ($1.11 per share) | | | | | | | | | | | (80,255 | ) | | | | | | | (80,255 | ) |
| | | | | | | | | | | | | | | | | | | | |
Balance, October 31, 2010 | | | 445,640 | | | | — | | | | 519,831 | | | | (530 | ) | | | 964,941 | |
| | | | | | | | | | | | | | | | | | | | |
Consolidated Statements of Stockholders’ Equity
For the Years Ended October 31, 2011, 2010 and 2009
| | | | | | | | | | | | | | | | | | | | | | |
In thousands except per share amounts | | Common
Stock | | | Paid-in
Capital | | | Retained
Earnings | | | Accumulated
Other
Comprehensive
Income (Loss) | | | Total | |
Comprehensive Income: | | | | | | | | | | | | | | | | | | | | | | |
Net income | | | | | | | | | | | 113,568 | | | | | | | | | | 113,568 | |
Other comprehensive income: | | | | | | | | | | | | | | | | | | | | | | |
Unrealized gain from hedging activities of equity method investments, net of tax of ($371) | | | | | | | | | | | | | | | | | (576 | ) | | | (576 | ) |
Reclassification adjustment of realized gain from hedging activities of equity method investments included in net income, net of tax of $420 | | | | | | | | | | | | | | | | | 654 | | | | 654 | |
| | | | | | | | | | | | | | | | | | | | | | |
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 | |
| | | | | | | | | | | | | | | | | | | | | | |
The components of accumulated other comprehensive income (loss) (OCI) as of October 31, 20082011 and 20072010 are as follows.
| | | | | | | | | |
| | | 2008 | | | 2007 | |
| | | In thousands | |
| |
| Hedging activities of equity method investments | | $ | 670 | | | $ | 720 | |
| | | | | | | | |
In thousands | | 2011 | | | 2010 | |
Hedging activities of equity method investments | | $ | (452 | ) | | $ | (530 | ) |
See notes to consolidated financial statements.
40
Piedmont Natural Gas Company, Inc.
| |
1. | Summary of Significant Accounting Policies |
| |
A. | Operations and Principles of Consolidation. |
1. Summary of Significant Accounting Policies
Nature of Operations and Basis of Consolidation
Piedmont 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, and regulated interstate natural gas storage and intrastate natural gas transportation. Our utility operations are regulated by three state regulatory commissions. For further information on regulatory matters, see Note 2 to the consolidated financial statements.
The consolidated financial statements reflect the accounts of Piedmont and its wholly owned subsidiaries.subsidiaries whose financial statements are prepared for the same reporting period as Piedmont using consistent accounting policies. Investments in non-utility activities, or joint ventures, are accounted for under the equity method as we do not have controlling voting interests or otherwise exercise control over the management of such companies. Our ownership interest in each entity is recorded in “Equity method investments in non-utility activities” in the consolidated balance sheets.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 the consolidated statements of income. For further information on equity method investments, see Note 1012 to the consolidated financial statements. Revenues and expenses of all other non-utility activities are included in “Non-operating income” in the consolidated statements of income. Inter-company transactions have been eliminated in consolidation where appropriate; however, we have not eliminated inter-company profit on sales to affiliates and costs from affiliates in accordance with Statementaccounting regulations prescribed under rate-based regulation.
We monitor significant events occurring after the balance sheet date and prior to the issuance of Financialthe 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 have been evaluated. There are no subsequent events that had a material impact on our financial position, results of operations or cash flows. For further information, see Note 15 to the consolidated financial statements.
Use of Estimates
The consolidated financial statements of Piedmont have been prepared in accordance with generally accepted accounting principles (GAAP) in the United States of America and under the rules of the Securities and Exchange Commission (SEC). In accordance with GAAP, we make certain estimates and assumptions regarding reported amounts of assets and liabilities, disclosure of contingent assets and liabilities as of the date of the consolidated financial statements, and reported amounts of revenues and expenses during the reporting period. Actual results could differ from estimates.
Segment Reporting
Our segments are based on the components of the company that are evaluated regularly by the chief operating decision maker in deciding how to allocate resources and in assessing performance. Our chief operating decision maker is the executive management team comprised of senior level management. Our segments are identified based on products and services, regulatory environments and our current corporate organization and business decision making activities. We evaluate the performance of the regulated utility based on margin, operations and maintenance expenses and operating income. We evaluate the performance of the non-utility activities segment based on earnings from the ventures.
We have two reportable business segments, regulated utility and non-utility activities. The regulated utility segment is the gas distribution business, including the operations of merchandising and its related service work and home warranty programs, with activities conducted by the parent company. Operations of our non-utility activities segment are comprised of our equity method investments in joint ventures. See Note 14 for further discussion of segments.
Rate-Regulated Basis of Accounting Standards (SFAS) No. 71, “Accounting For The Effects of Certain Types of Regulation” (Statement 71).
| |
B. | 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. Statement 71 providesThe 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 Statement 71,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.
Our regulatory assets are recoverable through either base rates or rate riders or base rates 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 commission during any future rate proceedings. In the event that accounting for the provisionseffects of Statement 71regulation were no longer applicable, we would recognize a write-off of netthe regulatory assets (regulatory assets lessand regulatory liabilities)liabilities that would result in a chargean adjustment to net income. Although the natural gas distribution industry is becoming increasingly competitive, ourOur 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 Statement 71rate-based regulation remains appropriate. It is also our opinion that all regulatory assets are recoverable in current rates or in future rate proceedings, and therefore we have not recorded any regulatory assets that are recoverable but are not yet included in base rates or contemplated in a future rate recovery proceeding.
41
Piedmont Natural Gas Company, Inc.
Notes to Consolidated Financial Statements — (Continued)
Regulatory assets and liabilities in the consolidated balance sheets as of October 31, 20082011 and 20072010 are as follows.
| | | | | | | | | |
| | | 2008 | | | 2007 | |
| | | In thousands | |
| |
| Regulatory Assets: | | | | | | | | |
| Unamortized debt expense | | $ | 9,915 | | | $ | 10,565 | |
| Amounts due from customers | | | 181,745 | | | | 76,035 | |
| Environmental costs* | | | 5,819 | | | | 4,223 | |
| Demand-side management costs* | | | 1,608 | | | | 2,631 | |
| Deferred operations and maintenance expenses* | | | 9,301 | | | | 9,286 | |
| Deferred pipeline integrity expenses* | | | 6,008 | | | | 4,417 | |
| Deferred pension and other retirement benefits costs* | | | 12,558 | | | | 11,146 | |
| FAS 158 pension and other retirement benefits costs* | | | 28,732 | | | | 1,865 | |
| Regulatory cost of removal asset | | | 6,398 | | | | 11,939 | |
| Other* | | | 1,121 | | | | 1,866 | |
| | | | | | | | | |
| Total | | $ | 263,205 | | | $ | 133,973 | |
| | | | | | | | | |
| Regulatory Liabilities: | | | | | | | | |
| Regulatory cost of removal obligations | | $ | 359,302 | | | $ | 334,079 | |
| Amounts due to customers | | | — | | | | 162 | |
| Deferred income taxes | | | 24,316 | | | | 25,463 | |
| FAS 158 pension and other retirement benefits costs | | | 66 | | | | 13,876 | |
| Environmental liability due customers* | | | — | | | | 386 | |
| | | | | | | | | |
| Total | | $ | 383,684 | | | $ | 373,966 | |
| | | | | | | | | |
| | | | | | | | |
In thousands | | 2011 | | | 2010 | |
Regulatory Assets: | | | | | | | | |
Unamortized debt expense | | $ | 11,315 | | | $ | 8,576 | |
Amounts due from customers | | | 38,649 | | | | 62,336 | |
Environmental costs * | | | 9,644 | | | | 7,960 | |
Deferred operations and maintenance expenses * | | | 7,676 | | | | 8,258 | |
Deferred pipeline integrity expenses * | | | 7,927 | | | | 6,728 | |
Deferred pension and other retirement benefits costs * | | | 22,119 | | | | 18,783 | |
Amounts not yet recognized as a component of pension and other retirement benefits costs | | | 81,073 | | | | 64,775 | |
Regulatory cost of removal asset | | | 19,336 | | | | 17,825 | |
Other * | | | 2,396 | | | | 2,531 | |
| | | | | | | | |
Total | | $ | 200,135 | | | $ | 197,772 | |
| | | | | | | | |
Regulatory Liabilities: | | | | | | | | |
Regulatory cost of removal obligations | | $ | 438,605 | | | $ | 412,776 | |
Amounts due to customers | | | 2,617 | | | | — | |
Deferred income taxes* | | | 25,731 | | | | 26,299 | |
| | | | | | | | |
Total | | $ | 466,953 | | | $ | 439,075 | |
| | | | | | | | |
| | |
| * | | Regulatory assets are included in “Other”“Other noncurrent assets” in “Investments, Deferred Charges and Other“Noncurrent Assets” and regulatory liabilities are included in “Other”“Other noncurrent liabilities” in “Deferred Credits and Other“Noncurrent Liabilities” in the consolidated balance sheets. |
As of October 31, 2008,2011, we had regulatory assets totaling $6.2$.5 million on which we do not earn a return during the recovery period. The original amortization periodsperiod for these assets range from 3 tois 15 years and, accordingly, $.1 million will be fully amortized by 2010, $5.4 million will be fully amortized by 2011 and the remaining $.7$.5 million will be fully amortized by 2018. We have $55.9$4.5 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 $28.7$81.1 million of regulatory postretirement assets, and $6.4$19.3 million of asset retirement obligations (AROs) and $9.6 million of estimated environmental costs on which we do not earn a return.
| |
C. | Utility Plant and Depreciation. |
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 cost 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 through 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 Other Income (Expense) in the consolidated statements of income.
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 income. Any portion of AFUDC attributable to equity funds would be included in “Other Income (Expense)” in the consolidated statements of income. The costs of property retired are removed from utility plant and charged to accumulated depreciation.
AFUDC for the years ended October 31, 2008, 20072011, 2010 and 20062009 is presented below.
| | | | | | | | | | | | | |
| | | October 31 | |
| | | 2008 | | | 2007 | | | 2006 | |
| | | In thousands | |
| |
| AFUDC | | $ | 4,002 | | | $ | 3,799 | | | $ | 3,893 | |
42
| | | | | | | | | | | | |
In thousands | | 2011 | | | 2010 | | | 2009 | |
AFUDC | | $ | 8,619 | | | $ | 9,981 | | | $ | 2,298 | |
In accordance with utility accounting practice, we have classified expenditures associated with a liquefied natural gas (LNG) peak storage facility in the eastern part of North Carolina that has been delayed due to current economic conditions as “Plant held for future use” in the consolidated balance sheets. Another project under construction will create cost effective expansion capacity that we will use to help serve the growing natural gas requirements of our customers in the eastern part of North Carolina. The timing and design scope of the expansion of our facilities in this area will be determined as our system infrastructure and market supply growth requirements in North Carolina dictate and such costs, approximately half being land purchase and preparation, will be moved to any such future project.
Piedmont Natural Gas Company, Inc.
Notes to Consolidated Financial Statements — (Continued)
We compute depreciation expense using the straight-line method over periods ranging from four4 to 88 years. The composite weighted-average depreciation rates were 3.23%3.19% for 2008, 3.23%2011, 3.20% for 20072010 and 3.46%3.25% for 2006.
2009.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 propose new depreciation rates for approval. Our last depreciation study was completed in 2004, and new depreciation rates were approved effective November 1, 2005.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. We collect throughhave proposed the implementation of the new depreciation rates thein Tennessee beginning March 1, 2012. We anticipate new rates to become effective in North Carolina in connection with our next general rate case filing.
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 accrue estimated non-legal costs of removal on any depreciable asset that includes cost of removal in its depreciation rates.
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D. | Asset Retirement Obligations. |
SFAS No. 143, “Accounting for Asset Retirement Obligations” (AROs) (Statement 143), addressesrate.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 financial accounting and reporting for AROs associated with the retirementstatements of long-lived assets that result from the acquisition, construction, development and operation of the asset. Statement 143 requires the recognition of the fair value of a liability for an ARO in the period in which the liability is incurred if a reasonable estimate of fair value can be made.cash flows. We have determined that AROs exist for our underground mains and services.
In accordance with long-standing regulatory treatment, our depreciation rates are comprised of two components, one based on average service life and one based on cost of removal, as stated above. We collect through rates the estimated costs of removal on certain regulated properties through depreciation expense, with a corresponding credit to accumulated depreciation. These removal costs are non-legal obligations as defined by Statement 143. Because these estimated removal costs meet the requirements of Statement 71, we have accounted for these non-legal asset removal obligations as a regulatory liability. We have reclassified the estimated non-legal asset removal obligations from “Accumulated depreciation” to “Cost of removal obligations” in “Deferred Credits and Other Liabilities” in our consolidated balance sheets. 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.
In 2006, we applied Financial Accounting Standards Board (FASB) Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (FIN 47), that requires recognition of a liability for the fair value of a conditional ARO when incurred if the liability can be reasonably estimated. An ARO will be capitalized concurrently by increasing the carrying amount of the related asset by the same amount of the 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 the conditional ARO must be recognized. Any accretion will not be reflected in the income statement as we have received regulatory treatment for deferral as a regulatory asset with netting against a regulatory liability. We have recorded a liabilityno restrictions on our distribution and transmission mains and services.
43
Piedmont Natural Gas Company, Inc.
Notes to Consolidated Financial Statements — (Continued)
The costcash balances that would impact the payment of removal obligations recorded in our consolidated balance sheetsdividends as of October 31, 20082011 and 2007 are shown below.
| | | | | | | | | |
| | | 2008 | | | 2007 | |
| | | In thousands | |
| |
| Regulatory non-legal asset removal obligations | | $ | 359,302 | | | $ | 334,079 | |
| Conditional asset retirement obligations | | | 8,148 | | | | 17,659 | |
| | | | | | | | | |
| Total cost of removal obligations | | $ | 367,450 | | | $ | 351,738 | |
| | | | | | | | | |
A reconciliation of the changes in the FIN 47 conditional ARO2010.Trade Accounts Receivable and Allowance for the year ended October 31, 2008 and 2007 is presented below.
| | | | | | | | | |
| | | 2008 | | | 2007 | |
| | | In thousands | |
| |
| Beginning of period | | $ | 17,659 | | | $ | 19,115 | |
| Liabilities incurred during the period | | | 2,004 | | | | 2,564 | |
| Liabilities settled during the period | | | (1,358 | ) | | | (1,660 | ) |
| Accretion | | | 1,104 | | | | 1,102 | |
| Adjustment to estimated cash flows* | | | (11,261 | ) | | | (3,462 | ) |
| | | | | | | | | |
| End of period | | $ | 8,148 | | | $ | 17,659 | |
| | | | | | | | | |
| | |
* | | Adjustment is primarily due to the change in the credit adjusted risk-free rate from 5.78% as of October 31, 2006 to 6.24% as of October 31, 2007 to 8.62% as of October 31, 2008. |
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E. | Trade Accounts Receivable and Allowance for Doubtful Accounts. |
Doubtful AccountsTrade 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 North Carolina Utilities Commission (NCUC), and the Public Service Commission of South Carolina (PSCSC) and the Tennessee Regulatory Authority (TRA), we are authorized to recover all uncollected gas costs through the purchased gas cost deferral account.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. MerchandiseIn Tennessee, to the extent that the gas cost portion of net write-offs for a fiscal year is less than the gas cost portion included in base rates, the difference would be refunded to customers through the Actual Cost Adjustment (ACA) filings; if the difference is greater, there would be a charge to customers through the ACA filing. Non-regulated merchandise and service work receivables due beyond one year are included in “Other”“Other noncurrent assets” in “Investments, Deferred Charges and Other“Noncurrent Assets” in the consolidated balance sheets.
We are exposed to credit risk when we enter into contracts with third parties to 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 internal credit policies require counterparties to have an investment-grade credit rating at the time of the contract. Where the counterparty does not have an investment-grade credit rating, 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. 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, 2011 and 2010, our trade accounts receivable consisted of the following.
| | | | | | | | |
In thousands | | 2011 | | | 2010 | |
Gas receivables | | $ | 55,928 | | | $ | 60,823 | |
Non-regulated merchandise and service work receivables | | | 2,454 | | | | 2,476 | |
Allowance for doubtful accounts | | | (1,347 | ) | | | (929 | ) |
| | | | | | | | |
Trade accounts receivable | | $ | 57,035 | | | $ | 62,370 | |
| | | | | | | | |
A reconciliation of the changes in the allowance for doubtful accounts for the years ended October 31, 2008, 20072011, 2010 and 20062009 is as follows.
| | | | | | | | | | | | | |
| | | 2008 | | | 2007 | | | 2006 | |
| | | (In thousands) | |
| |
| Balance at beginning of year | | $ | 544 | | | $ | 1,239 | | | $ | 1,188 | |
| Additions charged to uncollectibles expense | | | 5,308 | | | | 4,981 | | | | 4,706 | |
| Accounts written off, net of recoveries | | | (4,786 | ) | | | (5,676 | ) | | | (4,655 | ) |
| | | | | | | | | | | | | |
| Balance at end of year | | $ | 1,066 | | | $ | 544 | | | $ | 1,239 | |
| | | | | | | | | | | | | |
44
| | | | | | | | | | | | |
In thousands | | 2011 | | | 2010 | | | 2009 | |
Balance at beginning of year | | $ | 929 | | | $ | 990 | | | $ | 1,066 | |
Additions charged to uncollectibles expense | | | 4,842 | | | | 4,886 | | | | 5,570 | |
Accounts written off, net of recoveries | | | (4,424 | ) | | | (4,947 | ) | | | (5,646 | ) |
| | | | | | | | | | | | |
Balance at end of year | | $ | 1,347 | | | $ | 929 | | | $ | 990 | |
| | | | | | | | | | | | |
Inventories
Piedmont Natural Gas Company, Inc.
Notes to Consolidated Financial Statements — (Continued)
| |
F. | Goodwill, Equity Method Investments and Long-Lived Assets. |
All of our goodwill is attributable to the regulated utility segment. We evaluate goodwill for impairment annually on October 31, or more frequently if impairment indicators arise during the year. An impairment charge would be recognized if the carrying value of the reporting unit, including goodwill, exceeded its fair value.
Our annual goodwill impairment assessment was performed at October 31, 2008, and we determined that there was no impairment to the carrying value of our goodwill. No impairment has been recognized during the years ended October 31, 2008, 2007 and 2006.
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. There were no events or circumstances during the years ended October 31, 2008, 2007 and 2006 that resulted in any impairment charges. For further information on equity method investments, see Note 10 to the consolidated financial statements.
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G. | 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. We amortize debt expense on a straight-line basis, which approximates the effective interest method, over the life of the related debt which has lives ranging from 10 to 30 years.
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 utilize asset management agreements with counterparties for certain natural gas storage and transportation assets. At October 31, 2008,2011 and 2010, such counterparties held natural gas storage assets, included in “Prepayments” in the consolidated balance sheets, with a value of $77.4$35.8 million and $36.6 million, respectively, through capacity release and agency relationships. Under the terms of the asset management agreements, we receive capacity and storage asset management fees.fees, which are recorded as secondary market transactions and shared between our utility customers and our shareholders. The asset management agreements expire at various times through April 30, 2009.
March 31, 2014. For further information on the revenue sharing of secondary market transactions, see Note 2 to the consolidated financial statements.Materials, supplies and merchandise inventories are valued at the lower of average cost or market and removed from such inventory at average cost.
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I. | Deferred Purchased Gas Adjustments. |
Fair Value Measurements
Effective November 1, 2009, we adopted the additional authoritative guidance related to nonrecurring fair value guidance for certain nonfinancial assets and liabilities and the use of fair value in the impairment testing of goodwill, intangible assets and long-lived assets. In February 2010, we adopted the amended fair value guidance, which clarified disclosure requirements for fair value measurements and requires disclosure of transfers between Levels 1, 2 or 3. The adoption of the additional fair value guidance had no material impact on our financial position, results of operations or cash flows.
The carrying values of cash and cash equivalents, receivables, bank debt, accounts payable, accrued interest and other current liabilities approximate fair value as all amounts reported are to be collected or paid within one year. Our financial 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, classified as trading securities, that are held in a rabbi trust established for our deferred compensation plans. Our pension and postretirement plan assets and liabilities 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 into 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 market place. Our Level 2 items include non-exchange-traded derivative instruments, such as some qualified pension plan assets held in hedge fund of funds, commodities hedge fund of funds, 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 valuation policies and procedures.
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 hedge fund of funds, diversified private equity fund of funds and commodities hedge fund of funds for some of our qualified pension plan assets. We do not have any other assets or liabilities classified as Level 3.
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 end of the reporting period.
For the fair value measurements of our derivatives and marketable securities, see Note 7 to the consolidated financial statements. For the fair value measurements of our benefit plan assets, see Note 9 to the consolidated financial statements.
Goodwill, Equity Method Investments and Long-Lived Assets
Goodwill is the excess of the purchase price over the fair value of identifiable net assets acquired in a business combination. We annually evaluate goodwill for impairment as of October 31, or more frequently if impairment indicators arise during the year. These indicators include, but are not limited to, a significant change in operating performance, the business climate, legal or regulatory factors, or a planned sale or disposition of a significant portion of the business. We test goodwill using a fair value approach at a reporting unit level, generally equivalent to our operating segments as discussed in Note 14. 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.
We early adopted the accounting guidance issued September 2011 that simplifies how an entity tests goodwill for impairment. As part of our qualitative assessment, we considered macroeconomic conditions such as a 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 change 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 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 a qualitative assessment, we have determined that it is not necessary to perform a quantitative goodwill impairment test as of October 31, 2011. 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 recognized during the years ended October 31, 2011, 2010 and 2009.
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. There were no events or circumstances during the years ended October 31, 2011, 2010 and 2009 that resulted in any impairment charges. For further information on equity method investments, see Note 12 to the consolidated financial statements.
Marketable Securities
We have marketable securities that are invested in money market and mutual funds that are liquid and actively traded on the exchanges. These securities are assets that are held in a rabbi trust established for our deferred compensation plans that became effective on January 1, 2009. For further information on the deferred compensation plans, see Note 9 to the consolidated financial statements.
We have classified these marketable securities as trading securities since their inception as the assets are held in a rabbi trust. 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 investments at any time. Any participant’s account that exceeds $25,000 will be paid over five years upon retirement. A lesser amount will be paid upon retirement in a lump sum. We have matched the current portion of the deferred compensation liability with the current asset and noncurrent deferred compensation liability with the noncurrent asset; the current portion has been included in “Other current assets” in the consolidated balance sheets.
The money market investments in the trust 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, 2011 and 2010 is as follows.
| | | | | | | | | | | | | | | | |
In thousands | | 2011 | | | 2010 | |
| | | Cost | | | Fair Value | | | Cost | | | Fair Value | |
Current trading securities: | | | | | | | | | | | | | | | | |
Money markets | | $ | — | | | $ | — | | | $ | — | | | $ | — | |
Mutual funds | | | 47 | | | | 52 | | | | 4 | | | | 5 | |
| | | | | | | | | | | | | | | | |
Total current trading securities | | | 47 | | | | 52 | | | | 4 | | | | 5 | |
| | | | | | | | | | | | | | | | |
Noncurrent trading securities: | | | | | | | | | | | | | | | | |
Money markets | | | 217 | | | | 217 | | | | 254 | | | | 254 | |
Mutual funds | | | 1,107 | | | | 1,222 | | | | 618 | | | | 743 | |
| | | | | | | | | | | | | | | | |
Total noncurrent trading securities | | | 1,324 | | | | 1,439 | | | | 872 | | | | 997 | |
| | | | | | | | | | | | | | | | |
Total trading securities | | $ | 1,371 | | | $ | 1,491 | | | $ | 876 | | | $ | 1,002 | |
| | | | | | | | | | | | | | | | |
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 which has lives ranging from 5 to 30 years. We amortize bank debt expense over the life of the syndicated revolving credit facility, which is three years.
Should we reacquire long-term debt prior to its term date and simultaneously issue new debt, we defer the gain or loss resulting from the transaction, essentially the remaining unamortized debt expense, and amortize it over the life of the new debt in accordance with established regulatory practice. Where the refunding of the debt is not simultaneous, we defer the gain or loss resulting from the reacquisition of the debt and amortize over the remaining life of the redeemed debt in accordance with established regulatory practice. For income tax purposes, any gain or loss would be recognized as incurred.
Issuances and Repurchases of Common Stock
As discussed in Note 6 to the consolidated financial statements, we repurchase shares on the open market and such shares are then cancelled and become authorized but unissued shares. Currently, it is our policy to issue new shares for share-based employee awards and shareholder and employee investment plans.
Asset Retirement Obligations
The accounting guidance for AROs addresses the financial accounting and reporting for AROs associated with the retirement of long-lived assets that result from the acquisition, construction, development and operation of the assets. The accounting guidance requires the recognition of the fair value of a liability for AROs in the period in which the liability is incurred if a reasonable estimate of fair value can be made. We have determined that AROs exist for our underground mains and services.
In accordance with long-standing regulatory treatment, our depreciation rates are comprised of two components, one based on average service life and one based on cost of removal. We collect through rates the estimated costs of removal on certain regulated properties through depreciation expense, with a corresponding credit to accumulated depreciation. These removal costs are non-legal obligations as defined by the accounting guidance. Because these estimated removal costs meet the requirements of rate regulated accounting guidance, we have accounted for these non-legal AROs as a regulatory liability. We record the estimated non-legal AROs in “Cost of removal obligations” in “Noncurrent Liabilities” in our consolidated balance sheets. 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.
In 2006, we applied 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. At the same time, the NCUC, the PSCSC and the TRA approved placing these ARO costs in deferred accounts to preserve the regulatory treatment of these costs. AROs will be capitalized concurrently by increasing the carrying amount of the related asset by the same amount as the 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 4.5% to 5.87% with a weighted average of 5.86% for the twelve months ended October 31, 2011. The estimate was calculated using a time value weighted average credit adjusted risk-free rate. Any accretion will not be reflected in the income statement as we have received regulatory treatment for deferral as a regulatory asset with netting against a regulatory liability. We have recorded a liability on our distribution and transmission mains and services.
The cost of removal obligations recorded in our consolidated balance sheets as of October 31, 2011 and 2010 are presented below.
| | | | | | | | |
In thousands | | 2011 | | | 2010 | |
Regulatory non-legal AROs | | $ | 438,605 | | | $ | 412,776 | |
Conditional AROs | | | 27,395 | | | | 23,296 | |
| | | | | | | | |
Total cost of removal obligations | | $ | 466,000 | | | $ | 436,072 | |
| | | | | | | | |
A reconciliation of the changes in conditional AROs for the year ended October 31, 2011 and 2010 is presented below.
| | | | | | | | |
In thousands | | 2011 | | | 2010 | |
Beginning of period | | $ | 23,295 | | | $ | 23,331 | |
Liabilities incurred during the period | | | 3,102 | | | | 137 | |
Liabilities settled during the period | | | (1,493 | ) | | | (1,141 | ) |
Accretion | | | 1,365 | | | | 1,350 | |
Adjustment to estimated cash flows | | | 1,126 | | | | (382 | ) |
| | | | | | | | |
End of period | | $ | 27,395 | | | $ | 23,295 | |
| | | | | | | | |
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 formal 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 South Carolina and Tennessee, a weather normalization adjustment (WNA) is calculated for residential and commercial customers during the winter heating season November through March. The WNA is designed to offset the impact that warmer-than-normal or colder-than-normal weather has on customer billings during the winter heating season. In North Carolina, a year around margin decoupling mechanism provides for the recovery of our approved margin from residential and commercial customers independent of consumption patterns. The gas cost portion of our costs is recoverable through PGA procedures and is not affected by the WNA or the margin decoupling mechanism.
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 mechanism, as applicable.
Secondary market revenues associated with the commodity are recognized when the physical sales are delivered based on contract or market prices. Asset management fees for storage and transportation remitted on a monthly basis are recognized as earned given the monthly capacity costs associated with the contracts involved. Asset management fees remitted in a lump sum are deferred and amortized ratably into income over the period in which they are earned, which is typically the contract term. See Note 2 to the consolidated financial statements regarding revenue sharing of secondary market transactions.
Utility sales, transportation and secondary market revenues are reported on a net of tax basis. For further information regarding taxes, see “Taxes” in this Note 1 to the consolidated financial statements.
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 purchased gas adjustment (PGA)PGA provisions that provide for the recovery of prudently incurred and allocated gas costs. With regulatory commission approval, we revise rates periodically without formal rate proceedings to reflect changes in the wholesale cost of gas. Under PGA provisions, charges to cost of gas are based on the amount recoverable under approved rate schedules. By jurisdiction, differences between gas costs incurred and gas costs billed to customers are deferred and included in “Amounts due from customers” or “Amounts due to customers” in the consolidated balance sheets. We review gas costs and deferral activity periodically and, with regulatory commission approval, increase rates to collect under-recoveries or decrease rates to refund over-recoveries over a subsequent period.
45
We charge our secondary market customers for natural gas based on specified contract terms. Within our cost of gas, we include amounts for lost and unaccounted for gas and adjustments to reflect the gains and losses associated with gas price hedging derivatives.Taxes
Piedmont Natural Gas Company, Inc.
NotesWe have two categories of income taxes in our consolidated statements of income: current and deferred. Current income tax expense consists of federal and state income tax less applicable tax credits related to Consolidated Financial Statements — (Continued)
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 in accordance with SFAS No. 109, “Accounting for Income Taxes,” and FASB Interpretation 48, “Accounting for Uncertainty in Income Taxes” (FIN 48). Deferred taxes are primarily attributable to utility plant, equity method investments and revenues and cost of gas.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 pursuant to Statement 71,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 our 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 in operating expenses in the consolidated statements of 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, public utility fees and other miscellaneous taxes.
Utility sales and transportation revenuesConsolidated Statements of Cash Flows
With respect to cash overdrafts, book overdrafts are based on rates approved by state regulatory commissions. Base rates charged to jurisdictional 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 provisions. In South Carolina and Tennessee, a weather normalization adjustment (WNA) is calculated for residential and commercial customers during the winter period November through March. The WNA is designed to offset the impact that warmer-than-normal or colder-than-normal weather has on customer billings during the winter season. In North Carolina, a margin decoupling mechanism provides for the recovery of our approved margin from residential and commercial customers independent of consumption patterns. The gas cost portion of our costs is recoverable through PGA procedures and is not affected by the WNA or the margin decoupling mechanism.
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, changes in weather during the period and the impact of the WNA or margin decoupling mechanism, as applicable.
Secondary market revenues are recognized when the physical sales are delivered based on contract or market prices. See Note 2 regarding revenue sharing of secondary market transactions.
Utility sales, transportation and secondary market revenues are reported on a net basis. For further information, see Note 1.J to the consolidated financial statements.
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Piedmont Natural Gas Company, Inc.
Notes to Consolidated Financial Statements — (Continued)
We compute basic earnings per share using the weighted average number of shares of common stock outstanding during each period. A reconciliation of basic and diluted earnings per share for the years ended October 31, 2008, 2007 and 2006 is presented below.
| | | | | | | | | | | | | |
| | | 2008 | | | 2007 | | | 2006 | |
| | | In thousands except per share amounts | |
| |
| Net Income | | $ | 110,007 | | | $ | 104,387 | | | $ | 97,189 | |
| | | | | | | | | | | | | |
| Average shares of common stock outstanding for basic earnings per share | | | 73,334 | | | | 74,250 | | | | 75,863 | |
| Contingently issuable shares under the Executive Long-Term Incentive Plan and Incentive Compensation Plan | | | 278 | | | | 222 | | | | 293 | |
| | | | | | | | | | | | | |
| Average shares of dilutive stock | | | 73,612 | | | | 74,472 | | | | 76,156 | |
| | | | | | | | | | | | | |
| Earnings Per Share: | | | | | | | | | | | | |
| Basic | | $ | 1.50 | | | $ | 1.41 | | | $ | 1.28 | |
| Diluted | | $ | 1.49 | | | $ | 1.40 | | | $ | 1.28 | |
| |
M. | Statements of Cash Flows. |
For purposes of reportingincluded within operating cash flows we consider instruments purchasedwhile any bank overdrafts are included with an original maturity at date of purchase of three months or less to befinancing cash equivalents.
We make estimates and assumptions when preparing the consolidated financial statements. These estimates and assumptions affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from estimates.
| |
O. | Recently Issued Accounting Standards. |
flows.Recently Issued Accounting Guidance
In September 2006,June 2009, the Financial Accounting Standards Board (FASB) issued SFAS No. 157, “Fair Value Measurements” (Statement 157). Statement 157 provides enhancedamended accounting guidance for using fair value to measure assetseliminate the quantitative approach that entities use to determine whether an entity has a controlling financial interest in a variable interest entity (VIE) and liabilities and applies whenever other standardsto require (or permit) the measurement of assets or liabilities at fair value, but does not expand the use of fair value measurement to any new circumstances. Under Statement 157, 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. Statement 157 clarifies that fair value should be based onwith a variable interest in a VIE qualitatively assess whether it has a controlling financial interest, and if so, determine whether it is the assumptions market participants would useprimary beneficiary. The guidance requires companies to continually evaluate the VIE for consolidation, rather than performing the assessment only when pricingspecific events occur. It also requires enhanced disclosures to provide more information about the asset or liability. Statement 157 establishes a fair value hierarchy for valuation inputs that prioritizesentity’s involvement with the information used to develop those assumptions into three levels as follows:
| | |
| • | Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that the entity has the ability to access as of the reporting date. |
|
�� | • | Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly, through corroboration with observable data. |
|
| • | Level 3 inputs are unobservable inputs, such as internally developed pricing models for the asset or liability due to little or no market activity for the asset or liability. |
47
Piedmont Natural Gas Company, Inc.
Notes to Consolidated Financial Statements — (Continued)
Under Statement 157, we anticipate fair value measurements would be disclosed by level for gas purchase options under our gas hedging plans.
In November 2007, the FASB delayed the implementation of Statement 157 for one year only for other nonfinancial assets and liabilities. Statement 157VIE. The guidance is effective for
fiscal periods beginning after November 15, 2009. Our adoption of this guidance on consolidation of VIEs, effective November 1, 2010, had no impact on our financial
statementsposition, results of operations or cash flows. For information regarding disclosures related to variable interests in unconsolidated VIEs, see Note 13 to the consolidated financial statements.In January 2010, the FASB issued accounting guidance to require separate disclosures about purchases, sales, issuances and settlements relating to Level 3 fair value measurements. The guidance will be effective for interim periods for fiscal years beginning after NovemberDecember 15, 2007,2010. We will adopt the guidance for Level 3 disclosure for recurring and interim periods within those fiscal years, with earlier application encouraged for financial assets and liabilities, as well as for any other assets and liabilities that are carried atnon-recurring items covered under the fair value on a recurring basis. Accordingly, we will adopt Statement 157guidance for the first quarter of our fiscal year beginning November 1, 2008 withending October 31, 2012. Since the exception of the application of the provisionguidance addresses only disclosures related to nonfinancial assets and liabilities. Thefair value measurements under Level 3, the adoption of Statement 157this guidance will not have a material impact on our financial position, results of operations or cash flows.
In April 2007,July 2010, the FASB issued FSPFIN 39-1accounting guidance to amend paragraph 3improve disclosures about the credit quality of FIN 39, “Offsettingan entity’s financing receivables and the reserves held against them. End of Amounts Related to Certain Contracts,” to replacereporting period disclosures are required for the terms conditional contracts and exchange contracts with the term derivative instruments as defined in SFAS 133, “Accounting for Derivative Instruments and Hedging Activities” (Statement 133).reporting period ending on or after December 15, 2010. The FSP amends paragraph 10 of FIN 39 to permitdisclosures about activity that occurred during a reporting entity to offset fair value amounts recognizedperiod were effective for interim and annual periods beginning on or after December 15, 2010. We adopted the guidance for the rightend of period disclosures as of January 31, 2011, and the guidance for the disclosures related to reclaim cash collateral oractivity in the obligation to return cash collateral against fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting arrangement. This FSP is effective for fiscal years beginning after November 15, 2007, with early application permitted. Accordingly, we have evaluated the impacts of the right to offset fair value amounts pursuant to amended paragraph 10 of FIN 39 forreporting period during our fiscal yearsecond quarter beginning NovemberFebruary 1, 2008. Our policy has been2011. Since the guidance addresses only disclosures related to present our positions, exclusivecredit quality of any receivable or payable, withfinancing receivables and the same counterparty onallowance for credit losses, the adoption of this guidance did not have a net basis; however, we will elect “not to net” under FSPFIN 39-1 and will reflect minor reclassificationsmaterial impact on our statement of financial position.
In December 2007, the FASB issued SFAS No. 141(R), “Business Combinations” (Statement 141(R)). Statement 141(R) establishes principles and requirements for how the acquirer in a business combination recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed and any noncontrolling interest in the acquiree at the acquisition date at fair value. Statement 141(R) changes the accounting for business combinations in various areas, including contingency consideration, preacquistion contingencies, transaction costs and restructuring costs. In addition, changes in the acquired entity’s deferred tax assets and uncertain tax positions after the measurement period will impact income tax expense. We will apply the provisions of Statement 141(R) to any acquisitions we may complete after November 1, 2009.
In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities — Including an Amendment of FASB Statement No. 115” (Statement 159). Statement 159 provides companies with an option to report selected financial assets and liabilities at fair value. Its objective is to reduce the complexity in accounting for financial instruments and to mitigate the volatility in earnings caused by measuring related assets and liabilities differently. Although Statement 159 does not eliminate disclosure requirements included in other accounting standards, it does establish additional presentation and disclosure requirements designed to facilitate comparisons between companies that choose different measurement attributes for similar types of assets and liabilities. Statement 159 is effective for financial statements issued for fiscal years beginning after November 15, 2007, with early adoption permitted for an entity that has elected also to apply Statement 157 early. Accordingly, we will adopt Statement 159 for our fiscal year beginning November 1, 2008. We have evaluated Statement 159, and we do not intend to elect the option to measure any applicable financial assets or liabilities at fair value pursuant to the provisions of Statement 159.
In March 2008, the FASB issued SFAS No. 161, “Disclosures About Derivative Instruments and Hedging Activities” (Statement 161). Statement 161 amends Statement 133, by requiring expanded qualitative, quantitative and credit-risk disclosures about derivative instruments and hedging activities, but does not change the scope or accounting under Statement 133 and its related interpretations. Statement 161 requires specific disclosures regarding how and why an entity uses derivative instruments; how derivative instruments and
48
Piedmont Natural Gas Company, Inc.
Notes to Consolidated Financial Statements — (Continued)
related hedged items are accounted for; and how derivative instruments and related hedged items affect an entity’s financial position, results of operations
andor cash flows.
Statement 161 also amended SFAS 107, “Disclosures about Fair ValueIn May 2011, the FASB issued accounting guidance to improve the comparability of fair value measurements presented and disclosed in financial statements prepared in accordance with U.S. GAAP and International Financial Instruments” (Statement 107),Reporting Standards (IFRS). The amendments are not intended to change the application of the current fair value requirements, but to clarify the application of existing requirements. The guidance does change particular principles or requirements for measuring fair value or disclosing information about fair value measurements. To improve consistency, language has been changed to ensure that derivative instrumentsU.S. GAAP and IFRS fair value measurement and disclosure requirements are subject to Statement 107’s concentration-of-credit-risk disclosures. Statement 161 isdescribed in the same way. The guidance will be effective for financial statements issued for fiscal yearsinterim and interimannual periods beginning after NovemberDecember 15, 2008, with early2011. We will adopt the amended fair value guidance for the second quarter of our fiscal year ending October 31, 2012. We do not expect the adoption permitted. Since Statement 161 only requires additional disclosures concerning derivatives and hedging activities,of this standard is not expectedguidance to have a material impact on our financial position, results of operations or cash flows.
In June 2011, the FASB issued accounting guidance to increase the prominence of OCI in financial statements. The guidance gives businesses two options for presenting OCI. An OCI statement can be included with the statement of operations, and together the two will comprise the statement of comprehensive income. Alternatively, businesses can present a separate OCI statement, but that statement must appear consecutively with the statement of operations within the financial report. The guidance will be effective for interim and annual periods beginning after December 15, 2011. In October 2011, the FASB tentatively decided to indefinitely defer the provisions to require entities to present the adjustment of items reclassified from OCI to net income in both net income and OCI. We will adopt Statement 161 on February 1, 2009.
In May 2008, the
FASB issued SFAS No. 162, “The Hierarchyunaffected provisions of
Generally Accepted Accounting Principles” (Statement 162). Statement 162 identifiesOCI presentation guidance for the
sourcessecond quarter of
accounting principles and the framework for selecting the principles used in the preparationour fiscal year ending October 31, 2012. The adoption of
financial statements that are presented in conformity with GAAP for nongovernmental entities. Statement 162 was issued to include the GAAP hierarchy in the accounting literature established by the FASB. Statement 162this guidance will
be effective sixty days following the Securities and Exchange Commission (SEC) approval of the Public Company Accounting Oversight Board amendments to AU Section 411, “The Meaning of Present Fairly in Conformity With Generally Accepted Accounting Principles.” We do not expect this statement to have
anyno impact on our financial position, results of operations or cash flows. We
will adopt Statement 162 whenintend to present net income and other comprehensive income in one continuous statement.In September 2011, the FASB issued accounting guidance to simplify how an entity tests goodwill for impairment. An entity is allowed an option to first assess qualitative factors to determine whether it becomes effective.
is more likely than not (greater than 50%) that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two-step quantitative impairment test. An entity is not required to calculate the fair value of a reporting unit unless the entity determines that it is more likely than not that its fair value is less than its carrying amount. This guidance, which we early adopted for our goodwill assessment performed for October 31, 2011, is effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011.2. Regulatory Matters
Our utility operations are regulated by the NCUC, PSCSC and TRA as to rates, service area, adequacy of service, safety standards, extensions and abandonment of facilities, accounting and depreciation. We are also regulated by the NCUC as to the issuance of long-term debt and equity securities.
In April 2005, we filedThe NCUC and the PSCSC regulate our gas purchasing practices under a general rate case with the NCUC requestingstandard of prudence and audit our gas cost accounting practices. The TRA regulates our gas purchasing practices under a consolidationgas supply incentive program which compares our actual costs to market pricing benchmarks. As part of the respective rate bases, revenues and expenses of Piedmont,this jurisdictional oversight, all three states address our gas supply hedging activities. Additionally, North Carolina Natural Gas Corporation (NCNG) and Eastern NorthSouth Carolina Natural Gas Company (EasternNC). In addition to a unified and uniform rate structureallow for all customers served by us in North Carolina, the application requested a general restructuring and increase in rates and charges for customers to produce an overall annual increase in margin of $36.7 million, a consolidationand/or amortization of certain deferred accounts, changes to cost allocations and rate design including a tariff mechanism that decouples margin recovery from residential and commercial customer consumption, changes and unification of existing service regulations and tariffs, common depreciation rates for plant and 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. In Tennessee, to the extent that the gas cost deferred account.
In November 2005, the NCUC issued an order in this general rate case proceeding establishing a margin decoupling mechanism that provides for the recoveryportion of our approved margin from residential and commercial customers independent of consumption patterns. The margin decoupling mechanism was experimentalnet write-offs for a three-year period, subjectfiscal year is less than the gas cost portion included in base rates, the difference would be refunded to review and approval for extension incustomers through the ACA filings; if the difference is greater, there would be a future general rate case proceeding. The margin decoupling mechanism, which replaced our WNA mechanism that adjusted margins for weather, has been operating for three years and reconciles our margin earned each month. We file for semi-annual rate adjustmentscharge to refund any over-collection of margin or recover any under-collection of margin. Each of these rate adjustments has been approved bycustomers through the NCUC.
Under the NCUC’s orders and the terms of a settlement with the ACA filing.North Carolina Attorney General for the three years of the experimental margin decoupling program, we allocated $500,000 to energy conservation program funding and shared the first $3 million of the margin adjustment that was non-weather related. Annually, the first $3 million of non-weather related amounts will be allocated 25% to customer rate reduction, 25% to energy conservation program funding and 50% to us. Since the inception of the program on November 1, 2005, we have incurred charges of $6.3 million for the benefit of residential and commercial customers. The charges consist of $3.75 million for the funding of conservation programs in North Carolina, $2.25 million for the reduction of residential and commercial customer rates in North Carolina and $.3 million
49
Piedmont Natural Gas Company, Inc.
Notes to Consolidated Financial Statements — (Continued)
for interest accruals on the conservation funding and reduction of customer rates. The conservation programs are subject to review and approval by the NCUC. At October 31, 2008 and 2007, we had liabilities for the conservation programs of $1.3 million and $1.5 million, respectively.
In March 2008, we filed a general rate case proceeding with the NCUC requesting an increase in rates and charges for all customers to produce overall increased annual revenues of $40.5 million, or 4% above the current annual revenues. In October 2008, the NCUC approved a settlement between us, the North Carolina Public Staff and all intervening parties with the exception of the North Carolina Attorney General’s office, in which the parties agreed to an annual revenue increase of $15.7 million and the continuation of the margin decoupling mechanism. In addition to the revenue increase, the stipulation also includes cost allocation and rate design changes under our existing rate schedules, approval to implement energy conservation and efficiency programs of $1.3 million annually with appropriate cost recovery mechanisms and changes to the existing service regulations and tariffs. The new rates became effective November 1, 2008.
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 EasternNCEastern 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 uneconomic feasibilityeconomic 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. WeWith 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 operations and maintenance 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 deferred amounts accrued 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, $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 operations and maintenance expenses was $9 million at October 31, 2008. This balance is being amortized over a twelve-year periodaccruing interest at a rate of 7.84% per annum.
Inannum and is being amortized over a twelve year period. As of October
2004,31, 2011 and 2010, we
filedhad unamortized balances of $7.7 million and $8.3 million, respectively.With the inception of our North Carolina energy conservation program on November 1, 2005, we incurred charges of $6.4 million for the benefit of residential and commercial customers. The charges consisted of $3.75 million for the funding of conservation programs in North Carolina, $2.25 million for the reduction of residential and commercial customer rates in North Carolina and $.4 million for interest accruals on the conservation funding and reduction of customer rates. At October 31, 2010, we had a petition withliability for the NCUC seeking deferred accounting treatment forconservation programs of $.4 million and no liability as of October 31, 2011.
We incur certain pipeline integrity management costs to be incurred by us in compliance with the Pipeline Safety Improvement Act of 1992 and regulations of the United States Department of Transportation. The NCUC approved deferral treatment of thesethe operations and maintenance costs applicable to all incremental expenditures beginning November 1, 2004. As a part of the 2005 general rate case discussed above, the balance of $.4 million in the deferred account as of June 30, 2005, is being amortized over three years beginning November 1, 2005, and subsequent expenditures that total $4.3 million as of October 31, 2007 will continue to be deferred. 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 are subject to amortizationwere fully amortized over a three-year period beginning November 1, 2008. The existing regulatory asset treatment for ongoing pipeline integrity management costs will continuecontinues until another recovery mechanism is established in a future rate proceeding. The unamortized balance as of October 31, 2008 that is not being amortized2011 that is subject to a future rate proceeding is $1.4$8 million.
On February 16, 2005, the Natural Gas Rate Stabilization Act (RSA) of 2005 became effective in South Carolina. The law provides electing natural gas utilities, including Piedmont, with a mechanism for the
50
Piedmont Natural Gas Company, Inc.
Notes to Consolidated Financial Statements — (Continued)
regular, periodic and more frequent (annual) adjustment of rates which is intended to: (1) encourage investment by natural gas utilities, (2) enhance economic development efforts, (3) reduce the cost of rate adjustment proceedings and (4) result in smaller but more frequent rate changes for customers. If the utility elects to operate under the Act, the annual filing will provide that the utility’s rate of return on equity will remain within a 50-basis points band above or below the current allowed rate of return on equity. In April 2005, we filed an election with the PSCSC to adopt this new mechanism.
In June 2006, we filed with the PSCSC a quarterly monitoring report for the twelve months ended March 31, 2006, along with revenue deficiency calculations and proposed changes in our tariff rates. In the filing, we requested an increase in annual margin of $10.3 million. In September 2006, we, the Office of Regulatory Staff (ORS) and the South Carolina Energy Users Committee (SCEUC) filed a settlement agreement with the PSCSC addressing our proposed rate changes under the RSA. In September 2006, the PSCSC issued an order approving a $5.6 million increase in margin based on 11.2% return on equity effective November 1, 2006.
In June 2007, we filed with the PSCSC a quarterly monitoring report for the twelve months ended March 31, 2007 and a cost and revenue study as permitted by the RSA requesting no change in margin. In October 2007, the PSCSC issued an order approving a settlement between us, the ORS and the SCEUC that resulted in a $2.5 million annual decrease in margin based on a return of equity of 11.2%. The new rates were effective November 1, 2007.
In June 2008, we filed with the PSCSC a quarterly monitoring report for the twelve months ended March 31, 2008 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 2007 order. In the filing, we requested an increase in annual margin of $2 million. In October 2008, the PSCSC issued an order approving a settlement between us, the ORS and the SCEUC that resulted in a $1.5 million annual decrease in margin based on a return on equity of 11.2%, effective November 1, 2008.
All three jurisdictions regulate our gas purchasing practices under a standard of prudence and audit our gas cost accounting practices. As part of this jurisdictional oversight, all three states address our gas supply hedging activities. Additionally, as detailed below, all three states allow for recovery of uncollectible gas costs through the PGA.
In North Carolina, our recovery of gas costs is subject to annual gas cost proceedings to determine the prudence of our gas purchases. WeCosts have never been found prudent in all past proceedings.
disallowed on the basis of prudence.In August 2007,February 2010, the NCUC approved our accounting forof gas costs duringfor the twelve months ended May 31, 2006,2009, with adjustments agreed to by us as a result of the North Carolina Public Staff’s audit of the 20062009 gas cost review period. We were deemed prudent on our gas purchasing policies and practices during this review period and allowed 100% recovery.
In this order the NCUC also required us to discontinue the accounting practice of capitalizing and amortizing storage demand charges, effective no later than November 1, 2007. This action resulted in a margin decrease of $5.4 million in 2007.
During 2007, under the provisions of the August 2007 NCUC order, we recorded as restricted cash $2.2 million, including interest, of supplier refunds. In September 2007, we petitioned the NCUC for authority to liquidate all certificates of deposit and similar investments that held any supplier refunds due to customers. In October 2007, the NCUC approved the transfer of these restricted funds to the North Carolina deferred account. The various certificates of deposit matured by January 31, 2008.
In November 2007,2011, the NCUC approved our accounting of gas costs for the twelve months ended May 31, 2007,2010, with adjustments agreed to by us as a result of the North Carolina Public Staff’s audit of the 20072010 gas cost review period. We were deemed prudent on our gas purchasing policies and practices during this review period and allowed 100% recovery.
51
Piedmont Natural Gas Company, Inc.
Notes to Consolidated Financial Statements — (Continued)
In August 2008,2011, we filed testimony in North Carolinawith the NCUC in support of our gas cost purchasing and accounting practices for the period endingtwelve months ended May 31, 2008.2011. A hearing on this matter was held on December 16, 2008.October 4, 2011. We are unable to determinepredict the outcome of thethis proceeding at this time.
Our gas cost hedging plan for North Carolina is designed for the purposeto provide some level of cost stabilization andprotection against significant price increases, targets 30%a percentage range of 22.5% to 60%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 are deemed to be reductionsis a reduction in or additionsan addition to gas costs, respectively, which, along with any hedging expenses, are flowed through to North Carolina customers in rates. The August 2007 gas cost review orderorders issued February 2010 and our November 2007 gas cost review orderJanuary
2011 found our hedging activities during the two review periods to be reasonable and prudent.
Since As part of the February 2010 order, the NCUC approved an adjustment of $1.1 million related to hedging activity that decreased “Amounts due from customers” as agreed to by us and the North Carolina Public Staff.South Carolina Jurisdiction
We currently operate under the Natural Gas Rate Stabilization Act (RSA) of 2005 in South Carolina. If a utility elects to operate under the RSA, the annual 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 2009, we filed with the PSCSC a quarterly monitoring report for the twelve months ended March 31, 2009 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 2008 order. In October 2009, the PSCSC issued an order approving a settlement between the Office of Regulatory Staff (ORS), the South Carolina Energy Users Committee (SCEUC) and us that resulted in a $1.1 million annual increase in margin based on a return on equity of 11.2%, effective November 1, 2005,2009.
In June 2010, we filed with the NCUC has allowedPSCSC a quarterly monitoring report for the recoverytwelve months ended March 31, 2010 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 2009 order. In October 2010, the PSCSC issued an order approving a settlement between the ORS, the SCEUC and us that resulted in a $.75 million annual increase in margin on a return on equity of all uncollectible gas costs through11.3%, effective November 1, 2010.
In June 2011, we filed with the gasPSCSC a quarterly monitoring report for the twelve months ended March 31, 2011 and a cost PGA deferral account. Asand revenue study as permitted by the RSA requesting a result,change in rates from those approved by the portionPSCSC in the October 2010 order. In October 2011, the PSCSC issued an order approving a settlement between the ORS, the SCEUC and us that resulted in a $3.1 million annual decrease in margin based on a return on equity of uncollectibles related to gas costs is recovered through the deferred account11.3% and only the non-gas costs, or margin, portiona decrease of uncollectibles is included$1.9 million in basedepreciation rates and uncollectibles expense.
for South Carolina utility plant in service, effective November 1, 2011.In South Carolina, our recovery of gas costs is subject to annual gas cost proceedings to determine the prudence of our gas purchases. WeCosts have never been found prudent in all past proceedings.
disallowed on the basis of prudence.In South Carolina, the PSCSC approved a settlement in August 2006 between us, the ORS and the SCEUC accepting our purchased gas adjustments and finding our gas purchasing policies prudent for the twelve months ended March 31, 2006. As part of this settlement, we began recovering uncollectible gas costs through the PGA effective November 1, 2006. In May 2008,2009, the PSCSC approved our purchased gas adjustments and found our gas purchasing policies prudent for the twelve months ended March 31, 2007.
In August 2008, the PSCSC approved our purchased gas adjustmentsPGAs and found our gas purchasing policies to be prudent for the
period coveringtwelve months ended March 31, 2009.In August 2010, the PSCSC approved our PGAs and found our gas purchasing policies to be prudent for the twelve months ended March 31, 2008.
2010.The PSCSC has approved a gas cost hedging plan for the purpose of cost stabilization for South Carolina customers. The plan targets 30%a percentage range of 22.5% to 60%45% of annual normalized sales volumes for South Carolina and operates using historical pricing indices that are 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 are recovered in rates as gas costs. Any gain or loss recognitionrecognized under the hedging program are deemed to be reductionsis a reduction in or additionsan addition to gas costs, respectively, and are flowedflows through to South Carolina customers in rates.
In February 2011, the ORS requested that the PSCSC temporarily suspend the PSCSC-approved gas hedging programs operated by the regulated gas utilities in South Carolina due to more moderate market conditions for the cost of natural gas. This suspension of the hedging program was requested to be effective prospectively upon the issuance of an order by the PSCSC. All existing hedges would continue to be managed under the current approved hedging programs as gas costs in the annual review of purchased gas costs and gas purchasing policies. In March 2011, we filed a letter with the PSCSC stating that we believe that it is reasonable and prudent to continue our current hedging program to provide some degree of price stability for natural gas consumers. We believe that some price volatility will continue to exist in the market due to unpredictable events. Oral arguments and informational briefings on this matter were heard by the PSCSC in April 2011. In June 2011, the ORS withdrew its petition for suspension of gas hedging programs. In July 2011, the PSCSC granted the ORS’ motion to withdraw the above mentioned petition and directed the ORS and the regulated gas utilities in South Carolina to address the prudence of gas hedging activities in annual review proceedings.
In August 2011, 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 that our hedging program should no longer have a required minimum volume of hedging. At the PSCSC’s request, the ORS held a public briefing in November 2011 on the issue of how to measure the prudence of hedging programs in future annual review proceedings with no action taken on the matter.
In October 2009, we filed a petition with the PSCSC requesting approval to offer three energy efficiency programs to residential and commercial customers at a total annual cost of $.35 million. The proposed programs in South Carolina were designed to promote energy conservation and efficiency by residential and commercial customers with full ratepayer recovery of program costs through annual RSA filings and were similar to approved energy efficiency programs in North Carolina. In May 2010, the PSCSC approved the energy efficiency programs on a three-year experimental basis with equipment rebates on the purchase of high-efficiency natural gas equipment and weatherization assistance for low-income residential customers.
Tennessee Jurisdiction
In Tennessee, the Tennessee Incentive Plan (TIP) replaced annual prudence reviews under the Actual Cost Adjustment (ACA)ACA mechanism in 1996 by benchmarking gas costs against amounts determined by published market indices and by sharing secondary market (capacity release and off-system sales) activity performance. The costs and benefits of hedging instruments and all other gas costs incurred are components of the TIP. In July 2005, in the order approving our 2004 TIP filing, the TRA established a separate docket to address issues raised by the Tennessee Consumer Advocate Staff and the TRA Staff related to the breadth of secondary market activities covered by the TIP, the method for selecting the independent consultant to review performance under the TIP, and the procedures utilized with respect to requests for proposal. In October 2007, the TRA approved our settlement with the staff of the TRA and the Tennessee Consumer Advocate Staff modifyingmodified our TIP with an effective date of July 1, 2006. The modificationsto clarify and simplify the calculation of allocatedallocating gains and losses to ratepayers and shareholders by adopting a uniform 75/25 sharing ratio, maintainratio. The TRA also maintained the current $1.6 million annual incentive cap for us on gains and losses, improveimproved the transparency of plan operations by an agreed to request for proposal procedures for asset management transactions and provideprovided for a triennial review of TIP operations by an independent consultant.
52
Piedmont Natural Gas Company, Inc.
Notes to Consolidated Financial Statements — (Continued)
We haveIn December 2008, we filed an annual report for the twelve months ended December 31,
20062007 with the TRA that
reflectsreflected the transactions in the deferred gas cost account for the ACA mechanism. In
June 2008,April 2009, the TRA staff filed its final audit report, with which we concurred. In
August 2008,May 2009, the TRA issued an order adopting all findings from the staff audit. The order includesincluded cost of gas adjustments for the calendar year 20062007 review period. There was no material impact from these gas cost adjustments.
adjustments on our financial position, results of operations or cash flows. We were found to be in compliance with the TRA rules in the use of the ACA mechanism.In July 2009, we filed an annual report for the twelve months ended December 31, 2008 with the TRA that reflected the transactions in the deferred gas cost account for the ACA mechanism. In July 2010, in coordination with the TRA Audit Staff, we withdrew the annual report filed in July 2009 and concurrently filed a revised annual report for the twelve months ended December 31, 2008. There was no material impact from these gas cost adjustments to our financial position, results of operations or cash flows. In October 2010, the TRA issued its order adopting the findings of the revised TRA Audit Staff report on this matter, which were in agreement with our revised report.
In December 2010, we filed our report for the eighteen months ended June 30, 2010 with the TRA that reflected 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 issued an order approving the deferred gas cost account.
In September 2010, 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, 2010 under the TIP. In May 2011, the TRA issued an order approving our TIP account balances.
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. We are unable to predict the outcome of this proceeding at this time.
In September 2011, we filed an annual report for the twelve months ended June 30, 2011 with the TRA that reflected the transactions in the deferred gas cost account for the ACA mechanism. We are unable to predict the outcome of this proceeding at this time.
In September 2011, we filed a general rate application with the TRA requesting authority for an increase to rates and charges for all customers to produce overall incremental revenues of $16.7 million annually, or 8.9% above the current annual revenues. In addition, the petition also requested modifications of the cost allocation and rate designs underlying our existing rates, approval to implement a school-based energy education program with appropriate cost recovery mechanisms, an amortization of certain regulatory assets and deferred accounts, revised depreciation rates for plant and changes to the existing service regulations and tariffs. The changes are proposed to be effective March 2003,1, 2012. A hearing on this matter has been scheduled for the week of January 23, 2012. We are unable to predict the outcome of this proceeding at this time.
In February 2010, we alongfiled a petition with two other natural gas companiesthe TRA to adjust the applicable rate for the collection of the Nashville franchise fee from certain customers. The proposed rate adjustment was calculated to recover the net $2.9 million of under-collected Nashville franchise fee payments as of May 31, 2009. In April 2010, the TRA passed a motion approving a new Nashville franchise fee rate designed to recover only the net under-collections that have accrued since June 1, 2005,
which would deny recovery of $1.5 million for us. 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 Tennessee,operations and maintenance expenses. In November 2011, we filed for reconsideration, which was granted on November 21, 2011. We are unable to predict the outcome of this proceeding at this time. However, we do not believe this matter will have a material effect on our financial position, results of operations or cash flows.
In September 2010, we filed a petition with the TRA requesting deferred accounting treatment for the direct, incremental expenses incurred as a declaratory order that the gas cost portionresult of uncollectible accounts be recovered through PGA procedures. We requested thatour response to the extent thatsevere flooding in Nashville in May 2010. The TRA approved our petition in October 2010. The balance in the gas cost portiondeferred account is $1 million as of net write-offs for a fiscal year is less thanOctober 31, 2011 and 2010. We are seeking recovery of these deferred expenses in the gas cost portion included in base rates, the difference would be refunded to customers through the ACA filings. With TRA approval, this methodology was used on an experimental basis for two years. In August 2006,general rate application filed with the TRA approved the methodology permanently.
in September 2011.All Jurisdictions
Due to the seasonal nature of our business, we contract with customers in the secondary market to sell supply and capacity assets when available. 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.
We filed petitions with In all three jurisdictions for the NCUC, the PSCSC and the TRA in September 2006 for authorization to place certain ARO costs in deferred accounts so that the regulatory treatment for these costs will not be altered due to our adoption of FIN 47. The petitions were approved in all of the jurisdictions in November 2007, effectivetwelve months ended October 31, 2006.
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. In August 2007,all three jurisdictions for the twelve months ended October 31, 2010, we filed petitions withgenerated $42.8 million of margin from secondary market activity, $32.1 million of which is allocated to customers as gas cost reductions and $10.7 million as margin allocated to us. In all three jurisdictions for the NCUC, the PSCSCtwelve months ended October 31, 2009, we generated $46 million of margin from secondary market activity, $34.5 million which is allocated to customers as gas cost reductions and the TRA requesting the ability$11.5 million as margin allocated to place certain defined benefit postretirement obligations related to the implementation of SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans” (Statement 158) in a deferred account instead of OCI. The petitions were approved in all of the jurisdictions.
us.We currently have commission approval in all three states that place tighter credit requirements on the retail natural gas marketers that schedule gas into our system in order to mitigate the risk exposure to the financial condition of the marketers.
53
3. Earnings Per ShareWe compute basic earnings per share (EPS) using the weighted average number of shares of common stock outstanding during each period. Shares of common stock to be issued under approved incentive compensation plans are contingently issuable shares and are included in our calculation of fully diluted earnings per share.
Piedmont Natural Gas Company, Inc.
Notes to Consolidated Financial Statements — (Continued)
A reconciliation of basic and diluted EPS for the years ended October 31, 2011, 2010 and 2009 is presented below. | | | | | | | | | | | | |
In thousands except per share amounts | | 2011 | | | 2010 | | | 2009 | |
Net Income | | $ | 113,568 | | | $ | 141,954 | | | $ | 122,824 | |
| | | | | | | | | | | | |
Average shares of common stock outstanding for basic earnings per share | | | 72,056 | | | | 72,275 | | | | 73,171 | |
Contingently issuable shares under incentive compensation plans | | | 210 | | | | 250 | | | | 290 | |
| | | | | | | | | | | | |
Average shares of dilutive stock | | | 72,266 | | | | 72,525 | | | | 73,461 | |
| | | | | | | | | | | | |
Earnings Per Share of Common Stock: | | | | | | | | | | | | |
Basic | | $ | 1.58 | | | $ | 1.96 | | | $ | 1.68 | |
Diluted | | $ | 1.57 | | | $ | 1.96 | | | $ | 1.67 | |
4. Long-Term Debt
All of our long-term debt is unsecured and is issued at fixed rates. Long-term debt as of October 31, 20082011 and 20072010 is as follows.
| | | | | | | | | |
| | | 2008 | | | 2007 | |
| | | In thousands | |
| |
| Senior Notes: | | | | | | | | |
| 8.51%, due 2017 | | $ | 35,000 | | | $ | 35,000 | |
| Medium-Term Notes: | | | | | | | | |
| 7.35%, due 2009 | | | 30,000 | | | | 30,000 | |
| 7.80%, due 2010 | | | 60,000 | | | | 60,000 | |
| 6.55%, due 2011 | | | 60,000 | | | | 60,000 | |
| 5.00%, due 2013 | | | 100,000 | | | | 100,000 | |
| 6.87%, due 2023 | | | 45,000 | | | | 45,000 | |
| 8.45%, due 2024 | | | 40,000 | | | | 40,000 | |
| 7.40%, due 2025 | | | 55,000 | | | | 55,000 | |
| 7.50%, due 2026 | | | 40,000 | | | | 40,000 | |
| 7.95%, due 2029 | | | 60,000 | | | | 60,000 | |
| 6.00%, due 2033 | | | 100,000 | | | | 100,000 | |
| Insured Quarterly Notes: | | | | | | | | |
| 6.25%, due 2036 | | | 199,261 | | | | 199,887 | |
| | | | | | | | | |
| Total | | | 824,261 | | | | 824,887 | |
| Less current maturities | | | 30,000 | | | | — | |
| | | | | | | | | |
| Total | | $ | 794,261 | | | $ | 824,887 | |
| | | | | | | | | |
| | | | | | | | |
In thousands | | 2011 | | | 2010 | |
Senior Notes: | | | | | | | | |
2.92%, due 2016 | | $ | 40,000 | | | $ | — | |
8.51%, due 2017 | | | 35,000 | | | | 35,000 | |
4.24%, due 2021 | | | 160,000 | | | | — | |
Medium-Term Notes: | | | | | | | | |
6.55%, due 2011 | | | — | | | | 60,000 | |
5.00%, due 2013 | | | 100,000 | | | | 100,000 | |
6.87%, due 2023 | | | 45,000 | | | | 45,000 | |
8.45%, due 2024 | | | 40,000 | | | | 40,000 | |
7.40%, due 2025 | | | 55,000 | | | | 55,000 | |
7.50%, due 2026 | | | 40,000 | | | | 40,000 | |
7.95%, due 2029 | | | 60,000 | | | | 60,000 | |
6.00%, due 2033 | | | 100,000 | | | | 100,000 | |
Insured Quarterly Notes: | | | | | | | | |
6.25%, due 2036 | | | — | | | | 196,922 | |
| | | | | | | | |
Total | | | 675,000 | | | | 731,922 | |
Less current maturities | | | — | | | | 60,000 | |
| | | | | | | | |
Total | | $ | 675,000 | | | $ | 671,922 | |
| | | | | | | | |
Current maturities for the next five years ending October 31 and thereafter are as follows.
| | | | | |
| | | In thousands | |
| |
| 2009 | | $ | 30,000 | |
| 2010 | | | 60,000 | |
| 2011 | | | 60,000 | |
| 2012 | | | — | |
| 2013 | | | — | |
| Thereafter | | | 674,261 | |
| | | | | |
| Total | | $ | 824,261 | |
| | | | | |
We had a shelf registration statement filed with the SEC that could have been used for either the issuance of debt or equity securities that expired on December 1, 2008. The remaining balance of unused long-term financing available under this shelf registration statement was $109.4 million.
| | | | |
In thousands | | | |
2012 | | $ | — | |
2013 | | | — | |
2014 | | | 100,000 | |
2015 | | | — | |
2016 | | | 40,000 | |
Thereafter | | | 535,000 | |
| | | | |
Total | | $ | 675,000 | |
| | | | |
Payments of $.1 million and $.6 million in 2011 and $.1 million in 2008 and 2007,2010, respectively, were paid to noteholders of the 6.25% insured quarterly notes based on a redemption right upon the death of the owner of the notes, within specified limitations.
We redeemed all of the 6.25% insured quarterly notes on June 1, 2011, which had an aggregate principal balance of $196.8 million. We retired the balance of $60 million of our 6.55% medium-term notes and $60 million of our 7.8% medium-term notes in September 2011 and September 2010, respectively, as they became due.On June 6, 2011, we issued $40 million unsecured senior notes maturing in 2016 at an interest rate of 2.92% and $160 million unsecured senior notes maturing in 2021 at an interest rate of 4.24%. We used the proceeds from the sale of the senior notes to reduce our short-term borrowings used to finance the redemption of the 6.25% insured quarterly notes, as well as for other general corporate purposes and working capital needs.
On July 7, 2011, we filed with the SEC a combined debt and equity shelf registration statement that became effective on the same date. Unless otherwise specified at the time such securities are offered for sale, the net proceeds from the sale of the securities will be used 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. Pending such use, we may temporarily invest any net proceeds that are not applied to the purposes mentioned above in investment grade securities.
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
54
Piedmont Natural Gas Company, Inc.
Notes to Consolidated Financial Statements — (Continued)
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, 2008,2011, our retained earnings were not restricted becauseas the amount available for restricted payments was greater than our actual retained earnings as of this date as presented below.
| | | | | |
| | | In thousands | |
| |
| Amount available for restricted payments | | $ | 538,383 | |
| Retained earnings | | | 414,246 | |
| | | | |
In thousands | | | |
Amount available for restricted payments | | $ | 605,481 | |
Retained earnings | | | 550,584 | |
We are subject to default provisions related to our long-term debt and short-term debt. FailureSince there are cross default provisions in all of our debt agreements, 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, 2008,2011, we are in compliance with all default provisions.
| |
4. | Capital Stock and Accelerated Share Repurchase |
5. Short-Term Debt Instruments
On January 25, 2011, we replaced our existing $450 million five-year revolving syndicated credit facility with a new $650 million three-year revolving syndicated credit facility that expires in January 2014. The new facility has an option to expand up to $850 million. We pay an annual fee of $30,000 plus fifteen basis points for any unused amount up to $650 million. The facility provides a line of credit for letters of credit of $10 million, of which $3.5 million was issued and outstanding at October 31, 2011. The prior five-year revolving syndicated credit facility provided a line of credit for letters of credit of $5 million, of which $2.7 million was issued and outstanding at October 31, 2010. 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 LIBOR rate plus from 65 to 150 basis points, based on our credit ratings. Amounts borrowed remain outstanding until repaid and do not mature daily. Due to the seasonal nature of our business, amounts borrowed can vary significantly during the year.
Our outstanding short-term bank borrowings, as included in “Bank debt” in the consolidated balance sheets, were $331 million, as of October 31, 2011, under our three-year revolving syndicated credit facility and $242 million, as of October 31, 2010, under our five-year revolving syndicated credit facility, in LIBOR cost-plus loans at a weighted average interest rate of .94% in 2011 and .50% in 2010. During the twelve months ended October 31, 2011, short-term borrowings ranged from $73.5 million to $426 million, and interest rates ranged from .51% to 1.17% when borrowing. Our three-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 51% at October 31, 2011.
6. Capital Stock and Accelerated Share Repurchase
Changes in common stock for the years ended October 31, 2006, 20072011, 2010 and 20082009 are as follows.
| | | | | | | | | |
| | | Shares | | | Amount | |
| | | In thousands | |
| |
| Balance, October 31, 2005 | | | 76,698 | | | $ | 562,880 | |
| Issued to participants in the Employee Stock Purchase Plan (ESPP) | | | 36 | | | | 882 | |
| Issued to the Dividend Reinvestment and Stock Purchase Plan (DRIP) | | | 735 | | | | 17,496 | |
| Issued to participants in the Executive Long-Term Incentive Plan (LTIP) | | | 75 | | | | 1,669 | |
| Shares repurchased under Common Stock Open Market Repurchase Plan | | | (1,080 | ) | | | (25,871 | ) |
| Shares repurchased under Accelerated Share Repurchase (ASR) Plan | | | (1,000 | ) | | | (24,292 | ) |
| | | | | | | | | |
| Balance, October 31, 2006 | | | 75,464 | | | | 532,764 | |
| Issued to ESPP | | | 34 | | | | 809 | |
| Issued to DRIP | | | 593 | | | | 14,973 | |
| Issued to LTIP | | | 117 | | | | 3,264 | |
| Shares repurchased under Common Stock Open Market Repurchase Plan | | | (150 | ) | | | (3,953 | ) |
| Shares repurchased under ASR Plan | | | (1,850 | ) | | | (50,287 | ) |
| | | | | | | | | |
| Balance, October 31, 2007 | | | 74,208 | | | | 497,570 | |
| Issued to ESPP | | | 33 | | | | 838 | |
| Issued to DRIP | | | 567 | | | | 14,753 | |
| Issued to LTIP | | | 40 | | | | 1,082 | |
| Shares repurchased under Common Stock Open Market Repurchase Plan | | | (1,000 | ) | | | (26,139 | ) |
| Shares repurchased under ASR Plan | | | (602 | ) | | | (16,539 | ) |
| | | | | | | | | |
| Balance, October 31, 2008 | | | 73,246 | | | $ | 471,565 | |
| | | | | | | | | |
| | | | | | | | |
In thousands | | Shares | | | Amount | |
Balance, October 31, 2008 | | | 73,246 | | | $ | 471,565 | |
Issued to participants in the Employee Stock Purchase Plan (ESPP) | | | 37 | | | | 875 | |
Issued to the Dividend Reinvestment and Stock Purchase Plan (DRIP) | | | 565 | | | | 13,560 | |
Issued to participants in the Executive Long-Term Incentive Plan (LTIP) | | | 89 | | | | 2,755 | |
Issued to participants in the Incentive Compensation Plan (ICP) | | | 29 | | | | 671 | |
Shares repurchased under Accelerated Share Repurchase (ASR) agreement | | | (700 | ) | | | (17,857 | ) |
| | | | | | | | |
Balance, October 31, 2009 | | | 73,266 | | | | 471,569 | |
Issued to ESPP | | | 35 | | | | 899 | |
Issued to DRIP | | | 676 | | | | 17,663 | |
Issued to ICP | | | 106 | | | | 2,804 | |
Shares repurchased under ASR agreement | | | (1,800 | ) | | | (47,276 | ) |
Shares repurchased under rescission offer | | | (1 | ) | | | (19 | ) |
| | | | | | | | |
Balance, October 31, 2010 | | | 72,282 | | | | 445,640 | |
Issued to ESPP | | | 30 | | | | 870 | |
Issued to DRIP | | | 657 | | | | 18,834 | |
Issued to ICP | | | 149 | | | | 4,451 | |
Shares repurchased under ASR agreement | | | (800 | ) | | | (23,004 | ) |
| | | | | | | | |
Balance, October 31, 2011 | | | 72,318 | | | $ | 446,791 | |
| | | | | | | | |
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 and become authorized but unissued shares available for issuance under the ESPP, DRIP and LTIP.
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
55
Piedmont Natural Gas Company, Inc.
Notes to Consolidated Financial Statements — (Continued)
on that date 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 arewere referred to as our ASR program. On March 6, 2009, the Board of Directors authorized the repurchase of up to an additional four million shares under the Common Stock Open Market Purchase Program and the ASR program, and have an expiration date of December 31, 2010.
which were consolidated.On November 1, 2007,January 10, 2011, we entered into an ASR agreement. On November 2, 2007,agreement where we purchased and retired 1 million800,000 shares of our common stock from an investment bank at the closing price that day of $24.70$27.79 per share. The settlement and retirement of those shares occurred on January 11, 2011. Total consideration paid to purchase the shares of $24.8$22.2 million including $92,500 in commissions and other fees, was recorded in “Stockholders’ equity” as a reduction in “Common stock” in the consolidated balance sheets.
As part of the ASR, agreement, we simultaneously entered into a forward sale contract with the investment bank that was expected to mature in approximately 6048 trading days.days, or March 18, 2011. Under the terms of the forward sale contract, the investment bank was required to purchase, in the open market, 1 million800,000 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 registered or unregistered shares of our common stock to the investment bank if the investment bank’s weighted average purchase price, less a $.10 per
share discount, was higher than the November 2, 2007initial purchase 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 $.10 per share discount, for the shares purchased was lower than the November 2, 2007initial purchase closing price. At settlement on January 15, 2008,March 21, 2011, we paid cash of $1.3$.8 million to the investment bank and recorded this amount in “Stockholders’ equity” as a reduction inof “Common stock”Stock” in the consolidated balance sheets. The $1.3$.8 million was the difference between the investment bank’s weighted average purchase price of $26.0459$28.8551 per share less a discount of $.10 per share for a settlement price of $28.7551 per share and the November 2, 2007initial purchase closing price of $24.70$27.79 per share multiplied by 1 million800,000 shares.
As of October 31, 2008, 2.9 million2011, our shares of common stock were reserved for issuance as follows.
| | | | |
In thousands | | | |
| | In thousands | |
|
ESPP | | | 75273 | |
DRIP | | | 3291,431 | |
LTIP and ICP | | | 2,490901 | |
ICP | | | 1,171 | |
| | | | |
Total | | | 2,8943,776 | |
| | | | |
| |
5. | Financial Instruments and Related Fair Value |
On January 16, 2008,In late 2009, we increased the aggregate commitmentsdiscovered that we had inadvertently sold more shares under our syndicated five-year revolving credit facility from $350DRIP than were registered with the SEC and authorized by our Board of Directors for issuance under the DRIP as well as having an expired registration statement. To correct these issuances, our Board of Directors ratified the authorization and issuance of the excess number of shares, we filed a registration statement in November 2009 covering the sale and issuance of an additional 2.75 million shares of our common stock under our DRIP, and we filed a registration statement in February 2010, which offered to $450 million to meet working capital requirements. This facility may be increased up to $600 million and includes annual renewal options and lettersrescind the purchase of credit. We pay an annual fee of $35,000 plus six basis points for any unused amount up to $450 million. The facility provides a line of credit for letters of credit of $5 million of which $1.9 million and $1.5 million were issued and outstanding at October 31,the shares sold under the DRIP between December 1, 2008 and 2007, respectively. These lettersNovember 16, 2009 and registered all previously unregistered shares issued under the DRIP during that period. All related unauthorized shares and related proceeds received by us and the repurchase of credit are usedrescinded shares and consideration paid were immaterial. We reported these events to guarantee claims from self-insurancethe relevant regulatory authorities, including the SEC and the NCUC. We have not been subjected to enforcement actions, penalties or fines by these regulatory authorities.
7. Financial Instruments and Related Fair Value
Derivative Assets and Liabilities under Master Netting Arrangements
We maintain brokerage accounts to facilitate transactions that support our general liability policies.gas cost hedging plans. The credit facility bears interest based on the30-day LIBOR rate plus from .15%accounting guidance related to .35%,derivatives and hedging requires that we use a gross presentation, based on our credit ratings.
On October 27election, for the fair value amounts of our derivative instruments and 29, 2008, we entered into two short-term credit facilities with banks for unsecured commitments totaling $75 million expiring on December 1, 2008. On December 1, 2008, these commitments were extendedthe fair value of the right to December 3, 2008. Advances under each short-term facility bear interest at a rate based on the30-day LIBOR rate plus from .75% to 1.75%, based on our credit ratings.reclaim cash collateral. We entered into these short-term facilitiesuse long position gas purchase options to provide linessome level of credit above the senior revolving credit facility discussed above in order to have additional resources to meet seasonal cash flow requirements, including supportprotection for our gas supply
56
Piedmont Natural Gas Company, Inc.
Notes to Consolidated Financial Statements — (Continued)
procurement program as well as general corporate needs. No borrowings under these facilities were outstanding at October 31, 2008.
customers in the event of significant commodity price increases. As of October 31,
20082011 and
2007, outstanding short-term borrowings under2010, we had long gas purchase options providing total coverage of 38.1 million dekatherms and 33.5 million dekatherms, respectively. The long gas purchase options held at October 31, 2011 are for the
credit facilityperiod from December 2011 through October 2012.Fair Value Measurements
We use financial instruments to mitigate commodity price risk for our customers. We also have marketable securities that are held in a rabbi trust 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 includedset forth in “Notes payable”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, 2011 and 2010. 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, 2011 and 2010.
| | | | | | | | | | | | | | | | |
| Recurring Fair Value Measurements as of October 31, 2011 | |
In thousands | | Quoted Prices
in Active
Markets
(Level 1) | | | Significant
Other
Observable
Inputs
(Level 2) | | | Significant
Unobservable
Inputs
(Level 3) | | | Total
Carrying
Value | |
Assets: | | | | | | | | | | | | | | | | |
Derivatives held for distribution operations | | $ | 2,772 | | | $ | — | | | $ | — | | | $ | 2,772 | |
Debt and equity securities held as trading securities: | | | | | | | | | | | | | | | | |
Money markets | | | 217 | | | | — | | | | — | | | | 217 | |
Mutual funds | | | 1,274 | | | | — | | | | — | | | | 1,274 | |
| | | | | | | | | | | | | | | | |
Total fair value assets | | $ | 4,263 | | | $ | — | | | $ | — | | | $ | 4,263 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
| Recurring Fair Value Measurements as of October 31, 2010 | |
In thousands | | Quoted Prices
in Active
Markets
(Level 1) | | | Significant
Other
Observable
Inputs
(Level 2) | | | Significant
Unobservable
Inputs
(Level 3) | | | Total
Carrying
Value | |
Assets: | | | | | | | | | | | | | | | | |
Derivatives held for distribution operations | | $ | 2,819 | | | $ | — | | | $ | — | | | $ | 2,819 | |
Debt and equity securities held as trading securities: | | | | | | | | | | | | | | | | |
Money markets | | | 254 | | | | — | | | | — | | | | 254 | |
Mutual funds | | | 748 | | | | — | | | | — | | | | 748 | |
| | | | | | | | | | | | | | | | |
Total fair value assets | | $ | 3,821 | | | $ | — | | | $ | — | | | $ | 3,821 | |
| | | | | | | | | | | | | | | | |
Our 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 costs and the 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 to customers” or “Amounts due from customers” in the consolidated balance sheets were $406.5 millionsheets. These derivative instruments reflect exchange-traded derivative contracts. Exchange-traded contracts are generally based on unadjusted quoted prices in active markets and $195.5 million, respectively,are classified within Level 1.
Trading securities include assets in LIBOR cost-plus loansa rabbi trust established for our deferred compensation plans and are included in “Marketable securities, at a weighted average interest rate of 2.84% in 2008 and 4.96% in 2007. Our credit facility’s financial covenants require us to maintain a ratio of total debt to total capitalization of no greater than 70%, and our actual ratio was 58% at October 31, 2008. As of October 31, 2008, the unused committed lines of credit totaled $116.6 million.
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, 2008 and 2007, our trade accounts receivable consisted of the following.
| | | | | | | | | |
| | | 2008 | | | 2007 | |
| | | In thousands | |
| |
| Gas receivables | | $ | 81,234 | | | $ | 95,918 | |
| Merchandise and jobbing receivables | | | 2,178 | | | | 2,251 | |
| Allowance for doubtful accounts | | | (1,066 | ) | | | (544 | ) |
| | | | | | | | | |
| Trade accounts receivable | | $ | 82,346 | | | $ | 97,625 | |
| | | | | | | | | |
The carrying amountsfair value” in the consolidated balance
sheetssheets. 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.In developing the fair value of our long-term debt, we use a discounted cash and cash equivalents, restricted cash, receivables, notes payable and accounts payable approximate their fair values dueflow 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 bench mark with consideration given to the short-term nature of these financial instruments. Based on quoted market prices of similar issues having the same remaining maturities, redemption terms and credit ratings similar to our debt issuances. The carrying amount and fair value of our long-term debt, including the estimatedcurrent portion, are shown below.
| | | | | | | | |
In thousands | | Carrying
Amount | | | Fair Value | |
As of October 31, 2011 | | $ | 675,000 | | | $ | 831,323 | |
As of October 31, 2010 | | | 731,922 | | | | 890,277 | |
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 hedging instruments under derivative accounting standards. As required by the accounting guidance, the fair value amounts are presented on a gross basis and do not reflect any netting of long-term debtasset and liability amounts or cash collateral amounts under master netting arrangements.
The following table presents the fair value and balance sheet classification of our financial options for natural gas as of October 31, 20082011 and 2007, including current portion, were as follows.
| | | | | | | | | | | | | | | | | |
| | | 2008 | | | 2007 | |
| | | Carrying
| | | Fair
| | | Carrying
| | | Fair
| |
| | | Amount | | | Value | | | Amount | | | Value | |
| | | In thousands | |
| |
| Long-term debt | | $ | 824,261 | | | $ | 798,057 | | | $ | 824,887 | | | $ | 892,506 | |
The use of different market assumptions or estimation methodologies could have a material effect on the estimated fair value amounts. The fair value amounts reflect principal amounts that we will ultimately be required to pay.
2010. | | | | | | | | |
| Fair Value of Derivative Instruments | |
In thousands | | Fair Value
October 31, 2011 | | | Fair Value
October 31, 2010 | |
Derivatives Not Designated as Hedging Instruments under Derivative Accounting Standards: | | | | | | | | |
Asset Financial Instruments | | | | | | | | |
Current Assets - Gas purchase derivative assets (December 2011 - October 2012) | | $ | 2,772 | | | | | |
| | | | | | | | |
Current Assets - Gas purchase derivative assets (December 2010 - November 2011) | | | | | | $ | 2,819 | |
| | | | | | | | |
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. We structure the pricing, quantity and term provisions of our gas supply contracts to maximize flexibility and minimize cost and risk for our customers. Our risk management policies allow us to use financial instruments to hedge commodity price risks, but not for speculative trading. The strategy and objective of our hedging programs is to use these financial instruments to provide increasedsome level of protection against significant price stabilityincreases. Accordingly, the operation of the hedging programs on the regulated utility segment as a result of the use of these financial derivatives generally has no earnings impact.
The following table presents the impact that financial instruments not designated as hedging instruments under derivative accounting standards would have had on our consolidated statements of income for our customers. We have a management-level Energy Risk Management Committee that monitors compliance with our risk management policies.
In 2008, we purchased and sold financial options for natural gas for our Tennessee gas supply portfolio. As ofthe twelve months ended October 31,
2008, we had forward positions for December 2008 through March 2010. The costs2011 and 2010, absent the regulatory treatment under our approved PGA procedures. | | | | | | | | | | | | | | | | | | |
In thousands | | Amount of Loss Recognized
on Derivative Instruments | | | Amount of Loss Deferred
Under PGA Procedures | | | Location of Loss
Recognized through
PGA Procedures |
| | | Twelve Months Ended
October 31 | | | Twelve Months Ended
October 31 | | | |
| | | 2011 | | | 2010 | | | 2011 | | | 2010 | | | |
Gas purchase options | | $ | 10 | | | $ | 62,516 | | | $ | 10 | | | $ | 62,516 | | | Cost of Gas |
In Tennessee, the cost of thesegas purchase options and all other costs related to hedging activities up to 1% of total annual gas costs are approved for recovery under the terms and conditions of our TIP approved by the TRA.
In 2008, we purchased and sold financial options for natural gas for our South Carolina, gas supply portfolio. As of October 31, 2008, we had forward positions for December 2008 through October 2010. Thethe costs of thesegas purchase options are pre-approved by the PSCSC for recovery from customers subject to the terms and conditions of our gas hedging plan approved by the PSCSC.
57
Piedmont Natural Gas Company, Inc.
Notes to Consolidated Financial Statements — (Continued)
In 2008, we purchased and sold financial options for natural gas for our North Carolina, gas supply portfolio. As of October 31, 2008, we had forward positions for December 2008 through October 2010. Costscosts associated with our North Carolina hedging program are not pre-approved by the NCUC but are treated as gas costs subject to an annual cost review proceeding by the NCUC.
Current period changes in the assetsRisk 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 liabilities from thesemanage risk management activities are recorded as a component of gas costs in amounts due to customers or amounts due from customers in accordance with Statement 71. We mark the derivative instruments to marketdefined policies and procedures under an Enterprise Risk Management program. In addition, we have an Energy Price Risk Management Committee that monitors compliance with a corresponding entry to “Amounts due to customers” or “Amounts due from customers” in the consolidated balance sheets. Accordingly, there is no earnings impact of theour hedging programs, on the regulated utility segment as a result of the use of these financial derivatives. The total fair value of gas purchase options included in the consolidated balance sheets as of October 31, 2008policies and 2007 is presented as follows.
| | | | | | | | | |
| | | 2008 | | | 2007 | |
| | | In thousands | |
| |
| Current portion — gas purchase options | | $ | (19,561 | ) | | $ | 13,725 | |
| Non-current portion — gas purchase options | | | 10,257 | | | | — | |
| | | | | | | | | |
| Total | | $ | (9,304 | ) | | $ | 13,725 | |
| | | | | | | | | |
| |
6. | Commitments and Contingent Liabilities |
procedures.8. Commitments and Contingent Liabilities
Leases
We lease certain buildings, land and equipment for use in our operations under noncancelable operating leases. We account for these leases by recognizing the future minimum lease payments as expense on a straight-line basis over the respective minimum lease terms under current accounting guidance.
Operating lease payments for the years ended October 31, 2008, 20072011, 2010 and 20062009 are as follows.
| | | | | | | | | | | | | |
| | | 2008 | | | 2007 | | | 2006 | |
| | | In thousands | |
| |
| Operating lease payments | | $ | 5,483 | | | $ | 6,587 | | | $ | 7,246 | |
| | | | | | | | | | | | | | |
In thousands | | 2011 | | | 2010 | | | 2009 | |
Operating lease payments | | $ | 4,496 | | | $ | 5,303 | | | | | $ | 6,173 | |
Future minimum lease obligations for the next five years ending October 31 and thereafter are as follows.
| | | | | |
| | | In thousands | |
| |
| 2009 | | $ | 6,232 | |
| 2010 | | | 4,739 | |
| 2011 | | | 4,098 | |
| 2012 | | | 4,029 | |
| 2013 | | | 3,973 | |
| Thereafter | | | 9,870 | |
| | | | | |
| Total | | $ | 32,941 | |
| | | | | |
| | | | |
In thousands | | | |
2012 | | $ | 3,560 | |
2013 | | | 4,068 | |
2014 | | | 3,941 | |
2015 | | | 3,766 | |
2016 | | | 3,720 | |
Thereafter | | | 35,424 | |
| | | | |
Total | | $ | 54,479 | |
| | | | |
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. The time periods for pipeline and storage capacity contracts range from one to fifteentwenty-one years. The time periods for gas supply contracts range from one to fourunder two years. The time periods for the telecommunications and technology outsourcing contracts, maintenance fees for hardware and software applications, usage fees, local and
58
Piedmont Natural Gas Company, Inc.
Notes to Consolidated Financial Statements — (Continued)
long-distance costs and wireless service range from one to fourthree years. Other purchase obligations consist primarily of commitments for pipeline products, vehicles and contractors.
Certain storage and pipeline capacity contracts require the payment of demand charges that are based on rates approved by the Federal Energy Regulatory Commission (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 income as part of gas purchases and included in cost of gas.
As of October 31, 2008,2011, future unconditional purchase obligations for the next five years ending October 31 and thereafter are as follows.
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | Telecommunications
| | | | | | | |
| | | Pipeline and
| | | | | | and Information
| | | | | | | |
| | | Storage Capacity | | | Gas Supply | | | Technology | | | Other | | | Total | |
| | | In thousands | |
| |
| 2009 | | $ | 148,907 | | | $ | 23,340 | | | $ | 18,555 | | | $ | 32,093 | | | $ | 222,895 | |
| 2010 | | | 152,305 | | | | 214 | | | | 10,306 | | | | — | | | | 162,825 | |
| 2011 | | | 151,210 | | | | 119 | | | | 4,598 | | | | — | | | | 155,927 | |
| 2012 | | | 150,080 | | | | 36 | | | | 2,202 | | | | — | | | | 152,318 | |
| 2013 | | | 97,293 | | | | — | | | | — | | | | — | | | | 97,293 | |
| Thereafter | | | 407,011 | | | | — | | | | — | | | | — | | | | 407,011 | |
| | | | | | | | | | | | | | | | | | | | | |
| Total | | $ | 1,106,806 | | | $ | 23,709 | | | $ | 35,661 | | | $ | 32,093 | | | $ | 1,198,269 | |
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | |
In thousands | | Pipeline and
Storage
Capacity | | | Gas
Supply | | | Telecommunications
and Information
Technology | | | Other | | | Total | |
2012 | | $ | 151,456 | | | $ | 6,974 | | | $ | 11,055 | | | $ | 5,912 | | | $ | 175,397 | |
2013 | | | 100,637 | | | | 11 | | | | 6,855 | | | | — | | | | 107,503 | |
2014 | | | 80,603 | | | | — | | | | 6,108 | | | | — | | | | 86,711 | |
2015 | | | 73,059 | | | | — | | | | 1,958 | | | | — | | | | 75,017 | |
2016 | | | 57,154 | | | | — | | | | — | | | | — | | | | 57,154 | |
Thereafter | | | 336,767 | | | | — | | | | — | | | | — | | | | 336,767 | |
| | | | | | | | | | | | | | | | | | | | |
Total | | $ | 799,676 | | | $ | 6,985 | | | $ | 25,976 | | | $ | 5,912 | | | $ | 838,549 | |
| | | | | | | | | | | | | | | | | | | | |
Legal
We have only routine immaterial litigation in the normal course of business.
We do not expect any of these routine litigation matters to have a material effect on our financial position, results of operations or cash flows.Letters of Credit
We use letters of credit to guarantee claims from self-insurance under our general and automobile liability policies. We had $1.9$3.5 million in letters of credit that were issued and outstanding at October 31, 2008.2011. Additional information concerning letters of credit is included in Note 5 to the consolidated financial statements.
Our three regulatory commissions have authorized us to utilize deferral accounting in connection with environmental costs. Accordingly, we have established regulatory assets for actual environmental costs incurred and for estimated environmental liabilities recorded.
Several years ago,In October 1997, we entered into a settlement with a third party with respect to nine manufactured gas plant (MGP) sites that we have owned, leased or operated and paid an amount, charged to the estimated environmental liability, 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. On one of these nine properties, we performed additionalclean-up activities, including the removal of an underground storage tank, in anticipation of an impending sale.
There are threefour other MGP sites located in Hickory and Reidsville, North Carolina, Nashville, Tennessee and Anderson, South Carolina that we have owned, leased or operated. In addition to these sites, we acquired the liability for an MGPRemediation work on our Reidsville site located in Reidsville, North Carolina, in connection with the acquisition in 2002 of certain assets and liabilities of North Carolina Services, a division of NUI Utilities, Inc.
59
Piedmont Natural Gas Company, Inc.
Notes to Consolidated Financial Statements — (Continued)
As part of a voluntary agreement with theunder our North Carolina Department of Environment and Natural Resources (NCDENR)
, approved plan is scheduled to be completed in fiscal 2012.As part of a voluntary agreement with the NCDENR, we startedconducted and completed the initial stepssoil and groundwater remediation for investigating the Hickory, North Carolina MGP site. The soil and groundwater remediation report was approved by the NCDENR. We continue to conduct periodic groundwater monitoring at this site in 2007. Basedaccordance with our site remediation plan. We have incurred $1.4 million of remediation costs on a limitedthis site assessment report in 2007, we concluded that gas plant residuals remaining on the Hickory site were thought to be mostly contained within two former tar separators associated with the site’s operations. During 2008, more extensive testing was conducted and completed, including soil investigation and phase 1 of the groundwater investigation. The investigation report from these tests was submitted to the NCDENR in the first quarter of fiscal 2009. Based on the report, we have revised our estimate of the total cost to remediate the Hickory MGP site to be approximately $1 million.
During 2008, we completed the remediation of our MGP site located in Nashville at a cost of $1.4 million. through October 31, 2011.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.Conservation (TDEC). Remediation has been completed, and a consent order imposing usage restrictions on the property was approved and signed by the TDEC in June 2010. The public comment period has ended, and we continue to conduct semi-annual groundwater monitoring at the site per the final consent order. We have not yet received the Department’s determination as to whether additional steps, if any, are required for the site.
During 2008, we became awareincurred $1.5 million of and began investigating three contaminated areas at our Huntersville liquefied natural gas (LNG) facility. The first area of investigation is an area potentially contaminated with trichloroethylene, a chlorinated hydrocarbon used in degreasing operations. At the Huntersville LNG facility, trichloroethylene may have been used to clean equipment. The second area is an area in which molecular sieve was buried and potentially contaminated with hydrocarbons and trichloroethylene. The third area to be potentially remediated is an area that may contain lead contamination. The Huntersville LNG facility was originally coated with lead based paint. As a precautionary measure to ensure that no lead contamination has occurred, we plan on removing all lead based paint from the site and sampling soil around the equipment to ensure that no contamination has occurred. Our estimate of the total cost to remediate these areas is $1.1 million. In accordance with the deferral accounting authorized by our regulatory commissions, we adjusted the regulatory asset and the estimated liability for this additional amount.
As ofremediation costs through October 31, 2008, our undiscounted environmental liability totaled $4.1 million, and consisted of $2.5 million for the four MGP sites for which we retain remediation responsibility, $1.1 million for the LNG facility and $.5 million for five underground storage tanks not yet remediated. We increased the liability in 2008 by $.2 million and in 2007 by $.1 million to reflect the impact of inflation based on the consumer price index.
As of October 31, 2008, our regulatory assets for unamortized environmental costs totaled $5.8 million. The portion of the regulatory assets representing actual costs incurred, including the settlement payment to the third party, is being amortized as recovered in rates from customers.
2011.In connection with the 2003 NCNGNorth Carolina Natural Gas Corporation (NCNG) acquisition, several MGP sites owned by NCNG were transferred to a wholly owned subsidiary of Progress Energy, Inc.’s (Progress) prior to closing. Progress has complete responsibility for performing all of NCNG’s remediation obligations to conduct testing andclean-up at these sites, including both the costs of such testing andclean-up and the implementation of any affirmative remediation obligations that NCNG has related to the sites. Progress’ responsibility does not include anythird-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.
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 for the Huntersville LNG molecular sieve issue. In October 2003,September 2011, we received a letter from the NCDENR indicating their desire to enter into an Administrative Consent Order (ACO) addressing the remaining groundwater issues at the site and imposing a fine in connection with a 2003 NCNG general rate case proceeding,an amount that will be less than $100,000. We are currently negotiating the NCUC ordered an environmental regulatory liability of $3.5 million be established for refundACO. Plans to customers overinvestigate the three-year period beginning November 1, 2003. This liability resulted from a payment made to NCNG by its insurers prior to our acquisition of NCNG. As partextent of the 2005 general rate case proceeding discussed in Note 2groundwater contamination related to the consolidated financial statements,sieve burial are being developed and are tentatively scheduled to be implemented in the NCUC orderedfirst quarter of our fiscal year 2012. The Huntersville LNG facility also was originally coated with lead-based paint. As a new three-year amortization periodprecautionary measure to ensure that no lead contamination occurs, removal of lead-based paint from the site was initiated in spring 2010. We have incurred $3.2 million to remediate the Huntersville LNG site through October 31, 2011. Additional facilities at our Huntersville LNG plant site are being evaluated for lead-based paint removal with work tentatively scheduled for our fiscal year 2012.
During the unamortized balance as of June 30, 2005, beginning November 1, 2005.twelve months ended October 31, 2011, we assessed the cost to remove lead-based paint at our Nashville LNG facility. As of October 31, 2008,2011, our estimate of the total cost to remediate the property is $.5 million, and we have incurred $.4 million through October 31, 2011. This work is scheduled to be completed in our fiscal year 2012.
We are transitioning away from owning and maintaining our own petroleum underground storage tanks (USTs). Our Charlotte, North Carolina district continues to operate USTs. During 2011, our Greenville, South Carolina and Greensboro and Salisbury, North Carolina districts had their USTs removed, and we do not anticipate significant environmental remediation with respect to the removal process. As of October 31, 2011, our estimated undiscounted environmental liability was completely amortized.
60for USTs for which we retain remediation responsibility is $.3 million.
Piedmont Natural Gas Company, Inc.
Notes to Consolidated Financial Statements — (Continued)
In July 2005, we were notified by the NCDENR that we were named as a potentially responsible party for alleged environmental issues associated with an underground storage tankUST 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 contractually transferred anyclean-up costs to the new owner of the site when we sold this venture in June 1988. Our current estimate of the cost to remediate the site is approximately $136,400.$144,540. It is unclear how many of the former owners may ultimately be held liable for this site; however, based on the uncertainty of the ultimate liability, we established a non-regulated environmental liabilitiesliability for $34,100,$36,135, one-fourth of the estimated cost.
One of our operating districts has coatings containing asbestos on some of their pipelines. We have educated our employees on the hazards of asbestos and implemented procedures for removing these coatings from our pipelines when we must excavate and expose small portions of the pipeline. Lead-based paint is being removed at multiple LNG facilities that we own. Employees have been trained on the hazards of lead exposure, and we have engaged independent environmental contractors to remove and dispose of the lead-based paint at these facilities.
As of October 31, 2011, our estimated undiscounted environmental liability totaled $2.8 million, and consisted of $1.5 million for the MGP sites for which we retain remediation responsibility, $1 million for the LNG facilities and $.3 million for USTs not yet remediated.
As of October 31, 2011, our regulatory assets for unamortized environmental costs totaled $9.6 million. We sought recovery of $2 million in the pending Tennessee rate case. We will seek recovery of the remaining balance in future rate proceedings.
Further evaluation of the MGP, LNG and UST sites and the underground storage tank sitesremoval of lead-based paint could significantly affect recorded amounts; however, we believe that the ultimate resolution of these matters will not have a material adverse effect on our financial position, cash flows or results of operations.
During 2008, through the normal course of an on-going business review, one of our operating districts was found to have coatings on their pipes containing asbestos. We have taken action to educate employees on the hazards of asbestos and to implement procedures for removing these coatings from our pipelines when we must excavate and expose small portions of the pipeline. We continue to determine the impacts and related costs to us, if any, and the impact to employees and contractors, if any.
Other
We have been in discussions with FERC’s Office of Enforcement (OE) regarding certain instances of possible non-compliance with FERC’s capacity release regulations regarding posting and bidding requirements for short-term releases. We have provided relevant information to FERC OE Staff and are cooperating with FERC in its investigation. We are continuing to meet with FERC’s OE staff to resolve this matter. We are unable to predict the outcome of the investigation at this time; however, we do not believe this matter will have a material effect on our earnings.
| |
7. | Employee Benefit Plans |
operations or cash flows.9. Employee Benefit Plans
Effective January 1, 2008, we amended our noncontributory defined benefit pension plan, other postretirement employee benefits (OPEB) plan and our defined contribution401(k) plans. These amendments applyapplied to nonunion employees and employees covered by the Carolinas bargaining unit contract. Effective January 1, 2009, these same amendments will applyapplied to all employees, including those covered by the Nashville, Tennessee bargaining unit contract.
Under GAAP, we are required to recognize all obligations related to defined benefit pension and OPEB plans and quantify the plans’ funding status as an asset or liability on our 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 under the authoritative guidance; 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 OBEB costs. Our plans’ assets are required to be accounted for at fair value. 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.
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 ofthat an eligible full-time employees.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 the12-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. Effective January 1, 2008, the defined benefitqualified pension plan was amended for all employees not covered by the bargaining unit contract in Nashville, Tennessee to close the plan to employees hired after December 31, 2007 and to modify how benefits are accrued in the future for existing employees. Employees hired prior to January 1, 2008 will continue to participate in the amended traditional defined benefitqualified pension plan. The amendment does not affect any pension benefit earned as of December 31, 2007. For service earnedEmployees are vested after December 31, 2007, a consistent rate will be applied to each year of service so that employees accrue benefits more evenly. For service earned prior to January 1, 2008, the rate used in the formula to calculate an employee’s pension benefit is greater for the first twentyfive years of service than it is for the next fifteen years of service. Employeesand can be credited with up to a total of 35 years of service. When ana vested employee leaves the company, his benefit payment will be calculated as the greater of the accrued benefit as of December 31, 2007
61
Piedmont Natural Gas Company, Inc.
Notes to Consolidated Financial Statements — (Continued)
under the old formula plus the accrued benefit under the new formula for years of service after December 31, 2007, or the benefit for all years of service up to 35 years under the new formula. These amendments
will bewere effective on January 1, 2009 for employees covered by the bargaining unit contract in Nashville, Tennessee.
The investment objectives of the qualified pension plan are oriented to meet both the current ongoing and future commitments to the participants and designed to grow at an acceptable rate of return for the risks permitted under the investment policy guidelines. Assets are structured to provide for both short-term and long-term needs and to meet the objectives of the qualified pension plan as specified by the Benefits Committee of the Board of Directors.
Our primary investment objective of the qualified pension plan is to generate sufficient assets to meet plan liabilities. The plan’s assets will therefore be invested to maximize long-term returns in a manner that is consistent with the plan’s liabilities, cash flow requirements and risk tolerance. The plan’s liabilities are defined in terms of participant salaries. Given the nature of these liabilities and recognizing the long-term benefits of investing in return-generating assets, the qualified pension plan seeks to invest in a diversified portfolio to:
Achieve full funding over the longer term, and
Control year-to-year fluctuations in pension expense that is created by asset and liability volatility.
We consider the historical long-term return experience of our assets, the current and targeted allocation of our plan assets and the expected long-term rates of return. Investment advisors assist us in deriving expected long-term rates of return. These rates are generally based on a 20-year horizon for various asset classes, our expected investments of plan assets and active asset management instead of a passive investment strategy of an index fund.
The investment philosophy of the qualified pension plan is to maintain a balanced portfolio which is diversified across asset classes. The portfolio is primarily composed of equity and fixed income investments in order to provide diversification as to issuers, economic sectors, markets and investment instruments. Risk and quality are viewed in the context of the diversification requirements of the aggregate portfolio. We measure and monitor investment risk on an ongoing basis through quarterly investment portfolio reviews, annual liability measurements and periodic asset/liability studies. We do not have a concentration of assets in a single entity, industry, country, commodity or class of investment fund.
The qualified pension plan maintains a 45% target allocation to fixed income securities, including U.S. treasuries, corporate bonds, high yield bonds, asset-backed securities and derivatives. The derivatives must be fully collateralized so that they either hedge an existing position or there is a cash position for an equivalent value of the underlying principal. No leveraged position greater than 10% within the fixed income portfolio can be taken with derivatives, and the aggregate risk exposure of the plan can be no greater than that which could be achieved without using derivatives. The qualified pension plan maintains a 35% target allocation to equities, including exposure to large cap growth, large cap value and small cap domestic equity securities, as well as exposure to international equity. There is a 5% target allocation to real estate in a diversified global real estate investment trust (REIT) fund. The remaining 15% target allocation is for investments in other types of funds, including commodities, hedge funds and private equity funds that follow several diversified strategies.
Employees hired or rehired after December 31, 2007 (or December 31, 2008 for employees covered by the bargaining unit contract in Nashville, Tennessee) will notcannot participate in the amended traditional pension plan but will beare participants in the new Money Purchase Pension (MPP) plan, a defined contribution pension plan that allows the employee to direct the investments. Full-timeinvestments 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 will annually deposit a percentage of each participant’s pay into an account of the MPP plan. This contribution will be equal toequals 4% of the participant’s compensation plus an additional 4% of compensation above the social security wage base.base up to the Internal Revenue Service (IRS) compensation limit. The participant becomesis vested in this plan after three years of service.
During the year ended October 31, 2011, we contributed $.3 million to the MPP plan.OPEB Plan
We provide certain postretirement health care and life insurance benefits to eligible retirees. The liability associated with such benefits is funded in irrevocable trust funds that can only be used to pay the benefits. Employees are first eligible to retire and receive these benefits at age 55 with ten or more years of service after the age of 45. Employees who met this requirement in 1993 or who retired prior to 1993 are in a “grandfathered” group for whom we pay the full cost of the retiree’s coverage and the retiree pays the full cost of dependent coverage. Retirees not in the grandfathered group have 80% of the cost of retiree coverage paid by us, subject to certain annual contribution limits. Retirees are responsible for the full cost of dependent coverage. Effective January 1, 2008 (January 1, 2009 for new employees covered under the bargaining unit contract in Nashville, Tennessee), new employees have to complete ten years of service after age 50 to be eligible for benefits, and no benefits will beare provided to those employees after age 65 when they are automatically eligible for Medicare benefits to
cover health costs.
In connection with the September 2003 acquisition of NCNG, we acquired certain pension and Our OPEB obligations of former employees of NCNG. The accrued pension benefits for this group were placed in a separate “frozen” plan at this date. The transferred active pension plan participants began accruing benefits under the Piedmont pension plan as of October 1, 2003. There were no assets attributable to the OPEB liability transferred from Progress. We merged the “frozen” qualified NCNG pension plan with the Piedmont pension plan as of December 31, 2006.
As a result of the Medicare Prescription Drug Improvement and Modernization Act of 2003, we amended our postretirement benefit plan in August 2005 to eliminate prescription drug coverage beginning January 1, 2006 for retirees who are Medicare eligible. This prescription drug benefit was replaced byincludes a defined dollar benefit to pay the premiums for Medicare Part D.
Employees who meet the eligibility requirements to retire also receive a life insurance benefit. For employees who retire after July 1, 2005, this benefit is $15,000. The life insurance amount for employees who retired prior to this date was calculated as a percentage of their basic life insurance prior to retirement.OPEB plan assets are comprised of mutual funds within a 401(h) and Voluntary Employees’ Beneficiary Association trusts. The investment philosophy is the same as the qualified pension plan as discussed above. We target an OPEB allocation of 45% to fixed income securities, including U.S. treasuries, corporate bonds, high yield bonds and asset-backed securities. The OPEB plan maintains a 47% target allocation to equities, which includes exposure to large cap growth, large cap value and small cap domestic equity, as well as exposure to international equity. The OPEB plan maintains a 5% target allocation to real estate in a diversified global REIT fund and a 3% target allocation to cash. We do not have a concentration of assets in a single entity, industry, country, commodity or class of investment fund.
Supplemental Executive Retirement Plans
We have pension liabilities related to supplemental executive retirement plans (SERPs) for certain former employees, non-employee directors or the surviving spouse. There are no assets related to thethese SERPs, and no additional benefits accrue to the participants. Payments to the participants are made from operating funds during the year. These nonqualified plans are presented below.
On September 4, 2008, the Compensation Committee of our Board of Directors terminated a former SERP effective October 31, 2008. The supplemental retirement benefit was replaced with a non-qualified defined contribution restoration plan (DCR plan), effective January 1, 2009. Benefits payable under the new plan are informally funded 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 executive. An additional one-time contribution was made for all eligible officers in January 2009 equal to the greater of:
13% of base salary paid in November 2008 and December 2008 (to the extent that calendar year-to-date base salary exceeded the 2008 annual limit), or
Two monthly premiums (without adjustment for taxes) under the former SERP.
In addition, an opening balance that totaled $.3 million was established for four Vice Presidents to compensate them for the loss of future benefits under the new plan. Participants may not contribute to the DCR plan. Vesting under the DCR plan is five-year cliff vesting, including service prior to adoption, of annual company contributions, and prospective five-year cliff vesting for the opening balances of the four Vice Presidents. If the officer severs employment before the expiration of the relevant five-year period, he or she receives nothing from that portion of the DCR plan. 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. The insurance portion of the SERP benefit was maintained in the form of new term life insurance as discussed below.
Also on September 4, 2008, the Compensation Committee of our Board of Directors approved a voluntary deferred compensation plan, effective January 1, 2009, for the benefit of all officers and director-level employees. Benefits under this plan, known as the Voluntary Deferral Plan, are also haveinformally funded through a SERP covering allrabbi trust with a bank as the trustee. There are no company contributions to the Voluntary Deferral Plan. Participants may defer up to 50% of base salary with elections made by December 31 prior to the upcoming calendar year, and up to 95% of annual incentive pay with elections made by April 30. Vesting is immediate and deferrals are held in the rabbi trust. Participants may provide instructions to us for the deemed investment of their plan accounts. Distributions can be made from the Voluntary Deferral Plan on a specified date that is at least two years from the date of deferral, on separation of service or upon death.
The funding to the DCR plan accounts for the years ended October 31, 2011 and 2010, and the amounts recorded as liabilities for these deferred compensation plans as of October 31, 2011 and 2010 are presented below.
| | | | | | | | |
In thousands | | 2011 | | | 2010 | |
Funding | | $ | 352 | | | $ | 444 | |
Liability: | | | | | | | | |
Current | | | 52 | | | | 5 | |
Noncurrent | | | 1,766 | | | | 1,293 | |
We provide term life insurance policies for officers at the vice president level and above. It provides supplemental retirement income for officers whose benefits underabove who were participants in the Company’s qualified retirement plan are limited by tax code provisions. Theformer SERP that terminated on October 31, 2008; the level of the insurance benefit and target retirement income benefits intended to be provided under the SERP dependis dependent upon the position of the officer. The SERP is funded byThese life insurance policies covering each officer, and the policy isare owned exclusively by each officer. Premiums on these policies are paid and expensed, by us, as grossed up for taxes to the individual officer,officer. Beginning on December 1, 2008, we provide a term life insurance benefit equal to $200,000 to all officers and director-level employees for which we bear the years ended October 31, 2008, 2007 and 2006 arecost of the policies. The cost of these premiums is presented below.
| | | | | | | | | | | | | |
| | | 2008 | | | 2007 | | | 2006 | |
| | | In thousands | |
| |
| SERP premiums | | $ | 446 | | | $ | 455 | | | $ | 709 | |
62
| | | | | | | | | | | | |
In thousands | | 2011 | | | 2010 | | | 2009 | |
Term life policies of former SERP officers | | $ | 56 | | | $ | 57 | | | $ | 59 | |
Officers and director-level employees | | | 24 | | | | 24 | | | | 20 | |
Actuarial Plan Information
Piedmont Natural Gas Company, Inc.
Notes to Consolidated Financial Statements — (Continued)
A reconciliation of changes in the plans’ benefit obligations and fair value of assets for the years ended October 31, 20082011 and 2007,2010, and a statement of the funded status and the amounts reflected in the consolidated balance sheets for the years ended October 31, 20082011 and 20072010 are presented below.
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Qualified Pension | | | Nonqualified Pension | | | Other Benefits | |
| | | 2008 | | | 2007 | | | 2008 | | | 2007 | | | 2008 | | | 2007 | |
| | | In thousands | |
| |
| Accumulated benefit obligation at year end | | $ | 135,516 | | | $ | 169,367 | | | $ | 4,194 | | | $ | 4,845 | | | | N/A | | | | N/A | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Change in benefit obligation: | | | | | | | | | | | | | | | | | | | | | | | | |
| Obligation at beginning of year | | $ | 188,698 | | | $ | 236,329 | | | $ | 4,845 | | | $ | 4,342 | | | $ | 33,612 | | | $ | 34,252 | |
| Adjustment to reflect prior obligation | | | — | | | | — | | | | — | | | | 857 | | | | — | | | | — | |
| Service cost | | | 7,634 | | | | 11,142 | | | | 27 | | | | 60 | | | | 1,250 | | | | 1,324 | |
| Interest cost | | | 11,408 | | | | 12,926 | | | | 277 | | | | 276 | | | | 2,011 | | | | 1,886 | |
| Plan amendments | | | (4,133 | ) | | | (29,795 | ) | | | 127 | | | | — | | | | — | | | | — | |
| Actuarial gain | | | (43,208 | ) | | | (14,844 | ) | | | (532 | ) | | | (95 | ) | | | (5,895 | ) | | | (778 | ) |
| Benefit payments | | | (16,939 | ) | | | (27,060 | ) | | | (550 | ) | | | (595 | ) | | | (2,866 | ) | | | (3,072 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Obligation at end of year | | $ | 143,460 | | | $ | 188,698 | | | $ | 4,194 | | | $ | 4,845 | | | $ | 28,112 | | | $ | 33,612 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Change in fair value of plan assets: | | | | | | | | | | | | | | | | | | | | | | | | |
| Fair value at beginning of year | | $ | 224,954 | | | $ | 211,926 | | | $ | — | | | $ | — | | | $ | 20,435 | | | $ | 16,800 | |
| Actual return on plan assets | | | (68,351 | ) | | | 24,045 | | | | — | | | | — | | | | (5,671 | ) | | | 1,169 | |
| Employer contributions | | | 11,000 | | | | 16,500 | | | | 550 | | | | 595 | | | | 3,624 | | | | 5,538 | |
| Administrative expenses | | | (407 | ) | | | (457 | ) | | | — | | | | — | | | | — | | | | — | |
| Benefit payments | | | (16,939 | ) | | | (27,060 | ) | | | (550 | ) | | | (595 | ) | | | (2,866 | ) | | | (3,072 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Fair value at end of year | | $ | 150,257 | | | $ | 224,954 | | | $ | — | | | $ | — | | | $ | 15,522 | | | $ | 20,435 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Noncurrent assets | | $ | 6,797 | | | $ | 36,256 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | |
| Current liabilities | | | — | | | | — | | | | (528 | ) | | | (553 | ) | | | — | | | | — | |
| Noncurrent liabilities | | | — | | | | — | | | | (3,666 | ) | | | (4,292 | ) | | | (12,591 | ) | | | (13,177 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Net amount recognized | | $ | 6,797 | | | $ | 36,256 | | | $ | (4,194 | ) | | $ | (4,845 | ) | | $ | (12,591 | ) | | $ | (13,177 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Amounts Not Yet Recognized as a Component of Cost and Recognized as Regulatory Asset or Liability(1): | | | | | | | | | | | | | | | | | | | | | | | | |
| Unrecognized transition obligation | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | (3,335 | ) | | $ | (4,002 | ) |
| Unrecognized prior service (cost) credit | | | 28,231 | | | | 25,991 | | | | (127 | ) | | | — | | | | — | | | | — | |
| Unrecognized actuarial gain (loss) | | | (54,616 | ) | | | (12,170 | ) | | | 498 | | | | (34 | ) | | | 989 | | | | 2,227 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Regulatory (asset) liability | | | (26,385 | ) | | | 13,821 | | | | 371 | (3) | | | (34 | )(2) | | | (2,346 | ) | | | (1,775 | ) |
| Cumulative employer contribution in excess of cost | | | 33,182 | | | | 22,435 | | | | (4,565 | ) | | | (4,811 | ) | | | (10,245 | ) | | | (11,402 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Net amount recognized | | $ | 6,797 | | | $ | 36,256 | | | $ | (4,194 | ) | | $ | (4,845 | ) | | $ | (12,591 | ) | | $ | (13,177 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | |
(1) | | As the future recovery of pension and OPEB costs is probable, we were granted permission to record the amount that would have been recorded in accumulated OCI as a regulatory asset or liability. |
|
(2) | | Amount is composed of a regulatory asset of $89 and a regulatory liability of $55. |
|
(3) | | Amount is composed of a regulatory asset of $2 and a regulatory liability of $373. |
63
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | Qualified Pension | | | Nonqualified Pension | | | Other Benefits | |
In thousands | | 2011 | | | 2010 | | | 2011 | | | 2010 | | | 2011 | | | 2010 | |
Accumulated benefit obligation at year end | | $ | 205,159 | | | $ | 182,822 | | | $ | 5,219 | | | $ | 5,039 | | | | N/A | | | | N/A | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Change in projected benefit obligation: | | | | | | | | | | | | | | | | | | | | | | | | |
Obligation at beginning of year | | $ | 211,003 | | | $ | 195,329 | | | $ | 5,039 | | | $ | 4,828 | | | $ | 31,919 | | | $ | 35,523 | |
Service cost | | | 8,508 | | | | 8,069 | | | | 45 | | | | 38 | | | | 1,398 | | | | 1,337 | |
Interest cost | | | 11,024 | | | | 10,898 | | | | 209 | | | | 243 | | | | 1,495 | | | | 1,906 | |
Plan amendments | | | — | | | | — | | | | 290 | | | | — | | | | — | | | | — | |
Actuarial (gain) loss | | | 16,896 | | | | 7,549 | | | | 130 | | | | 420 | | | | (327 | ) | | | (3,769 | ) |
Participant contributions | | | — | | | | — | | | | — | | | | — | | | | 898 | | | | 883 | |
Administrative expenses | | | (391 | ) | | | (306 | ) | | | — | | | | — | | | | — | | | | — | |
Benefit payments | | | (10,408 | ) | | | (10,536 | ) | | | (494 | ) | | | (490 | ) | | | (3,483 | ) | | | (3,961 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | |
Obligation at end of year | | $ | 236,632 | | | $ | 211,003 | | | $ | 5,219 | | | $ | 5,039 | | | $ | 31,900 | | | $ | 31,919 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Change in fair value of plan assets: | | | | | | | | | | | | | | | | | | | | | | | | |
Fair value at beginning of year | | $ | 228,345 | | | $ | 184,277 | | | $ | — | | | $ | — | | | $ | 21,636 | | | $ | 19,278 | |
Actual return on plan assets | | | 19,965 | | | | 32,910 | | | | — | | | | — | | | | 792 | | | | 2,841 | |
Employer contributions | | | 22,000 | | | | 22,000 | | | | 494 | | | | 490 | | | | 2,202 | | | | 2,595 | |
Participant contributions | | | — | | | | — | | | | — | | | | — | | | | 898 | | | | 883 | |
Administrative expenses | | | (391 | ) | | | (306 | ) | | | — | | | | — | | | | — | | | | — | |
Benefit payments | | | (10,408 | ) | | | (10,536 | ) | | | (494 | ) | | | (490 | ) | | | (3,483 | ) | | | (3,961 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | |
Fair value at end of year | | $ | 259,511 | | | $ | 228,345 | | | $ | — | | | $ | — | | | $ | 22,045 | | | $ | 21,636 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Noncurrent assets | | $ | 22,879 | | | $ | 17,342 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | |
Current liabilities | | | — | | | | — | | | | (517 | ) | | | (517 | ) | | | — | | | | — | |
Noncurrent liabilities | | | — | | | | — | | | | (4,702 | ) | | | (4,522 | ) | | | (9,855 | ) | | | (10,283 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | |
Net amount recognized | | $ | 22,879 | | | $ | 17,342 | | | $ | (5,219 | ) | | $ | (5,039 | ) | | $ | (9,855 | ) | | $ | (10,283 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | |
Amounts Not Yet Recognized as a Component of Cost and Recognized in a Deferred | | | | | | | | | | | | | | | | | | | | | | | | |
Regulatory Account: | | | | | | | | | | | | | | | | | | | | | | | | |
Unrecognized transition obligation | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | (1,334 | ) | | $ | (2,001 | ) |
Unrecognized prior service (cost) credit | | | 21,638 | | | | 23,836 | | | | (358 | ) | | | (88 | ) | | | — | | | | — | |
Unrecognized actuarial loss | | | (99,653 | ) | | | (85,661 | ) | | | (941 | ) | | | (852 | ) | | | (424 | ) | | | (9 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | |
Regulatory asset | | | (78,015 | ) | | | (61,825 | ) | | | (1,299 | ) | | | (940 | ) | | | (1,758 | ) | | | (2,010 | ) |
Cumulative employer contribution in excess of cost | | | 100,894 | | | | 79,167 | | | | (3,920 | ) | | | (4,099 | ) | | | (8,097 | ) | | | (8,273 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | |
Net amount recognized | | $ | 22,879 | | | $ | 17,342 | | | $ | (5,219 | ) | | $ | (5,039 | ) | | $ | (9,855 | ) | | $ | (10,283 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | |
In 2006 with the implementation of accounting guidance for employers’ accounting for defined benefit pension and other postretirement plans, the NCUC, the PSCSC and the TRA approved our request to place certain defined benefit postretirement obligations in a deferred regulatory account instead of OCI as presented above. The regulators have allowed future recovery of our pension and OPEB costs to this date.
Piedmont Natural Gas Company, Inc.
Notes to Consolidated Financial Statements — (Continued)
Net periodic benefit cost for the years ended October 31, 2008, 20072011, 2010 and 20062009 includes the following components.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Qualified Pension | | | Nonqualified Pension | | | Other Benefits | |
| | | 2008 | | | 2007 | | | 2006 | | | 2008 | | | 2007 | | | 2006 | | | 2008 | | | 2007 | | | 2006 | |
| | | In thousands | |
| |
| Service cost | | $ | 7,634 | | | $ | 11,142 | | | $ | 10,972 | | | $ | 27 | | | $ | 60 | | | $ | 66 | | | $ | 1,250 | | | $ | 1,324 | | | $ | 1,134 | |
| Interest cost | | | 11,408 | | | | 12,926 | | | | 13,436 | | | | 277 | | | | 276 | | | | 239 | | | | 2,011 | | | | 1,886 | | | | 1,747 | |
| Expected return on plan assets | | | (16,895 | ) | | | (17,013 | ) | | | (17,112 | ) | | | — | | | | — | | | | — | | | | (1,461 | ) | | | (1,273 | ) | | | (1,151 | ) |
| Amortization of transition obligation | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | 667 | | | | 667 | | | | 667 | |
| Amortization of prior service cost | | | (1,893 | ) | | | 590 | | | | 933 | | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | |
| Amortization of actuarial loss (gain) | | | — | | | | 1,027 | | �� | | 604 | | | | — | | | | — | | | | — | | | | — | | | | — | | | | (218 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Net periodic benefit cost | | | 254 | | | | 8,672 | | | | 8,833 | | | | 304 | | | | 336 | | | | 305 | | | | 2,467 | | | | 2,604 | | | | 2,179 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Other changes in plan assets and benefit obligation recognized through regulatory asset or liability: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Prior service cost (credit) | | | (4,133 | ) | | | N/A | | | | N/A | | | | 127 | | | | N/A | | | | N/A | | | | — | | | | N/A | | | | N/A | |
| Net loss (gain) | | | 42,446 | | | | N/A | | | | N/A | | | | (532 | ) | | | N/A | | | | N/A | | | | 1,237 | | | | N/A | | | | N/A | |
| Amounts recognized as a component of net periodic benefit cost: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Transition obligation | | | — | | | | N/A | | | | N/A | | | | — | | | | N/A | | | | N/A | | | | (667 | ) | | | N/A | | | | N/A | |
| Prior service credit | | | 1,893 | | | | N/A | | | | N/A | | | | — | | | | N/A | | | | N/A | | | | — | | | | N/A | | | | N/A | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Total recognized in regulatory asset (liability) | | | 40,206 | | | | — | | | | — | | | | (405 | ) | | | — | | | | — | | | | 570 | | | | — | | | | — | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Total recognized in net periodic benefit cost and regulatory asset (liability) | | $ | 40,460 | | | $ | 8,672 | | | $ | 8,833 | | | $ | (101 | ) | | $ | 336 | | | $ | 305 | | | $ | 3,037 | | | $ | 2,604 | | | $ | 2,179 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Qualified Pension | | | Nonqualified Pension | | | Other Benefits | |
In thousands | | 2011 | | | 2010 | | | 2009 | | | 2011 | | | 2010 | | | 2009 | | | 2011 | | | 2010 | | | 2009 | |
Service cost | | $ | 8,508 | | | $ | 8,069 | | | $ | 5,733 | | | $ | 45 | | | $ | 38 | | | $ | 25 | | | $ | 1,398 | | | $ | 1,337 | | | $ | 885 | |
Interest cost | | | 11,024 | | | | 10,898 | | | | 11,240 | | | | 209 | | | | 243 | | | | 325 | | | | 1,495 | | | | 1,906 | | | | 2,267 | |
Expected return on plan assets | | | (20,608 | ) | | | (18,773 | ) | | | (16,755 | ) | | | — | | | | — | | | | — | | | | (1,534 | ) | | | (1,381 | ) | | | (1,104 | ) |
Amortization of transition obligation | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | 667 | | | | 667 | | | | 667 | |
Amortization of prior service cost (credit) | | | (2,198 | ) | | | (2,198 | ) | | | (2,198 | ) | | | 20 | | | | 20 | | | | 20 | | | | — | | | | — | | | | — | |
Amortization of actuarial loss (gain) | | | 3,547 | | | | 1,998 | | | | — | | | | 41 | | | | 9 | | | | (20 | ) | | | — | | | | 236 | | | | — | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Net periodic benefit (income) cost | | | 273 | | | | (6 | ) | | | (1,980 | ) | | | 315 | | | | 310 | | | | 350 | | | | 2,026 | | | | 2,765 | | | | 2,715 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Other changes in plan assets and benefit obligation recognized through regulatory asset or liability: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Prior service cost | | | — | | | | — | | | | — | | | | 290 | | | | — | | | | — | | | | — | | | | — | | | | — | |
Net loss (gain) | | | 17,539 | | | | (6,587 | ) | | | 39,631 | | | | 130 | | | | 420 | | | | 923 | | | | 415 | | | | (5,229 | ) | | | 6,464 | |
Amounts recognized as a component of net periodic benefit cost: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Transition obligation | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | (667 | ) | | | (667 | ) | | | (667 | ) |
Amortization of net (loss) gain | | | (3,547 | ) | | | (1,998 | ) | | | — | | | | (41 | ) | | | (9 | ) | | | 20 | | | | — | | | | (236 | ) | | | — | |
Prior service (cost) credit | | | 2,198 | | | | 2,198 | | | | 2,198 | | | | (20 | ) | | | (20 | ) | | | (20 | ) | | | — | | | | — | | | | — | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Total recognized in regulatory asset (liability) | | | 16,190 | | | | (6,387 | ) | | | 41,829 | | | | 359 | | | | 391 | | | | 923 | | | | (252 | ) | | | (6,132 | ) | | | 5,797 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Total recognized in net periodic benefit cost and regulatory asset (liability) | | $ | 16,463 | | | $ | (6,393 | ) | | $ | 39,849 | | | $ | 674 | | | $ | 701 | | | $ | 1,273 | | | $ | 1,774 | | | $ | (3,367 | ) | | $ | 8,512 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
The 20092012 estimated amortization of the following items, thatwhich are recorded inas a regulatory asset or liability instead of accumulated OCI discussed above, and expected refunds for our plans are as follows.
| | | | | | | | | | | | | |
| | | Qualified
| | | Nonqualified
| | | Other
| |
| | | Pension | | | Pension | | | Benefits | |
| | | In thousands | |
| |
| Amortization of transition obligation | | $ | — | | | $ | — | | | $ | 667 | |
| Amortization of unrecognized prior service credit | | | (2,198 | ) | | | 20 | | | | — | |
| Amortization of unrecognized actuarial loss | | | — | | | | (20 | ) | | | — | |
| Refunds expected | | | (2,198 | ) | | | — | | | | 667 | |
In addition, equity | | | | | | | | | | | | |
In thousands | | Qualified Pension | | | Nonqualified Pension | | | Other Benefits | |
Amortization of transition obligation | | $ | — | | | $ | — | | | $ | 667 | |
Amortization of unrecognized prior service cost (credit) | | | (2,198 | ) | | | 81 | | | | — | |
Amortization of unrecognized actuarial loss | | | 5,478 | | | | 49 | | | | — | |
Refunds expected | | | 3,280 | | | | 130 | | | | 667 | |
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 Moody’s Investors Service’s AA or better-rated non-callable bonds that produces similar results to a hypothetical bond portfolio. The discount rate can vary from plan year to plan year. As of October 31, 2011, the benchmark by plan was as follows.
| | | | |
Pension plan | | | 4.67 | % |
NCNG SERP | | | 4.01 | % |
Directors’ SERP | | | 4.26 | % |
Piedmont SERP | | | 3.50 | % |
OPEB | | | 4.36 | % |
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.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. The discount rate can vary from plan year to plan year. October 31 is the measurement date for the plans.
64
Piedmont Natural Gas Company, Inc.
Notes to Consolidated Financial Statements — (Continued)
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 Moody’s Investors Service’s AA or better-rated non-callable bonds that produces similar results to a hypothetical bond portfolio. As of October 31, 2008, the benchmark by plan was as follows.
| | | | |
Pension plan | | | 8.15 | % |
NCNG SERP | | | 8.45 | % |
Directors’ SERP | | | 8.56 | % |
Piedmont SERP | | | 8.23 | % |
Tennessee SERP | | | 8.07 | % |
OPEB | | | 8.50 | % |
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 method of amortization in all cases is straight-line.
The weighted average assumptions used in the measurement of the benefit obligation as of October 31, 20082011 and 20072010 are presented below.
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | Other
| |
| | | Qualified Pension | | | Nonqualified Pension | | | Benefits | |
| | | 2008 | | | 2007 | | | 2008 | | | 2007 | | | 2008 | | | 2007 | |
| |
| Discount rate | | | 8.15 | % | | | 6.43 | % | | | 8.46 | % | | | 6.06 | % | | | 8.50 | % | | | 6.25 | % |
| Rate of compensation increase | | | 3.97 | % | | | 3.99 | % | | | N/A | | | | N/A | | | | N/A | | | | N/A | |
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | Qualified Pension | | | Nonqualified Pension | | | Other Benefits | |
| | | 2011 | | | 2010 | | | 2011 | | | 2010 | | | 2011 | | | 2010 | |
Discount rate | | | 4.67 | % | | | 5.47 | % | | | 4.10 | % | | | 4.37 | % | | | 4.36 | % | | | 4.85 | % |
Rate of compensation increase | | | 3.78 | % | | | 3.87 | % | | | N/A | | | | N/A | | | | N/A | | | | N/A | |
The weighted average assumptions used to determine the net periodic benefit cost as of October 31, 2008, 20072011, 2010 and 20062009 are presented below.
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Qualified Pension | | | Nonqualified Pension | |
| | | 2008 | | | 2007 | | | 2006 | | | 2008 | | | 2007 | | | 2006 | |
| |
| Discount rate | | | 6.43 | % | | | 5.78 | % | | | 6.00 | % | | | 6.06 | % | | | 5.67 | % | | | 5.75 | % |
| Expected long-term rate of return on plan assets | | | 8.00 | % | | | 8.50 | % | | | 8.50 | % | | | N/A | | | | N/A | | | | N/A | |
| Rate of compensation increase | | | 3.99 | % | | | 4.01 | % | | | 4.05 | % | | | N/A | | | | N/A | | | | N/A | |
| | | | | | | | | | | | | |
| | | Other Benefits | |
| | | 2008 | | | 2007 | | | 2006 | |
| |
| Discount rate | | | 6.25 | % | | | 5.74 | % | | | 5.89 | % |
| Expected long-term rate of return on plan assets | | | 8.00 | % | | | 8.50 | % | | | 8.50 | % |
| Rate of compensation increase | | | N/A | | | | N/A | | | | N/A | |
The weighted average asset allocations by asset category for the pension plan and the OPEB plan as of October 31, 2008, 2007 and 2006 are presented below.
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Pension Benefits | | | Other Benefits | |
| | | 2008 | | | 2007 | | | Target | | | 2008 | | | 2007 | | | Target | |
| |
| Domestic equity securities | | | 43 | % | | | 48 | % | | | 50 | % | | | 35 | % | | | 42 | % | | | 50 | % |
| International equity securities | | | 8 | % | | | 10 | % | | | 10 | % | | | 23 | % | | | 8 | % | | | 10 | % |
| Fixed income securities | | | 44 | % | | | 41 | % | | | 40 | % | | | 37 | % | | | 26 | % | | | 40 | % |
| Cash | | | 5 | % | | | 1 | % | | | — | % | | | 5 | % | | | 24 | % | | | — | % |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Total | | | 100 | % | | | 100 | % | | | 100 | % | | | 100 | % | | | 100 | % | | | 100 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | |
65
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | Qualified Pension | | | Nonqualified Pension | |
| | | 2011 | | | 2010 | | | 2009 | | | 2011 | | | 2010 | | | 2009 | |
Discount rate | | | 5.47 | % | | | 5.99 | % | | | 8.15 | % | | | 4.37 | % | | | 5.28 | % | | | 8.46 | % |
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 | | | 3.87 | % | | | 3.92 | % | | | 3.97 | % | | | N/A | | | | N/A | | | | N/A | |
| | | | | | | | | | | | |
| | | Other Benefits | |
| | | 2011 | | | 2010 | | | 2009 | |
Discount rate | | | 4.85 | % | | | 5.58 | % | | | 8.50 | % |
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 | |
Piedmont Natural Gas Company, Inc.
Notes to Consolidated Financial Statements — (Continued)
Our primary investment objective is to generate sufficient assets to meet plan liabilities. The plans’ assets will therefore be invested to maximize long-term returns consistent with the plans’ liabilities, cash flow requirements and risk tolerance. 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 a20-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 plans’ liabilities are primarily defined in terms of participant salaries. Given the nature of these liabilities, and recognizing the long-term benefits of investing in both domestic and international equity securities, we invest in a diversified portfolio which includes a significant exposure to these investments. Investment risk is measured and monitored on an ongoing basis through quarterly investment portfolio reviews, annual liability measurements and periodic asset/liability studies. We intend to use 8% as the expected long-term rate of return on the pension and OPEB plans for 2009.
Specific financial targets include:
| | |
| • | Achieve full funding over the longer term for our defined benefit pension plan, |
|
| • | Control fluctuation in pension expense from year to year, |
|
| • | Achieve satisfactory performance relative to other similar pension plans, and |
|
| • | Achieve positive returns in excess of inflation over short to intermediate time frames. |
We anticipate that we will contribute the following amounts to our plans in 2009.
| | | | | |
| | | In thousands | |
| |
| Qualified pension plan | | $ | 11,000 | |
| Nonqualified pension plans | | | 528 | |
| OPEB plan | | | 3,400 | |
Because 2008 is the first year of the MPP plan, we have made no contributions to the plan to date. We anticipate contributing $90,000 to the MPP plan in January 2009.
2012. | | | | |
In thousands | | | |
Qualified pension plan | | $ | — | |
Nonqualified pension plans | | | 517 | |
MPP plan | | | 535 | |
OPEB plan | | | 1,600 | |
The Pension Protection Act of 2006 (PPA) contains newspecified funding requirements for single employer defined benefit pension plans. The PPA establishesestablished a 100% funding target for plan years beginning after December 31, 2007. We contributed more than was required for our qualified plan2007, and we are in 2008.
compliance.Benefit payments, which reflect expected future service, as appropriate, are expected to be paid for the next ten years ending October 31 as follows.
| | | | | | | | | | | | | |
| | | Qualified
| | | Nonqualified
| | | Other
| |
| | | Pension | | | Pension | | | Benefits | |
| | | In thousands | |
| |
| 2009 | | $ | 11,689 | | | $ | 528 | | | $ | 2,884 | |
| 2010 | | | 11,491 | | | | 531 | | | | 2,888 | |
| 2011 | | | 10,839 | | | | 517 | | | | 2,855 | |
| 2012 | | | 12,207 | | | | 486 | | | | 2,836 | |
| 2013 | | | 12,063 | | | | 480 | | | | 2,877 | |
| 2014-2018 | | | 66,110 | | | | 2,063 | | | | 16,342 | |
66
| | | | | | | | | | | | |
In thousands | | Qualified
Pension | | | Nonqualified
Pension | | | Other
Benefits | |
2012 | | $ | 21,486 | | | $ | 517 | | | $ | 1,992 | |
2013 | | | 16,161 | | | | 484 | | | | 2,031 | |
2014 | | | 13,946 | | | | 450 | | | | 2,233 | |
2015 | | | 14,827 | | | | 461 | | | | 2,330 | |
2016 | | | 15,452 | | | | 436 | | | | 2,381 | |
2017 - 2021 | | | 94,812 | | | | 1,977 | | | | 13,151 | |
Piedmont Natural Gas Company, Inc.
Notes to Consolidated Financial Statements — (Continued)
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, 20082011 and 20072010 are presented below.
| | | | | | | | | |
| | | 2008 | | | 2007 | |
| |
| Health care cost trend rate assumed for next year | | | 8.25 | % | | | 8.25 | % |
| 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 | | | 2017 | | | | 2012 | |
| | | | | | | | |
| | | 2011 | | | 2010 | |
Health care cost trend rate assumed for next year | | | 7.70 | % | | | 7.80 | % |
Rate to which the cost trend is assumed to decline (the ultimate trend rate) | | | 5.00 | % | | | 5.00 | % |
Year that the rate reaches the ultimate trend rate | | | 2027 | | | | 2027 | |
The health care cost trend rate assumptions could have a significant effect on the amounts reported. A change of 1% would have the following effects.
| | | | | | | | | |
| | | 1% Increase | | | 1% Decrease | |
| | | In thousands | |
| |
| Effect on total of service and interest cost components of net periodic postretirement health care benefit cost for the year ended October 31, 2008 | | $ | 81 | | | $ | (88 | ) |
| Effect on the health care cost component of the accumulated postretirement benefit obligation as of October 31, 2008 | | | 725 | | | | (709 | ) |
| | | | | | | | |
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, 2011 | | $ | 37 | | | $ | (38 | ) |
Effect on the health care cost component of the accumulated postretirement benefit obligation as of October 31, 2011 | | | 693 | | | | (706 | ) |
Fair Value Measurements
The qualified pension plan’s asset allocations by level within the fair value hierarchy at October 31, 2011 and 2010 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.
| | | | | | | | | | | | | | | | | | | | |
| | | Qualified Pension Plan as of October 31, 2011 | |
In thousands | | Quoted Prices
in Active
Markets
(Level 1) | | | Significant
Other
Observable
Inputs
(Level 2) | | | Significant
Unobservable
Inputs
(Level 3) | | | Total
Carrying
Value | | | % of
Total | |
Cash and cash equivalents | | $ | 5,891 | | | $ | 2 | | | $ | — | | | | 5,893 | | | | 2 | % |
| | | | | | | | | | | | | | | | | | | | |
Fixed Income Securities: | | | | | | | | | | | | | | | | | | | 45 | % |
| | | | | | | | | | | | | | | | | | | | |
U.S. treasuries | | | — | | | | 11,109 | | | | — | | | | 11,109 | | | | 4 | % |
Long duration bonds (1) | | | 66,824 | | | | — | | | | — | | | | 66,824 | | | | 26 | % |
Corporate bonds | | | — | | | | 24,383 | | | | — | | | | 24,383 | | | | 9 | % |
High yield bonds (2) | | | 12,504 | | | | — | | | | — | | | | 12,504 | | | | 5 | % |
Collateralized mortgage obligations | | | — | | | | 1,448 | | | | — | | | | 1,448 | | | | 1 | % |
Municipals | | | — | | | | 324 | | | | — | | | | 324 | | | | — | % |
Derivatives | | | (25 | ) | | | 437 | | | | — | | | | 412 | | | | — | % |
| | | | | | | | | | | | | | | | | | | | |
Equity Securities: (3) | | | | | | | | | | | | | | | | | | | 35 | % |
| | | | | | | | | | | | | | | | | | | | |
Large cap core index (4) | | | 11,206 | | | | — | | | | — | | | | 11,206 | | | | 4 | % |
Large cap value | | | 8,623 | | | | — | | | | — | | | | 8,623 | | | | 3 | % |
Large cap growth | | | 15,897 | | | | — | | | | — | | | | 15,897 | | | | 6 | % |
Small cap | | | 23,827 | | | | — | | | | — | | | | 23,827 | | | | 9 | % |
International value | | | 13,770 | | | | — | | | | — | | | | 13,770 | | | | 6 | % |
International growth | | | 18,057 | | | | — | | | | — | | | | 18,057 | | | | 7 | % |
| | | | | | | | | | | | | | | | | | | | |
Real Estate: | | | | | | | | | | | | | | | | | | | 6 | % |
| | | | | | | | | | | | | | | | | | | | |
Global REIT | | | 14,909 | | | | — | | | | — | | | | 14,909 | | | | 6 | % |
| | | | | | | | | | | | | | | | | | | | |
Other Investments: | | | | | | | | | | | | | | | | | | | 12 | % |
| | | | | | | | | | | | | | | | | | | | |
Hedge fund of funds (5) | | | — | | | | 10,089 | | | | 6,207 | | | | 16,296 | | | | 6 | % |
Private equity fund of funds (6) | | | — | | | | — | | | | 1,925 | | | | 1,925 | | | | 1 | % |
Commodities (7) | | | — | | | | 3,632 | | | | 8,472 | | | | 12,104 | | | | 5 | % |
| | | | | | | | | | | | | | | | | | | | |
Total assets at fair value | | $ | 191,483 | | | $ | 51,424 | | | $ | 16,604 | | | $ | 259,511 | | | | 100 | % |
| | | | | | | | | | | | | | | | | | | | |
Percent of fair value hierarchy | | | 74 | % | | | 20 | % | | | 6 | % | | | 100 | % | | | | |
| | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | |
| | | Qualified Pension Plan as of October 31, 2010 | |
In thousands | | Quoted Prices
in Active
Markets
(Level 1) | | | Significant
Other
Observable
Inputs
(Level 2) | | | Significant
Unobservable
Inputs
(Level 3) | | | Total
Carrying
Value | | | % of
Total | |
Cash and cash equivalents | | $ | 1,969 | | | $ | — | | | $ | — | | | | 1,969 | | | | 1 | % |
| | | | | | | | | | | | | | | | | | | | |
Fixed Income Securities: | | | | | | | | | | | | | | | | | | | 50 | % |
| | | | | | | | | | | | | | | | | | | | |
U.S. treasuries | | | — | | | | 26,886 | | | | — | | | | 26,886 | | | | 12 | % |
Long duration bonds (1) | | | 60,393 | | | | — | | | | — | | | | 60,393 | | | | 26 | % |
Corporate bonds | | | — | | | | 13,063 | | | | — | | | | 13,063 | | | | 6 | % |
High yield bonds (2) | | | 11,509 | | | | — | | | | — | | | | 11,509 | | | | 5 | % |
Derivatives | | | (27 | ) | | | 1,694 | | | | — | | | | 1,667 | | | | 1 | % |
| | | | | | | | | | | | | | | | | | | | |
Equity Securities: (3) | | | | | | | | | | | | | | | | | | | 39 | % |
| | | | | | | | | | | | | | | | | | | | |
Large cap core index (4) | | | 10,815 | | | | — | | | | — | | | | 10,815 | | | | 5 | % |
Large cap value | | | 10,640 | | | | — | | | | — | | | | 10,640 | | | | 5 | % |
Large cap growth | | | 12,601 | | | | — | | | | — | | | | 12,601 | | | | 5 | % |
Small cap | | | 21,748 | | | | — | | | | — | | | | 21,748 | | | | 9 | % |
International value | | | 17,170 | | | | — | | | | — | | | | 17,170 | | | | 7 | % |
International growth | | | 17,243 | | | | — | | | | — | | | | 17,243 | | | | 8 | % |
| | | | | | | | | | | | | | | | | | | | |
Real Estate: | | | | | | | | | | | | | | | | | | | 5 | % |
| | | | | | | | | | | | | | | | | | | | |
Global REIT | | | 12,070 | | | | — | | | | — | | | | 12,070 | | | | 5 | % |
| | | | | | | | | | | | | | | | | | | | |
Other Investments: | | | | | | | | | | | | | | | | | | | 5 | % |
| | | | | | | | | | | | | | | | | | | | |
Hedge fund of funds (5) | | | — | | | | 4,795 | | | | 5,196 | | | | 9,991 | | | | 5 | % |
Private equity fund of funds (6) | | | — | | | | — | | | | 580 | | | | 580 | | | | — | % |
| | | | | | | | | | | | | | | | | | | | |
Total assets at fair value | | $ | 176,131 | | | $ | 46,438 | | | $ | 5,776 | | | $ | 228,345 | | | | 100 | % |
| | | | | | | | | | | | | | | | | | | | |
Percent of fair value hierarchy | | | 77 | % | | | 20 | % | | | 3 | % | | | 100 | % | | | | |
| | | | | | | | | | | | | | | | | | | | |
| (1) | This category represents actively managed long duration fixed income funds. |
| (2) | This category represents actively managed high yield fixed income funds. |
| (3) | This category represents actively managed equity funds and separate accounts with diversified investment strategies with the exception of the Large Cap Core Index Fund category. |
| (4) | This category represents low-cost equity index funds not actively managed that track the S&P 500 index. |
| (5) | This category represents investments 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. |
| (6) | This category represents exposure to a diversified private equity fund of funds investment. The target allocation is 5% but is still being funded through capital calls. Until a 5% allocation can be achieved, the balance of the 5% allocation is invested in a low-cost equity fund managed to track the S&P 500 index. |
| (7) | This category represents exposure to a commodities fund of funds investment, which is comprised of actively managed commodity market-oriented strategies through opportunistic investments in a well diversified group of underlying managers. |
The following is a reconciliation of the assets in the qualified pension plan that are classified as Level 3 in the fair value hierarchy.
| | | | | | | | | | | | | | | | |
In thousands | | Hedge
Fund
of Funds | | | Private
Equity
Fund
of Funds | | | Commodities | | | Total | |
Balance, October 31, 2009 | | $ | — | | | $ | — | | | $ | — | | | $ | — | |
Actual return on plan assets: | | | | | | | | | | | | | | | | |
Relating to assets still held at the reporting date | | | 307 | | | | (4 | ) | | | — | | | | 303 | |
Relating to assets sold during the period | | | — | | | | — | | | | — | | | | — | |
Purchases, sales and settlements (net) | | | 4,889 | | | | 584 | | | | — | | | | 5,473 | |
Transfer in/out of Level 3 | | | — | | | | — | | | | — | | | | — | |
| | | | | | | | | | | | | | | | |
Balance, October 31, 2010 | | | 5,196 | | | | 580 | | | | — | | | | 5,776 | |
Actual return on plan assets: | | | | | | | | | | | | | | | | |
Relating to assets still held at the reporting date | | | (1,236 | ) | | | 66 | | | | (488 | ) | | | (1,658 | ) |
Relating to assets sold during the period | | | — | | | | — | | | | — | | | | — | |
Purchases, sales and settlements (net) | | | 2,247 | | | | 1,279 | | | | 8,960 | | | | 12,486 | |
Transfer in/out of Level 3 | | | — | | | | — | | | | — | | | | — | |
| | | | | | | | | | | | | | | | |
Balance, October 31, 2011 | | $ | 6,207 | | | $ | 1,925 | | | $ | 8,472 | | | $ | 16,604 | |
| | | | | | | | | | | | | | | | |
The OPEB plan’s asset allocations by level within the fair value hierarchy at October 31, 2011 and 2010 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 (1) as of October 31, 2011 | |
In thousands | | Quoted Prices
in Active
Markets
(Level 1) | | | Significant
Other
Observable
Inputs
(Level 2) | | | Significant
Unobservable
Inputs
(Level 3) | | | Total
Carrying
Value | | | % of
Total | |
Cash and cash equivalents | | $ | 1,011 | | | $ | — | | | $ | — | | | $ | 1,011 | | | | 5 | % |
| | | | | | | | | | | | | | | | | | | | |
Fixed Income Securities: | | | | | | | | | | | | | | | | | | | 45 | % |
| | | | | | | | | | | | | | | | | | | | |
U.S. treasuries | | | 2,162 | | | | — | | | | — | | | | 2,162 | | | | 10 | % |
Corporate bonds (2) / Asset-backed securities | | | 7,790 | | | | — | | | | — | | | | 7,790 | | | | 35 | % |
| | | | | | | | | | | | | | | | | | | | |
Equity Securities: | | | | | | | | | | | | | | | | | | | 45 | % |
| | | | | | | | | | | | | | | | | | | | |
Large cap value | | | 1,108 | | | | — | | | | — | | | | 1,108 | | | | 5 | % |
Large cap growth | | | 1,107 | | | | — | | | | — | | | | 1,107 | | | | 5 | % |
Small cap value | | | 1,092 | | | | — | | | | — | | | | 1,092 | | | | 5 | % |
Small cap growth | | | 1,131 | | | | — | | | | — | | | | 1,131 | | | | 5 | % |
Large cap index | | | 1,996 | | | | — | | | | — | | | | 1,996 | | | | 9 | % |
International blend | | | 3,557 | | | | — | | | | — | | | | 3,557 | | | | 16 | % |
| | | | | | | | | | | | | | | | | | | | |
Real Estate: | | | | | | | | | | | | | | | | | | | 5 | % |
| | | | | | | | | | | | | | | | | | | | |
Global REIT | | | 1,091 | | | | — | | | | — | | | | 1,091 | | | | 5 | % |
| | | | | | | | | | | | | | | | | | | | |
Total assets at fair value | | $ | 22,045 | | | $ | — | | | $ | — | | | $ | 22,045 | | | | 100 | % |
| | | | | | | | | | | | | | | | | | | | |
Percent of fair value hierarchy | | | 100 | % | | | — | % | | | — | % | | | 100 | % | | | | |
| | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | |
| | | Other Benefits (1) as of October 31, 2010 | |
In thousands | | Quoted Prices
in Active
Markets
(Level 1) | | | Significant
Other
Observable
Inputs
(Level 2) | | | Significant
Unobservable
Inputs
(Level 3) | | | Total
Carrying
Value | | | % of
Total | |
Cash and cash equivalents | | $ | 526 | | | $ | — | | | $ | — | | | $ | 526 | | | | 3 | % |
| | | | | | | | | | | | | | | | | | | | |
Fixed Income Securities: | | | | | | | | | | | | | | | | | | | 45 | % |
| | | | | | | | | | | | | | | | | | | | |
U.S. treasuries | | | 2,164 | | | | — | | | | — | | | | 2,164 | | | | 10 | % |
Corporate bonds (2) / Asset-backed securities | | | 7,603 | | | | — | | | | — | | | | 7,603 | | | | 35 | % |
| | | | | | | | | | | | | | | | | | | | |
Equity Securities: | | | | | | | | | | | | | | | | | | | 47 | % |
| | | | | | | | | | | | | | | | | | | | |
Large cap value | | | 1,131 | | | | — | | | | — | | | | 1,131 | | | | 5 | % |
Large cap growth | | | 1,152 | | | | — | | | | — | | | | 1,152 | | | | 5 | % |
Small cap value | | | 1,158 | | | | — | | | | — | | | | 1,158 | | | | 5 | % |
Small cap growth | | | 1,162 | | | | — | | | | — | | | | 1,162 | | | | 5 | % |
Large cap index | | | 2,019 | | | | — | | | | — | | | | 2,019 | | | | 10 | % |
International blend | | | 3,650 | | | | — | | | | — | | | | 3,650 | | | | 17 | % |
| | | | | | | | | | | | | | | | | | | | |
Real Estate: | | | | | | | | | | | | | | | | | | | 5 | % |
| | | | | | | | | | | | | | | | | | | | |
Global REIT | | | 1,071 | | | | — | | | | — | | | | 1,071 | | | | 5 | % |
| | | | | | | | | | | | | | | | | | | | |
Total assets at fair value | | $ | 21,636 | | | $ | — | | | $ | — | | | $ | 21,636 | | | | 100 | % |
| | | | | | | | | | | | | | | | | | | | |
Percent of fair value hierarchy | | | 100 | % | | | — | % | | | — | % | | | 100 | % | | | | |
| | | | | | | | | | | | | | | | | | | | |
| (1) | The plan assets are invested in mutual funds. |
| (2) | This category represents primarily investment grade corporate securities even though the plan maintains a 5% allocation to a high yield bond fund. |
401(k) Plan
We maintain a 401(k) plans which areplan that is a profit-sharing plansplan under Section 401(a) of the Internal Revenue Code of 1986, as amended (the Tax Code), which includeincludes qualified cash or deferred arrangements under Tax Code Section 401(k). The 401(k) plans areplan is subject to the provisions of the Employee Retirement Income Security Act. Full-timeEligible 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 plansplan, and we match a portion of their contributions. Employee contributions vest immediately, and company contributions vest after six months of service.
EffectiveBeginning January 1, 2008 we made changes(January 1, 2009 for employees covered under the bargaining unit contract in Nashville, Tennessee), employees receive a company match of 100% up to our 401(k) plans.the first 5% of eligible pay contributed. Prior to January 1, 2008, we matched 50% of employee contributions up to the first 10% of pay contributed. Beginning January 1, 2008 (January 1, 2009 for employees covered under the bargaining unit contract in Nashville, Tennessee), employees are able to receive a company match of 100% up to the first 5% of eligible pay contributed. Employees are still able tomay contribute up to 50% of eligible pay to the 401(k) on a pre-tax basis, up to the Tax Code annual contribution limit. We automatically enroll all affected non-participating employees in the 401(k) plan as of January 1, 2008 (January 1, 2009 for employees covered under the bargaining unit contract in Nashville, Tennessee) at a 2% contribution rate unless the employee chooses not to participate by notifying our plan administrator.record keeper. For employees who are automatically enrolled in the 401(k) plan, we will 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 invest in Piedmont stockdirect up to a maximum of 20% of their account.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, 2008, 20072011, 2010 and 2006,2009, we made matching contributions to participant accounts as follows.
| | | | | | | | | | | | | |
| | | 2008 | | | 2007 | | | 2006 | |
| | | In thousands | |
| |
| 401(k) matching contributions | | $ | 4,252 | | | $ | 3,191 | | | $ | 3,288 | |
| | | | | | | | | | | | | | |
In thousands | | 2011 | | | 2010 | | | 2009 | |
401(k) matching contributions | | $ | 5,203 | | | $ | 5,269 | | | | | $ | 4,698 | |
As a result of a plan merger effective in 2001, participants’ accounts in our employee stock ownership plan (ESOP) were transferred into ourthe participants’ 401(k) plans.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.
67
10. Employee Share-Based PlansPiedmont Natural Gas Company, Inc.
Notes to Consolidated Financial Statements — (Continued)
| |
8. | Employee Share-Based Plans |
Under the LTIP and Incentive Compensation Plan (ICP),our shareholder approved by the Company’s shareholders in March 2006, the Board of Directors has awarded units toincentive compensation plans, eligible officers and other participants. Dependingparticipants are awarded units that pay out depending upon the level of performance achieved by Piedmont during multi-yearthree-year incentive plan performance periods, distributionperiods. Distribution of those awards may be made in the form of shares of common stock and cash withheldwithholdings for payment of applicable taxes on the compensation. The LTIP and ICPThese plans require that a minimum threshold performance level be achieved in order for any award to be distributed. For the years ended October 31, 2008, 20072011, 2010 and 2006,2009, we recorded compensation expense, and as of October 31, 20082011 and 2007,2010, we have accrued amountsa 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. Shares of common stock to be issued under the LTIP and ICP are contingently issuable shares and are included in our calculation of fully diluted earnings per share.
We have three awards under the LTIP and ICPapproved incentive compensation plans with three-year performance periods ending October 31, 2008,2011, October 31, 20092012 and October 31, 2010. Fifty percent2013. 50% of the units awarded will be based on achievement of a target annual compounded increase in basic earnings per share (EPS).EPS. For this 50% portion, an EPS performance of 80% of target will result in an 80% payout, an EPS performance of 100% of target will result in a 100% payout and an EPS performance of 120% of target will result in a maximum 120% payout, and EPS performance levels between these levels will be subject to mathematical interpolation. EPS performance below 80% of target will result in no payout of this portion. The other 50% of the units awarded will be based on the achievement of a target total annual shareholder return (increase in our common stock price plus dividends paidreinvested over the specified period of time) in comparison to a peer group consistingwhich consists of the natural gas distribution companies formerly comprising the A. G. Edwards Large Natural Gas Distribution Index (peer group).companies. The total shareholder return performance measure will be the registrant’sour percentile ranking in relationship to the peer group. For this 50% portion, a ranking below the 25th percentile will result in no payout, a ranking between the 25th and 39th percentile will result in an 80% payout, a ranking between the 40th and 49th percentile will result in a 90% payout, a ranking between the 50th and 74th percentile will result in a 100% payout, a ranking between the 75th and 89th percentile will result in a 110% payout, and a ranking at or above the 90th percentile will result in a maximum 120% payout.
WeIn December 2010, a long-term retention award under the incentive compensation plan was approved for eligible officers and other participants. This retention award will be distributed to participants who have one additional award withmet the retention requirements at the end of a five-year performancethree-year period thatending in
December 2013 in the form of shares of common stock and withholdings for payment of applicable taxes on the compensation. The Compensation Committee of our Board of Directors has the discretion to accelerate the vesting of a participant’s retention units. For the twelve months ended October 31, 2006, for a group of retired employees with 75% of the units awarded being based on achievement of a target cumulative increase in net income and 25% of the units awarded based on achievement of a target total annual shareholder return in comparison to the A. G. Edwards Large Natural Gas Distribution Index industry peer group and in the same percentile rankings. The payout under this award will occur over a three-year period. The second payout occurred in fiscal 2008.
Information for the LTIP and ICP for the years ended October 31, 2008, 2007 and 2006,2011, we recorded compensation expense, and as of October 31, 2008 and 20072011, we have accrued a liability for these awards based on the fair market value of our stock at the end of each quarter. The liability is presented below.
| | | | | | | | | | | | | |
| | | 2008 | | | 2007 | | | 2006 | |
| | | In thousands | |
| |
| Compensation expense | | $ | 6,689 | | | $ | 1,666 | | | $ | 5,356 | |
| Tax benefit | | | 1,723 | | | | 654 | | | | 2,111 | |
| Liability | | | 10,749 | | | | 6,200 | | | | | |
Based on current accrual assumptions,re-measured to market value at the expected payout for performance periods ending October 31, 2008, 2009 and 2010 will occur in the following fiscal years.
| | | | | | | | | | | | | |
| | | 2009 | | | 2010 | | | 2011 | |
| | | In thousands | |
| |
| Amount of payout | | $ | 5,329 | | | $ | 2,990 | | | $ | 1,941 | |
68
Piedmont Natural Gas Company, Inc.
Notes to Consolidated Financial Statements — (Continued)
UnderAlso under our ICP,approved incentive compensation plan, 65,000 restrictedunvested shares of our common stock with a value at the date of grant of $1.7 million were granted to our President and Chief Executive Officer in September 2006. The restricted shares shall vest and be payable onDuring the following schedule only if he is an employee on the vesting date for each tranche:
| | | | | |
| | | Projected
| |
| | | Amount | |
| | | In thousands | |
| |
| 20% on September 1, 2009 | | $ | 374 | |
| 30% on September 1, 2010 | | | 562 | |
| 50% on September 1, 2011 | | | 936 | |
During thefive-year vesting period, any dividends paid on these shares
will bewere accrued and converted into additional shares at the closing price on the date of the dividend payment.
The restricted shares and any additional shares accrued through dividends will vest according toIn accordance with the vesting schedule
above. We are recording20%, 30% and 50% of the shares vested on September 1, 2009, 2010 and 2011, respectively.The compensation underexpense related to the ICP on the straight-line method.
Information for the restricted sharesincentive compensation plans for the years ended October 31, 2008, 20072011, 2010 and 2006 is2009, and the amounts recorded as liabilities as of October 31, 2011 and 2010 are presented below.
| | | | | | | | | | | | | |
| | | October 31 | |
| | | 2008 | | | 2007 | | | 2006 | |
| | | In thousands, except shares | |
| |
| Number of shares granted | | | | | | | | | | | 65,000 | |
| Value at date of grant | | | | | | | | | | $ | 1,700 | |
| Compensation expense | | $ | 338 | | | $ | 336 | | | $ | 56 | |
| Tax (expense) benefit | | | (168 | ) | | | 132 | | | | 22 | |
| | | | | | | | | | | | |
In thousands | | 2011 | | | 2010 | | | 2009 | |
Compensation expense | | $ | 2,604 | | | $ | 6,118 | | | $ | 2,487 | |
Tax benefit | | | 673 | | | | 1,756 | | | | 207 | |
Liability | | | 5,015 | | | | 9,914 | | | | | |
Based on current accrual assumptions as of October 31, 2011, the expected payout for the approved incentive compensation plans ending October 31, 2011, 2012 and 2013 will occur in the following fiscal years.
| | | | | | | | | | | | | | |
In thousands | | 2012 | | | 2013 | | | 2014 | |
Amount of payout | | $ | — | | | $ | 2,719 | | | | | $ | 2,296 | |
On a quarterly basis, we issue shares of common stock under the ESPP and have accounted for the issuance as an equity transaction. The exercise price is calculated as 95% of the fair market value on the purchase date of each quarter where fair market value is determined by calculating the mean average of the high and low trading prices on the purchase date.
As discussed in Note 4, we repurchase shares on the open market and such shares are then cancelled and become authorized but unissued shares available for issuance under our employee plans, including the ESPP, LTIP and ICP.
69
11. Income TaxesPiedmont Natural Gas Company, Inc.
Notes to Consolidated Financial Statements — (Continued)
The components of income tax expense for the years ended October 31, 2008, 20072011, 2010 and 20062009 are presented below.
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | 2008 | | | 2007 | | | 2006 | |
| | | Federal | | | State | | | Federal | | | State | | | Federal | | | State | |
| | | In thousands | |
| |
| Charged to operating income: | | | | | | | | | | | | | | | | | | | | | | | | |
| Current | | $ | 27,971 | | | $ | 6,679 | | | $ | 28,233 | | | $ | 4,987 | | | $ | 27,470 | | | $ | 4,977 | |
| Deferred | | | 24,285 | | | | 4,237 | | | | 15,250 | | | | 3,279 | | | | 14,775 | | | | 3,855 | |
| Amortization of investment tax credits | | | (358 | ) | | | — | | | | (434 | ) | | | — | | | | (534 | ) | | | — | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Total | | | 51,898 | | | | 10,916 | | | | 43,049 | | | | 8,266 | | | | 41,711 | | | | 8,832 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Charged to other income (expense): | | | | | | | | | | | | | | | | | | | | | | | | |
| Current | | | 10,040 | | | | 1,786 | | | | 7,557 | | | | 1,153 | | | | 9,052 | | | | 1,427 | |
| Deferred | | | (1,025 | ) | | | (123 | ) | | | 4,644 | | | | 957 | | | | 1,107 | | | | 301 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Total | | | 9,015 | | | | 1,663 | | | | 12,201 | | | | 2,110 | | | | 10,159 | | | | 1,728 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Total | | $ | 60,913 | | | $ | 12,579 | | | $ | 55,250 | | | $ | 10,376 | | | $ | 51,870 | | | $ | 10,560 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | 2011 | | | 2010 | | | 2009 | |
In thousands | | Federal | | | State | | | Federal | | | State | | | Federal | | | State | |
Charged (Credited) to operating income: | | | | | | | | | | | | | | | | | | | | | | | | |
Current | | $ | (11,403 | ) | | $ | 4,209 | | | $ | 18,133 | | | $ | 3,928 | | | $ | (7,774 | ) | | $ | 181 | |
Deferred | | | 64,806 | | | | 6,597 | | | | 33,432 | | | | 6,866 | | | | 65,828 | | | | 12,047 | |
Tax Credits | | | | | | | | | | | | | | | | | | | | | | | | |
Utilization | | | 184 | | | | — | | | | 105 | | | | — | | | | 130 | | | | — | |
Amortization | | | (325 | ) | | | — | | | | (382 | ) | | | — | | | | (333 | ) | | | — | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Total | | | 53,262 | | | | 10,806 | | | | 51,288 | | | | 10,794 | | | | 57,851 | | | | 12,228 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Charged (Credited) to other income (expense): | | | | | | | | | | | | | | | | | | | | | | | | |
Current | | | 3,263 | | | | (36 | ) | | | 22,519 | | | | 3,755 | | | | 7,764 | | | | 1,064 | |
Deferred | | | 4,167 | | | | 824 | | | | 2,963 | | | | 557 | | | | 2,492 | | | | 483 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Total | | | 7,430 | | | | 788 | | | | 25,482 | | | | 4,312 | | | | 10,256 | | | | 1,547 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Total | | $ | 60,692 | | | $ | 11,594 | | | $ | 76,770 | | | $ | 15,106 | | | $ | 68,107 | | | $ | 13,775 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
A reconciliation of income tax expense at the federal statutory rate to recorded income tax expense for the years ended October 31, 2008, 20072011, 2010 and 20062009 is presented below.
| | | | | | | | | | | | | |
| | | 2008 | | | 2007 | | | 2006 | |
| | | In thousands | |
| |
| Federal taxes at 35% | | $ | 64,225 | | | $ | 59,504 | | | $ | 55,867 | |
| State income taxes, net of federal benefit | | | 8,176 | | | | 6,745 | | | | 6,864 | |
| Amortization of investment tax credits | | | (358 | ) | | | (434 | ) | | | (534 | ) |
| Other, net | | | 1,449 | | | | (189 | ) | | | 233 | |
| | | | | | | | | | | | | |
| Total | | $ | 73,492 | | | $ | 65,626 | | | $ | 62,430 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | |
In thousands | | 2011 | | | 2010 | | | 2009 | |
Federal taxes at 35% | | $ | 65,049 | | | $ | 81,841 | | | $ | 71,647 | |
State income taxes, net of federal benefit | | | 7,536 | | | | 9,819 | | | | 8,954 | |
Amortization of investment tax credits | | | (325 | ) | | | (382 | ) | | | (333 | ) |
Other, net | | | 26 | | | | 598 | | | | 1,614 | |
| | | | | | | | | | | | |
Total | | $ | 72,286 | | | $ | 91,876 | | | $ | 81,882 | |
| | | | | | | | | | | | |
As of October 31, 20082011 and 2007,2010, deferred income taxes consisted of the following temporary differences.
| | | | | | | | | |
| | | 2008 | | | 2007 | |
| | | In thousands | |
| |
| Utility plant | | $ | 271,060 | | | $ | 239,448 | |
| Equity method investments | | | 19,241 | | | | 20,554 | |
| Revenues and cost of gas | | | 17,370 | | | | 23,741 | |
| Deferred cost | | | 25,605 | | | | 21,594 | |
| Other, net | | | (21,036 | ) | | | (21,436 | ) |
| | | | | | | | | |
| Net deferred income tax liabilities | | $ | 312,240 | | | $ | 283,901 | |
| | | | | | | | | |
| | | | | | | | |
In thousands | | 2011 | | | 2010 | |
Deferred tax assets: | | | | | | | | |
Benefit of loss carryforwards | | $ | 2,474 | | | $ | 2,474 | |
Employee benefits and compensation | | | 10,267 | | | | 13,082 | |
Revenue requirement | | | 10,306 | | | | 10,530 | |
Utility plant | | | 10,799 | | | | 9,183 | |
Other | | | 6,043 | | | | 4,958 | |
| | | | | | | | |
Total deferred tax assets | | | 39,889 | | | | 40,227 | |
Valuation Allowance | | | (505 | ) | | | (1,324 | ) |
| | | | | | | | |
Total deferred tax assets, net | | | 39,384 | | | | 38,903 | |
| | | | | | | | |
Deferred tax liabilities: | | | | | | | | |
Utility plant | | | 437,388 | | | | 370,348 | |
Revenues and cost of gas | | | 6,896 | | | | 14,976 | |
Equity method investments | | | 32,296 | | | | 27,244 | |
Deferred costs | | | 55,142 | | | | 46,387 | |
Other | | | 18,830 | | | | 14,106 | |
| | | | | | | | |
Total deferred tax liabilities | | | 550,552 | | | | 473,061 | |
| | | | | | | | |
Net deferred income tax liabilities | | $ | 511,168 | | | $ | 434,158 | |
| | | | | | | | |
As of October 31, 20082011 and 2007, total deferred income tax liabilities were $345 million and $321.3 million and total net deferred income tax assets were $32.8 million and $37.4 million, respectively. As of October 31, 2008 and 2007, these2010, total net deferred income tax assets were net of a valuation allowance of $1.1 million and $.4 million, respectively, to reduce amounts to the amounts that we believe will be more likely than not realized. We and our wholly owned subsidiaries file a consolidated federal income tax return and various state income tax returns. As of October 31, 20082011 and 2007,2010, we had federal net operating loss carryforwards of $6.2 million and $6.5 million, respectively, which expire from 2024 through 2026. As of October 31, 2011 and 2010, we had state net operating
70
Piedmont Natural Gas Company, Inc.
Notes to Consolidated Financial Statements — (Continued)
loss carryforwards of $6.6$7 million and $6.9$7.1 million, respectively, thatwhich expire from 20172018 through 2025. We may use the loss carryforwards to offset taxable income,income. Of the loss carryforwards, $6.2 million are subject to an annual limitation of $.3 million.
DuringOur return for the tax year ended October 31, 2007,2008 is currently under examination by the Internal Revenue Service finalized itsIRS. We do not expect the audit of our returns for the tax years ended October 31, 2003 through 2005. The audit results, which did notto have a material effect on our financial position, or results of operations have been reflected in the consolidated financial statements.or cash flows. We are no longer subject to federal income tax examinations for tax years ending before and including October 31, 2005,2007, and with few exceptions, state income tax examinations by tax authorities for years ended before and including October 31, 2003.
2007.A reconciliation of changes in the deferred tax valuation allowance for the years ended October 31, 2008, 20072011, 2010 and 20062009 is presented below.
| | | | | | | | | | | | | |
| | | 2008 | | | 2007 | | | 2006 | |
| | | In thousands | |
| |
| Balance at beginning of year | | $ | 394 | | | $ | 568 | | | $ | 583 | |
| Charged (credited) to income tax expense | | | 720 | | | | (174 | ) | | | (15 | ) |
| | | | | | | | | | | | | |
| Balance at end of year | | $ | 1,114 | | | $ | 394 | | | $ | 568 | |
| | | | | | | | | | | | | |
We adopted the provisions of FIN 48 on November 1, 2007. As a result of the implementation of FIN 48, there was no material impact on the consolidated financial statements, and no adjustment to retained earnings. The amount of unrecognized tax benefits at November 1, 2007 and October 31, 2008 was $.5 million, of which $.3 million would impact our effective income tax rate if recognized.
| | | | | | | | | | | | |
In thousands | | 2011 | | | 2010 | | | 2009 | |
Balance at beginning of year | | $ | 1,324 | | | $ | 1,400 | | | $ | 1,114 | |
Charged (credited) to income tax expense | | | (819 | ) | | | (76 | ) | | | 286 | |
| | | | | | | | | | | | |
Balance at end of year | | $ | 505 | | | $ | 1,324 | | | $ | 1,400 | |
| | | | | | | | | | | | |
A reconciliation of the unrecognized tax benefits for the yearyears ended October 31, 20082011 and 2010 is presented below.
| | | | | |
| | | In thousands | |
| |
| Balance, beginning of year (date of adoption) | | $ | 474 | |
| Increase from prior year’s tax positions | | | 72 | |
| Decrease from settlements with taxing authority | | | 40 | |
| | | | | |
| Balance, end of year | | $ | 506 | |
| | | | | |
We recognize accrued interest and penalties related to unrecognized tax benefits in operating expenses in the consolidated statements of income, which is consistent with the recognition of these items in prior reporting periods. | | | | | | | | |
In thousands | | 2011 | | | 2010 | |
Balance, beginning of year | | $ | — | | | $ | 293 | |
Decrease from settlements with taxing authorities | | | — | | | | — | |
Decrease from expiration of statute of limitations | | | — | | | | 293 | |
| | | | | | | | |
Balance, end of year | | $ | — | | | $ | — | |
| | | | | | | | |
We recorded $.1 million ofno interest related to unrecognized tax benefits during the year ended October 31, 2008.
For state tax purposes, we have unrecognized tax benefits related to2011 and only immaterial amounts of interest during the treatment of sales of certain assets that we anticipate will decrease by $.2 million due to a settlement with taxing authorities or the expiration of the statute of limitations within the next twelve months.
| |
10. | Equity Method Investments |
year ended October 31, 2010.12. Equity Method Investments
The consolidated financial statements include the accounts of wholly owned subsidiaries whose investments in joint venture, energy-related businesses are accounted for under the equity method. Our ownership interest in each entity is included in “Equity method investments in non-utility activities” in the consolidated balance sheets. Earnings or losses from equity method investments are included in “Income from equity method investments” in the consolidated statements of income.
As of October 31, 2008,2011, there were no amounts that represented undistributed earnings of our 50% or less owned equity method investments in our retained earnings.
71
Piedmont Natural Gas Company, Inc.
Notes to Consolidated Financial Statements — (Continued)
Cardinal Pipeline Company, L.L.C.
We own 21.49% of the membership interests in Cardinal Pipeline Company, L.L.C. (Cardinal), a North Carolina limited liability company. The other members are subsidiaries of The Williams Companies, Inc., and SCANA Corporation. Cardinal owns and operates an intrastate natural gas pipeline in North Carolina and is regulated by the NCUC. Cardinal has firm service agreements with local distribution companies for 100% of the firm transportation capacity on the pipeline, of which Piedmont subscribes to approximately 37%. Cardinal is dependent on the Williams-Transco pipeline system to deliver gas into its system for service to its customers. Cardinal’s long-term debt is nonrecourse to the members and is secured by Cardinal’s assets and by each member’s equity investment in Cardinal.
In October 2009, we reached an agreement with Progress Energy Carolinas, Inc. to provide natural gas delivery service to a power generation facility to be built at their Wayne County, North Carolina site. To provide the additional delivery service, we have executed an agreement with Cardinal, which was approved by the NCUC in May 2010, to expand our firm capacity requirement by 149,000 dekatherms per day to serve Progress Energy Carolinas. This will require Cardinal to spend an estimated $48 million for a new compressor station and expanded meter stations in order to increase the capacity of its system by up to 199,000 dekatherms per day of firm capacity for us and another customer. As an equity venture partner of Cardinal, we will invest an estimated $10.3 million in Cardinal’s system expansion. Capital contributions related to this system expansion began in January 2011 and will continue on a periodic basis through September 2012. As of October 31, 2011, our contributions related to this expansion were $6.2 million.
The members’ capital will be replaced with permanent financing with a target overall capital structure of 45-50% debt and 50-55% equity after the project is placed into service, scheduled to be June 2012. Our service subscription to Cardinal’s capacity following the system expansion will increase from approximately 37% to approximately 53%. The NCUC issued a formal certificate order to Progress Energy Carolinas for their Wayne County generation project in October 2009.
We have related party transactions as a transportation customer of Cardinal, and we record in cost of gas the transportation costs charged by Cardinal. For each of the years ended October 31, 2008, 20072011, 2010 and 2006,2009, these transportation costs and the amounts we owed Cardinal as of October 31, 20082011 and 20072010 are as follows.
| | | | | | | | | | | | | |
| | | 2008 | | | 2007 | | | 2006 | |
| | | In thousands | |
| |
| Transportation costs | | $ | 4,116 | | | $ | 4,549 | | | $ | 4,684 | |
| Trade accounts payable | | | 349 | | | | 349 | | | | | |
| | | | | | | | | | | | |
In thousands | | 2011 | | | 2010 | | | 2009 | |
Transportation costs | | $ | 4,104 | | | $ | 4,104 | | | $ | 4,104 | |
Trade accounts payable | | | 349 | | | | 349 | | | | | |
Summarized financial information provided to us by Cardinal for 100% of Cardinal as of September 30, 20082011 and 2007,2010, and for the twelve months ended September 30, 2008, 20072011, 2010 and 20062009 is presented below.
| | | | | | | | | | | | | |
| | | 2008 | | | 2007 | | | 2006 | |
| | | In thousands | |
| |
| Current assets | | $ | 10,010 | | | $ | 8,706 | | | $ | | |
| Non-current assets | | | 80,851 | | | | 83,388 | | | | | |
| Current liabilities | | | 5,229 | | | | 3,814 | | | | | |
| Non-current liabilities | | | 31,439 | | | | 33,637 | | | | | |
| Revenues | | | 13,670 | | | | 15,369 | | | | 15,524 | |
| Gross profit | | | 13,670 | | | | 15,369 | | | | 15,524 | |
| Income before income taxes | | | 7,050 | | | | 8,371 | | | | 8,785 | |
| | | | | | | | | | | | |
In thousands | | 2011 | | | 2010 | | | 2009 | |
Current assets | | $ | 25,868 | | | $ | 9,239 | | | | | |
Non-current assets | | | 88,329 | | | | 75,508 | | | | | |
Current liabilities | | | 5,665 | | | | 3,977 | | | | | |
Non-current liabilities | | | 24,225 | | | | 26,592 | | | | | |
Revenues | | | 13,633 | | | | 13,633 | | | $ | 13,633 | |
Gross profit | | | 13,633 | | | | 13,633 | | | | 13,633 | |
Income before income taxes | | | 6,473 | | | | 6,375 | | | | 6,893 | |
Pine Needle LNG Company, L.L.C.
We own 40% of the membership interests in Pine Needle LNG Company, L.L.C. (Pine Needle), a North Carolina limited liability company. The other members are the Municipal Gas Authority of Georgia and subsidiaries of The Williams Companies, Inc., SCANA Corporation and Hess Corporation. Pine Needle owns an interstate LNG storage facility in North Carolina and is regulated by the FERC. Pine Needle has firm service agreements for 100% of the storage capacity of the facility, of which Piedmont subscribes to approximately 64%.
Pine Needle enters into interest-rate swap agreements to modify the interest characteristics of itslong-term debt. Our share of movements in the market value of these agreements are recorded as a hedge in “Accumulated other comprehensive income”loss” in the consolidated balance sheets. Pine Needle’s long-term debt is nonrecourse to the members and is secured by Pine Needle’s assets and by each member’s equity investment in Pine Needle.
We have related party transactions as a customer of Pine Needle, and we record in cost of gas the storage costs charged by Pine Needle. For the years ended October 31, 2008, 20072011, 2010 and 2006,2009, these gas storage costs and the amounts we owed Pine Needle as of October 31, 20082011 and 20072010 are as follows.
| | | | | | | | | | | | | |
| | | 2008 | | | 2007 | | | 2006 | |
| | | In thousands | |
| |
| Gas storage costs | | $ | 11,516 | | | $ | 11,727 | | | $ | 12,704 | |
| Trade accounts payable | | | 1,019 | | | | 932 | | | | | |
72
| | | | | | | | | | | | |
In thousands | | 2011 | | | 2010 | | | 2009 | |
Gas storage costs | | $ | 10,677 | | | $ | 12,158 | | | $ | 12,364 | |
Trade accounts payable | | | 849 | | | | 985 | | | | | |
Piedmont Natural Gas Company, Inc.
Notes to Consolidated Financial Statements — (Continued)
Summarized financial information provided to us by Pine Needle for 100% of Pine Needle as of September 30, 20082011 and 2007,2010, and for the twelve months ended September 30, 2008, 20072011, 2010 and 20062009 is presented below.
| | | | | | | | | | | | | |
| | | 2008 | | | 2007 | | | 2006 | |
| | | In thousands | |
| |
| Current assets | | $ | 12,618 | | | $ | 11,178 | | | $ | | |
| Non-current assets | | | 81,934 | | | | 85,506 | | | | | |
| Current liabilities | | | 10,846 | | | | 9,401 | | | | | |
| Non-current liabilities | | | 25,175 | | | | 29,862 | | | | | |
| Revenues | | | 18,694 | | | | 18,668 | | | | 19,231 | |
| Gross profit | | | 18,694 | | | | 18,668 | | | | 19,231 | |
| Income before income taxes | | | 8,227 | | | | 8,827 | | | | 10,047 | |
| | | | | | | | | | | | |
In thousands | | 2011 | | | 2010 | | | 2009 | |
Current assets | | $ | 10,984 | | | $ | 15,593 | | | | | |
Non-current assets | | | 74,472 | | | | 78,863 | | | | | |
Current liabilities | | | 1,826 | | | | 3,923 | | | | | |
Non-current liabilities | | | 35,657 | | | | 35,007 | | | | | |
Revenues | | | 17,666 | | | | 18,808 | | | $ | 18,744 | |
Gross profit | | | 17,666 | | | | 18,808 | | | | 18,744 | |
Income before income taxes | | | 5,763 | | | | 8,317 | | | | 8,381 | |
SouthStar Energy Services LLC
We own 30%15% of the membership interests in SouthStar Energy Services LLC (SouthStar), a Delaware limited liability company. Under the terms of the Amended and Restated Limited Liability Company Agreement (Restated Agreement), earnings and losses are allocated 25% to us and 75% to theThe other member is Georgia Natural Gas Company (GNGC), a wholly-owned subsidiary of AGL Resources, Inc., with the exception of earnings and losses in the Ohio and Florida markets, which are allocated to us at our ownership percentage of 30%. SouthStar primarily sells natural gas to residential, commercial and industrial customers in the southeastern United States and Ohio with most of its business being conducted in the unregulated retail gas market in Georgia.
The SouthStar Restated Agreement includes a provision granting GNGC the option to purchase On January 1, 2010, we sold half of our ownership30% membership interest in SouthStar. By November 1, 2009,SouthStar to GNGC and retained a 15% earnings and membership share in SouthStar after the sale. At closing, we received $57.5 million from GNGC resulting in an after-tax gain of $30.3 million, or $.42 per diluted share for 2010. GNGC has no further rights to acquire our remaining 15% interest. We will continue to account for our 15% membership interest in SouthStar using the optionequity method, as we retain board representation with voting rights equal to purchase our entire 30% interest effectiveGNGC on January 1, 2010. If GNGC exercises its option,significant governance matters and policy decisions, and thus, exercise significant influence over the purchase price would be based on the market valueoperations of SouthStar as defined in the Restated Agreement.
SouthStar.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 income”loss” in the consolidated balance sheets.
We have related party transactions as we sell wholesale gas supplies to SouthStar, and we record in operating revenues the amounts billed to SouthStar. For the years ended October 31, 2008, 20072011, 2010 and 2006,2009, our operating revenues from these sales and the amounts SouthStar owed us as of October 31, 20082011 and 20072010 are as follows.
| | | | | | | | | | | | | |
| | | 2008 | | | 2007 | | | 2006 | |
| | | In thousands | |
| |
| Operating revenues | | $ | 14,624 | | | $ | 8,866 | | | $ | 21,598 | |
| Trade accounts receivable | | | 1,202 | | | | 1,650 | | | | | |
73
| | | | | | | | | | | | |
In thousands | | 2011 | | | 2010 | | | 2009 | |
Operating revenues | | $ | 4,961 | | | $ | 5,083 | | | $ | 8,226 | |
Trade accounts receivable | | | 736 | | | | 713 | | | | | |
Piedmont Natural Gas Company, Inc.
Notes to Consolidated Financial Statements — (Continued)
Summarized financial information provided to us by SouthStar for 100% of SouthStar as of September 30, 20082011 and 2007,2010, and for the twelve months ended September 30, 2008, 20072011, 2010 and 20062009 is presented below.
| | | | | | | | | | | | | |
| | | 2008 | | | 2007 | | | 2006 | |
| | | In thousands | |
| |
| Current assets | | $ | 238,662 | | | $ | 204,598 | | | $ | | |
| Non-current assets | | | 13,463 | | | | 8,899 | | | | | |
| Current liabilities | | | 144,552 | | | | 60,783 | | | | | |
| Non-current liabilities | | | 338 | | | | 53 | | | | | |
| Revenues | | | 941,123 | | | | 908,416 | | | | 1,053,770 | |
| Gross profit | | | 143,534 | | | | 177,822 | | | | 155,416 | |
| Income before income taxes | | | 73,224 | | | | 112,260 | | | | 88,765 | |
| | | | | | | | | | | | |
In thousands | | 2011 | | | 2010 | | | 2009 | |
Current assets | | $ | 169,286 | | | $ | 167,218 | | | | | |
Non-current assets | | | 9,292 | | | | 9,382 | | | | | |
Current liabilities | | | 62,869 | | | | 62,899 | | | | | |
Non-current liabilities | | | 141 | | | | 160 | | | | | |
Revenues | | | 733,987 | | | | 843,483 | | | $ | 854,455 | |
Gross profit | | | 176,010 | | | | 183,748 | | | | 169,639 | |
Income before income taxes | | | 103,704 | | | | 107,096 | | | | 98,308 | |
Hardy Storage Company, LLC
Piedmont Hardy Storage Company, LLC (Piedmont Hardy), a wholly owned subsidiary of Piedmont, owns 50% of the membership interests in Hardy Storage Company, LLC (Hardy Storage), a West Virginia limited liability company. The other owner is a subsidiary of Columbia Gas Transmission Corporation, a subsidiary of NiSource Inc. Hardy Storage owns and operates an underground interstate natural gas storage facility located in Hardy and Hampshire Counties, West Virginia, that is regulated by the FERC. Phase one service to customers began April 1, 2007 when customers began injecting gas into storage for subsequent winter withdrawals, and Phase II service levels began on April 1, 2008. Hardy Storage is now in the final stages of phase III project construction. Hardy Storage has firm service contracts for 100% of itsthe storage capacity of the facility, of which Piedmont subscribes to approximately 40%.
OnIn June 29, 2006, Hardy Storage signed a note purchase agreement for interim notes and a revolving equity bridge facility for up to a total of $173.1 million for funding during the construction period. On November 1, 2007, Hardy Storagefinancing. The revolving equity bridge facility was subsequently paid off the equity line of $10.2 million with member equity contributions, leaving an amount outstanding on the interim notes of $123.4 million.
For 2008, we made equity contributions of $10.9 million to fund additional construction expenditures, with our total equity contributions for the project totaling $23.8 million at October 31, 2008. Upon completion of project construction, including any contingency wells if needed, the members intend to target a capitalization structure of 70% debt and 30% equity. After the satisfaction of certain conditions in the note purchase agreement, amounts outstanding under the interim notes will convert to a fifteen-year mortgage-style debt instrument without recourse to the members. We expect the conversion to occur in May 2010. To the extent that more funding is needed, the members will evaluate funding options at that time.
2007. The members of Hardy Storage have each agreed to guarantee 50% of the construction financing. Ourfinancing as well as a separate guaranty was executed by Piedmont Energy Partners, Inc. (PEP), a wholly owned subsidiary of Piedmont and a sister company50% of Piedmont Hardy. Our shareconstruction expenditures should contingency wells be required based on the performance of the guaranty is capped at $111.5 million. Depending upon the facility’s performancefacility over the first three years after the in-service date, there could be additional construction expendituresdate. The Guaranty of up to $10 million for contingency wells,Principal and Residual Guaranty were executed by a wholly owned subsidiary of which PEP will guarantee 50%.
Piedmont, Piedmont Energy Partners, Inc. Securing
PEP’sour guaranty
iswas a pledge of intercompany notes issued by Piedmont
held byto its non-utility subsidiaries
of PEP. Shouldheld under its wholly owned subsidiary. Also pledged was our membership interest in Hardy Storage.In March 2010, Hardy Storage be unablepaid $3.6 million on the interim notes to perform its payment obligation underenable completion of their conversion to long-term project financing of $119.8 million due in 2023 at an interest rate of 5.88%. As a result of the constructionconversion, our Guaranty of Principal and Residual Guaranty, as executed in connection with the interim financing, PEP will call on Piedmontterminated with no payments having been made. The long-term project financing is nonrecourse to the members of Hardy Storage and their parent entities.
Prior to the long-term financing, we had recorded a liability of $1.2 million for the payment of the notes, plus accrued interest, for the amount of the guaranty. Also pledged is our membership interests in Hardy Storage.
We record a liability at fair value forof this guaranty based on the present value of 50% of the construction financing outstanding at the end of each quarter with the risk of the project evaluated at each quarter end, with a corresponding increase to our investment account in
74
Piedmont Natural Gas Company, Inc.
Notes to Consolidated Financial Statements — (Continued)
the venture. As our risk in the project changes, the fair valueUpon completion of the guaranty ispermanent financing in March 2010, the liability was reversed, and our investment account was adjusted accordingly through a quarterly evaluation. The detailsto reflect the elimination of the guaranty at October 31, 2008 and 2007 are as follows.
| | | | | | | | | |
| | | 2008 | | 2007 |
| | | In thousands |
| |
| Guaranty liability | | $ | 1,234 | | | $ | 1,336 | |
| Amount outstanding under the construction financing | | | 123,410 | | | | 133,556 | |
guaranty.We have related party transactions as a customer of Hardy Storage and record in cost of gas the Hardy storage costs charged to us.by Hardy Storage. For the years ended October 31, 20082011, 2010 and 2007,2009, these gas storage costs and the amounts we owed Hardy Storage as of October 31, 20082011 and 20072010 are as follows.
| | | | | | | | | |
| | | 2008 | | | 2007 | |
| | | In thousands | |
| |
| Gas storage costs | | $ | 9,219 | | | $ | 3,505 | |
| Trade accounts payable | | | 774 | | | | 791 | |
| | | | | | | | | | | | |
In thousands | | 2011 | | | 2010 | | | 2009 | |
Gas storage costs | | $ | 9,702 | | | $ | 9,386 | | | $ | 9,340 | |
Trade accounts payable | | | 808 | | | | 808 | | | | | |
Summarized financial information provided to us by Hardy Storage for 100% of Hardy Storage as of October 31, 20082011 and 2007,2010, and for the twelve months ended October 31, 2008, 20072011, 2010 and 20062009 is presented below.
| | | | | | | | | | | | | |
| | | 2008 | | | 2007 | | | 2006 | |
| | | In thousands | |
| |
| Current assets | | $ | 27,760 | | | $ | 19,972 | | | $ | | |
| Non-current assets | | | 168,160 | | | | 160,326 | | | | | |
| Current liabilities | | | 5,878 | | | | 21,388 | | | | | |
| Non-current liabilities | | | 123,410 | | | | 123,410 | | | | | |
| Revenues | | | 23,658 | | | | 13,902 | | | | * | |
| Gross profit | | | 23,658 | | | | 13,902 | | | | * | |
| Income before income taxes | | | 9,297 | | | | 8,918 | | | | 707 | |
| | |
* | | Hardy Storage was not “in service” during the period presented. The income above is related to AFUDC associated with the financing and construction activities of the storage facilities, and is recorded in accordance with regulatory guidelines. 2006 includes interest expense from a construction loan and operating expenses in addition to AFUDC. |
We | | | | | | | | | | | | |
In thousands | | 2011 | | | 2010 | | | 2009 | |
Current assets | | $ | 7,358 | | | $ | 13,070 | | | | | |
Non-current assets | | | 167,221 | | | | 170,693 | | | | | |
Current liabilities | | | 10,945 | | | | 15,280 | | | | | |
Non-current liabilities | | | 102,490 | | | | 109,495 | | | | | |
Revenues | | | 24,378 | | | | 23,562 | | | $ | 23,465 | |
Gross profit | | | 24,378 | | | | 23,562 | | | | 23,465 | |
Income before income taxes | | | 9,657 | | | | 8,249 | | | | 8,155 | |
13. Variable Interest Entities
Effective November 1, 2010, we adopted the FASB guidance that requires us to evaluate our variable interest in a VIE to qualitatively assess whether we have two reportablea controlling financial interest, and if so, determine whether we are the primary beneficiary. Under accounting guidance, a VIE is a legal entity that conducts a business segments, regulated utilityor holds property whose equity, by design, has any of the following characteristics: an insufficient amount of equity at risk to finance its activities, equity owners who do not have the power to direct the significant activities of the entity (or have voting rights that are disproportionate to their ownership interest), or where equity owners do not receive expected losses or returns. An entity may have an interest in a VIE through ownership or other contractual rights or obligations and non-utility activities. These segments were identified based on productsthat interest changes as the entity’s net assets change. The consolidating investor is the entity that has the power to direct the activities of a VIE that most significantly impact the VIE’s economic performance, and services, regulatory environments and our current corporate organization and business decision-making activities. Operationsthe obligation to absorb losses of our regulated utility segmentthe 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.
As of October 31, 2011, we have determined that we are conductednot the primary beneficiary, as defined by the parent company. Operations of our non-utility activities segment are comprisedauthoritative guidance related to consolidations, in any of our equity method investments, as discussed in joint ventures.
Note 12 to the consolidated financial statements. Based on our involvement in these investments, we do not have the power to direct the activities of these investments that most significantly impact the VIE’s economic performance. As we are not the consolidating investor, we will continue to apply equity method accounting to these investments as discussed in Note 12 to the consolidated financial statements. Our maximum loss exposure related to these equity method investments is limited to our equity investment in each entity. As of October 31, 2011 and 2010, our investment balances are as follows. | | | | | | | | |
In thousands | | October 31,
2011 | | | October 31,
2010 | |
Cardinal | | $ | 18,323 | | | $ | 11,837 | |
Pine Needle | | | 18,690 | | | | 21,810 | |
SouthStar | | | 17,536 | | | | 17,146 | |
Hardy Storage | | | 30,572 | | | | 29,494 | |
| | | | | | | | |
Total equity method investments in non-utility activities | | $ | 85,121 | | | $ | 80,287 | |
| | | | | | | | |
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. Business Segments
Operations of the regulated utility segment are reflected in operating income“Operating Income” in the consolidated statements of income. Operations of the non-utility activities segment are included in the consolidated statements of income in “Income from equity method investments” and “Non-operating income.”
We evaluate the performance of the regulated utility segment based on margin, operations and maintenance expenses and operating income. We evaluate the performance of the non-utility activities segment based on earnings from the ventures. All of our operations are within the United States. No single customer accounts for more than 10% of our consolidated revenues.
75
Piedmont Natural Gas Company, Inc.
Notes to Consolidated Financial Statements — (Continued)
Operations by segment for the years ended October 31, 2008, 20072011, 2010 and 2006,2009, and as of October 31, 20082011, 2010 and 20072009 are presented below.
| | | | | | | | | | | | | |
| | | Regulated
| | | Non-Utility
| | | | |
| | | Utility | | | Activities | | | Total | |
| | | In thousands | |
| |
| 2008 | | | | | | | | | | | | |
| Revenues from external customers | | $ | 2,089,108 | | | $ | — | | | $ | 2,089,108 | |
| Margin | | | 552,973 | | | | — | | | | 552,973 | |
| Operations and maintenance expenses | | | 210,757 | | | | 160 | | | | 210,917 | |
| Depreciation | | | 93,121 | | | | 29 | | | | 93,150 | |
| Income from equity method investments | | | — | | | | 27,718 | | | | 27,718 | |
| Interest expense | | | 59,273 | | | | 79 | | | | 59,352 | |
| Operating income (loss) before income taxes | | | 215,925 | | | | (277 | ) | | | 215,648 | |
| Income before income taxes | | | 156,400 | | | | 27,099 | | | | 183,499 | |
| Total assets | | | 2,908,690 | | | | 99,699 | | | | 3,008,389 | |
| Equity method investments in non-utility activities | | | — | | | | 99,214 | | | | 99,214 | |
| Construction expenditures | | | 181,012 | | | | — | | | | 181,012 | |
| | | | | | | | | | | | | |
| 2007 | | | | | | | | | | | | |
| Revenues from external customers | | $ | 1,711,292 | | | $ | — | | | $ | 1,711,292 | |
| Margin | | | 524,165 | | | | — | | | | 524,165 | |
| Operations and maintenance expenses | | | 214,442 | | | | 325 | | | | 214,767 | |
| Depreciation | | | 88,654 | | | | 29 | | | | 88,683 | |
| Income from equity method investments | | | — | | | | 37,156 | | | | 37,156 | |
| Interest expense | | | 57,272 | | | | — | | | | 57,272 | |
| Operating income (loss) before income taxes | | | 188,662 | | | | (518 | ) | | | 188,144 | |
| Income before income taxes | | | 133,726 | | | | 36,287 | | | | 170,013 | |
| Total assets | | | 2,655,311 | | | | 95,707 | | | | 2,751,018 | |
| Equity method investments in non-utility activities | | | — | | | | 95,193 | | | | 95,193 | |
| Construction expenditures | | | 135,241 | | | | — | | | | 135,241 | |
| | | | | | | | | | | | | |
| 2006 | | | | | | | | | | | | |
| Revenues from external customers | | $ | 1,924,628 | | | $ | — | | | $ | 1,924,628 | |
| Margin | | | 523,479 | | | | — | | | | 523,479 | |
| Operations and maintenance expenses | | | 219,353 | | | | 503 | | | | 219,856 | |
| Depreciation | | | 89,696 | | | | 4 | | | | 89,700 | |
| Income from equity method investments | | | — | | | | 29,917 | | | | 29,917 | |
| Interest expense | | | 52,310 | | | | 50 | | | | 52,360 | |
| Operating income (loss) before income taxes | | | 181,292 | | | | (623 | ) | | | 180,669 | |
| Income before income taxes | | | 130,730 | | | | 28,889 | | | | 159,619 | |
| Construction expenditures | | | 196,730 | | | | 551 | | | | 197,281 | |
76
| | | | | | | | | | | | |
In thousands | | Regulated
Utility | | | Non-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 | |
| | | | | | | | | | | | |
In thousands | | Regulated
Utility | | | Non-Utility
Activities | | | Total | |
2010 | | | | | | | | | | | | |
Revenues from external customers | | $ | 1,552,295 | | | $ | — | | | $ | 1,552,295 | |
Margin | | | 552,592 | | | | — | | | | 552,592 | |
Operations and maintenance expenses | | | 219,829 | | | | 301 | | | | 220,130 | |
Depreciation | | | 98,494 | | | | 29 | | | | 98,523 | |
Income from equity method investments | | | — | | | | 28,854 | | | | 28,854 | |
Gain on sale of interest in equity method investment | | | — | | | | 49,674 | | | | 49,674 | |
Interest expense | | | 43,711 | | | | — | | | | 43,711 | |
Operating income (loss) before income taxes | | | 200,360 | | | | (697 | ) | | | 199,663 | |
Income before income taxes | | | 155,923 | | | | 77,907 | | | | 233,830 | |
Total assets | | | 2,784,087 | | | | 80,808 | | | | 2,864,895 | |
Equity method investments in non-utility activities | | | — | | | | 80,287 | | | | 80,287 | |
Construction expenditures | | | 199,059 | | | | — | | | | 199,059 | |
| | | | | | | | | | | | |
In thousands | | Regulated
Utility | | | Non-Utility
Activities | | | Total | |
2009 | | | | | | | | | | | | |
Revenues from external customers | | $ | 1,638,116 | | | $ | — | | | $ | 1,638,116 | |
Margin | | | 561,574 | | | | — | | | | 561,574 | |
Operations and maintenance expenses | | | 208,105 | | | | 326 | | | | 208,431 | |
Depreciation | | | 97,425 | | | | 29 | | | | 97,454 | |
Income from equity method investments | | | — | | | | 33,464 | | | | 33,464 | |
Interest expense | | | 46,675 | | | | 34 | | | | 46,709 | |
Operating income (loss) before income taxes | | | 221,454 | | | | (503 | ) | | | 220,951 | |
Income before income taxes | | | 171,752 | | | | 32,954 | | | | 204,706 | |
Total assets | | | 2,919,260 | | | | 104,891 | | | | 3,024,151 | |
Equity method investments in non-utility activities | | | — | | | | 104,429 | | | | 104,429 | |
Construction expenditures | | | 129,006 | | | | — | | | | 129,006 | |
Piedmont Natural Gas Company, Inc.
Notes to Consolidated Financial Statements — (Continued)
Reconciliations to the consolidated financial statements for the years ended October 31, 2008, 20072011, 2010 and 2006,2009, and as of October 31, 20082011 and 20072010 are as follows.
| | | | | | | | | | | | | |
| | | 2008 | | | 2007 | | | 2006 | |
| | | In thousands | |
| |
| Operating Income: | | | | | | | | | | | | |
| Segment operating income before income taxes | | $ | 215,648 | | | $ | 188,144 | | | $ | 180,669 | |
| Utility income taxes | | | (62,814 | ) | | | (51,315 | ) | | | (50,543 | ) |
| Non-utility activities before income taxes | | | 277 | | | | 518 | | | | 623 | |
| | | | | | | | | | | | | |
| Total | | $ | 153,111 | | | $ | 137,347 | | | $ | 130,749 | |
| | | | | | | | | | | | | |
| Net Income: | | | | | | | | | | | | |
| Income before income taxes for reportable segments | | $ | 183,499 | | | $ | 170,013 | | | $ | 159,619 | |
| Income taxes | | | (73,492 | ) | | | (65,626 | ) | | | (62,430 | ) |
| | | | | | | | | | | | | |
| Total | | $ | 110,007 | | | $ | 104,387 | | | $ | 97,189 | |
| | | | | | | | | | | | | |
| Consolidated Assets: | | | | | | | | | | | | |
| Total assets for reportable segments | | $ | 3,008,389 | | | $ | 2,751,018 | | | | | |
| Eliminations/Adjustments | | | 85,191 | | | | 69,300 | | | | | |
| | | | | | | | | | | | | |
| Total | | $ | 3,093,580 | | | $ | 2,820,318 | | | | | |
| | | | | | | | | | | | | |
| |
12. | Restructuring and Other Termination Benefits |
In 2006, we restructured our management group | | | | | | | | | | | | |
In thousands | | 2011 | | | 2010 | | | 2009 | |
Operating Income: | | | | | | | | | | | | |
Segment operating income before income taxes | | $ | 206,959 | | | $ | 199,663 | | | $ | 220,951 | |
Utility income taxes | | | (64,068 | ) | | | (62,082 | ) | | | (70,079 | ) |
Non-utility activities operating loss before income taxes | | | 120 | | | | 697 | | | | 503 | |
| | | | | | | | | | | | |
Total | | $ | 143,011 | | | $ | 138,278 | | | $ | 151,375 | |
| | | | | | | | | | | | |
Net Income: | | | | | | | | | | | | |
Income before income taxes for reportable segments | | $ | 185,854 | | | $ | 233,830 | | | $ | 204,706 | |
Income taxes | | | (72,286 | ) | | | (91,876 | ) | | | (81,882 | ) |
| | | | | | | | | | | | |
Total | | $ | 113,568 | | | $ | 141,954 | | | $ | 122,824 | |
| | | | | | | | | | | | |
| | | | | | | | |
In thousands | | 2011 | | | 2010 | |
Consolidated Assets: | | | | | | | | |
Total assets for reportable segments | | $ | 3,054,093 | | | $ | 2,864,895 | |
Eliminations/Adjustments | | | 188,448 | | | | 188,380 | |
| | | | | | | | |
Total | | $ | 3,242,541 | | | $ | 3,053,275 | |
| | | | | | | | |
15. Subsequent Events
We monitor significant events occurring after the balance sheet date and recognized a liability and expense of $7.9 million, which was included inprior to the regulated utility segment in operations and maintenance expense for the costissuance of the restructuring program. This restructuring wasfinancial statements to determine the beginningimpacts, if any, of an ongoing, larger effort aimed at streamlining business processes, capturing operational and organizational efficiencies and improving customer service. This liability included early retirement for 22 employeesevents on the financial statements to be issued. All subsequent events of the management group and severance for 17 additional employees through further consolidation. Duewhich we are aware were evaluated. For information on subsequent event disclosure items related to regulatory matters, see Note 2 to the short discount period, the liability for the program was recorded at its gross value. As of October 31, 2008 and 2007, there was no remaining liability for the management group restructuring program.
In 2007, we implemented additional organizational changes under our business process improvement program to streamline business processes, capture operational and organizational efficiencies and improve customer service. As a part of this effort, we began initiating changes in our customer payment and collection processes, including no longer accepting customer payments in our business offices and streamlining our district operations. We also further consolidated our call centers. Collections of delinquent accounts have been consolidated in our central business office. These specific initiatives were largely completed as of October 31, 2008.
We have accrued costs in connection with these initiatives in the form of severance benefits to employees who will be either voluntarily or involuntarily severed. These benefits are under existing arrangements and are accounted for in accordance with SFAS No. 112, “Employers’ Accounting for Postemployment Benefits.” All costs are included in the regulated utility segment in “Operations and maintenance” expenses in the consolidated statements of income.
77
Piedmont Natural Gas Company, Inc.
Notes to Consolidated Financial Statements — (Continued)
A reconciliation of activity to the liability as of October 31, 2008 and 2007 is as follows.
| | | | | | | | | |
| | | 2008 | | | 2007 | |
| | | In thousands | |
| |
| Beginning liability | | $ | 1,459 | | | $ | — | |
| Costs incurred and expensed | | | — | | | | 3,648 | |
| Costs paid | | | (1,132 | ) | | | (2,189 | ) |
| Adjustment to accruals | | | (305 | ) | | | — | |
| | | | | | | | | |
| Ending liability | | $ | 22 | | | $ | 1,459 | |
| | | | | | | | | |
On November 25, 2008, we filed an expedited petition with the PSCSC requesting approval to reduce the hedging horizon from 24 months to twelve months under the gas cost hedging plan, effective December 1, 2008. The PSCSC approved the request on December 10, 2008.
* * * * * *
16. Selected Quarterly Financial Data (In thousands except per share amounts) (Unaudited)
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | Earnings (Loss)
| |
| | | | | | | | | | | | Net
| | | Per Share of
| |
| | | Operating
| | | | | | Operating
| | | Income
| | | Common Stock | |
| | | Revenues | | | Margin | | | Income | | | (Loss) | | | Basic | | | Diluted | |
| |
| Fiscal Year 2008 | | | | | | | | | | | | | | | | | | | | | | | | |
| January 31 | | $ | 788,470 | | | $ | 227,026 | | | $ | 91,936 | | | $ | 82,268 | | | $ | 1.12 | | | $ | 1.12 | |
| April 30 | | | 634,178 | | | | 161,281 | | | | 51,822 | | | | 48,624 | | | | 0.66 | | | | 0.66 | |
| July 31 | | | 354,709 | | | | 77,020 | | | | 2,619 | | | | (7,678 | ) | | | (0.10 | ) | | | (0.10 | ) |
| October 31 | | | 311,751 | | | | 87,646 | | | | 6,734 | | | | (13,207 | ) | | | (0.18 | ) | | | (0.18 | ) |
| Fiscal Year 2007 | | | | | | | | | | | | | | | | | | | | | | | | |
| January 31 | | $ | 677,241 | | | $ | 208,485 | | | $ | 81,697 | | | $ | 70,716 | | | $ | 0.95 | | | $ | 0.94 | |
| April 30 | | | 531,579 | | | | 159,727 | | | | 50,621 | | | | 51,120 | | | | 0.69 | | | | 0.69 | |
| July 31 | | | 224,442 | | | | 75,158 | | | | 1,021 | | | | (9,140 | ) | | | (0.12 | ) | | | (0.12 | ) |
| October 31 | | | 278,030 | | | | 80,795 | | | | 4,008 | | | | (8,309 | ) | | | (0.11 | ) | | | (0.11 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | Earnings (Loss)
Per Share of
Common Stock | |
| | | | | | | | | Operating
Income
(Loss) | | | Net
Income
(Loss) | | |
| | | Operating
Revenues | | | | | | | |
| | | | Margin | | | | | Basic | | | Diluted | |
Fiscal Year 2011 | | | | | | | | | | | | | | | | | | | | | | | | |
January 31 | | $ | 652,056 | | | $ | 230,006 | | | $ | 90,869 | | | $ | 84,440 | | | $ | 1.17 | | | $ | 1.16 | |
April 30 | | | 392,567 | | | | 172,931 | | | | 52,927 | | | | 47,408 | | | | 0.66 | | | | 0.66 | |
July 31 | | | 197,274 | | | | 81,963 | | | | 389 | | | | (8,703 | ) | | | (0.12 | ) | | | (0.12 | ) |
October 31 | | | 192,008 | | | | 88,739 | | | | (1,174 | ) | | | (9,577 | ) | | | (0.13 | ) | | | (0.13 | ) |
Fiscal Year 2010 | | | | | | | | | | | | | | | | | | | | | | | | |
January 31 | | $ | 673,736 | | | $ | 222,942 | | | $ | 87,801 | | | $ | 113,749 | | | $ | 1.55 | | | $ | 1.55 | |
April 30 | | | 472,846 | | | | 168,678 | | | | 52,225 | | | | 46,825 | | | | 0.65 | | | | 0.65 | |
July 31 | | | 211,603 | | | | 77,897 | | | | (3,471 | ) | | | (9,518 | ) | | | (0.13 | ) | | | (0.13 | ) |
October 31 | | | 194,110 | | | | 83,075 | | | | 1,723 | | | | (9,102 | ) | | | (0.13 | ) | | | (0.13 | ) |
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.
78
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial DisclosureNone.
| |
Item 9. | Changes in and Disagreements With Accountants on Accounting and Financial Disclosure |
None.
| |
Item 9A. | Controls and Procedures |
Item 9A. Controls and ProceduresManagement’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 inRules 13a-15(e) and15d-15(e) under the Exchange Act. Based on such evaluation, the President and Chief Executive Officer and the Senior Vice President and Chief Financial Officer concluded that,Act as of the end of the period covered by thisForm 10-K, our10-K. Such disclosure controls and procedures were effective in that theyare designed to provide reasonable assurancesassurance 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 specifiedrequired 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 inRules 13a-15(f) and15d-15(f) under the Exchange Act during the fourth quarter of fiscal 20082011 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
79
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
23, 2011Our management is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting as that term is defined inRules 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 and Ethics 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” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based upon such evaluation, our management concluded that as of October 31, 2008,2011, 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, 2008.
Piedmont Natural Gas Company, Inc.
Thomas E. Skains
Chairman, President and Chief Executive Officer
| | |
| | /s/ David J. DzurickyPiedmont Natural Gas Company, Inc. |
David J. Dzuricky
Senior Vice President and Chief Financial Officer
| | |
| | /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 |
Jose M. Simon
Vice President and Controller
80
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, 2008,2011, based on the criteria established inInternal Control — Control—Integrated Frameworkissued 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 Overover 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, 2008,2011, based on the criteria established inInternal Control — Control—Integrated Frameworkissued 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, 20082011 of the Company and our report dated December 29, 200823, 2011 expressed an unqualified opinion on those financial statements.
/s/ Deloitte & Touche LLP
Charlotte, North Carolina
December 29, 2008
81
| |
Item 9B. | Other Information/s/ Deloitte & Touche LLP |
None.
PART III
| |
Item 10.Charlotte, North Carolina |
Directors, Executive Officers and Corporate GovernanceDecember 23, 2011 |
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 “Information Regarding the Board of Directors” and “Executive Officers” in our Proxy Statement for the 20092012 Annual Meeting of Shareholders, which sections are incorporated in this annual report onForm 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 Proxy Statement for the 20092012 Annual Meeting of Shareholders, which section is incorporated in this annual report onForm 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 Proxy Statement for the 20092012 Annual Meeting of Shareholders, which section is incorporated in this annual report onForm 10-K by reference.
We have adopted a Code of Ethics and Business Conduct and Ethics that is applicable to all our directors, officers and employees, including our principal executive officer, principal financial officer and principal accounting officer. We have also adopted Special Provisions Relating to the Company’s Principal Executive Officer and Senior Financial Officers (Special Provisions) that are part of our Corporate Governance Guidelines and that apply to our principal executive officer, principal financial officer and principal accounting officer. The Code of Ethics and Business Conduct and Ethics was filed as Exhibit 14.1 to our annual report onForm 10-K for the year ended October 31, 2003, and isSpecial Provisions are available on the “For Investors-Corporate Governance” section of our website atwww.piedmontng.com.www.piedmontng.com. If we amend the Code of Business Conduct and Ethics or grant a waiver, including an implicit waiver, from the Code of Ethics and Business Conduct and Ethicsor Special Provisions that apply to the principal executive officer, principal financial officer and controller or persons performing similar functions and that relate to any element of the code enumerated in Item 406(b) ofRegulation S-K, we will disclose the amendment or waiver on the “About Us-Corporate“For Investors-Corporate Governance” section of our website within four business days of such amendment or waiver.
| |
Item 11. | Executive Compensation |
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 Proxy Statement for the 20092012 Annual Meeting of Shareholders, which sections are incorporated in this annual report onForm 10-K by reference.
| |
Item 12. | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters |
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 Proxy Statement for the 20092012 Annual Meeting of Shareholders, which section is incorporated in this annual report onForm 10-K by reference.
We know of no arrangement, or pledge, which may result in a change in control.
Information concerning securities authorized for issuance under our equity compensation plans is set forth in the section entitled “Equity Compensation Plan Information” in our Proxy Statement for the 20092012 Annual Meeting of Shareholders, which section is incorporated in this annual report onForm 10-K by reference.
| |
Item 13. | Certain Relationships and Related Transactions, and Director Independence |
Item 13. Certain Relationships and Related Transactions, and Director Independence
Information for this item is set forth in the section entitled “Independence of Board Members and Related PartyPerson Transactions” in our Proxy Statement for the 20092012 Annual Meeting of Shareholders, which section is incorporated in this annual report onForm 10-K by reference.
| |
Item 14. | Principal Accounting Fees and Services |
Item 14. Principal Accounting Fees and Services
Information for this item is set forth in the table entitled “Fees For Services” in “Proposal B —2 – Ratification of the Appointment of Deloitte & Touche LLP As Independent Registered Public Accounting Firm For Fiscal Year 2009”2012” in our Proxy Statement for the 20092012 Annual Meeting of Shareholders, which section is incorporated in this annual report onForm 10-K by reference.
82
PART IVItem 15. Exhibits, Financial Statement Schedules
| | | | |
Item 15.(a) | Exhibits, | 1. | | Financial Statement SchedulesStatements |
(a) 1. Financial Statements
The following consolidated financial statements for the year ended October 31, 2008,2011, are included in Item 8 of this report as follows:
| | | | |
| 2010 | | | 37 | |
| 2009 | | | 38 | |
| 2009 | | | 39 | |
| 2009 | | | 40 | |
| | |
41Report of Independent Registered Public Accounting Firm | | |
(a) 2. Supplemental Consolidated Financial Statement Schedules
| | | | |
(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 10.21 are management contracts or compensatory plans or arrangements. |
| | 3 | .1 | | Articles of Incorporation of the Company as of March 3, 2006, filed in the Department of State of the State of North Carolina (Exhibit 4.1,Form S-8 Registration StatementNo. 333-132738). |
| | 3 | .2 | | Copy of Certificate of Merger (New York) and Articles of Merger (North Carolina), each dated March 1, 1994, evidencing merger of Piedmont Natural Gas Company, Inc., with and into PNG Acquisition Company, with PNG Acquisition Company being renamed “Piedmont Natural Gas Company, Inc.” (Exhibits 3.2 and 3.1, Registration Statement onForm 8-B, dated March 2, 1994). |
| | 3 | .3 | | By-Laws of Piedmont Natural Gas Company, Inc., dated December 15, 2006 (Exhibit 3.3,Form 10-K for the fiscal year ended October 31, 2007). |
| | 4 | .1 | | Note Agreement, dated as of September 21, 1992, between Piedmont and Provident Life and Accident Insurance Company (Exhibit 4.30,Form 10-K for the fiscal year ended October 31, 1992). |
| | 4 | .2 | | Amendment to Note Agreement, dated as of September 16, 2005, by and between Piedmont and Provident Life and Accident Insurance Company (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 (Exhibit 4.1,Form S-3 Registration StatementNo. 33-59369). |
| | 4 | .4 | | Medium-Term Note, Series A, dated as of October 6, 1993 (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 (Exhibit 4.2,Form S-3 Registration StatementNo. 33-59369). |
| | 4 | .6 | | Medium-Term Note, Series A, dated as of September 19, 1994 (Exhibit 4.9,Form 10-K for the fiscal year ended October 31, 1994). |
| | 4 | .7 | | Form of Master Global Note (Exhibit 4.4,Form S-3 Registration StatementNo. 33-59369). |
| | 4 | .8 | | Pricing Supplement of Medium-Term Notes, Series B, dated October 3, 1995 (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 (Exhibit 4.11,Form 10-K for the fiscal year ended October 31, 1996). |
83
| | | | |
| (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 10.21 are management contracts or compensatory plans or arrangements. |
| | |
| | 3.1 | | Restated Articles of Incorporation of Piedmont Natural Gas Company, Inc., dated as of March 2009 (Exhibit 3.1, Form 10-Q for the quarter ended July 31, 2009). |
| | |
| | 3.2 | | By-laws of Piedmont Natural Gas Company, Inc., as Amended and Restated Effective September 8, 2011 (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 (Exhibit 4.30, Form 10-K for the fiscal year ended October 31, 1992). |
| | | | |
| | |
| | 4.2 | | Amendment to Note Agreement, dated as of September 16, 2005, by and between Piedmont and Provident Life and Accident Insurance Company (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 (Exhibit 4.1, Form S-3 Registration Statement No. 33-59369). |
| | |
| | 4.4 | | Medium-Term Note, Series A, dated as of October 6, 1993 (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 (Exhibit 4.2, Form S-3 Registration Statement No. 33-59369). |
| | |
| | 4.6 | | Medium-Term Note, Series A, dated as of September 19, 1994 (Exhibit 4.9, Form 10-K for the fiscal year ended October 31, 1994). |
| | |
| | 4.7 | | Form of Master Global Note (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 (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 (Exhibit 4.11, Form 10-K for the fiscal year ended October 31, 1996). |
| | |
| | 4.10 | | Form of Master Global Note, executed September 9, 1999 (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 (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 (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 (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 (Exhibit 99.2, Form 8-K, dated December 23, 2003). |
| | | | | |
| | 4 | .10 | | Rights Agreement, dated as of February 27, 1998, between Piedmont and Wachovia Bank, N.A., as Rights Agent, including the Rights Certificate (Exhibit 10.1,Form 8-K dated February 27, 1998). |
| | 4 | .11 | | Agreement of Substitution and Amendment of Common Shares Rights Agreement, dated as of December 18, 2003, between Piedmont and American Stock Transfer and Trust Company, Inc. (Exhibit 4.10,Form S-3 Registration StatementNo. 333-111806). |
| | 4 | .12 | | Form of Master Global Note, executed September 9, 1999 (Exhibit 4.4,Form S-3 Registration StatementNo. 333-26161). |
| | 4 | .13 | | Pricing Supplement of Medium-Term Notes, Series C, dated September 15, 1999 (Rule 424(b)(3) Pricing Supplement toForm S-3 Registration Statement Nos.33-59369 and333-26161). |
| | 4 | .14 | | Pricing Supplement of Medium-Term Notes, Series C, dated September 15, 1999 (Rule 424(b)(3) Pricing Supplement toForm S-3 Registration Statement Nos.33-59369 and333-26161). |
| | 4 | .15 | | Pricing Supplement No. 3 of Medium-Term Notes, Series C, dated September 26, 2000 (Rule 424(b)(3) Pricing Supplement toForm S-3 Registration StatementNo. 333-26161). |
| | 4 | .16 | | Form of Master Global Note, executed June 4, 2001 (Exhibit 4.4,Form S-3 Registration StatementNo. 333-62222). |
| | 4 | .17 | | Pricing Supplement No. 1 of Medium-Term Notes, Series D, dated September 18, 2001 (Rule 424(b)(3) Pricing Supplement toForm S-3 Registration StatementNo. 333-62222). |
| | 4 | .18 | | Second Supplemental Indenture, dated as of June 15, 2003, between Piedmont and Citibank, N.A., Trustee (Exhibit 4.3,Form S-3 Registration StatementNo. 333-106268). |
| | 4 | .19 | | Form of 5% Medium-Term Note, Series E, dated as of December 19, 2003 (Exhibit 99.1,Form 8-K, dated December 23, 2003). |
| | 4 | .20 | | Form of 6% Medium-Term Note, Series E, dated as of December 19, 2003 (Exhibit 99.2,Form 8-K, dated December 23, 2003). |
| | 4 | .21 | | Third Supplemental Indenture, dated as of June 20, 2006, between Piedmont Natural Gas Company, Inc. and Citibank, N.A., as trustee (Exhibit 4.1,Form 8-K dated June 20, 2006). |
| | 4 | .22 | | Form of 6.25% Insured Quarterly Note Series 2006, Due 2036 (Exhibit 4.2 (as included in Exhibit 4.1),Form 8-K dated June 20, 2006). |
| | 4 | .23 | | Agreement of Resignation, Appointment and Acceptance dated as of March 29, 2007, by and among the registrant, Citibank, N.A., and The Bank of New York Trust Company, N.A. (Exhibit 4.1,Form 10-Q for quarter ended April 30, 2007). |
| | | | | Compensatory Contracts: |
| | 10 | .1 | | Form of Director Retirement Benefits Agreement with outside directors, dated September 1, 1999 (Exhibit 10.54,Form 10-K for the fiscal year ended October 31, 1999). |
| | 10 | .2 | | Establishment of Measures for Long-Term Incentive Plan 10 (filed inForm 8-K dated October 20, 2006, as Item 1.01). |
| | 10 | .3 | | Form of Award Agreement under Executive Long-Term Incentive Plan (Exhibit 10.5,Form 10-K for the fiscal year ended October 31, 2006). |
| | 10 | .4 | | Employment Agreement with David J. Dzuricky, dated December 1, 1999 (Exhibit 10.37,Form 10-K for the fiscal year ended October 31, 1999). |
| | 10 | .5 | | Employment Agreement with Thomas E. Skains, dated December 1, 1999 (Exhibit 10.40,Form 10-K for the fiscal year ended October 31, 1999). |
| | 10 | .6 | | Employment Agreement with Franklin H. Yoho, dated March 18, 2002 (Exhibit 10.23,Form 10-K for the fiscal year ended October 31, 2002). |
| | 10 | .7 | | Employment Agreement with Michael H. Yount, dated May 1, 2006 (Exhibit 10.1,Form 10-Q for the quarter ended April 30, 2006). |
| | 10 | .8 | | Employment Agreement with Kevin M. O’Hara, dated May 1, 2006 (Exhibit 10.2,Form 10-Q for the quarter ended April 30, 2006). |
| | 10 | .9 | | Form of Severance Agreement with Thomas E. Skains, dated September 4, 2007 (Substantially identical agreements have been entered into as of the same date with David J. Dzuricky, Franklin H. Yoho, Michael H. Yount, Kevin M. O’Hara, June B. Moore and Jane R. Lewis-Raymond) (Exhibit 10.2,Form 10-Q for the quarter ended July 31, 2007). |
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| | | | |
| | |
| | 4.15 | | Third Supplemental Indenture, dated as of June 20, 2006, between Piedmont Natural Gas Company, Inc. and Citibank, N.A., as trustee (Exhibit 4.1, Form 8-K dated June 20, 2006). |
| | |
| | 4.16 | | 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. (Exhibit 4.1, Form 10-Q for quarter ended April 30, 2007). |
| | |
| | 4.17 | | Note Purchase Agreement, dated as of May 6, 2011, among Piedmont Natural Gas Company, Inc. and the Purchasers party thereto (Exhibit 10, Form 8-K, dated May 12, 2011). |
| | |
| | 4.18 | | Form of 2.92% Series A Senior Notes due June 6, 2016 (Exhibit 4.1, Form 8-K dated May 12, 2011). |
| | |
| | 4.19 | | Form of 4.24% Series B Senior Notes due June 6, 2021 (Exhibit 4.2, Form 8-K dated May 12, 2011). |
| | |
| | 4.20 | | 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 (Exhibit 4.2, Form S-3-ASR Registration Statement No. 333-175386). |
| | |
| | 4.21 | | 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 (Exhibit 10.3, Form 10-Q for the quarter ended April 30, 2011). |
| | |
| | | | Compensatory Contracts: |
| | |
| | 10.1 | | Form of Director Retirement Benefits Agreement with outside directors, dated September 1, 1999 (Exhibit 10.54, Form 10-K for the fiscal year ended October 31, 1999). |
| | |
| | 10.2 | | Establishment of Measures for Long-Term Incentive Plan 10 (filed in Form 8-K dated October 20, 2006, as Item 1.01). |
| | |
| | 10.3 | | Employment Agreement with Thomas E. Skains, dated December 1, 1999 (Exhibit 10.40, Form 10-K for the fiscal year ended October 31, 1999). |
| | |
| | 10.4 | | Employment Agreement with Franklin H. Yoho, dated March 18, 2002 (Exhibit 10.23, Form 10-K for the fiscal year ended October 31, 2002). |
| | |
| | 10.5 | | Employment Agreement with Michael H. Yount, dated May 1, 2006 (Exhibit 10.1, Form 10-Q for the quarter ended April 30, 2006). |
| | | | |
| | |
| | 10.6 | | Employment Agreement with Kevin M. O’Hara, dated May 1, 2006 (Exhibit 10.2, Form 10-Q for the quarter ended April 30, 2006). |
| | |
| | 10.7 | | Form of 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, Michael H. Yount, Kevin M. O’Hara and Jane R. Lewis-Raymond) (Exhibit 10.2, Form 10-Q for the quarter ended July 31, 2007). |
| | |
| | 10.8 | | Schedule of Severance Agreements with Executives (Exhibit 10.2a, Form 10-Q for the quarter ended July 31, 2007). |
| | |
| | 10.9 | | Piedmont Natural Gas Company, Inc. Incentive Compensation Plan as Amended and Restated Effective December 15, 2010 (Appendix A, Form DEF14A dated January 14, 2011). |
| | |
| | 10.10 | | Form of Performance Unit Award Agreement (Exhibit 10.1, Form 10-Q for the quarter ended January 31, 2011). |
| | |
| | 10.11 | | Resolution of Board of Directors, June 3, 2011, establishing compensation for non-management directors (Exhibit 10.1, Form 10-Q for the quarter ended July 31, 2011). |
| | |
| | 10.12 | | Piedmont Natural Gas Company, Inc. Voluntary Deferral Plan, dated as of December 8, 2008, effective November 1, 2008 (Exhibit 10.1, Form 10-Q for the quarter ended January 31, 2009). |
| | |
| | 10.13 | | Piedmont Natural Gas Company, Inc. Defined Contribution Restoration Plan, dated as of December 8, 2008, effective January 1, 2009 (Exhibit 10.2, Form 10-Q for the quarter ended January 31, 2009). |
| | |
| | 10.14 | | Piedmont Natural Gas Company Employee Stock Purchase Plan, amended and restated as of April 1, 2009 (Exhibit 4.1, Form 8-K dated April 3, 2009). |
| | |
| | 10.15 | | Amendment No. 1 to Director Retirement Benefits Agreements with outside directors, dated as of December 31, 2008 (Exhibit 10.1, Form 10-Q for the quarter ended July 31, 2009). |
| | |
| | 10.16 | | Form of Amendment No. 1 to Employment Agreement between Piedmont Natural Gas Company, Inc. and Thomas A. Skains, dated as of June 4, 2010 (Substantially identical agreements have been entered into as of the same date with Kevin M. O’Hara, Michael H. Yount and Franklin H. Yoho) (Exhibit 10.1, Form 10-Q for the quarter ended July 31, 2010). |
| | | | |
| | |
| | 10.17 | | Employment Agreement between Piedmont Natural Gas Company, Inc. and Karl W. Newlin, dated as of June 4, 2010 (Exhibit 10.2, Form 10-Q for the quarter ended July 31, 2010). |
| | |
| | 10.18 | | Severance Agreement between Piedmont Natural Gas Company, Inc. and Karl W. Newlin, dated as of June 4, 2010 (Exhibit 10.3, Form 10-Q for the quarter ended July 31, 2010). |
| | |
| | 10.19 | | Employment Agreement between Piedmont Natural Gas Company, Inc. and Jane R. Lewis-Raymond, dated as of August 1, 2011. |
| | |
| | 10.20 | | Form of 2013 Retention Award Agreement (Exhibit 10.2, Form 10-Q for the quarter ended January 31, 2011). |
| | |
| | 10.21 | | Consulting Agreement dated as of November 1, 2011 between David J. Dzuricky and Piedmont Natural Gas Company, Inc. |
| | |
| | | | Other Contracts: |
| | |
| | 10.22 | | 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 (Exhibit 10.1, Form 10-Q for the quarter ended April 30, 2004). |
| | |
| | 10.23 | | First Amendment to Amended and Restated Limited Liability Company Agreement of SouthStar Energy Services LLC, dated as of July 31, 2006, between Piedmont Energy Company and Georgia Natural Gas Company (Exhibit 10.28, 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 August 28, 2006, between Piedmont Energy Company and Georgia Natural Gas Company (Exhibit 10.29, Form 10-K for the fiscal year ended October 31, 2006). |
| | |
| | 10.25 | | 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 (Exhibit 10.30, Form 10-K for the fiscal year ended October 31, 2006). |
| | |
| | 10.26 | | Equity Contribution Agreement, dated as of November 12, 2004, between Columbia Gas Transmission Corporation and Piedmont Natural Gas Company (Exhibit 10.1, Form 8-K dated November 16, 2004). |
| | | | | |
| | 10 | .10 | | Schedule of Severance Agreements with Executives (Exhibit 10.2a,Form 10-Q for the quarter ended July 31, 2007). |
| | 10 | .11 | | Piedmont Natural Gas Company, Inc. Supplemental Executive Benefit Plan (Amended and Restated as of November 1, 2004) (Exhibit 10.1,Form 8-K dated December 10, 2004). |
| | 10 | .12 | | Form of Participation Agreement under the Piedmont Natural Gas Company, Inc. Supplemental Executive Benefit Plan (Amended and Restated as of November 1, 2004) (with supplemental retirement benefit) (Exhibit 10.14,Form 10-K for the fiscal year ended October 31, 2004). |
| | 10 | .13 | | Form of Participation Agreement under the Piedmont Natural Gas Company, Inc. Supplemental Executive Benefit Plan (Amended and Restated as of November 1, 2004) (without supplemental retirement benefit) (Exhibit 10.15,Form 10-K for the fiscal year ended October 31, 2004). |
| | 10 | .14 | | Piedmont Natural Gas Company, Inc. Incentive Compensation Plan (Exhibit 10.1,Form 8-K dated March 3, 2006). |
| | 10 | .15 | | Restricted Stock Award Agreement between Piedmont Natural Gas Company, Inc. and Thomas E. Skains, dated September 1, 2006 (Exhibit 10.26,Form 10-K for the fiscal year ended October 31, 2006). |
| | 10 | .16 | | Form of Participation Agreement under the Piedmont Natural Gas Company, Inc. Short-Term Incentive Plan (STIP) (Exhibit 10.1,Form 10-Q for the quarter ended April 30, 2007). |
| | 10 | .17 | | Form of Performance Unit Award Agreement (Exhibit 10.1,Form 10-Q for the quarter ended July 31, 2007). |
| | 10 | .18 | | Amendment No. 1 to the Piedmont Natural Gas Company Executive Long-Term Incentive Plan, dated September 7, 2007 (Exhibit 10.22,Form 10-K for the fiscal year ended October 31, 2007). |
| | 10 | .19 | | Resolution of Board of Directors, September 7, 2007, establishing compensation for non-management directors (Exhibit 10.23,Form 10-K for the fiscal year ended October 31, 2007). |
| | 10 | .20 | | Incentive Compensation Plan Interpretive Guidelines as of September 7, 2007 (Exhibit 10.24,Form 10-K for the fiscal year ended October 31, 2007). |
| | 10 | .21 | | Executive Long-Term Incentive Plan, dated February 27, 2004 (Corrected) (Exhibit 10.1,Form 10-Q for quarter ended April 30, 2008). |
| | | | | Other Contracts: |
| | 10 | .22 | | 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 (Exhibit 10.1,Form 10-Q for the quarter ended April 30, 2004). |
| | 10 | .23 | | First Amendment to Amended and Restated Limited Liability Company Agreement of SouthStar Energy Services LLC, dated as of July 31, 2006, between Piedmont Energy Company and Georgia Natural Gas Company (Exhibit 10.28,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 August 28, 2006, between Piedmont Energy Company and Georgia Natural Gas Company (Exhibit 10.29,Form 10-K for the fiscal year ended October 31, 2006). |
| | 10 | .25 | | 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 (Exhibit 10.30,Form 10-K for the fiscal year ended October 31, 2006). |
| | 10 | .26 | | Equity Contribution Agreement, dated as of November 12, 2004, between Columbia Gas Transmission Corporation and Piedmont Natural Gas Company (Exhibit 10.1,Form 8-K dated November 16, 2004). |
| | 10 | .27 | | Construction, Operation and Maintenance Agreement by and Between Columbia Gas Transmission Corporation and Hardy Storage Company, LLC, dated November 12, 2004 (Exhibit 10.2,Form 8-K dated November 16, 2004). |
| | 10 | .28 | | Operating Agreement of Hardy Storage Company, LLC, dated as of November 12, 2004 (Exhibit 10.3,Form 8-K dated November 16, 2004). |
| | 10 | .29 | | Guaranty of Principal dated as of June 29, 2006, by Piedmont Energy Partners, Inc. in favor of U.S. Bank National Association, as agent (Exhibit 10.1,Form 8-K dated July 5, 2006). |
| | 10 | .30 | | Residual Guaranty dated as of June 29, 2006, by Piedmont Energy Partners, Inc. in favor of U.S. Bank National Association, as agent (Exhibit 10.2,Form 8-K dated July 5, 2006). |
85
| | | | |
| | |
| | 10.27 | | Construction, Operation and Maintenance Agreement by and Between Columbia Gas Transmission Corporation and Hardy Storage Company, LLC, dated November 12, 2004 (Exhibit 10.2, Form 8-K dated November 16, 2004). |
| | |
| | 10.28 | | Operating Agreement of Hardy Storage Company, LLC, dated as of November 12, 2004 (Exhibit 10.3, Form 8-K dated November 16, 2004). |
| | |
| | 10.29 | | Second Amendment to Amended and Restated Limited Liability Company Agreement of SouthStar Energy Services LLC by and between Georgia Natural Gas Company and Piedmont Energy Company, dated July 2, 2009 (Exhibit 10.2, Form 10-Q for the quarter ended July 31, 2009). |
| | |
| | 10.30 | | Settlement Agreement by and between Georgia Natural Gas Company and Piedmont Energy Company, dated July 29, 2009 (Exhibit 10.1, Form 8-K dated August 4, 2009). |
| | |
| | 10.31 | | 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 (Exhibit 10.2, Form 8-K dated August 4, 2009). |
| | |
| | 10.32 | | Assignment and Assumption between Citibank, N.A. and Northern Trust Company, dated as of September 18, 2009 (Exhibit 10.37, Form 10-K for the fiscal year ended October 31, 2009). |
| | |
| | 10.33 | | Credit Agreement dated as of January 25, 2011 among Piedmont Natural Gas Company, Inc., Bank of America, N.A., as Administrative Agent, Swing Line Lender, and L/C Issuer, Branch Banking and Trust Company and U.S. Bank National Association as Co-Syndication Agents, and the other Lenders party thereto (Exhibit 10.1, Form 8-K filed January 31, 2011). |
| | |
| | 10.34 | | Amendment No. 1 to Credit Agreement dated as of March 21, 2011 by and among Piedmont Natural Gas Company, Inc., Bank of America, N.A., as Administrative Agent, Swing Line Lender and L/C Issuer, and the Lenders thereunder (Exhibit 10.2, Form 10-Q for the quarter ended April 30, 2011). |
| | |
| | 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 (1) |
| | 101.SCH | | XBRL Taxonomy Extension Schema (1) |
| | 101.CAL | | XBRL Taxonomy Calculation Linkbase (1) |
| | 101.DEF | | XBRL Taxonomy Definition Linkbase (1) |
| | 101.LAB | | XBRL Taxonomy Extension Label Linkbase (1) |
| | 101.PRE | | XBRL Taxonomy Extension Presentation Linkbase (1) |
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, 2011 and 2010; (3) Consolidated Statements of Income for the years ended October 31, 2011, 2010 and 2009; (4) Consolidated Statements of Cash Flows for the years ended October 31, 2011, 2010 and 2009; (5) Consolidated Statements of Stockholders’ Equity for the years ended October 31, 2011, 2010 and 2009; and Notes to Consolidated Financial Statements.
Pursuant to Rule 406T of Regulation S-T, these interactive data files are deemed furnished, not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933 or Section 18 of the Securities Exchange Act of 1934 and otherwise are not subject to liability. We also make available on our web site the Interactive Data Files submitted as Exhibit 101 to this Annual Report.
| | | | | |
| | 10 | .31 | | Credit Agreement dated as of April 25, 2006 among Piedmont Natural Gas Company, Inc. and Bank of America, N.A. as Administrative Agent, Swing Line Lender and L/C Issuer, and The Other Lenders Party Hereto (Exhibit 10.1,Form 10-Q for the quarter ended January 31, 2008). |
| | 10 | .32 | | Revolving Credit Facility between Piedmont Natural Gas Company, Inc. and Bank of America, N.A., dated October 27, 2008. |
| | 10 | .33 | | Revolving Credit Facility between Piedmont Natural Gas Company, Inc. and Branch Banking and Trust Company, dated October 29, 2008. |
| | 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. |
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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)
| | |
| 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, 2011 |
Thomas E. Skains
Chairman of the Board, President
and Chief Executive Officer
Date: December 29, 2008
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
| | |
/s/ THOMAS E. SKAINS Thomas E. Skains | | Title
|
|
| | |
/s/ Thomas E. Skains
Thomas E. Skains | | Chairman of the Board, President and
Chief Executive Officer
(Principal Executive Officer) |
| | |
Date: December 23, 2011 | | |
Date: December 29, 2008 | | |
| | |
/s/ KARL W. NEWLIN Karl W. Newlin | | |
/s/ David J. Dzuricky
David J. Dzuricky | | Senior Vice President and
Chief Financial Officer
(Principal Financial Officer) |
| | |
Date: December 23, 2011 | | |
Date: December 29, 2008 | | |
| | |
/s/ JOSE M. SIMON Jose M. Simon | | |
/s/ Jose M. Simon
Jose M. Simon | | Vice President and Controller
(Principal Accounting Officer) |
| | |
Date: December 23, 2011 | | |
Date: December 29, 2008 | | |
87
| | | | |
| Signature | | | | Title |
Signature
| | |
/s/ E. JAMES BURTON E. James Burton | | Title
|
|
| | Director |
/s/ Jerry W. Amos
Jerry W. Amos | | Director |
| | |
/s/ MALCOLME. James Burton
E. James Burton | | Director |
| | |
/s/ EVERETT III Malcolm E. Everett III
Malcolm E. Everett III | | Director |
| | Director |
| | |
/s/ JOHN W. HARRIS John W. Harris
John W. Harris | | Director |
| | Director |
| | |
/s/ AUBREY B. HARWELL, JR. Aubrey B. Harwell, Jr.
Aubrey B. Harwell, Jr. | | Director |
| | Director |
| | |
/s/ FRANK B. HOLDING, JR. Frank B. Holding, Jr.
Frank B. Holding, Jr. | | Director |
| | Director |
| | |
/s/ FRANKIE T. JONES, SR. Frankie T. Jones, Sr.
Frankie T. Jones, Sr. | | Director |
| | Director |
| | |
/s/ VICKI MCELREATH Vicki McElreath
Vicki McElreath | | Director |
| | Director |
| | |
/s/ MINOR M. SHAW Minor M. Shaw
Minor M. Shaw | | Director |
| | Director |
| | |
/s/ MURIEL W. SHEUBROOKS Muriel W. Sheubrooks
Muriel W. Sheubrooks | | Director |
| | Director |
| | |
/s/ DAVID E. SHI David E. Shi
David E. Shi | | | | Director |
88
Piedmont Natural Gas Company, Inc.
Form 10-K
For the Fiscal Year Ended October 31, 2011
Exhibits
| | |
| 10.19 | | Employment Agreement between Piedmont Natural Gas Company, Inc. and Jane R. Lewis-Raymond, dated as of August 1, 2011 |
| |
| 10.21 | | Consulting Agreement between Piedmont Natural Gas Company, Inc. and David J. Dzuricky, dated as of November 1, 2011 |
| |
| 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 |
