UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
(Mark One)
x | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
ýANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended October 31, 20112014
or
¨orTRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
¨ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to Commission file number1-6196Piedmont Natural Gas Company, Inc.
(Exact name of registrant as specified in its charter)
|
|
| Piedmont Natural Gas Company, Inc. |
| (Exact name of registrant as specified in its charter) |
|
| | |
| North Carolina | | 56-0556998 |
(State or other jurisdiction of incorporation or organization) | | (I.R.S. Employer Identification No.) |
|
| | |
| 4720 Piedmont Row Drive, Charlotte, North Carolina | | 28210 |
| (Address of principal executive offices) | | (Zip Code) |
Registrant’s telephone number, including area code (704) 364-3120
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| | |
| Registrant’s telephone number, including area code | | (704) 364-3120 |
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
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| | |
Title of each class | | Name of each exchange on which registered |
Common Stock, no par value | | New York Stock Exchange |
Indicate by check mark if the registrant is a well-known seasoned issuer as defined in Rule 405 of the Securities Act. Yes xý No ¨ Indicate by check mark if the registrant is not required to file reports pursuant to sectionSection 13 or 15 (d) of the Act. Yes ¨ No xý Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes xý No ¨ Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website,Web site, if any, every Interactive Data fileFile required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes xý No ¨ Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨ Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
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Large accelerated filerx | | x | | Accelerated filer | | ¨o |
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Non-accelerated filer | | o¨ (Do not check if a smaller reporting company) | | Smaller reporting company | | ¨o |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ¨ No xý State the aggregate market value of the voting common equity held by non-affiliates of the registrant as of April 30,
2011.2014.
Common Stock, no par value -
$2,259,483,861$2,764,512,081
Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date.
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| | |
Class | | Outstanding at December 16, 2011 12, 2014 |
Common Stock, no par value | | 72,338,30378,638,925 |
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Proxy Statement for the Annual Meeting of Shareholders on March
8, 20125, 2015 are incorporated by reference into Part III.
Piedmont Natural Gas Company, Inc.
2011 FORM 10-K ANNUAL REPORT
TABLE OF CONTENTS
Piedmont Natural Gas Company, Inc. (Piedmont) was incorporated in New York in 1950 and began operations in 1951. In 1994, we merged into a newly formed North Carolina corporation with the same name for the purpose of changing our state of incorporation to North Carolina.
Unless the context requires otherwise, references to “we,” “us,” “our,” “the Company” or “Piedmont” means consolidated Piedmont Natural Gas Company, Inc. and its subsidiaries.
Piedmont is an energy services company whose principal business is the distribution of natural gas to over one million residential, commercial, industrial and power generation customers in portions of North Carolina, South Carolina and Tennessee, including
51,800 customers served by
municipalities who are our wholesale customers.municipalities. We are invested in joint venture, energy-related businesses, including unregulated retail natural gas marketing,
and regulated interstate natural gas
transportation and storage and
regulated intrastate natural gas transportation.
In the Carolinas, our service area is comprised of numerous cities, towns and communities. We provide service
tofrom resource centers in Anderson,
Gaffney, Greenville and Spartanburg in South Carolina and Charlotte, Salisbury, Greensboro, Winston-Salem, High Point, Burlington, Hickory, Indian Trail, Spruce Pine, Reidsville, Fayetteville, New Bern, Wilmington, Tarboro, Elizabeth City, Rockingham and Goldsboro in North Carolina. In North Carolina, we also provide
wholesale natural gas service to Greenville, Rocky Mount and Wilson. In Tennessee, our service area is the metropolitan area of Nashville, including wholesale natural gas service to Gallatin and Smyrna.
We have twothree reportable business segments, regulated utility, regulated non-utility activities and unregulated non-utility activities. Theactivities, with the regulated utility segment isbeing the largest segment of our business with approximately 97% of our consolidated assets.largest. Factors critical to the success of the regulated segmentutility include operating a safe and reliable natural gas distribution system and the ability to recover the costs and expenses of the business in the rates charged to customers. For the year ended October 31, 2011, 87% of our earnings before taxes came from ourThe regulated utility segment. The non-utility activities segment consists of our equity method investments in joint venture regulated energy-related businesses that are involvedheld by our wholly-owned subsidiaries. The unregulated non-utility activities segment consists primarily of our equity method investment in an unregulated retail natural gas marketing,energy-related joint venture that is held by a wholly-owned subsidiary. The percentages of assets as of October 31, 2014 and regulated interstate natural gas storage and intrastate natural gas transportation. Forearnings before taxes by segment for the year ended October 31, 2011, 13%2014 are presented below.
|
| | | | | | |
| | | | | Earnings |
| | | Assets | | Before Taxes |
| Regulated Utility | | 96 | % | | 86 | % |
| Non-utility Activities: | | | | |
| Regulated non-utility activities | | 3 | % | | 5 | % |
| Unregulated non-utility activities | | 1 | % | | 9 | % |
| Total non-utility activities | | 4 | % | | 14 | % |
Operations of our
earnings before taxes came from our non-utility segment, which consists of 5% from regulated non-utility activities and 8% from unregulated non-utility activities. Operations of both segments are conducted within the United States of America. For further information on equity method investments and business segments, see Note 12 and Note 14, respectively, to the consolidated financial
statements.statements in this Form 10-K.
Operating revenues shown in the
consolidated statementsConsolidated Statements of
incomeComprehensive Income represent revenues from the regulated utility segment. The cost of purchased gas is a component of operating revenues. Increases or decreases in prudently incurred purchased gas costs from suppliers are passed through to customers through purchased gas adjustment
(PGA) procedures. Therefore, our operating revenues are impacted by changes in gas costs as well as by changes in volumes of gas sold and transported.
For the year ended October 31, 2011, 46% of our operating revenues were from residential customers, 27% from commercial customers, 10% from large volume customers, including industrial, power generation and resale customers, and 17% from secondary market activities. Secondary market transactions consist of off-system sales and capacity release arrangements and
asset management arrangements and are part of our
utilityregulatory gas supply management program with regulator-approved sharing mechanisms between our utility customers and our shareholders. Operations of the
regulated and unregulated non-utility activities
segmentsegments are included in the
consolidated statementsConsolidated Statements of
incomeComprehensive Income in “Other Income (Expense)” in “Income from equity method investments” and “Non-operating income.”
Operating revenues by major customer class for the years ended October 31, 2014 and 2013 are presented below. |
| | | | | | |
| | | 2014 | | 2013 |
| Residential customers | | 46 | % | | 46 | % |
| Commercial customers | | 27 | % | | 26 | % |
| Large volume customers, including industrial, power generation and resale customers | | 14 | % | | 15 | % |
| Secondary market activities | | 12 | % | | 12 | % |
| Other sources | | 1 | % | | 1 | % |
| Total | | 100 | % | | 100 | % |
Our utility operations are regulated by the North Carolina Utilities Commission (NCUC), the Public Service Commission of South Carolina (PSCSC) and the Tennessee Regulatory Authority (TRA) as to rates, service area, adequacy of service, safety standards, extensions and abandonment of facilities, accounting and depreciation. The NCUC also regulates us as to the issuance of long-term debt and equity securities.
We are also subject to
or affected by various federal
regulations.regulations that affect our utility and non-utility operations. These federal regulations include regulations that are particular to the natural gas industry, such as regulations of the Federal Energy Regulatory Commission (FERC) that affect the
certification and siting of new interstate natural gas pipeline projects, the purchase and sale of,
and the prices paid
for, and the terms and conditions of service for the interstate transportation and storage of natural gas, regulations of the
U.S. Department of Transportation
(DOT) that affect the design, construction, operation, maintenance, integrity, safety and security of natural gas distribution and transmission systems, and regulations of the Environmental Protection Agency
(EPA) relating to the
environment.environment, including air emissions regulations that could be expanded to address emissions of methane. In addition, we are subject to numerous other regulations, such as those relating to employment and benefit practices, which are generally applicable to companies doing business in the United States of America.
We hold non-exclusive franchises for natural gas service in many of the communities we serve, with expiration dates from December
20112014 to 2058. The franchises are adequate for the operation of our gas distribution business and do not contain materially burdensome restrictions or conditions.
Twenty-oneFrom time to time, some of our franchise agreements
have expired as of October 31, 2011. Weexpire; however, we continue to operate in those areas pursuant to the provisions of the expired franchises with no significant impact on our business.
Two franchise agreements will expire duringDepending on the
2012 fiscal year. The likelihood of cessation of service under an expired franchise is remote. Wejurisdiction, we believe that these franchises will be renewed or that service will be continued in the ordinary course of business
while we negotiate renewals or continue to operate under our state-granted franchise rights without
thea specific franchise
agreementsagreement with each city or
municipality, with nomunicipality. The likelihood of cessation of service under an expired franchise is remote, and we do not believe there will be a material adverse impact on us.
Our regulatory commissions approve rates and tariffs that are designed to give us the opportunity to recover the cost of natural gas we purchased for our customers and our operating expenses and to earn a fair rate of return on invested capital for our shareholders. The traditional utility rate design provides for the collection of margin revenue based on volumetric throughput which can be affected by customer consumption patterns, weather, conservation, price levels for natural gas or general economic conditions. By continually assessing alternative rate structures and cost recovery mechanisms that are more appropriate to the changing energy economy and through requests filed with our regulatory commissions, we have secured alternative rate structures and cost recovery mechanisms designed to allow us to recover certain costs through tracking mechanisms or riders without the need to file general rate cases. Our ability to earn our authorized rates of return is based in part on our ability to reduce or eliminate regulatory lag through rate stabilization adjustment (RSA) tariffs, integrity management riders (IMRs) or similar mechanisms and also by improved rate designs that decouple the recovery of our approved margins from customer usage patterns impacted by seasonal weather patterns and customer conservation. This allows a better alignment of the interests of our shareholders and customers.
In North Carolina, we have a margin decoupling mechanism that provides for the recovery of our approved margin from residential and commercial customers on an annual basis independent of consumption patterns. The margin decoupling mechanism provides for semi-annual rate adjustments to refund any over-collection of margin or to recover any under-collection of margin. In South Carolina, we operate under a RSA tariff mechanism that achieves the objective of margin decoupling for residential and commercial customers with a one year lag. Under the RSA tariff mechanism, we reset our rates based on updated costs and revenues on an annual basis. We also have a weather normalization adjustment (WNA) mechanism for residential and commercial customers in South Carolina for bills rendered during the months of November through March and in Tennessee for bills rendered during the months of October through April that partially offsets the impact of colder- or warmer-than-normal winter weather on our margin collections. Our WNA formulas calculate the actual weather variance from normal, using 30 years of history, and increase margin revenues when weather is warmer than normal and decrease margin
revenues when weather is colder than normal. The WNA formulas do not ensure full recovery of approved margin during periods when customer consumption patterns vary from those used to establish the WNA factors and when weather is significantly warmer or colder than normal. Weather in 2014 on average over our three-state market area was 9% colder than normal and 6% colder than 2013. For the year ended October 31, 2014, the margin decoupling mechanism in North Carolina decreased margin by $33.4 million, and the WNA mechanisms in South Carolina and Tennessee together decreased margin by $8.4 million.
With approval in North Carolina and Tennessee in December 2013, we have IMRs that separately track and recover, on an annual basis outside general rate cases, costs associated with capital expenditures to comply with pipeline safety and integrity requirements. The first Tennessee IMR rate adjustment was recognized in earnings through customer billings beginning in January 2014, and the first North Carolina IMR rate adjustment was recognized in earnings through customer billings beginning in February 2014.
In all three states, the gas cost portion of our costs is recoverable through PGA procedures and is not affected by the margin decoupling mechanism or the WNA mechanism. Through the use of various tariff mechanisms and fixed-rate contracts, we are able to achieve a higher degree of margin stabilization. For further information on state commission regulation, see Note 2 to the consolidated financial statements in this Form 10-K. The following table presents the breakdown of our gas utility margin for the years ended October 31, 2014, 2013 and 2012.
|
| | | | | | | | | |
| | | 2014 | | 2013 | | 2012 |
| Fixed margin (from margin decoupling in North Carolina, facilities charges to our | | | | | | |
| customers, Tennessee and North Carolina IMRs in 2014 only and fixed-rate contracts) | | 72 | % | | 73 | % | | 72 | % |
| Semi-fixed margin (RSA in South Carolina and WNA in South Carolina and | | | | | | |
| Tennessee) | | 16 | % | | 16 | % | | 17 | % |
| Volumetric or periodic renegotiation (including secondary marketing activity) | | 12 | % | | 11 | % | | 11 | % |
| Total | | 100 | % | | 100 | % | | 100 | % |
The natural gas distribution business is seasonal in nature as variations in weather conditions and our regulated utility rate designs generally result in greater revenues and earnings during the winter months when temperatures are colder. For further information on weather sensitivity and the impact of seasonality on working capital, see “Financial Condition and Liquidity” in Item 7 of this Form 10-K in Management’s Discussion and Analysis of Financial Condition and Results of Operations. As
Our Strategies
We monitor our progress and measure our performance related to our strategic directives and business objectives over the course of each fiscal year. The metrics we use to measure our performance include, but are not limited to, earnings per share (EPS) and EPS growth, total shareholder return compared to our industry peer group, return on invested capital, return on equity, utility margin, investment grade credit ratings, customer growth, utility customer satisfaction and loyalty, operations and maintenance (O&M) expense discipline, employee health and safety, pipeline safety, and sustainable business practices.
Safety is prevalenta critical component to our ongoing success as a company, and we have always placed the highest priority on the safety of our system, public safety and employee safety. We must comply with laws that regulate system integrity as well as new rulemaking proceedings under the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011. We are subject to DOT and state regulation of our pipeline and related facilities and have ongoing transmission and distribution pipeline integrity programs to inspect our system for anomalies, corrosion and leaks as well as monitoring key metrics of our system for its safe operation. We anticipate federal legislative and regulatory enactments will increase in scope and add further requirements and costs to our pipeline safety and integrity programs and our capital and O&M expenditure programs. Items currently being discussed by federal regulators include possible mandates addressing the integrity verification process of maximum allowable operating pressure of transmission pipelines. We will continue our efforts to educate the public about our pipeline system in an effort to decrease third-party excavation damage, which is the greatest cause of damage on our system. We encourage focused efforts to improve the safety of our industry as a whole.
We believe natural gas is a safe and reliable energy source that is clean, affordable, reliable and environmentally responsible, as well as being domestically abundant. We incorporate this message into our pursuit of growth in our core residential, commercial, industrial and power generation markets as well as complementary energy-related investments. We promote the increased awareness and use of natural gas and want our customers to choose us because of the value of natural gas and the quality of our service to them.
Our business model supports new clean energy technologies and energy efficiencies in the industry, we injectend use of natural gas. We seek opportunities for regulatory innovation and strategic alliances to advance our customers’ interests in energy conservation, efficiency and environmental stewardship. We are promoting the direct use of natural gas in more homes, businesses, industries and vehicles as we strongly believe that the expanded use of clean, efficient, abundant and domestic natural gas with its relatively low emissions can help revitalize our economy, reduce both overall energy consumption and greenhouse gas emissions and enhance our national energy security.
We see an opportunity in the clean energy technology of compressed natural gas (CNG) vehicles. We have converted 28% of our nearly 1,100 vehicle fleet to CNG and intend for one-third of the vehicles in our fleet to be fueled by CNG by the end of 2015. As of October 31, 2014, we have approximately $17.8 million of utility plant related to our CNG fueling stations that is included in the Consolidated Balance Sheets in “Utility plant in service.” We are allowed by each of our three state regulatory commissions to include this utility plant in service in our utility rate base and have the opportunity to earn the allowed rate of return in each jurisdiction.
We continued to execute our plan to build CNG fueling stations in our service area for use by our own vehicle fleet as well as by third-party fleets and other customers when there is sufficient demand to allow us to earn our allowed rate of return. In the current fiscal year, we opened our second CNG fueling station in Tennessee, which was our tenth station in our three-state service territory. We are also actively pursuing building customer-owned CNG fueling stations at commercial customers’ sites for use by their commercial fleets. There are currently twelve customer owned stations in our service territory.
CNG throughput increased by 152% in 2014 compared with the same prior period, and we anticipate CNG throughput to increase by at least 30% in 2015. Between Piedmont and customer-owned CNG stations, we sold or transported 250,000 dekatherms of CNG to commercial customers for the year ended October 31, 2014, equivalent to approximately 4,350 homes, and used 17,000 dekatherms of CNG in our own fleets. Between our customers and use by our own fleet, this CNG usage displaced more than 2.1 million gallons of gasoline and diesel fuel.
Due to the environmental and cost benefits of using natural gas compared to coal in the generation of electricity, we completed five pipeline expansion projects since 2010 to provide long-term natural gas delivery service to new natural gas-fired power generation facilities in our market area. These new natural gas power plants are designed to emit significantly less carbon emissions than the coal power plants they replaced. We currently provide service to 25 power generation customer accounts. In addition to delivering the natural gas supply to the new natural gas-fired power plants, the construction of natural gas pipelines for two of these projects increased our natural gas infrastructure in the eastern part of North Carolina with enhancement of future opportunities for economic growth and development. In June 2014, we executed an agreement to construct approximately 1.5 miles of natural gas transmission pipeline and associated compression facilities to serve Duke Energy Corporation’s (Duke Energy) W.S. Lee power generation facility near Anderson, South Carolina. Piedmont’s anticipated investment of approximately $38 million in the pipeline and compression facilities is supported by a long-term service agreement with Duke Energy with a scheduled in service date of May 2017.
Our capital program primarily supports our system infrastructure and the growth in our customer base. We are investing in our pipeline integrity, safety and compliance programs, and systems and technology infrastructure to enhance our pipeline system and integrity. For further information on our forecasted capital investments for fiscal 2015 – 2017, see “Cash Flows from Investing Activities” in Item 7 of this Form 10-K in Management’s Discussion and Analysis of Financial Condition and Results of Operations.
We strive to achieve excellence in service to our customers and in our business operations with every customer contact we make. In our business practices, we promote a sustainable enterprise by reducing our impact on the environment, developing strong communities in which we operate and enhancing long-term shareholder value. We support our employees with improved processes and technology to better serve our customers while continuing to build a healthy, high performance culture in order to recruit, retain and motivate our workforce.
Our financial strength and flexibility is critical to our success as a company. We will continue our efforts to maintain our financial strength which includes a strong balance sheet, investment-grade credit ratings and continued access to capital markets. We evaluate the strength of financial institutions with which we have working relationships to ensure access to funds for operations and capital investments. Our capital plan includes maintaining a capitalization ratio of 50 – 60% in total debt and 40 – 50% in common equity. We will continue our efforts to control our operating costs, implement new technologies and work with our state regulators to maintain fair rates of return and innovative rate designs for the benefit of our customers and shareholders.
While we will preserve our identity as a pure-play local distribution company, we pursue strategic opportunities aligned with our core natural gas or complementary energy related businesses. It is our long-term strategic intent for our joint venture portfolio to be primarily weighted towards regulated and asset-based investments in natural gas infrastructure. We analyze and evaluate potential projects based on projected rates of return commensurate with the risk of such projects. We participate in the governance of our ventures by having management representatives on the governing boards. We monitor actual performance against expectations, specifically annual approved budgets, and any decision to exit an existing joint venture would be based on many factors, including performance results and continued alignment with our business strategies.
To further our strategy of expanding our complementary energy-related businesses, we invested in Constitution Pipeline Company, LLC, whose purpose is to construct and operate approximately 120 miles of interstate natural gas pipeline and related facilities connecting shale natural gas supplies and gathering systems in Susquehanna County, Pennsylvania, to the Iroquois Gas Transmission and Tennessee Gas Pipeline systems in New York. We have committed to fund an amount in proportion to our ownership interest of 24% for the development and construction of the new pipeline, which is expected to cost approximately $730 million. For further information on this equity method investment, see Note 12 to the consolidated financial statements in this Form 10-K.
Also, in September 2014, Piedmont, Duke Energy, Dominion Resources, Inc., and AGL Resources, Inc. announced the formation of Atlantic Coast Pipeline, LLC (ACP), a Delaware limited liability company. ACP intends to construct, operate and maintain a 550 mile natural gas pipeline, with associated compression, from West Virginia through Virginia into storage duringeastern North Carolina. The pipeline will provide wholesale natural gas transportation services for Marcellus and Utica gas supplies into southeastern markets. We are a 10% equity member of ACP. We have committed to fund an amount in proportion to our ownership interest of 10% for the summer months (principally Aprildevelopment and construction of the new pipeline, which is expected to cost between $4.5 billion to $5 billion. For further information on this equity method investment, see Note 12 to the consolidated financial statements in this Form 10-K.
Operating Statistics
The following is a five-year comparison of operating statistics for the years ended October 31, 2010 through October) when customer demand is lower for withdrawal from storage during the winter heating season (principally November through March) when customer demand is higher. 2014.
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| | | | | | | | | | | | | | | | | | | | |
|
| 2014 |
| 2013 |
| 2012 |
| 2011 |
| 2010 |
| Operating Revenues (in thousands): |
|
|
|
|
|
|
|
|
| Sales and Transportation: |
|
|
|
|
|
|
|
|
|
|
| Residential |
| $ | 683,848 |
|
| $ | 588,546 |
|
| $ | 534,321 |
|
| $ | 658,892 |
|
| $ | 743,346 |
|
| Commercial |
| 397,004 |
|
| 331,831 |
|
| 301,013 |
|
| 379,846 |
|
| 428,085 |
|
| Industrial |
| 115,515 |
|
| 113,182 |
|
| 95,177 |
|
| 104,774 |
|
| 116,122 |
|
| Power Generation |
| 85,902 |
|
| 64,109 |
|
| 36,027 |
|
| 28,969 |
|
| 21,708 |
|
| For Resale |
| 9,587 |
|
| 9,549 |
|
| 9,512 |
|
| 9,692 |
|
| 11,061 |
|
| Total |
| 1,291,856 |
|
| 1,107,217 |
| | 976,050 |
| | 1,182,173 |
| | 1,320,322 |
|
| Secondary Market Sales |
| 169,543 |
|
| 164,130 |
|
| 140,380 |
|
| 244,824 |
|
| 224,973 |
|
| Miscellaneous |
| 8,589 |
|
| 6,882 |
|
| 6,350 |
|
| 6,908 |
|
| 7,000 |
|
| Total |
| $ | 1,469,988 |
|
| $ | 1,278,229 |
| | $ | 1,122,780 |
| | $ | 1,433,905 |
| | $ | 1,552,295 |
|
| | | | | | | | | | | |
| Gas Volumes - Dekatherms (in thousands) |
|
|
|
|
|
|
|
|
| System Throughput: |
|
|
|
|
|
|
|
|
|
|
| Residential |
| 61,782 |
|
| 55,283 |
|
| 43,788 |
|
| 57,778 |
|
| 58,327 |
|
| Commercial |
| 44,259 |
|
| 39,602 |
|
| 33,774 |
|
| 40,749 |
|
| 39,994 |
|
| Industrial |
| 95,780 |
|
| 95,019 |
|
| 89,234 |
|
| 90,842 |
|
| 82,805 |
|
| Power Generation |
| 201,707 |
|
| 190,862 |
|
| 151,675 |
|
| 83,522 |
|
| 63,024 |
|
| For Resale |
| 7,174 |
|
| 6,834 |
|
| 5,829 |
|
| 6,870 |
|
| 8,465 |
|
| Total |
| 410,702 |
|
| 387,600 |
| | 324,300 |
| | 279,761 |
| | 252,615 |
|
| | | | | | | | | | | |
| Secondary Market Sales |
| 20,516 |
|
| 41,605 |
|
| 48,373 |
|
| 48,835 |
|
| 46,823 |
|
| | | | | | | | | | | |
| Number of Customers Billed (12-month average): |
|
|
|
|
|
|
|
|
| Residential |
| 903,067 |
|
| 890,887 |
|
| 878,851 |
|
| 871,401 |
|
| 864,205 |
|
| Commercial |
| 97,288 |
|
| 96,009 |
|
| 95,100 |
|
| 94,485 |
|
| 94,287 |
|
| Industrial |
| 2,279 |
|
| 2,271 |
|
| 2,265 |
|
| 2,265 |
|
| 2,273 |
|
| Power Generation |
| 25 |
|
| 24 |
|
| 22 |
|
| 22 |
|
| 20 |
|
| For Resale |
| 16 |
|
| 15 |
|
| 15 |
|
| 15 |
|
| 16 |
|
| Total |
| 1,002,675 |
|
| 989,206 |
| | 976,253 |
| | 968,188 |
| | 960,801 |
|
| | | | | | | | | | | |
| Cost of Gas (in thousands): |
|
|
|
|
|
|
|
|
|
|
| Natural Gas Commodity Costs |
| $ | 621,604 |
|
| $ | 526,703 |
|
| $ | 379,145 |
|
| $ | 666,930 |
|
| $ | 753,529 |
|
| Capacity Demand Charges |
| 144,313 |
|
| 151,369 |
|
| 129,090 |
|
| 136,139 |
|
| 127,137 |
|
| Natural Gas Withdrawn From |
| |
|
|
|
|
|
|
|
|
| (Injected Into) Storage, net |
| (13,578 | ) |
| (5,867 | ) |
| 27,580 |
|
| 11,362 |
|
| 5,293 |
|
| Regulatory Charges (Credits), net |
| 27,441 |
|
| (15,466 | ) |
| 11,519 |
|
| 45,835 |
|
| 113,744 |
|
| Total |
| $ | 779,780 |
|
| $ | 656,739 |
|
| $ | 547,334 |
|
| $ | 860,266 |
|
| $ | 999,703 |
|
| | | | | | | | | | | |
| Supply Available for Distribution (dekatherms in thousands): |
|
|
|
|
|
|
| Natural Gas Purchased |
| 134,986 |
|
| 142,884 |
|
| 132,426 |
|
| 155,550 |
|
| 157,021 |
|
| Transportation Gas |
| 299,166 |
|
| 287,980 |
|
| 235,474 |
|
| 175,005 |
|
| 147,038 |
|
| Natural Gas Withdrawn From |
|
|
|
|
|
|
|
|
|
|
| (Injected Into) Storage, net |
| (1,232 | ) |
| (509 | ) |
| (378 | ) |
| 196 |
|
| (1,309 | ) |
| Company Use |
| (731 | ) |
| (369 | ) |
| (296 | ) |
| (309 | ) |
| (282 | ) |
| Total |
| 432,189 |
|
| 429,986 |
|
| 367,226 |
|
| 330,442 |
|
| 302,468 |
|
During the year ended October 31, 2011, the amount of natural gas in storage varied from 14.62014, we delivered 410.7 million dekatherms (one dekatherm equals 1,000,000 BTUs) to 26.3our utility retail customers compared to 387.6 million dekatherms and the aggregate commodity cost of this gas in storage varied from $75.9 million to $133.2 million.During the year ended October 31, 2011, 181.2before. Of this amount, 304.7 million dekatherms of gas were sold to or transported for large volume customers compared with 154.3292.7 million dekatherms in 2010.2013. Of these volumes sold to or transported for large volume customers, we transported 83.5201.7 million dekatherms this yearin 2014 to power generation facilities as compared with 63190.9 million dekatherms in the prior year. The margin earned from power generation customers is largely based on fixed monthly demand contracts.charge contracts and does not vary significantly based on the volumes transported. Deliveries to temperature-sensitive residential
and commercial customers, whose consumption varies with the weather, totaled 98.5106 million
dekatherms in 2014, compared with 94.9 million dekatherms in
2011, compared with 98.3 million dekatherms in 2010.2013. Weather, as measured by degree days, was
10%9% colder than normal in
20112014 and
6%2% colder than normal in
2010.The following is a five-year comparison2013.
With continued improvement in economic conditions resulting in growth in both the residential and commercial markets and targeted marketing programs on the benefits of
operating statistics for the years ended October 31, 2007 through 2011. | | | | | | | | | | | | | | | | | | | | |
| | | 2011 | | | 2010 | | | 2009 | | | 2008 | | | 2007 | |
Operating Revenues (in thousands): | | | | | | | | | | | | | | | | | | | | |
Sales and Transportation: | | | | | | | | | | | | | | | | | | | | |
Residential | | $ | 658,892 | | | $ | 743,346 | | | $ | 787,994 | | | $ | 813,032 | | | $ | 743,637 | |
Commercial | | | 379,846 | | | | 428,085 | | | | 462,160 | | | | 503,317 | | | | 418,426 | |
Industrial | | | 104,774 | | | | 116,122 | | | | 126,855 | | | | 209,341 | | | | 190,204 | |
For Power Generation | | | 28,969 | | | | 21,708 | | | | 19,609 | | | | 25,266 | | | | 29,135 | |
For Resale | | | 9,692 | | | | 11,061 | | | | 11,746 | | | | 12,326 | | | | 13,907 | |
| | | | | | | | | | | | | | | | | | | | |
Total | | | 1,182,173 | | | | 1,320,322 | | | | 1,408,364 | | | | 1,563,282 | | | | 1,395,309 | |
Secondary Market Sales | | | 244,824 | | | | 224,973 | | | | 221,300 | | | | 515,968 | | | | 308,904 | |
Miscellaneous | | | 6,908 | | | | 7,000 | | | | 8,452 | | | | 9,858 | | | | 7,079 | |
| | | | | | | | | | | | | | | | | | | | |
Total | | $ | 1,433,905 | | | $ | 1,552,295 | | | $ | 1,638,116 | | | $ | 2,089,108 | | | $ | 1,711,292 | |
| | | | | | | | | | | | | | | | | | | | |
Gas Volumes - Dekatherms (in thousands): | | | | | | | | | | | | | | | | | | | | |
System Throughput: | | | | | | | | | | | | | | | | | | | | |
Residential | | | 57,778 | | | | 58,327 | | | | 55,298 | | | | 51,909 | | | | 50,072 | |
Commercial | | | 40,749 | | | | 39,994 | | | | 38,526 | | | | 36,766 | | | | 33,647 | |
Industrial | | | 90,842 | | | | 82,805 | | | | 74,363 | | | | 81,780 | | | | 79,266 | |
For Power Generation | | | 83,522 | | | | 63,024 | | | | 39,639 | | | | 30,875 | | | | 34,096 | |
For Resale | | | 6,870 | | | | 8,465 | | | | 9,048 | | | | 8,921 | | | | 8,923 | |
| | | | | | | | | | | | | | | | | | | | |
Total | | | 279,761 | | | | 252,615 | | | | 216,874 | | | | 210,251 | | | | 206,004 | |
| | | | | | | | | | | | | | | | | | | | |
Secondary Market Sales | | | 48,835 | | | | 46,823 | | | | 46,057 | | | | 53,442 | | | | 42,049 | |
| | | | | | | | | | | | | | | | | | | | |
Number of Customers Billed (12-month average): | | | | | | | | | | | | | | | | | | | | |
Residential | | | 871,401 | | | | 864,205 | | | | 855,670 | | | | 852,586 | | | | 835,636 | |
Commercial | | | 94,485 | | | | 94,287 | | | | 94,404 | | | | 94,045 | | | | 93,472 | |
Industrial | | | 2,265 | | | | 2,273 | | | | 2,358 | | | | 2,937 | | | | 2,959 | |
For Power Generation | | | 22 | | | | 20 | | | | 20 | | | | 20 | | | | 15 | |
For Resale | | | 15 | | | | 16 | | | | 17 | | | | 17 | | | | 15 | |
| | | | | | | | | | | | | | | | | | | | |
Total | | | 968,188 | | | | 960,801 | | | | 952,469 | | | | 949,605 | | | | 932,097 | |
| | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | |
| | | 2011 | | | 2010 | | | 2009 | | | 2008 | | | 2007 | |
Average Per Residential Customer: | | | | | | | | | | | | | | | | | | | | |
Gas Used - Dekatherms | | | 66.30 | | | | 67.49 | | | | 64.63 | | | | 60.88 | | | | 59.92 | |
Revenue | | $ | 756.13 | | | $ | 860.15 | | | $ | 920.91 | | | $ | 953.61 | | | $ | 889.90 | |
Revenue Per Dekatherm | | $ | 11.40 | | | $ | 12.74 | | | $ | 14.25 | | | $ | 15.66 | | | $ | 14.85 | |
Cost of Gas (in thousands): | | | | | | | | | | | | | | | | | | | | |
Natural Gas Commodity Costs | | $ | 666,930 | | | $ | 753,529 | | | $ | 727,744 | | | $ | 1,454,073 | | | $ | 1,055,600 | |
Capacity Demand Charges | | | 136,139 | | | | 127,137 | | | | 128,081 | | | | 127,640 | | | | 116,977 | |
Natural Gas Withdrawn From (Injected Into) Storage, net | | | 11,362 | | | | 5,293 | | | | 126,480 | | | | (78,283 | ) | | | (12,815 | ) |
Regulatory Charges (Credits), net | | | 45,835 | | | | 113,744 | | | | 94,237 | | | | 32,705 | | | | 27,365 | |
| | | | | | | | | | | | | | | | | | | | |
Total | | $ | 860,266 | | | $ | 999,703 | | | $ | 1,076,542 | | | $ | 1,536,135 | | | $ | 1,187,127 | |
| | | | | | | | | | | | | | | | | | | | |
Supply Available for Distribution (dekatherms in thousands): | | | | | | | | | | | | | | | | | | | | |
Natural Gas Purchased | | | 155,550 | | | | 157,021 | | | | 149,696 | | | | 159,857 | | | | 143,598 | |
Transportation Gas | | | 175,005 | | | | 147,038 | | | | 115,519 | | | | 108,332 | | | | 108,355 | |
Natural Gas Withdrawn From (Injected Into) Storage, net | | | 196 | | | | (1,309 | ) | | | 1,010 | | | | (2,980 | ) | | | (1,640 | ) |
Company Use | | | (309 | ) | | | (282 | ) | | | (283 | ) | | | (135 | ) | | | (141 | ) |
| | | | | | | | | | | | | | | | | | | | |
Total | | | 330,442 | | | | 302,468 | | | | 265,942 | | | | 265,074 | | | | 250,172 | |
| | | | | | | | | | | | | | | | | | | | |
natural gas, new customer additions increased in our fiscal year 2014 as compared to fiscal year 2013 as presented below.
|
| | | | | | | | | |
|
|
|
|
|
| Percent |
|
| 2014 |
| 2013 |
| Change |
| Residential new home construction |
| 11,659 |
|
| 10,299 |
|
| 13.2 | % |
| Residential conversion |
| 2,814 |
|
| 2,463 |
|
| 14.3 | % |
| Commercial |
| 1,763 |
|
| 1,512 |
|
| 16.6 | % |
| Industrial |
| 15 |
|
| 19 |
|
| (21.1 | )% |
| Total new customers |
| 16,251 |
|
| 14,293 |
|
| 13.7 | % |
We forecast continuing gross customer growth in fiscal 2015 of 1.6% on our base of approximately one million utility retail customers. Total net customers billed increased 1.3% in fiscal year 2014 compared to 2013.
Natural Gas Utility Operations
We purchase natural gas under firm contracts to meet our design-day requirements for firm sales customers. These contracts provide that we pay a reservation fee to the supplier to reserve or guarantee the availability of gas supplies for delivery. Under these provisions, absent force majeure conditions, any disruption of supply deliverability is subject to penalty and damage assessment against the supplier. We ensure the delivery of the gas supplies to our distribution system to meet the peak day, seasonal and annual needs of our firm customers by using a variety of firm transportation and storage capacity contracts. The pipeline capacity contracts require the payment of fixed
monthly demand charges to reserve firm transportation or storage entitlements. We align the contractual agreements for supply with the firm capacity agreements in terms of volumes, receipt and delivery locations and demand fluctuations. We may supplement these firm contracts with other supply arrangements to serve our interruptible market.
As of October 31,
2011,2014, we had contracts for the following pipeline firm transportation
capacity in dekatherms per day.
| |
| | |
Williams-Transco
| | Williams – Transco | 632,200 |
|
El Paso-TennesseeKinder Morgan – Tennessee Pipeline
| | | 74,100 |
|
Spectra-TexasSpectra – Texas Eastern (through(partially through East Tennessee and Transco)
| | | 36,700 |
|
NiSource-ColumbiaOneok – Midwestern (through either Tennessee, Columbia Gulf, East Tennessee or Transco)
| 120,000 |
|
| NiSource – Columbia Gas (through Transco and Columbia Gulf) | | | 42,800 |
|
NiSource-ColumbiaNiSource – Columbia Gulf
| 41,000 | | 10,000 |
|
ONEOK-Midwestern (through Tennessee, Columbia Gulf, East Tennessee and Transco)
Total | 946,800 | | 120,000 | |
| | | | |
Total
| | | 915,800 | |
| | | |
|
As of October 31,
2011,2014, we had the following assets or contracts for local peaking facilities and storage for seasonal or peaking capacity in dekatherms of daily deliverability to meet the firm demands of our markets with deliverability from 5 days to one year.
|
| | | |
Piedmont Liquefied Natural Gas (LNG) | 270,000 |
| 268,000 | * |
Pine Needle LNG (through Transco) | | | 263,400 |
| |
Williams-TranscoWilliams – Transco Storage
| | | 86,100 |
| |
NiSource-ColumbiaNiSource – Columbia Gas Storage
| | | 96,400 |
| |
Hardy Storage (through Columbia Gas and Transco) | | | 68,800 |
| |
Dominion Storage (through Transco)
Kinder Morgan – Tennessee Pipeline | 55,900 | | 13,200
| |
El Paso-Tennessee Pipeline Storage
Total | 840,600 | | 55,900 | |
| | | | |
Total
| | | 851,800 | |
| | |
| |
* During the winter heating season 2013 - 2014, deliverability was reduced due to facility restrictions.
As of October 31,
2011,2014, we own or have under contract
36.135.6 million dekatherms of storage capacity, either in the form of underground storage or LNG. This
capabilitycapacity is used to supplement or replace regular pipeline supplies.
The source
As is prevalent in the industry, we inject natural gas into storage during the summer months (principally April through October) when customer demand is lower for withdrawal from storage during the winter heating season (principally November through March) when customer demand is higher. During the year ended October 31, 2014, the amount of natural gas in storage varied from 10.4 million (one dekatherm equals 1,000,000 BTUs) to 24.2 million, and the weighted average commodity cost of this gas in storage varied from $44.3 million to $97.5 million.
Natural gas development and production in North America continues to provide abundant supply and price stability and moderation for natural gas as an energy commodity. With lower gas prices over the past seven years, we distributehave been able to significantly lower the cost of gas to our customers with multiple filings for reductions in the wholesale natural gas component of customer rates in the three jurisdictions that we serve. Currently, natural gas has a price advantage over other fuels, and it is anticipated that the cost of natural gas will remain competitive due to abundant sources of shale gas reserves.
We purchase our natural gas supplies by contracting primarily from the Gulf Coast production region and is purchased primarily fromwith major and independent producers and marketers. NaturalWe also purchase a diverse portfolio of transportation and storage services from interstate pipelines that are regulated by the FERC. Peak-use requirements are met through the use of company owned storage facilities, pipeline transportation capacity, purchased storage services and other supply sources. We have been able to obtain sufficient supplies of natural gas to meet customer requirements, and with the prospect of abundant domestic shale natural gas supplies and our contracted pipeline capacity, we believe that we will be able to meet our market demands in the future.
When firm pipeline services or contracted gas supplies are temporarily not needed due to market demand is continuingfluctuations, we may release these services and supplies in the secondary market under FERC-approved capacity release provisions or make wholesale secondary market sales. The proceeds from those transactions are used to growreduce the cost of natural gas we charge to customers through sharing mechanisms that are in our service area, particularly from power generation customers. Toplace in all three jurisdictions whereby customers are allocated 75% of the savings through the incentive plans. For further information on these regulatory sharing mechanisms, see Note 2 to the consolidated financial statements in this Form 10-K.
We continue to diversify our
reliance away from the Gulf Coast region, we receive firm, long-term market area storage service from Hardy Storage Company, LLC (Hardy Storage) located in West Virginia, Columbia Gas Storage located in West Virginia, Ohiosupply portfolio by contracting to bring abundant and
Pennsylvania, and Dominion Storage located in West Virginia, Pennsylvania and New York that may be filled with Appalachian sourced supply. We also have firm, long-term transportation service from Midwestern Gas Transmission Company that provides access tolow cost natural gas supplies from
Canadian and Rocky Mountainthe Marcellus supply
basins via the Chicago hub that can supply city gate demand or be used to fill storage facilities on Tennessee Gas Pipeline, Columbia Gas, Pine Needle and Transco.We completed two pipeline expansion projects in fiscal year 2011 and one in December 2011 to provide long-term gas transportation service to power generation customers in our market area. We have two pipeline expansion projects under construction to provide natural gas delivery service to power generation facilities currently under construction in North Carolina with targeted in service dates of June 2012 and June 2013. In addition to the environmental benefits of replacing a coal-fired power plant with a new natural gas-fired power plant, the construction of the natural gas pipelines for these projects will also addbasin to our natural gas infrastructuremarkets in the eastern partCarolinas. In November 2012, we signed a long-term contract with Cabot Oil & Gas to purchase firm, price-competitive Marcellus gas supplies. We also signed a long-term firm capacity contract with Williams – Transco under its Leidy Southeast expansion project to transport the Marcellus based Cabot gas supplies to our markets. In December 2012, we also signed a long-term firm capacity contract with Williams – Transco under its Virginia Southside expansion project that will also allow us to further diversify our supply portfolio with Marcellus based natural gas. These new supply and capacity arrangements are scheduled to begin in late 2015, and we believe they will provide diversification, reliability and gas cost benefits to Piedmont’s customers across the Carolinas. Also, with the new ACP project that is targeted to be in service in late 2018, we will have additional pipeline capacity from the Marcellus and Utica supply basin under a long-term firm service agreement that we executed with ACP, subject to FERC approval of North Carolinathe project.
Competition
Our regulated utility competes with other energy products, such as electricity and
enhance future opportunitiespropane, in the residential and commercial customer markets. The most significant product competition is with electricity for
economic growthspace heating, water heating and
development. Seecooking. Numerous factors can influence customer demand for natural gas including price, value, availability, environmental attributes, comfort, convenience, reliability and energy efficiency. Increases in the
following discussionprice of
natural gas can negatively impact our
forecasted capital investment relatedcompetitive position by decreasing the price benefits of natural gas to the
constructionconsumer. This can lead to slower customer growth or customer conservation, or both, resulting in reduced gas purchases and customer billings. In turn, this can impact our capital expenditures and overall cash needs, including working capital needs. The direct use of
the natural gas
pipelines and compressor stations to serve these new power generation facilities in
“Cash Flows from Investing Activities” in Item 7 of this Form 10-K in Management’s Discussion and Analysis of Financial Condition and Results of Operations.We continue to see challenging economic conditions in our market area with continued high rates of unemployment, weakened housing markets with high inventories of unsold homes and slower new home construction. However, we took advantagebusinesses is the most efficient and cost effective use of the growth opportunities that existed in those markets and continue to focus on residential, commercial and industrial customer conversions to natural gas and power generation gas delivery service opportunities. In fiscal year 2011, we added 10,522 new customers, including 6,843 residential new home construction customers, 1,406 commercial and industrial customers and 2,273 conversion customers, as well as two new power generation customers mentioned above. As we seek to expandresults in overall lower carbon emissions. However, the use of natural gas we continue to emphasizefor power generation also adds significant value as a result of natural gas as the fuel of choice for energy consumers because of the comfort, affordabilitygas’ environmental attributes, competitive cost advantage and efficiency of natural gas, as well as remind our customers of our reliability and safety as a company. We forecast gross customer addition growth for fiscal 2012 of approximately 1%.
We continue to work toward a business model that positions us for long-term success in a lower carbon energy economy with a focus on future growth opportunities that support new clean energy technologies. We are seeking opportunities for regulatory innovation and strategic alliances to advance our customers’ interests in energy conservation, efficiency and environmental stewardship. We are executing a plan to build more compressed natural gas (CNG) fueling stations in our service area for use by our own vehicle fleet as well as third party use and the general public. Currently, approximately 11% of our vehicle fleet uses CNG. We have five CNG fueling stations, and we plan to construct four more. Within two years, we anticipate that up to 33% of our fleet will be capable of using CNG.
delivery.
During the year ended October 31,
2011,2014, approximately
5%4% of our margin (operating revenues less cost of gas) was generated from deliveries to industrial or large commercial customers that have the capability to burn a fuel other than natural
gas. The alternative fuels are primarily fuel oil and propane and, to a much lesser extent, coal or wood. Our ability to maintain or increase deliveries of gas to these customers depends on a number of factors, including weather conditions, governmental regulations, the price of gas from suppliers, availability and the price of alternate fuels. Under FERC policies, certain large volume customers located in proximity to the interstate pipelines delivering gas to us could bypass us and take delivery of gas directly from the pipeline or from a third party connecting with the pipeline. During the fiscal year ended October 31, 2011, no bypass occurred. The future level of bypass activity cannot be predicted.As noted above, many of our industrial customers are capable of burning a fuel other than natural gas, with fuel oil being the most prevalentsignificant competing energy alternative. Our ability to maintain industrial market share is largely dependent on price.relative prices of energy. The relationship between supply and demand has the greatest impact on the price of natural gas. The price of oil depends upon a number of factors beyond our control, including the relationship between worldwide supply and demand and the policies of foreign and domestic governments and organizations, as well as the value of
the
USU.S. dollar versus other currencies. Our liquidity could be impacted, either positively or negatively, as a result of
changes in oil and natural gas prices and the alternate fuel decisions made by industrial customers.
Under FERC policies, certain large volume customers located in proximity to the interstate pipelines delivering gas to us could bypass us and take delivery of gas directly from the pipeline or from a third party connecting with the pipeline. During the fiscal year ended October 31, 2014, no bypass occurred. The regulated utility alsofuture level of bypass activity cannot be predicted.
Natural gas for power generation competes with other
energy products, suchfuel sources for the generation of electricity, including coal, nuclear and renewable resources. Additionally, as
electricity and propane, inwith industrial customers, we compete with other pipeline providers to serve the
residential and small commercial customer markets. The most significant product competition is with electricity for space heating, water heating and cooking. There are four major electric companies within our service areas. We believe that the consumer’s preference for natural gas is influenced by such factors as price, value, availability, environmental attributes, comfort, convenience, reliability and energy efficiency. The direct use of natural gas in homes and businesses is the most efficient and cost effective use of natural gas and lowers the carbon footprint of those premises in our market area.power generation plants.
Other
During the year ended October 31,
2011,2014, our largest revenue generating customer contributed
$49.5$89.2 million, or
3%6%, of total operating revenues. Our largest margin generating customer contributed
$15.6$73.8 million, or
3%11% of total margin.
Our largest revenue and margin generating customer is the same customer.
Our costs for research and development are not material and are primarily limited to natural gas industry-sponsored research projects.
Compliance with federal, state and local environmental protection laws have had no material effect on our construction expenditures, earnings or competitive position. For further information on environmental issues, see “Environmental Matters” in Item 7
ofin this Form 10-K in Management’s Discussion and Analysis of Financial Condition and Results of Operations.
Costs incurred for natural gas, labor, employee benefits, consulting and construction are the business charges that we incur that are most significantly impacted by inflation. Changes to the cost of gas are generally recovered through regulatory mechanisms and do not significantly impact net income. Labor and employee benefits are components of the cost of service, and construction costs less utility deferred income taxes are the primary components of rate base. In order to recover increased costs and earn a fair return on rate base, we file general rate cases for review and approval by regulatory authorities when necessary. The ratemaking process has a natural time lag between incurrence of additional costs and the setting of new rates. See discussion above for information on IMRs to track and recover certain capital costs in North Carolina and Tennessee outside of a general rate case. In South Carolina, we operate under a RSA mechanism that reduces regulatory lag to one year, but we reserve the right to file general rate cases when necessary. Regulatory lag can impact earnings.
As of October 31,
2011,2014, our fiscal year end, we had
1,7821,879 employees compared with
1,7881,795 as of October 31,
2010.2013.
Our reports on Form 10-K, Form 10-Q and Form 8-K, and any amendments to these reports, are available at no cost on our website atwww.piedmontng.com as soon as reasonably practicable after the report is filed with or furnished to the Securities and Exchange Commission (SEC).Commission.
An overall economic downturn
or slow recovery could negatively impact our earnings.
Weakening or slow recovery
Any weakening of economic activity in our markets could result in a loss of customers, a decline in customer additions, especially in the new home construction market, or a decline in energy consumption, which could adversely affect our revenues or restrict our future growth. It may become more difficult for customers to pay their gas bills, leading to slow collections and higher-than-normal levels of accounts receivable. This could increase our financing requirements and non-gas cost bad debt expense. Deteriorating economic conditions could also affect pension costs by reducing the value of the investments that fund our pension plan and negatively affect actuarial
assumptions. Inflationary pressureassumptions, resulting in increased pension costs. The foregoing could
increase the costs of goods, servicesnegatively affect earnings and
labor, and an increase in interest rates could increase our interest expense and make it more difficult or expensive for us to access the capital markets. Earnings and liquidity,
would be negatively affected, reducing our ability to grow the business.
Increases in the wholesale price of natural gas could reduce our earnings and working capital.
The
A supply and demand balanceimbalance in natural gas markets could cause an increase in the price of natural gas. Recently, the increased production of U.S. shale natural gas has put downward pressure on the wholesale cost of natural gas, andgas; accordingly, restrictions or regulations on shale gas production could cause natural gas prices to increase. Additionally, the Commodity Futures Trading Commission (CFTC) under the 2010 Dodd-Frank Wall Street Reform and Consumer Protection Act has
regulatory authority of the over-the-counter derivatives markets. Regulations affecting derivatives could increase the price of our gas supply. The prudently incurred cost we pay for natural gas is passed directly through to our customers. Therefore, significant increases in the price of natural gas may cause our existing customers to conserve or motivate them to switch to alternate sources of energy as well as cause new home developers, builders and new customers to select alternative sources of energy. Decreases in the volume of gas we sell could reduce our earnings in the absence of decoupled rate structures, and a decline in new customers could impede growth in our future earnings. In addition, during periods when natural gas prices are high, our working capital costs could increase due to higher carrying costs of gas storage inventories,
and customersadding further upward pressure on customer bills. Customers may have trouble paying
those higher bills
leadingwhich may lead to bad debt expenses,
which may reduceultimately reducing our earnings.
A decrease in the
The availability of adequate interstate pipeline transportation capacity and natural gas supply
could reduce our earnings.may decrease.
We purchase
almost all of our gas supply from interstate sources that must then be transported to our service territory. Interstate pipeline companies transport the gas to our system under firm service agreements that are designed to meet the requirements of our core markets. A significant disruption to
or reduction in that supply or interstate pipeline capacity due to
unforeseen events including but not limited to, operational failures or disruptions, hurricanes, tornadoes, floods, freeze off of natural gas wells, terrorist
attacksor cyber-attacks or other acts of war,
or legislative or regulatory actions or requirements, including remediation related to integrity inspections, could reduce our normal interstate supply of gas and thereby reduce our earnings. Moreover, if additional natural gas infrastructure, including but not limited to exploration and drilling rigs and platforms, processing and gathering systems, off-shore pipelines, interstate pipelines and storage, cannot be built at a pace that meets demand, then our growth opportunities would be limited and our earnings negatively impacted.
Regulatory actions at the state level could impact our ability to earn a reasonable rate of return on our invested capital and to fully recover our operating costs as well as reduce our earnings.
Our regulated utility segment is regulated by the NCUC, the PSCSC and the TRA. These agencies set the rates that we charge our customers for our services. We monitor allowed rates of return and our ability to earn appropriate rates of return based on factors, such as increased operating costs, and initiate general rate proceedings as needed. Our earnings could be negatively impacted if a state regulatory commission were to prohibit us from setting rates that allow for the timely recovery of our costs and a reasonable return, or significantly lowers our allowed return or negatively alters our cost allocation, rate design, cost trackers, including margin decoupling and cost of gas, or prohibits recovery of regulatory assets, including deferred gas costs.
In the normal course of business in the regulatory environment, assets are placed in service before rate cases can be filed that could result in an adjustment of our returns. Once rate cases are filed, regulatory bodies have the authority to suspend implementation of the new rates while studying the cases. Because of this process, we may suffer the negative financial effects of having placed in service assets that do not initially earn our authorized rate of return without the benefit of rate relief, which is commonly referred to as “regulatory lag.” Additionally, our capital investment in recent years has been and is projected to remain at higher levels, increasing the risk of cost recovery. All of this may negatively impact our results of operations and earnings.
Rate cases also involve a risk of rate reduction, because once rates have been filed, they are still subject to challenge for their reasonableness by various intervenors. State regulators have approved various mechanisms to stabilize our gas utility margin, including margin decoupling in North Carolina, rate stabilization in South Carolina, and uncollectible gas cost recovery in all states. State regulators have approved other margin stabilizing mechanisms that, for example, allow us to recover any margin losses associated with negotiated transactions designed to retain large volume customers that could use alternative fuels or that may otherwise directly access natural gas supply through their own connection to an interstate pipeline. If regulators decided to discontinue allowing us to use these tariff mechanisms, it would negatively impact our results of operations, financial condition and cash flows. In addition, regulatory authorities also review whether our gas costs are prudent and can disallow the recovery of a portion of our gas costs that we seek to recover from our customers, which would adversely impact earnings.
Our debt and equity financings are also subject to regulation by the NCUC. Delays or failure to receive NCUC approval could limit our ability to access or take advantage of changes in the capital markets. This could negatively impact our liquidity or earnings.
Our business is subject to competition that could negatively affect our results of operations.
The natural gas business is competitive, and we face competition from other companies that supply energy, including electric companies, oil and propane dealers, renewable energy providers and coal companies in relation to sources of energy for electric power plants, as well as nuclear energy. A significant competitive factor is price.
In residential, commercial and industrial customer markets, our natural gas distribution operations compete with other energy products, primarily electricity, propane and fuel oil. Our primary product competition is with electricity for heating, water heating and cooking. Increases in the price of natural gas or decreases in the price of other energy sources could negatively impact our competitive position by decreasing the price benefits of natural gas to the consumer. In the case of industrial customers, such as manufacturing plants, adverse economic or market conditions, including higher gas costs, could cause these customers to
suspend business operations or to use alternative sources of energy or bypass our systems in favor of energy sources with lower per-unit costs.
Higher gas costs or decreases in the price of other energy sources may allow competition from alternative energy sources for applications that have traditionally used natural gas, encouraging some customers to move away from natural gas-fired equipment to equipment fueled by other energy sources. Competition between natural gas and other forms of energy is also based on efficiency, performance, reliability, safety and other non-price factors. Technological improvements in other energy sources and events that impair the public perception of the non-price attributes of natural gas could erode our competitive advantage. These factors in turn could decrease the demand for natural gas, impair our ability to attract new customers, and cause existing customers to switch to other forms of energy or to bypass our systems in favor of alternative competitive sources. This could result in slow or no customer growth and could cause customers to reduce or cease using our product, thereby reducing our ability to make capital expenditures and otherwise grow our business and adversely affecting our earnings.
Our business activities are concentrated in three states.
Approximately 96% of our assets and 86% of our earnings before taxes come from our regulated utility businesses. Further, approximately 70% of our natural gas utility customers, including customers served by three North Carolina municipalities who are our wholesale customers, and most of our utility transmission and distribution pipelines are located in North Carolina, with the remainder located in South Carolina and Tennessee. Changes in the regional economies, politics, regulations and weather patterns of North Carolina, South Carolina and Tennessee could negatively impact the growth opportunities available to us and the usage patterns and financial condition of customers and could adversely affect our earnings.
Changes
We are subject to new and existing laws and regulations that may require significant expenditures, significantly increase operating costs, or significant fines or penalties for noncompliance.
Our business and operations are subject to regulation by the FERC, the NCUC, the PSCSC, the TRA, the DOT, the EPA, the CFTC and other agencies, and we are subject to numerous federal and state laws and regulations. Compliance with existing or new laws and regulations may result in
federal laws or regulations could reduce the availability or increase the cost of our interstate pipeline capacity and/or gas supplyincreased capital, operating and
thereby reduce our earnings.The FERC has regulatory authority over some of our operations, including sales of natural gas in the wholesale market and the purchase and sale of interstate pipeline and storage capacity. Additionally, the Commodities Futures Trading Commission under the 2010 Dodd-Frank Wall Street Reform and Consumer Protection Act has regulatory authority of the over-the-counter derivatives markets. Regulations affecting derivatives could increase the price of our gas supply. Any federal legislation or agency regulation that has the effect of significantly raisingother costs that couldwhich may not be recoveredrecoverable in rates from our customerscustomers. For example, while we have implemented an IMR mechanism in North Carolina and Tennessee to recover certain capital expenditures made in compliance with federal and state safety and integrity management laws or reducingregulations, there is a risk that the availability of supply or capacity, the liquidityrelevant regulators will disallow some of the natural gas supply marketexpenditures under the IMR mechanism, and that the costs expended in compliance with such laws would not be recoverable through such rate mechanisms (but rather through general rate cases with extended lag). Because the language in some laws and regulations is not prescriptive, there is a risk that our interpretation of these laws and regulations may not be consistent with expectations of regulators. Any compliance failure related to these laws and regulations may result in fines, penalties or injunctive measures affecting operating assets. For example, under the Energy Policy Act of 2005, the FERC has civil penalty authority under the Natural Gas Act to impose penalties for current violations of up to $1 million per day for each violation. As the regulatory environment for our competitivenessindustry increases in complexity, the risk of inadvertent noncompliance could negatively impactalso increase. All of these events could result in a material adverse effect on our earnings.
business, results of operations or financial condition.
Climate change, carbon neutral or energy efficiency legislation or regulations could increase our operating costs or restrict our market opportunities, negatively affecting our growth, cash flows and earnings.
The federal and/or state governments may enact legislation or regulations that attempt to control or limit the causes of climate change, including greenhouse gas emissions such as carbon dioxide.dioxide and air emissions regulations that could be expanded to address emissions of methane. Such laws or regulations could impose costs tied to carbon emissions, operational
requirements
imposeor restrictions, or additional charges to fund energy efficiency
activities,activities. They could also provide a cost advantage to alternative energy sources,
other than natural gas, impose costs or restrictions on end users of natural gas, or result in other costs or
requirements. As a result, there is a possibility that, if enactedrequirements, such as costs associated with the adoption of new infrastructure and technology to respond to new mandates. The focus on climate change could negatively impact the reputation of fossil fuel products or
adopted, such legislation or regulationservices. The occurrence of these events could put upward pressure on the cost of natural gas relative to other energy sources, increase our costs
and the prices we charge to customers, reduce the demand for natural gas, and impact the competitive position of natural gas and the ability to serve new customers, negatively affecting our growth opportunities, cash flows and earnings.
Regulatory actions at the state level could impact our ability to earn a reasonable rate of return on our invested capital and to fully recover our operating costs as well as reduce our earnings.
Our regulated utility segment is regulated by the NCUC, the PSCSC and the TRA. These agencies set the rates that we charge our customers for our services. We monitor allowed rates of return and our ability to earn appropriate rates of return based on factors, such as increased operating costs, and initiate general rate proceedings as needed. If a state regulatory commission were to prohibit us from setting rates that allow for the timely recovery of our costs and a reasonable return by significantly lowering our allowed return or negatively altering our cost allocation, rate design, cost trackers (including margin decoupling and cost of gas) or other tariff provisions, then our earnings could be negatively impacted. In the normal course of business in the regulatory environment, assets are placed in service before rate cases can be filed that could result in an adjustment of our returns. Once rate cases are filed, regulatory bodies have the authority to suspend implementation of the new rates while studying the cases. Because of this process, we may suffer the negative financial effects of having placed in service assets that do not initially earn our authorized rate of return without the benefit of rate relief, which is commonly referred to as “regulatory lag.” Rate cases also involve a risk of rate reduction, because once rates have been filed, they are still subject to challenge for their reasonableness by various appropriate entities. Regulatory authorities also review whether our gas costs are prudent and can adjust the amount of our gas costs that we pass through to our customers. Additionally, our state regulators foster a competitive regulatory model that, for example, allows us to recover any margin losses associated with negotiated transactions designed to retain large volume customers that could use
alternative fuels or that may directly access natural gas supply through their own connection to an interstate pipeline. If there were changes in regulatory philosophies that altered our ability to compete for these customers, then we could lose customers or incur significant unrecoverable expenses to retain them. Both scenarios would impact our results of operations, financial condition and cash flows. Our debt and equity financings are also subject to regulation by the NCUC. Delays or failure to receive NCUC approval could limit our ability to access or take advantage of changes in the capital markets. This could negatively impact our liquidity or earnings.
Weather conditions may cause our earnings to vary from year to year.
Our earnings can vary from year to year, depending in part on weather conditions.
Currently, weWarmer-than-normal weather can reduce our utility margins as customer consumption declines. We have in place regulatory mechanisms
and rate design that normalize
ourthe margin
for weatherwe collect from certain customer classes during the winter, providing for an adjustment up or down, to take into account warmer-than-normal or colder-than-normal weather.
Mild winter temperatures can cause a decrease in the amount of gas we sell and deliver in any year and the margin we collect from these customers. If our rates and tariffs
wereare modified to eliminate weather protection
provisions, such as weather normalization and rate decoupling tariffs, then we would be exposed to significant risk associated with
weather. Additionally, our weather
normalization mechanisms do not ensure full protection, especially for significantly warmer-than-normal winter weather. As a result of these events, our results of operations and
our earnings could vary
as a result.Our gas supply risk management programs are subject to state regulatory approval or annual review in gas cost proceedings.
We manage our gas supply costs through short-term and long-term procurement and storage contracts. In the normal coursebe negatively impacted.
The operation of
business, we utilize New York Mercantile Exchange (NYMEX) exchange traded instruments of various durations for the forward purchase or sale of our natural gas requirements, subject to regulatory approval or review. As a component of our gas costs, these expenses are subject to regulatory approval, and we may be exposed to additional liability if the recovery of these costs of gas supply procurement or risk management activities is excluded by our regulators in gas cost recovery proceedings.Operational interruptions to our gas distribution and transmission activities causedmay be interrupted by accidents, work stoppage, severe weather conditions, including destructive weather patterns, such as hurricanes, tornadoes and floods, pandemic or acts of terrorism could adversely impact earnings.
and sabotage.
Inherent in our gas distribution and transmission activities,
including natural gas and LNG storage, are a variety of hazards and operational risks, such as
third partythird-party excavation damage, leaks, ruptures and mechanical problems. Severe weather conditions, as well as acts of terrorism
and sabotage, could also damage our pipelines and other infrastructure and disrupt our ability to conduct our natural gas distribution and transportation business.
PandemicThe outbreak of a pandemic could result in a significant part of our workforce being unable to operate or maintain our infrastructure or perform other tasks necessary to conduct our business. If
the foregoingthese events are severe enough or if they lead to operational interruptions, they could cause substantial financial losses. In addition, these risks could result in loss of human life, significant damage to property, environmental damage, impairment of our operations and substantial loss to us. The location of pipeline and storage facilities near populated areas, including residential areas, commercial business centers, industrial sites and other public gathering places, could increase the level of damages resulting from these risks. Our regulators may not allow us to recover part or all of the increased cost related to the foregoing events from our customers, which would negatively affect our earnings.
With part of our workforce represented by unions, we are exposed to the risk of a work stoppage. The occurrence of any of these events could adversely affect our financial position, results of operations and cash flows.
We may not be able to complete necessary or desirable pipeline
integrityexpansion or infrastructure development
or maintenance projects, which may delay or prevent us from serving our customers or expanding our business.
In order to serve current or new customers or expand our service to existing customers, we need to maintain, expand or upgrade our distribution, transmission and/or storage infrastructure, including laying new pipeline and building compressor stations. Various factors may prevent or delay us from completing such projects or make completion more costly, such as the inability to obtain required approval from local, state and/or federal regulatory and governmental bodies, public opposition to the project, inability to obtain adequate financing, competition for labor and materials, construction delays, cost overruns, and inability to negotiate acceptable agreements relating to rights-of-way, construction or other material development components. As a result, we may not be able to adequately serve existing customers or support customer growth, or could result in higher than anticipated cost, both of which would negatively impact our earnings.
Elevated levels of capital expenditures may weaken our financial position and inhibit customer growth.
We make significant annual capital expenditures for system integrity, infrastructure and maintenance that do not immediately produce revenue. We have the ability to recover these costs either through general rate cases or alternative rate mechanisms approved by state regulatory commissions, such as RSAs and IMRs, that periodically adjust rates to reflect incurred capital expenditures. However, before rates are adjusted, we fund construction through operating cash flows and by accessing short- and long-term capital markets and as a result, we may experience reduced liquidity and deteriorating credit metrics, which may weaken our financial position and could trigger a possible downgrade from the rating agencies. In addition,
after these capital costs are reflected in rates, to the
counterpartiesextent that rates rise considerably, customers may choose alternative forms of energy to
meet their needs. This would reduce our
power generation construction and service agreements may elect to terminate the agreements,customer growth, which would
negatively affect futureweaken our financial position by reducing earnings and cash
flow.flows.
A downgrade in our credit ratings could negatively affect our cost of and ability to access capital.
Our ability to obtain adequate and cost effective financing depends
in part on our credit ratings. A negative change in our ratings outlook or any downgrade in our current investment-grade credit ratings by our rating agencies, particularly below investment grade, could adversely affect our
costcosts of borrowing and/or access to sources of liquidity and capital. Such a downgrade could further limit our access to private credit markets and increase the costs of borrowing under available credit lines. Should our credit ratings be downgraded, the interest rate on our borrowings under our revolving credit agreement
and commercial paper (CP) program, as well as on any future public or private debt issuances, would increase. An increase in borrowing costs without the ability to recover these higher costs in the rates charged to our customers could adversely affect earnings by limiting our ability to earn our allowed rate of return.
The inability
We may be unable to access capital or
significant increases in the cost of capital
could adversely affect our business.may significantly increase.
Our ability to obtain adequate and cost effective financing is dependent upon the liquidity of the financial markets, in addition to our credit ratings. Disruptions in the capital and credit markets
or waning investor sentiment could adversely affect our ability to access short-term and long-term capital. Our access to funds under
short-term credit facilitiesour CP program is dependent on
the ability of the participating banks to meet their funding commitments. Those banks may not be able to meet their funding commitments if they experience shortages of capital and liquidity.investor demand for our commercial paper. Disruptions and volatility in the
Europeanglobal credit
marketmarkets could
causelimit the
demand for our commercial paper or result in the need to offer higher interest
rate we pay on our short-term credit facility,rates to investors, which
is based on the London Interbank Offered Rate, to increase, couldwould result in higher
interestexpense and could adversely impact liquidity. Tax rates on
future financings, anddividends may increase, which could
impactincrease the
liquiditycost of
the lenders under our short-term credit facility, potentially impairing their ability to meet their funding commitments. Longer disruptions in the capital and credit markets as a result of uncertainty, changing or increased regulation, reduced alternatives or failures of significant financial institutions could adversely affect our access to capital needed for our business.equity. The inability to access adequate
capital or the increase in cost of capital may require us to conserve cash, prevent or delay us from making capital expenditures, and require us to reduce or eliminate the dividend or other discretionary uses of cash. A significant reduction in our liquidity could cause a negative change in our ratings outlook or even a reduction in our credit ratings. This could in turn further limit our access to credit markets and increase our
costcosts of borrowing.
Changes in federal
andand/or state fiscal,
tax and monetary policy could significantly increase our costs or decrease our cash flows.
Changes in federal
andand/or state fiscal,
tax and monetary policy may result in increased taxes, interest rates, and inflationary pressures on the costs of goods, services and labor. This could increase our expenses and decrease our earnings if we are not able to recover such increased costs from our customers.
This series ofThese events may increase our rates to customers and thus may negatively impact customer billings and customer growth. Changes in accounting or tax rules could negatively affect our cash
flow.flows. Any of these events may cause us to increase debt, conserve cash, negatively affect our ability to make capital expenditures to grow the business or require us to reduce or eliminate the dividend or other discretionary uses of cash, and could negatively affect earnings.
We do not generate sufficient cash flows to meet all our cash needs.
Historically, we
We have made,
and expect to continue to make, large capital expenditures in order to finance the expansion,
upgrading and
upgradingmaintenance of our transmission and distribution systems. We also purchase natural gas for storage. We have made several equity method investments and will continue to pursue other similar investments, all of which are and will be important to our growth and profitability. We fund a portion of our cash needs for these purposes, as well as contributions to our employee pensions and benefit plans, through borrowings under credit arrangements and by offering new debt and equity securities. Our dependency on external sources of financing creates the risk that our profits could decrease as a result of higher borrowing costs and that we may not be able to secure external sources of cash necessary to fund our operations and new investments on terms acceptable to us. Volatility in seasonal cash flow requirements, including requirements for our gas supply procurement and risk management programs, may require increased levels of borrowing that could result in non-compliance with the debt-to-equity ratios in our credit facilities as well as cause a credit rating downgrade. Any disruptions in the capital and credit markets could require us to conserve cash until the markets stabilize or until alternative credit arrangements or other funding required for our needs can be secured. Such measures could cause deferral of major capital expenditures, changes in our gas supply procurement program, the reduction or elimination of the dividend payment or other discretionary uses of cash, and could negatively affect our future growth and earnings.
As a result of cross-default provisions in our borrowing arrangements, we may be unable to satisfy all of our outstanding obligations in the event of a default on our part.
The terms of our senior indebtedness, including our revolving credit facility, contain cross-default provisions which provide that we will be in default under such agreements in the event of certain defaults under the indenture or other loan agreements. Accordingly, should an event of default occur under any of those agreements, we face the prospect of being in
default under all of our debt agreements, obliged in such instance to satisfy all of our outstanding indebtedness and unable to satisfy all of our outstanding obligations simultaneously. In such an event, we might not be able to obtain alternative financing or, if we are able to obtain such financing, we might not be able to obtain it on terms acceptable to us, which would negatively affect our ability to implement our business plan, make capital expenditures and finance our operations.
We are exposed to credit risk of counterparties with whom we do business.
Adverse economic conditions affecting, or financial difficulties of, counterparties with whom we do business could impair the ability of these counterparties to pay for our services or fulfill their contractual obligations. We depend on these counterparties to remit payments to fulfill their contractual obligations on a timely basis. Any delay or default in payment or failure of the counterparties to meet their contractual obligations could adversely affect our financial position, results of operations or cash flows.
The cost of providing pension benefits
is subject to changes in pension fund values and
other factors and could unfavorably impact our liquidity and results of operations.related funding obligations may increase.
Our costs of providing a non-contributory defined benefit pension plan are dependent on a number of factors, such as the rates of return on plan assets, discount rates, the level of interest rates used to measure the required minimum funding levels of the plan, changes in these actuarial assumptions, future government regulation,
changes in life expectancy and our required or voluntary contributions made to the plan. Changes in actuarial assumptions and differences between the assumptions and actual values, as well as a significant decline in the value of investments that fund our pension plan, if not offset or mitigated by a decline in our liabilities, could increase the expense of our pension plan, and we could be required to fund our plan with significant amounts of cash. Such cash funding obligations could have a material impact on our liquidity by reducing cash flows and could negatively affect results of operations.
We are subject to numerous environmental laws and regulations that may require significant expenditures or increase operating costs.
We are subject to numerous federal and state environmental laws and regulations affecting many aspects of our present and future operations. These laws and regulations can result in increased capital, operating and other costs. These laws and regulations generally require us to obtain and comply with a wide variety of environmental licenses, permits, inspections and approvals. Compliance with these laws and regulations can require significant expenditures for clean-up costs and damages arising out of contaminated properties. Failure to comply may result in fines, penalties and injunctive measures affecting operating assets. Additionally, the discovery of presently unknown environmental conditions could give rise to expenditures and liabilities, including fines or penalties, which could have a material adverse effect on our business, results of operations or financial condition.
We are subject to new and existing pipeline safety and system integrity laws and regulations that may require significant expenditures or significantly increase operating costs.
We are subject to existing and may be subject to new pipeline safety and system integrity laws and regulations affecting various aspects of our present and future operations. These laws and regulations generally require us to enhance pipeline safety and system integrity by identifying and reducing pipeline risks. Compliance with these laws and regulations may result in increased capital, operating and other costs which may not be recoverable in rates from our customers. Furthermore, because the language in some of these laws and regulations is not prescriptive, there is a risk that our interpretation of these laws and regulations may not be consistent with expectations of regulators. Any compliance failure related to these laws and regulations may result in fines, penalties or injunctive measures. All of the above could result in a material adverse effect on our business, results of operations or financial condition.
We may invest in companies that have risks that are inherent in their businesses, and these risks may negatively affect our earnings from those companies.
We are invested in several natural gas related businesses as an equity method investor. The businesses in which we invest are subject to laws, regulations or market conditions, or have risks inherent in their operations, that could adversely affect their performance. Those that are not directly regulated by state or federal regulatory bodies could be subject to adverse market conditions not experienced by
theour regulated utility
segment and our regulated non-utilities segment. We do not control the day to day operations of our equity method investments, and thus the management of these businesses by our partners could adversely impact their performance.
We may not be able to fully direct the management and policies of these businesses, and other participants in those relationships may take action contrary to our interests, including making operational decisions that could affect our costs and liabilities related to our investment. In addition, other participants may withdraw from the business, become financially distressed or bankrupt, or have economic or other business interests or goals that are inconsistent with ours. The results of operations from those investments may be significantly less or realized significantly later than anticipated. All the
foregoingabove could adversely affect our earnings from or return of our investment in these businesses. We could make future
equity method investments,
in similarlyacquisitions, or other business arrangements involving regulated or unregulated businesses
that haveas a minority or majority owner, with the similar potential to adversely affect our earnings from or return of our investment in those businesses.
All these adverse impacts could negatively affect our results of operations or financial condition.Our inability
We may be unable to attract and retain professional and technical employees,
which could adversely impact our earnings.
Our ability to implement our business strategy and serve our customers is dependent upon the continuing ability to employ talented professionals and attract,
train, develop and retain a skilled workforce. We are subject to the risk that we will not be able to effectively replace the knowledge and expertise of an aging workforce as those workers retire. Without a
properly skilled
and experienced workforce, our
abilitycosts, including productivity and safety costs, costs to
provide quality service to our customersreplace employees, and
meet our regulatory requirements will be challengedcosts as a result of errors may increase, and this could negatively impact our earnings.
Changes
Cybersecurity attack, acts of cyber-terrorism or failure of technology systems could disrupt our business operations, shut down our facilities or result in accounting standardsthe loss or exposure of confidential or sensitive customer, employee or Company information.
We are placing greater reliance on technological tools that support our operations and corporate functions and processes. We may own these tools or have a license to use them, or we may rely on the technological tools of third parties to whom we outsource processes. We use such tools to manage our natural gas distribution and transmission pipeline operations, maintain customer, employee, Company and vendor data, prepare our financial statements and manage supply chain and other business processes. One or more of these technologies may fail due to physical disruption such as flooding, design defects or human error, or we may be unable to have these technologies supported, updated, expanded or integrated into other
technologies. As technology and as our business operations change, we may replace or add systems and tools, and failure to successfully execute on these projects may result in business disruption or loss of data. Additionally, our business operations and information technology systems may be vulnerable to attack by individuals or organizations that could result in disruption to them.
Disruption or failure of business operations and information technology systems could shut down our facilities or otherwise adversely impact our
financial condition and resultsability to safely deliver natural gas to our customers, operate our pipeline systems, serve our customers effectively or manage our assets. An attack on or failure of
operations.The SEC is considering whether issuersinformation technology systems could result in the United States shouldunauthorized release of customer, employee or other confidential or sensitive data. These events could adversely affect our business reputation, diminish customer confidence, disrupt operations, subject us to financial liability or increased regulation, increase our costs and expose us to material legal claims and liability, and our operations and financial results could be requiredadversely affected.
Our insurance coverage may not be sufficient.
We currently have general liability and property insurance in place in amounts that we consider appropriate based on our business risk and best practices in our industry and in general business. Such policies are subject to
prepare financial statementscertain limits and deductibles and include business interruption coverage for limited circumstances. Insurance coverage for risks against which we and others in
accordance with International Financial Reporting Standards (IFRS) insteadour industry typically insure may not be available in the future, or may be available but at materially increased costs, reduced coverage or on terms that are not commercially reasonable. Premiums and deductibles may increase substantially. The insurance proceeds received for any loss of, or any damage to, any of our facilities or to third parties may not be sufficient to restore the total loss or damage. Further, the proceeds of any such insurance may not be paid in a timely manner. The occurrence of any of the
current generally accepted accounting principles (GAAP) in the United States. IFRS isforegoing could have a
comprehensive set of accounting standards promulgated by the International Accounting Standards Board (IASB), which are currently inmaterial adverse effect
for most other countries in the world. Unlike U.S. GAAP, IFRS does not currently provide an industry accounting standard for rate-regulated activities. As such, if IFRS were adopted in its current state, we may be precluded from applying certain regulatory accounting principles, including the recognition of certain regulatory assets and regulatory liabilities. The potential issues associated with rate-regulated accounting, along with other potential changes associated with the adoption of IFRS, may adversely impacton our
reported financial
condition andposition, results of operations
should adoption of IFRS be required. Also, the U.S. Financial Accounting Standards Board is considering various changes to U.S. GAAP, some of which may be significant, as part of a joint effort with the IASB to converge accounting standards over the next several years. If approved, adoption of these changes may adversely impact our reported financial condition and
results of operations.cash flows.
Item 1B. Unresolved Staff Comments
All property included in the
consolidated balance sheetsConsolidated Balance Sheets in “Utility Plant” is owned by us and used in our regulated utility segment. This property consists of intangible plant,
production plant,other storage plant, transmission plant, distribution plant and general plant as categorized by natural gas utilities, with
94%the majority of the total invested in utility distribution and transmission plant to serve our customers. We have approximately
2,7002,910 linear miles of transmission
pipelinespipeline up to 30 inches in diameter that connect our distribution systems with the transmission systems of our pipeline suppliers. We distribute natural gas through approximately
22,00022,300 linear miles of distribution mains up to 16 inches in diameter. The transmission pipelines and distribution mains are generally underground, located near public streets and highways, or on property owned by others, for which we have obtained the necessary legal rights to place and operate our facilities on such property. All of these properties are located in North Carolina, South Carolina and Tennessee. Utility Plant includes “Construction work in
progress”progress," which primarily represents distribution, transmission and general plant projects that have not been placed into service pending completion.
None of our property is encumbered, and all property is in use except for “Plant held for future use” as classified in
our consolidated balance sheets.the Consolidated Balance Sheets. The amount classified as plant held for future use
relates to expenditures associated with a potential LNG peak storage facilityis comprised of land located in
the eastern part of North Carolina that has been delayed given the slowing of our growth due to current economic conditions. Another project under construction will help serve the near term system pressure requirements in a cost effective manner in that part ofRobeson County, North Carolina.
The timingFor further information on this Robeson County property, see Note 1 and
design scope ofNote 2 to the
expansion of our facilitiesconsolidated financial statements in this
area will be determined as our system infrastructure and market supply growth requirements in North Carolina dictate.Form 10-K.
We own or lease for varying periods our corporate headquarters building located in Charlotte, North Carolina and our
operating locations and resource centers
located in
the locations shown below.North Carolina, South Carolina and Tennessee. Lease payments for these various offices totaled
$4$4.5 million for the year ended October 31,
2011. | | | | |
North Carolina
| | South Carolina | | Tennessee |
Burlington
| | Anderson | | Nashville |
Cary
| | Gaffney | | |
Charlotte
| | Greenville | | |
Elizabeth City
| | Spartanburg | | |
Fayetteville
| | | | |
Goldsboro
| | | | |
Greensboro
| | | | |
Hickory
| | | | |
High Point
| | | | |
Indian Trail
| | | | |
New Bern
| | | | |
Reidsville
| | | | |
Rockingham
| | | | |
Salisbury
| | | | |
Spruce Pine
| | | | |
Tarboro
| | | | |
Wilmington
| | | | |
Winston-Salem
| | | | |
2014.
Property included in the
consolidated balance sheetsConsolidated Balance Sheets in “Other Physical Property” is owned by the parent company and one of its subsidiaries. The property owned by the parent company primarily consists of natural gas water heaters leased to commercial customers. The property owned by the subsidiary is real estate. None of our other subsidiaries directly own property as their operations consist solely of participating in joint ventures as an equity member.
Item 3. Legal Proceedings
We have only
immaterial litigation or routine
immaterial litigation in the normal course of business.
Item 4.
(Removed and Reserved)Mine Safety Disclosures
Not applicable.
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Our common stock (symbol PNY) is traded on the New York Stock Exchange (NYSE). The following table provides information with respect to the high and low sales prices from the NYSE Composite for each quarterly period for the years ended October 31,
20112014 and
2010. | | | | | | | | | | | | | | | | | | |
2011 | | High | | | Low | | | 2010 | | High | | | Low | |
Quarter ended: | | | | | | | | | | Quarter ended: | | | | | | | | |
January 31 | | $ | 30.10 | | | $ | 27.57 | | | January 31 | | $ | 27.84 | | | $ | 22.51 | |
April 30 | | | 32.00 | | | | 27.88 | | | April 30 | | | 28.52 | | | | 23.87 | |
July 31 | | | 31.98 | | | | 28.80 | | | July 31 | | | 27.97 | | | | 24.50 | |
October 31 | | | 33.60 | | | | 25.86 | | | October 31 | | | 29.85 | | | | 26.15 | |
2013.
|
| | | | | | | | | | | | | | | | | | |
| 2014 | | High |
| | Low |
| | 2013 | | High |
| | Low |
|
| Quarter ended: | | | | | | Quarter ended: | | | | |
| January 31 | | $ | 34.18 |
|
| $ | 31.94 |
| | January 31 | | $ | 33.10 |
| | $ | 28.51 |
|
| April 30 | | 36.55 |
|
| 32.12 |
| | April 30 | | 34.92 |
| | 31.73 |
|
| July 31 | | 37.86 |
|
| 34.30 |
| | July 31 | | 35.53 |
| | 32.39 |
|
| October 31 | | 38.36 |
|
| 33.38 |
| | October 31 | | 35.05 |
| | 31.56 |
|
As of December
16, 2011,12, 2014, our common stock was owned by
13,91613,379 shareholders of record. Holders of record exclude the individual and institutional security owners whose shares are held in
the street name or in the name of an investment company.
The following table provides information with respect to quarterly dividends paid on common stock for the years ended October 31,
20112014 and
2010.2013. We expect that comparable cash dividends will continue to be paid in the future.
| | | | | | | | | | |
2011 | | Dividends Paid
Per Share | | | 2010 | | Dividends Paid
Per Share | |
Quarter ended: | | | | | | Quarter ended: | | | | |
January 31 | | | 28 | ¢ | | January 31 | | | 27 | ¢ |
April 30 | | | 29 | ¢ | | April 30 | | | 28 | ¢ |
July 31 | | | 29 | ¢ | | July 31 | | | 28 | ¢ |
October 31 | | | 29 | ¢ | | October 31 | | | 28 | ¢ |
|
| | | | | | | | | | |
| | | Dividends Paid | | | | Dividends Paid |
| 2014 | | Per Share | | 2013 | | Per Share |
| Quarter ended: | | | | | Quarter ended: | | | |
| January 31 | | 31 |
| ¢ | | January 31 | | 30 |
| ¢ |
| April 30 | | 32 |
| ¢ | | April 30 | | 31 |
| ¢ |
| July 31 | | 32 |
| ¢ | | July 31 | | 31 |
| ¢ |
| October 31 | | 32 |
| ¢ | | October 31 | | 31 |
| ¢ |
The amount of cash dividends that may be paid on common stock is restricted by provisions contained in certain note agreements under which long-term debt was issued, with those for the senior notes being the most restrictive. We cannot pay or declare any dividends or make any other distribution on any class of stock or make any investments in subsidiaries or permit any subsidiary to do any of the above (all of the foregoing being “restricted payments”) except out of net earnings available for restricted payments. As of October 31,
2011, net earnings available for restricted payments were greater than retained earnings; therefore,2014, our
retained earnings wereability to pay dividends was not restricted.
The following table provides information with respect to repurchases of our common stock under the Common Stock Open Market Purchase Program during the three months ended October 31,
2011. | | | | | | | | | | | | | | | | |
Period | | Total Number
of Shares
Purchased | | | Average Price
Paid Per Share | | | Total Number of
Shares Purchased
as Part of Publicly
Announced Program | | | Maximum Number
of Shares that May
Yet be Purchased
Under the Program (1) | |
Beginning of the period | | | | | | | | | | | | | | | 3,710,074 | |
8/1/11 - 8/31/11 | | | — | | | $ | — | | | | — | | | | 3,710,074 | |
9/1/11 - 9/30/11 | | | 19,345 | (2) | | $ | 31.28 | | | | — | | | | 3,710,074 | |
10/1/11 - 10/31/11 | | | 1,753 | (2) | | $ | 33.29 | | | | — | | | | 3,710,074 | |
Total | | | 21,098 | | | $ | 31.45 | | | | — | | | | | |
|
| | | | | | | | |
| Period | | Total Number of Shares Purchased | | Average Price Paid Per Share | | Total Number of Shares Purchased as Part of Publicly Announced Program | | Maximum Number of Shares that May Yet be Purchased Under the Program (1) |
| Beginning of the period | | | | | | | | 2,910,074 |
| 8/1/14 – 8/31/14 | | — | | — | | — | | 2,910,074 |
| 9/1/14 – 9/30/14 | | — | | — | | — | | 2,910,074 |
| 10/1/14 – 10/31/14 | | — | | — | | — | | 2,910,074 |
| | | | | | | | |
| Total | | — | | — | | — | | |
| |
(1) | The Common Stock Open Market Purchase Program was approved by the Board of Directors and announced on June 4, 2004 to purchase up to three million shares of common stock for reissuance under our dividend reinvestment and stock purchase, employee stock purchase and incentive compensation plans. On December 16, 2005, the Board of Directors approved an increase in the number of shares in this program from three million to six million to reflect the two-for-one stock split in 2004. TheOn that date, the Board also approved on that date an amendment of the Common Stock Open Market Purchase Program to provide for the purchase of up to four million additional shares of common stock to maintain our debt-to-equity capitalization ratios at target levels. The additional four million shares were referred to as our accelerated share repurchase (ASR) program. On March 6, 2009, the Board of Directors authorized the repurchase of up to an additional four million shares under the Common Stock Open Market Purchase Program and the ASR program, which were consolidated. |
(2) | The total number of shares purchased is shares withheld by us to satisfy tax withholding obligations related to the vesting of shares of restricted stock and shares awarded under a retention award under incentive compensation plans, which are outside of the Common Stock Open Market Purchase Program. |
Discussion of our compensation plans, under which shares of our common stock are authorized for issuance, is included in the portion of our proxy statement captioned “Executive Compensation” to be filed no later than January 31, 2015, in connection with our Annual Meeting to be held on March 5, 2015, and is incorporated herein by reference.
Comparisons of Cumulative Total Shareholder Returns
The following performance graph compares our cumulative total shareholder return from October 31,
20062009 through October 31,
20112014 (a five-year period) with
the average performance of our
utilityindustry peer group and the Standard & Poor’s 500 Stock Index, a broad market index (the S&P
500)500 Index).
Large natural gasOur local distribution
company (LDC) Peer Group index is comprised of peer group companies that are
representative of our peersdomiciled in the
natural gas distribution industry are included in our LDC Peer Group index.The Laclede Group, Inc. and South Jersey Industries, Inc. were added to our peer group because they areUnited States, publicly traded companiesin the U.S. energy industry with a primary focus on natural gas distribution and transmission businesses in multi-state territories and have similar annual revenues and market capitalization as compared with us.to ours. We attempt to have our peer group companies meet a majority of these criteria for inclusion in the group, and we use the same peer group to calculate our cumulativerelative total shareholder return asreturns, which we use for market benchmarking for our executive compensation plans. It
Over the past several years, we have made significant additional investments in transmission pipeline infrastructure. In light of this transmission business and now owning and operating over 2,900 miles of transmission pipeline, our LDC Peer Group was
recommended byupdated to include CenterPoint Energy and Questar Corporation, effective with our performance award under an approved incentive compensation plan covering a
benefits consultantthree-year performance period that
we expand our peer group.ended October 31, 2014. Our total return of $100 invested as of October 31, 20112014 was $147.$198. With the addition of The LacledeCenterPoint Energy and Questar Corporation, our LDC Peer Group Inc. and South Jersey Industries, Inc., our peer group return was $148.$236. Without them, the peer group return would have been $142.
$241.
The graph assumes that the value of an investment in Common Stock and in each index was $100 at October 31,
20062009 and that all dividends were reinvested. Stock price performances shown on the graph are not indicative of future price performance.
|
Comparisons of Five-Year Cumulative Total Returns
Value of $100 Invested as of October 31, 2006
|
 |
LDC Peer Group—The following companies are included: AGL Resources, Inc., Atmos Energy Corporation,
CenterPoint Energy, New Jersey Resources Corporation,
NICOR Inc., NiSource Inc., Northwest Natural Gas Company,
Questar Corporation, South Jersey Industries, Inc., Southwest Gas Corporation, The Laclede Group, Inc., Vectren Corporation and WGL Holdings, Inc.
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | 2009 | | 2010 | | 2011 | | 2012 | | 2013 | | 2014 |
| Piedmont | | $ | 100 |
| | $ | 132 |
| | $ | 152 |
| | $ | 154 |
| | $ | 171 |
| | $ | 198 |
|
| LDC Peer Group | | 100 |
| | 129 |
| | 156 |
| | 167 |
| | 201 |
| | 236 |
|
| S&P 500 Index | | 100 |
| | 117 |
| | 126 |
| | 145 |
| | 185 |
| | 216 |
|
Item 6. Selected Financial Data
The following table provides selected financial data for the years ended October 31,
20072010 through
2011. | | | | | | | | | | | | | | | | | | | | |
In thousands except per share amounts | | 2011 | | | 2010 | | | 2009 | | | 2008 | | | 2007 | |
Operating Revenues | | $ | 1,433,905 | | | $ | 1,552,295 | | | $ | 1,638,116 | | | $ | 2,089,108 | | | $ | 1,711,292 | |
Margin (operating revenues less cost of gas) | | $ | 573,639 | | | $ | 552,592 | | | $ | 561,574 | | | $ | 552,973 | | | $ | 524,165 | |
Net Income | | $ | 113,568 | | | $ | 141,954 | | | $ | 122,824 | | | $ | 110,007 | | | $ | 104,387 | |
Earnings per Share of Common Stock: | | | | | | | | | | | | | | | | | | | | |
Basic | | $ | 1.58 | | | $ | 1.96 | | | $ | 1.68 | | | $ | 1.50 | | | $ | 1.41 | |
Diluted | | $ | 1.57 | | | $ | 1.96 | | | $ | 1.67 | | | $ | 1.49 | | | $ | 1.40 | |
Cash Dividends per Share of Common Stock | | $ | 1.15 | | | $ | 1.11 | | | $ | 1.07 | | | $ | 1.03 | | | $ | 0.99 | |
Total Assets * | | $ | 3,242,541 | | | $ | 3,053,275 | | | $ | 3,118,819 | | | $ | 3,138,401 | | | $ | 2,823,106 | |
Long-Term Debt (less current maturities) | | $ | 675,000 | | | $ | 671,922 | | | $ | 732,512 | | | $ | 794,261 | | | $ | 824,887 | |
* | Total assets for the years 2007 and 2008 have been adjusted to reflect the gross presentation rather than a net presentation in accordance with the adoption of new accounting guidance related to offsetting of amounts related to certain contracts with the same counterparty. |
2014.
|
| | | | | | | | | | | | | | | | | | | | |
| In thousands, except per share amounts |
| 2014 |
| 2013 |
| 2012 |
| 2011 |
| 2010 |
| Operating Revenues |
| $ | 1,469,988 |
|
| $ | 1,278,229 |
|
| $ | 1,122,780 |
|
| $ | 1,433,905 |
| | $ | 1,552,295 |
|
| Margin (operating revenues less cost of gas) |
| $ | 690,208 |
|
| $ | 621,490 |
|
| $ | 575,446 |
|
| $ | 573,639 |
| | $ | 552,592 |
|
| Net Income |
| $ | 143,801 |
|
| $ | 134,417 |
|
| $ | 119,847 |
|
| $ | 113,568 |
| | $ | 141,954 |
|
| Earnings per Share of Common Stock: |
|
|
|
|
|
|
| | | |
| Basic |
| $ | 1.85 |
|
| $ | 1.80 |
|
| $ | 1.67 |
|
| $ | 1.58 |
| | $ | 1.96 |
|
| Diluted |
| $ | 1.84 |
|
| $ | 1.78 |
|
| $ | 1.66 |
|
| $ | 1.57 |
| | $ | 1.96 |
|
| Cash Dividends per Share of Common Stock |
| $ | 1.27 |
| | $ | 1.23 |
| | $ | 1.19 |
| | $ | 1.15 |
| | $ | 1.11 |
|
| Total Assets |
| $ | 4,784,253 |
|
| $ | 4,368,609 |
|
| $ | 3,769,939 |
| | $ | 3,242,541 |
| | $ | 3,053,275 |
|
| Long-Term Debt (less current maturities) |
| $ | 1,424,430 |
|
| $ | 1,174,857 |
|
| $ | 975,000 |
| | $ | 675,000 |
| | $ | 671,922 |
|
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Forward-Looking Statements
This report, as well as other documents we file with the Securities and Exchange Commission (SEC), may contain forward-looking statements. In addition, our senior management and other authorized spokespersons may make forward-looking statements in print or orally to analysts, investors, the media and others. These statements are based on management’s current expectations from information currently available and are believed to be reasonable and
are made in good faith. However, the forward-looking statements are subject to risks and uncertainties that could cause actual results to differ materially from those projected in the statements. Factors that may make the actual results differ from anticipated results include, but are not limited to the following, as well as those discussed in Item 1A. Risk Factors:
| • | | Regulatory issues. Deregulation, regulatory restructuring and other regulatory issues may affect us and those from whom we purchase natural gas transportation and storage service, including issues that affect allowed rates of return, terms and conditions of service, rate structures and financings. We monitor our ability to earn appropriate rates of return and initiate general rate proceedings as needed.
|
| • | | Customer growth and consumption. Residential, commercial, industrial and power generation growth and energy consumption in our service areas may change. The ability to retain and grow our customer base, the pace of that growth and the levels of energy consumption are impacted by general business and economic conditions, such as interest rates, inflation, fluctuations in the capital markets and the overall strength of the economy in our service areas and the country, and by fluctuations in the wholesale prices of natural gas and competitive energy sources. Large-volume industrial customers may switch to alternate fuels or bypass our system or shift to special competitive contracts or to tariff rates that are at lower per-unit margins than that customer’s existing rate.
|
| • | | Competition in the energy industry. We face competition in the energy industry, such as from electric companies, energy marketing and trading companies, fuel oil and propane dealers, renewable energy companies and coal companies, and we expect this competitive environment to continue.
|
| • | | The capital-intensive nature of our business. In order to maintain growth, we must invest in our natural gas transmission and distribution system each year. The cost of and the ability to complete these capital projects may be affected by the ability to obtain and the cost of obtaining governmental approvals, compliance with federal and state pipeline safety and integrity regulations, cost and timing of project development-related contracts and approvals, project development delays, federal and state tax policies, and the cost and availability of labor and materials. Weather, general economic conditions and the cost of funds to finance our capital projects can materially alter the cost and timing of a project.
|
| • | | Access to capital markets. Our internally generated cash flows are not adequate to finance the full cost of capital expenditures. As a result, we rely on access to both short-term and long-term capital markets as a significant source of liquidity for capital requirements not satisfied by cash flows from operations. Changes in the capital markets, our financial condition or the financial condition of our lenders or investors could affect access to and cost of capital.
|
| • | | Changes in the availability and cost of natural gas. To meet firm customer requirements, we must acquire sufficient gas supplies and pipeline capacity to ensure delivery to our distribution system while also ensuring that our supply and capacity contracts allow us to remain competitive. Natural gas is an unregulated commodity market subject to supply and demand and price volatility. Producers, marketers and pipelines are subject to operating, regulatory and financial risks associated with exploring, drilling, producing, gathering, marketing and transporting natural gas and have risks that increase our exposure to supply and price fluctuations. Since such risks may affect the availability and cost of natural gas, they also may affect the competitive position of natural gas relative to other energy sources.
|
| • | | Changes in weather conditions. Weather conditions and other natural phenomena can have a material impact on our earnings. Severe weather conditions, including destructive weather patterns such as hurricanes, tornadoes and floods, can impact our customers, our suppliers and the pipelines that deliver gas to our distribution system and our distribution and transmission assets. Weather conditions directly influence the supply, demand, distribution and cost of natural gas.
|
| • | | Changes in and costs of compliance with laws and regulations. We are subject to extensive federal, state and local laws and regulations. Environmental, safety, system integrity, tax and other laws and regulations, including those related to carbon regulation, may change. Compliance with such laws and regulations could increase capital or operating costs, affect our reported earnings or cash flows, increase our liabilities or change the way our business is conducted.
|
| • | | Ability to retain and attract professional and technical employees. To provide quality service to our customers and meet regulatory requirements, we are dependent on our ability to recruit, train, motivate and retain qualified employees.
|
| • | | Changes in accounting regulations and practices. We are subject to accounting regulations and practices issued periodically by accounting standard-setting bodies. New accounting standards may be issued that could change the way we record revenues, expenses, assets and liabilities, and could affect our reported earnings or increase our liabilities.
|
| • | | Earnings from our equity method investments. We invest in companies that have risks that are inherent in their businesses, and these risks may negatively affect our earnings from those companies.
|
| • | | Changes in outstanding shares. The number of outstanding shares may fluctuate due to new issuances or repurchases under our Common Stock Open Market Purchase Program.
|
Economic conditions in our markets
Wholesale price of natural gas
Availability of adequate interstate pipeline transportation capacity and natural gas supply
Regulatory actions at the state level that impact our ability to earn a reasonable rate of return and fully recover our operating costs on a timely basis
Competition from other companies that supply energy
Changes in the regional economies, politics, regulations and weather patterns of the three states in which our operations are concentrated
Costs of complying or effect of noncompliance with state and federal laws and regulations that are applicable to us
Effect of climate change, carbon neutral or energy efficiency legislation or regulations on costs and market opportunities
Changes in local building codes or appliance standards
Weather conditions
Operational interruptions to our gas distribution and transmission activities
Inability to complete necessary or desirable pipeline expansion or infrastructure development projects
Elevated levels of capital expenditures
Changes to our credit ratings
Availability and cost of capital
Federal and state fiscal, tax and monetary policies
Ability to generate sufficient cash flows to meet all our cash needs
Ability to satisfy all of our outstanding debt obligations
Ability of counterparties to meet their obligations to us
Costs of providing pension benefits
Earnings from the joint venture businesses in which we invest
Ability to attract and retain professional and technical employees
Cybersecurity breaches or failure of technology systems
Ability to obtain and maintain sufficient insurance
Change in number of outstanding shares
Other factors may be described elsewhere in this report. All of these factors are difficult to predict, and many of them are beyond our control. For these reasons, you should not
relyplace undue reliance on these forward-looking statements when making investment decisions. When used in our documents or oral presentations, the words “expect,” “believe,” “project,” “anticipate,” “intend,
” “may,” “should,” “could,” “assume,” “estimate,” “forecast,” “future,” “indicate,” “outlook,” “plan,” “predict,” “seek,” “target,” “would” and variations of such words and similar expressions are intended to identify forward-looking statements.
Forward-looking statements are based on information available to us as of the date they are made, and we do not undertake any obligation to update publicly any forward-looking statement either as a result of new information, future events or otherwise except as required by applicable laws and regulations. Our reports on Form 10-K, Form 10-Q and Form 8-K and amendments to these reports are available at no cost on our website atwww.piedmontng.com as soon as reasonably practicable after the report is filed with or furnished to the SEC.Executive
Piedmont Natural Gas Company, Inc., which began operations in 1951, is an energy services company whose principal business is the distribution of natural gas to over one million residential, commercial, industrial and power generation customers in portions of North Carolina, South Carolina and Tennessee, including
51,800 customers served by municipalities who are our wholesale customers. We are invested in joint venture, energy-related businesses, including unregulated retail natural gas marketing,
and regulated interstate natural gas
transportation and storage and
regulated intrastate natural gas
transportation.In 1994, our predecessor, which was incorporated in 1950 under the same name, was merged into a newly formed North Carolina corporation for the purpose of changing our state of incorporation to North Carolina.
In the Carolinas, our service area is comprised of numerous cities, towns and communities. transportation businesses.
We
provide service to Anderson, Gaffney, Greenville and Spartanburg in South Carolina and Charlotte, Salisbury, Greensboro, Winston-Salem, High Point, Burlington, Hickory, Indian Trail, Spruce Pine, Reidsville, Fayetteville, New Bern, Wilmington, Tarboro, Elizabeth City, Rockingham and Goldsboro in North Carolina. In North Carolina, we also provide wholesale natural gas service to the cities of Greenville, Rocky Mount and Wilson. In Tennessee, our service area is the metropolitan area of Nashville, including wholesale natural gas service to the cities of Gallatin and Smyrna.We have twooperate with three reportable business segments, regulated utility, and non-utility activities. The regulated utility segment is the largest segment of our business with approximately 97% of our consolidated assets. Factors critical to the success of the regulated utility include operating a safe, reliable natural gas distribution system and the ability to recover the costs and expenses of the business in rates charged to customers. For the year ended October 31, 2011, 87% of our earnings before taxes came from our regulated utility segment. The non-utility activities segment consists of our equity method investments in joint venture, energy-related businesses that are involved in unregulated retail natural gas marketing, and regulated interstate natural gas storage and intrastate natural gas transportation. For the year ended October 31, 2011, 13% of our earnings before taxes came from our non-utility segment, which consisted of 5% from regulated non-utility activities and 8% from unregulated non-utility activities. For further information on equity method investments and business segments, see Note 12 and Note 14, respectively, toactivities, with the consolidated financial statements.
regulated utility segment being the largest. Our utility operations are regulated by the North Carolina Utilities Commission (NCUC), the Public Service Commission of South Carolina and the Tennessee Regulatory Authority (TRA) as to rates, service area, adequacy of service, safety standards, extensions and abandonment of facilities, accounting and depreciation. The NCUC also regulates us as to the issuance of long-term debt and equity securities. Factors critical to the success of the regulated utility segment include operating a safe and reliable natural gas distribution system and the ability to recover the costs and expenses of the business in the rates charged to customers. The regulated non-utility activities segment consists of our equity method investments in joint venture regulated energy-related businesses that are held by our wholly-owned subsidiaries. The unregulated non-utility activities segment consists primarily of our equity method investment in SouthStar Energy Services LLC (SouthStar) that is held by a wholly-owned subsidiary. For further information on equity method investments and business segments, see Note 12 and Note 14, respectively, to the consolidated financial statements in this Form 10-K.
Executive Summary
A summary of our annual results is as follows:
|
| | | | | | | | | | | | | | | | | | |
| Comprehensive Income Statements Components |
| | | | | | | | | |
| | | | | | | | | Percent Change |
| | | | | | | | | 2014 vs. | | 2013 vs. |
| In thousands, except per share amounts | | 2014 | | 2013 | | 2012 | | 2013 | | 2012 |
| Operating Revenues | | $ | 1,469,988 |
| | $ | 1,278,229 |
| | $ | 1,122,780 |
| | 15.0 | % | | 13.8 | % |
| Cost of Gas | | 779,780 |
| | 656,739 |
| | 547,334 |
| | 18.7 | % | | 20.0 | % |
| Margin | | 690,208 |
| | 621,490 |
| | 575,446 |
| | 11.1 | % | | 8.0 | % |
| Operations and Maintenance | | 270,877 |
| | 253,120 |
| | 242,599 |
| | 7.0 | % | | 4.3 | % |
| Depreciation | | 118,996 |
| | 112,207 |
| | 103,192 |
| | 6.1 | % | | 8.7 | % |
| General Taxes | | 37,294 |
| | 34,635 |
| | 34,831 |
| | 7.7 | % | | (0.6 | )% |
| Utility Income Taxes | | 83,176 |
| | 77,334 |
| | 69,101 |
| | 7.6 | % | | 11.9 | % |
| Total Operating Expenses | | 510,343 |
| | 477,296 |
| | 449,723 |
| | 6.9 | % | | 6.1 | % |
| Operating Income | | 179,865 |
| | 144,194 |
| | 125,723 |
| | 24.7 | % | | 14.7 | % |
| Other Income (Expense), net of tax | | 18,622 |
| | 15,161 |
| | 14,221 |
| | 22.8 | % | | 6.6 | % |
| Utility Interest Charges | | 54,686 |
| | 24,938 |
| | 20,097 |
| | 119.3 | % | | 24.1 | % |
| Net Income | | $ | 143,801 |
| | $ | 134,417 |
| | $ | 119,847 |
| | 7.0 | % | | 12.2 | % |
| | | | | | | | | | | |
| Average Shares of Common Stock: | | | | | | | | | | |
| Basic | | 77,883 |
|
| 74,884 |
| | 71,977 |
| | 4.0 | % | | 4.0 | % |
| Diluted | | 78,193 |
|
| 75,333 |
| | 72,278 |
| | 3.8 | % | | 4.2 | % |
| | | | | | | | | | | |
| Earnings per Share of Common Stock: | | | | | | | | | | |
| Basic | | $ | 1.85 |
|
| $ | 1.80 |
| | $ | 1.67 |
| | 2.8 | % | | 7.8 | % |
| Diluted | | $ | 1.84 |
|
| $ | 1.78 |
| | $ | 1.66 |
| | 3.4 | % | | 7.2 | % |
|
| | | | | | | | | | | | | | | | | | | | | |
| Margin by Customer Class |
| | | | | | | |
| In thousands | | 2014 | | 2013 | | 2012 |
| Sales and Transportation: | | | | | | | | | | | | |
| Residential | | $ | 348,782 |
| | 51 | % | | $ | 331,920 |
| | 54 | % | | $ | 321,056 |
| | 56 | % |
| Commercial | | 169,442 |
| | 25 | % | | 155,065 |
| | 25 | % | | 150,306 |
| | 26 | % |
| Industrial | | 50,889 |
| | 7 | % | | 52,268 |
| | 8 | % | | 46,993 |
| | 8 | % |
| Power Generation | | 77,573 |
| | 11 | % | | 56,312 |
| | 9 | % | | 32,289 |
| | 6 | % |
| For Resale | | 8,819 |
| | 1 | % | | 7,477 |
| | 1 | % | | 7,465 |
| | 1 | % |
| Total | | 655,505 |
| | 95 | % | | 603,042 |
| | 97 | % | | 558,109 |
| | 97 | % |
| Secondary Market Sales | | 25,414 |
| | 4 | % | | 8,979 |
| | 1 | % | | 9,681 |
| | 2 | % |
| Miscellaneous | | 9,289 |
| | 1 | % | | 9,469 |
| | 2 | % | | 7,656 |
| | 1 | % |
| Total | | $ | 690,208 |
| | 100 | % | | $ | 621,490 |
| | 100 | % | | $ | 575,446 |
| | 100 | % |
|
| | | | | | | | | | | | | | | |
| Gas Deliveries, Customers, Weather Statistics and Number of Employees |
| | | | | | | | | | | |
| | | | | | | | | Percent Change |
| | | | | | | | | 2014 vs. | | 2013 vs. |
| | | 2014 | | 2013 | | 2012 | | 2013 | | 2012 |
| Deliveries in Dekatherms (in thousands): | | | | | | | | | | |
| Residential | | 61,782 |
| | 55,283 |
| | 43,788 |
| | 11.8 | % | | 26.3 | % |
| Commercial | | 44,259 |
| | 39,602 |
| | 33,774 |
| | 11.8 | % | | 17.3 | % |
| Industrial | | 95,780 |
| | 95,019 |
| | 89,234 |
| | 0.8 | % | | 6.5 | % |
| Power Generation | | 201,707 |
| | 190,862 |
| | 151,675 |
| | 5.7 | % | | 25.8 | % |
| For Resale | | 7,174 |
| | 6,834 |
| | 5,829 |
| | 5.0 | % | | 17.2 | % |
| Throughput | | 410,702 |
|
| 387,600 |
| | 324,300 |
| | 6.0 | % | | 19.5 | % |
| Secondary Market Volumes | | 20,516 |
| | 41,605 |
| | 48,373 |
| | (50.7 | )% | | (14.0 | )% |
| | | | | | | | | | | |
| Customers Billed (at period end) | | 992,551 |
|
| 979,909 |
| | 969,239 |
| | 1.3 | % | | 1.1 | % |
| Gross Residential, Commercial and Industrial Customer Additions | | 16,251 |
| | 14,293 |
| | 13,274 |
| | 13.7 | % | | 7.7 | % |
| Degree Days | | | | | | | | | | |
| Actual | | 3,543 |
|
| 3,336 |
| | 2,668 |
| | 6.2 | % | | 25.0 | % |
| Normal | | 3,265 |
|
| 3,276 |
| | 3,310 |
| | (0.3 | )% | | (1.0 | )% |
| Percent colder (warmer) than normal | | 8.5 | % |
| 1.8 | % | | (19.4 | )% | | n/a |
| | n/a |
|
| Number of Employees (at period end) | | 1,879 |
| | 1,795 |
| | 1,752 |
| | 4.7 | % | | 2.5 | % |
Financial Performance – Fiscal 2014 Compared with Fiscal 2013
Our 2014 fiscal year was a solid one with a 7% increase in net income. Margin increased 11% due to customer growth, higher volumes delivered to residential and commercial customers in South Carolina and Tennessee due to colder weather, new rates effective January 1, 2014 in North Carolina under a rate case settlement, the Tennessee and North Carolina integrity management rider (IMR) rate adjustments, increased transportation delivery services for power generation customers and higher margin sales from secondary market activity. Operations and maintenance (O&M) expenses and depreciation expense increased 7% and 6%, respectively. The increase in O&M expenses was related to increases in payroll, regulatory, bad debt and contract labor expenses. Depreciation was higher due to increases in plant in service from our capital investment program. General taxes increased 8% primarily due to increased property taxes, franchise taxes and payroll taxes. Other Income (Expense) increased 23% primarily due to an increase in income from equity method investments, primarily from SouthStar and Constitution Pipeline Company, LLC (Constitution), partially offset by a write-off of an investment that had been accounted for under the cost method. Utility interest charges increased 119% from increases in long-term debt outstanding, a decrease in capitalized interest recorded as income and the recording of interest expense on amounts due to customers.
Business Summary – Fiscal 2014 Compared with Fiscal 2013
Our fiscal 2014 performance reflects execution of our long-term business strategy that focuses on safety and growth in our markets, favorable changes in state regulation with new rates and IMRs, and secondary market activity. As discussed above, financial performance was solid for the year with increased earnings and an increase in our dividend rate per share to our investors.
Financial Strength and Flexibility – In order to prudently fund our investment in growth and our ongoing capital needs, we executed our financing programs to optimize and reduce our cost of capital, preserve our liquidity and strong balance sheet and protect our high quality credit ratings with a goal of maintaining a total debt to capital ratio between 50% and 60%. As reflected in this annual report, we revised this target to include both short- and long-term debt as we believe it provides a more accurate representation of our overall leverage and our financing targets. We continue to rely on our commercial paper (CP) program to meet our short-term liquidity needs. We accomplished the following in fiscal year 2014:
In November 2013, we entered into an agreement with our revolving credit facility lenders that increased our borrowing capacity to $850 million.
In December 2013, we repaid the balance of $100 million of our 5% medium-term notes as they became due.
In December 2013, we issued 1.6 million shares under forward sale agreements (FSAs) entered into in February 2013, receiving proceeds of $47.3 million.
In September 2014, we issued $250 million of twenty-year, unsecured senior notes, receiving net proceeds of $247.7 million, net of debt issuance costs.
For further information on these transactions, see Note 4, Note 5 and Note 6 to the consolidated financial statements in this Form 10-K and the following discussion of "Cash Flows from Financing Activities."
Managing Gas Supplies and Prices – Our gas supply acquisition strategy is regularly reviewed and adjusted to ensure that we have adequate and reliable supplies of competitively-priced natural gas to meet the needs of our utility customers. In November 2012, in order to provide additional diversification, reliability and gas cost benefits to our customers, we signed long-term capacity and supply contracts to transport more of our gas supplies from the Marcellus shale basin in Pennsylvania for our markets in the Carolinas. This source of supply is scheduled to be available in late 2015 once construction of the Williams – Transco Leidy Southeast expansion project has been completed. In October 2014, we signed a long-term pipeline capacity precedent agreement under the Atlantic Coast Pipeline, LLC (ACP) project to source gas supplies from the Marcellus and Utica shale basins in central West Virginia that are anticipated to be available for the winter 2018 – 2019 season.
Customer Growth – We have added increasing numbers of customers in our service areas each year over our last three fiscal years. Affordable and stable wholesale natural gas costs continued to favorably position natural gas relative to other energy sources. With continued improvement in economic conditions resulting in growth in both the residential and commercial markets and targeted marketing programs on the benefits of natural gas, total new customers increased 13.7% in 2014 compared to 2013.
|
| | | | | | | | | |
| | | | | | | Percent |
| | | 2014 | | 2013 | | Change |
| Residential new home construction | | 11,659 |
| | 10,299 |
| | 13.2 | % |
| Residential conversion | | 2,814 |
| | 2,463 |
| | 14.3 | % |
| Commercial | | 1,763 |
| | 1,512 |
| | 16.6 | % |
| Industrial | | 15 |
| | 19 |
| | (21.1 | )% |
| Total new customers | | 16,251 |
| | 14,293 |
| | 13.7 | % |
Overall, total net customers billed increased 1.3% as compared to 2013.
Capital Expenditures – We continued to execute our capital expansion and improvement programs that will provide benefits to our customers through safe and reliable natural gas service while providing our shareholders a fair and reasonable return on invested capital. Our capital expenditures are driven by pipeline integrity, safety and compliance programs, investments for customer growth, and technology and system infrastructure, including a new comprehensive work and asset management system.
With significant capital costs incurred under our ongoing system integrity programs, we implemented new regulatory mechanisms that will allow us to recover and earn on those investments in a more timely manner. In December 2013, the NCUC approved the settlement of our 2013 general rate case, including the implementation of an IMR to separately track and recover the costs associated with capital expenditures in order to comply with federal pipeline safety and integrity requirements. With the IMR mechanism, we will avoid having to file costly and more frequent future general rate proceedings, consuming both our resources and the resources of the NCUC and its staff. Under the IMR tariff, we will make annual filings each November to capture such costs closed to plant through October with revised rates effective the following February. For the annual period beginning February 1, 2014, the North Carolina IMR will increase our margin revenues by $.8 million with $.6 million recorded through the 2014 fiscal year end. With its approval of the rate case settlement, the NCUC continued to allow regulatory asset treatment of our external pipeline integrity management O&M costs and recovery of these costs through future amortization in rates. Also in December 2013, the TRA approved the settlement of our August 2013 IMR filing in Tennessee to recover the costs of our capital investments associated with federal and state mandated safety and integrity programs. Under the Tennessee IMR, we will file to adjust rates to be effective each January 1 based on capital expenditures incurred through the previous October. For the twelve-month period beginning January 1, 2014, the Tennessee IMR will increase our margin revenues by $13.1 million with $10.1 million recorded through the fourth quarter of 2014.
We completed pipeline expansion projects over our last three fiscal years that provide natural gas delivery service to new power generation facilities in our market area. We currently provide service to 25 power generation customer accounts. See the discussion of our forecasted capital investments in “Cash Flows from Investing Activities” in this Form 10-K .
Business Process and Technology Improvements – We are also subjectexecuting a multi-year, multi-project program designed to or affected by various federal regulations. These federalbring additional technology and automation to our field operations to enable our employees to more effectively and efficiently manage our pipeline assets. This program is expected to facilitate compliance with pipeline safety and integrity regulations include regulationsand create operating efficiencies. Implementation began in April 2014. Several phases of the program are expected to be implemented through our fiscal year 2016.
Regulatory and Legislative Activity – We continue our regulatory strategy to implement rate structures that better align and balance the interests of shareholders and customers. As discussed above, with the NCUC approval of the settlement of our 2013 general rate case, we implemented adjustments in our rates and charges, effective January 1, 2014, to provide incremental annual total revenues of $30.7 million, yielding an annual pre-tax income increase of $24.2 million. This revenue increase was a .7% annual rate increase for our customers since our last general rate proceeding in 2008. The new rates are particularbased on a rate base in North Carolina of $1.8 billion as of September 30, 2013, an equity capital structure component of 50.7% and a return on common equity of 10%.
Equity Method Investments – Our investments in complementary energy-related businesses continue to thebe an attractive way to generate earnings growth and long-term shareholder returns. Our 2014 earnings before taxes from SouthStar increased $5 million with our additional investment of $22.5 million made in September 2013, maintaining our 15% equity ownership. Our partner contributed retail natural gas industry, such as regulationsmarketing assets and related customers located in Illinois.
We are a 24% equity member of theConstitution, a Federal Energy Regulatory Commission (FERC) that affect the purchase and sale of and the prices paid for theregulated interstate transportation and storage of natural gas regulationspipeline that is proposed to transport natural gas produced from the Marcellus shale basin in Pennsylvania to northeast markets. The forecasted in-service date of the U.S. Departmentproject is late 2015 or 2016. We expect our total 24% equity contributions will be an estimated $175 million. We contributed $37.6 million and $15.9 million in 2014 and 2013, respectively, for a total of Transportation (DOT) that affect the design, construction, operation, maintenance, integrity, safety$53.5 million to date.
In September 2014, we became a 10% equity member of ACP, a Delaware limited liability company. ACP intends to construct, operate and security ofmaintain a 550 mile natural gas distributionpipeline, with associated compression, from West Virginia through Virginia into eastern North Carolina. The pipeline will provide wholesale natural gas transportation services for Marcellus and transmission systems, and regulations of the Environmental Protection Agency relatingUtica gas supplies into southeastern markets. We expect our total 10% equity contributions will be an estimated $450 million to the environment. In addition, we are subject to numerous other regulations, such as those relating to employment and benefit practices, which are generally applicable to companies doing business in the United States of America.Our regulatory commissions approve rates and tariffs that are designed to give us the opportunity to generate revenues to cover our gas and non-gas costs and to earn a fair rate of return on invested capital for our shareholders. Our ability to earn our authorized rates of return is based in part on our ability to reduce or eliminate regulatory lag and also by improved rate designs that decouple the recovery of our approved margins from customer usage patterns impacted by seasonal weather patterns and customer conservation.
In North Carolina, a margin decoupling mechanism provides for the recovery of our approved margin from residential and commercial customers on a year around basis independent of consumption patterns. The margin decoupling mechanism results in semi-annual rate adjustments to refund$500 million before any over-collection of margin or recover any under-collection of margin. We have weather normalization adjustment (WNA) mechanisms in South Carolina and Tennessee that partially offset the impact of colder- or warmer-than-normal winter weather on bills rendered during the months of November through March for residential and commercial customers. The WNA formula calculates the actual weather variance from normal, using 30 years of history, which increases revenues when weather is warmer than normal and decreases revenues when weather is colder than normal. The gas cost portion of our costs is recoverable through purchased gas adjustment (PGA) procedures and is not affected by the margin decoupling mechanism or the WNA.project financing. For further information on equity method investments and business segments, see
Note 212 and Note 14, respectively, to the consolidated financial statements.We continually assess alternative rate structuresstatements and cost recovery mechanisms that are more appropriate to the changing energy economy. We have been pursuing alternatives to the traditional utility rate design that provide for the collection of margin revenue based"Cash Flows from Investing Activities" in this Form 10-K.
Strategy and Focus Areas
Our long-term strategic directives shape our annual business objectives and focus on
volumetric throughput with new rate designs and incentives that allow utilities to encourage energy efficiency and conservation. By decoupling the link between energy consumption and margin revenues, our interests are aligned with our customers’ interests on conservation and energy efficiency. In North Carolina, we have decoupled residential and commercial rates. In South Carolina, we operate under a rate stabilization mechanism that achieves the objectives of margin decoupling for residential and commercial customers with a one year lag. For the twelve months ended October 31, 2011, these and other rate designs stabilized our gas utility margin by providing fixed recovery of 70% of our utility margins, including margin decoupling in North Carolina, facilities charges to our customers,
our communities, our employees and
fixed-rate contracts; semi-fixed recovery of 18% of our
utility margins, including the rate stabilization mechanism in South Carolina and WNA in South Carolina andTennessee; and volumetric or periodic renegotiation of 12% of our utility margins. For the twelve months ended October 31, 2011, the margin decoupling mechanism in North Carolina reduced margin by $7 million, and the WNA in South Carolina and Tennessee reduced margin by $4.9 million.
On September 2, 2011, we filed a general rate application with the TRA for an increase in rates and charges to all customers that would be effective March 1, 2012. Weshareholders. They also requested a modification 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. For further information, see Note 2 to the consolidated financial statements.
We have refined our strategic objectives to a customer-centered approach andreflect what we believe isare the inherent benefitadvantages of natural gas compared to other types of energy. Our overall corporate focus is to expandseven foundational strategic priorities are as follows:
Promote the benefits of natural gas,
Expand our core natural gas and complementary energy-related businesses to enhance shareholder value. This focus includes traditional growth invalue,
Be the core residential, commercial and industrial markets, growth in the power generation market, supply diversity and complementary energy-related investments and natural gas end use technology. We want our customers to choose us becauseenergy service provider of the value of natural gas and the quality of our service to them. We strive to achievechoice,
Achieve excellence in customer service to our customersevery time,
Preserve financial strength and in our business operations with every customer contact we make. We pursueflexibility,
Execute sustainable business practices, to promote a sustainable enterprise by reducing our impact on the environment, developing strong communities in which we operate and fostering increased awareness and use of natural gas. We support our employees with improved processes and technology to better serve our customers and to add value for our shareholders while continuing to build on
Enhance our healthy, high performance
culture in order to recruit, retain and motivate our workforce.To supportculture.
With a focus on these
objectives, we are reorganizing our field customer services, sales and marketing, field operations and maintenance and construction departments into functional organizations to provide a more focused and better managed approach to customer service and increase customer loyalty and satisfaction while improving operational efficiencies. We have also implemented new centralized service scheduling work processes and system enhancements to better serve our customers in a more timely and efficient fashion.The safety of our system, the public and our employees is a critical component to our ongoing success as a company. We are subject to DOT and state regulation of our pipeline and related facilities and have ongoing programs to inspect our system for corrosion and leaks. Given an increased interest in pipeline safety and integrity in the wake of several serious pipeline incidents in the United States, we anticipate federal legislative and regulatory enactments that will add further requirements to our pipeline safety and integrity programs. We met an August 2011 deadline to evaluate any risks to our distribution pipeline system (such as corrosion and leak detection) and created an action plan to address those risks. We have transmission pipeline integrity programs where we execute standard procedures and programs for pipeline safety that include leak detection surveys, periodic valve maintenance, periodic corrosion and atmospheric corrosion inspections, cathodic protection, in-line inspection devices, hydrostatic and compressed air pressure testings of new facilities and other evaluation methods. It is likely that these programs will increase in scope as a result of anticipated legislation and regulation. We will continue our efforts to educate the public about our pipeline system in an effort to decrease third party excavation damage, which is the greatest cause of any pipeline damage on our system. We encourage focused efforts to improve the safety of our industry as a whole.
The safeguarding of our information technology infrastructure is important to our business. There is risk associated with the unauthorized access of digital data with the intent to misappropriate information, corrupt data or cause operational disruptions. To protect confidential customer, vendor, financial and employee information,priorities, we believe we have appropriate levels of security measures in place to secure our information systems from cybersecurity attacks or breaches. We also havewill enhance long-term shareholder value. For a comprehensive identity theft protection program to protect customer information, as well as a cybersecurity insurance policy.
We continue our efforts to promote the benefits of natural gas. Promotion efforts are led by educating consumers on the benefits of natural gas compared to other energy sources as well as advocating the benefits of natural gas to prospective customers in our communities. We continue our efforts to promote the direct use of natural gas in more homes, businesses, industries and vehicles as we strongly believe that the expanded use of clean, efficient, abundant and domestic natural gas with its relatively low emissions can help revitalize our economy, reduce both overall energy consumption and greenhouse gas emissions and enhance our national energy security. We also promote and market the cost and environmental benefits of natural gas to power generation customers in our market area. Price moderation and stability of natural gas continues, which has made natural gas more economical than many other fuels.
We completed two pipeline expansion projects in fiscal year 2011 and one in December 2011 to provide long-term gas transportation service to power generation customers in our market area. We have two pipeline expansion projects under construction to provide natural gas delivery service to power generation facilities currently under construction in North Carolina with targeted in service dates of June 2012 and June 2013. In addition to the environmental benefits of replacing a coal-fired power plant with a new natural gas-fired power plant, the construction of the natural gas pipelines for these projects will also add to our natural gas infrastructure in the eastern part of North Carolina and enhance future opportunities for economic growth and development. See the followingfull discussion of our forecasted capital investment related to the construction of the natural gas pipelinesstrategy and compressor stations to serve these new power generation facilitiesfocus areas, see Item 1. Business in “Cash Flows from Investing Activities” in Item 7 of this Form 10-K in Management’s Discussion and Analysis of Financial Condition and Results of Operations.
We continue to see challenging economic conditions in our market area with continued high rates of unemployment, weakened housing markets with high inventories of unsold homes, and slower new home construction. We took advantage of the growth opportunities that existed in those markets and continue to focus10-K.
Additional information on
residential, commercial and industrial customer conversions to natural gas and power generation gas delivery service opportunities. In fiscal 2011, our gross customers additions were 4% lower than 2010; however, our month-end customers billed as well as the twelve-month average customers billed during fiscal year 2011 increased 1% over the respective prior year. As we seek to expand the use of natural gas, we continue to emphasize natural gas as the fuel of choice for energy consumers because of the comfort, affordability and efficiency of natural gas, as well as remind our customers of our reliability and safety as a company. We forecast gross customer addition growth for fiscal 2012 of approximately 1%.We continue to work toward a business model that positions us for long-term success in a lower carbon energy economy with a focus on future growth opportunities that support new clean energy technologies. We are seeking opportunities for regulatory innovation and strategic alliances to advance our customers’ interests in energy conservation, efficiency and environmental stewardship. We are executing a plan to build more compressed natural gas (CNG) fueling stations in our service area for use by our own vehicle fleet as well as third party use and the general public. Currently, approximately 11% of our vehicle fleet uses CNG. We have five CNG fueling stations in use, and we plan to construct four more. Within two years, we anticipate that up to 33% of our fleet will be capable of using CNG.
Our financial strength and flexibility is critical to our success as a company. We will continue our stewardship to maintain our financial strength, which translates to continued access to capital markets. We continue to evaluate the strength of financial institutions with which we have working relationships to ensure access to funds for operations and capital investments. In June 2011, we replaced $196.8 million of notes with a 6.25% stated interest rate with $200 million of notes with a weighted interest rate of 4%. In July 2011, we filed a shelf registration statement that will allow for future issuances of debt or equity. Our capital plan includes maintaining a long-term debt-to-capitalization ratio within a range of 45% to 50%. We will continue to control our operating costs, implement new technologies and work with our state regulators to maintain fair rates of return and balance the interests of our customers and shareholders. We also seek to maintain a strong balance sheet and investment-grade credit ratings to support our operating and investment needs.
We invest in joint ventures to complement or supplement income from our regulated utility operations if an opportunity aligns with our overall business strategies and allows us to leverage our core competencies. We analyze and evaluate potential projects with a major factor being projected rates of return commensurate with the risk of such projects. We participate in the governance of our ventures by having management representatives on the governing boards. We monitor actual performance against expectations, and any decision to exit an existing joint venture would be based on many factors, including performance results and continued alignment with our business strategies
Several new laws were enacted in 2010 for health care reform and the regulation of U.S. financial markets. We continue to follow the progress of new regulations that are being issued and will be issued by various regulatory agencies. While we are not able to assess the full impact of these laws until the implementing regulations have been adopted, based on the information available to us at this time, we do not expect these laws to have a material impact on our financial position, results of operations or cash flows.
Also, the Tax Relief, Unemployment Insurance Reauthorization and Job Creation Act of 2010, enacted in December 2010, extended the 50% “bonus depreciation” that expired December 31, 2009 and temporarily increased “bonus depreciation” for federal income tax purposes to 100% for certain qualified investments. These provisions are effective for our fiscal year tax returns for 2010-2014. The Internal Revenue Service has issued regulations that are intended to provide guidance in interpreting the law. Based on current capital projections and timelines, we are anticipating a benefit through 2014 of $130 - 170 million. We anticipate that the bonus depreciation allowance will have a material favorable impact on our cash flows in the near term by reducing cash needed to pay federal income taxes.
Results of Operations
The following tables present our financial highlights for the years ended October 31, 2011, 20102014, 2013 and 2009.
Income Statement Components
| | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | Percent Change | |
In thousands except per share amounts | | 2011 | | | 2010 | | | 2009 | | | 2011 vs.
2010 | | | 2010 vs.
2009 | |
Operating Revenues | | $ | 1,433,905 | | | $ | 1,552,295 | | | $ | 1,638,116 | | | | (7.6 | )% | | | (5.2 | )% |
Cost of Gas | | | 860,266 | | | | 999,703 | | | | 1,076,542 | | | | (13.9 | )% | | | (7.1 | )% |
| | | | | | | | | | | | | | | | | | | | |
Margin | | | 573,639 | | | | 552,592 | | | | 561,574 | | | | 3.8 | % | | | (1.6 | )% |
| | | | | | | | | | | | | | | | | | | | |
Operations and Maintenance | | | 225,351 | | | | 219,829 | | | | 208,105 | | | | 2.5 | % | | | 5.6 | % |
Depreciation | | | 102,829 | | | | 98,494 | | | | 97,425 | | | | 4.4 | % | | | 1.1 | % |
General Taxes | | | 38,380 | | | | 33,909 | | | | 34,590 | | | | 13.2 | % | | | (2.0 | )% |
Utility Income Taxes | | | 64,068 | | | | 62,082 | | | | 70,079 | | | | 3.2 | % | | | (11.4 | )% |
| | | | | | | | | | | | | | | | | | | | |
Total Operating Expenses | | | 430,628 | | | | 414,314 | | | | 410,199 | | | | 3.9 | % | | | 1.0 | % |
| | | | | | | | | | | | | | | | | | | | |
Operating Income | | | 143,011 | | | | 138,278 | | | | 151,375 | | | | 3.4 | % | | | (8.7 | )% |
Other Income (Expense), net of tax | | | 14,549 | | | | 47,387 | | | | 18,124 | | | | (69.3 | )% | | | 161.5 | % |
Utility Interest Charges | | | 43,992 | | | | 43,711 | | | | 46,675 | | | | 0.6 | % | | | (6.4 | )% |
| | | | | | | | | | | | | | | | | | | | |
Net Income | | $ | 113,568 | | | $ | 141,954 | | | $ | 122,824 | | | | (20.0 | )% | | | 15.6 | % |
| | | | | | | | | | | | | | | | | | | | |
Average Shares of Common Stock: | | | | | | | | | | | | | | | | | | | | |
Basic | | | 72,056 | | | | 72,275 | | | | 73,171 | | | | (0.3 | )% | | | (1.2 | )% |
Diluted | | | 72,266 | | | | 72,525 | | | | 73,461 | | | | (0.4 | )% | | | (1.3 | )% |
Earnings per Share of Common Stock: | | | | | | | | | | | | | | | | | | | | |
Basic | | $ | 1.58 | | | $ | 1.96 | | | $ | 1.68 | | | | (19.4 | )% | | | 16.7 | % |
Diluted | | $ | 1.57 | | | $ | 1.96 | | | $ | 1.67 | | | | (19.9 | )% | | | 17.4 | % |
Gas Deliveries, Customers, Weather Statistics2012 follows.
Results of Operations
Operating Revenues
Changes in operating revenues for 2014 and
Number of Employees | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | Percent Change | |
| | | 2011 | | | 2010 | | | 2009 | | | 2011 vs.
2010 | | | 2010 vs.
2009 | |
Deliveries in Dekatherms (in thousands): | | | | | | | | | | | | | | | | | | | | |
Sales Volumes | | | 104,740 | | | | 105,583 | | | | 110,379 | | | | (0.8 | )% | | | (4.3 | )% |
Transportation Volumes | | | 175,021 | | | | 147,032 | | | | 106,495 | | | | 19.0 | % | | | 38.1 | % |
| | | | | | | | | | | | | | | | | | | | |
Throughput | | | 279,761 | | | | 252,615 | | | | 216,874 | | | | 10.8 | % | | | 16.5 | % |
| | | | | | | | | | | | | | | | | | | | |
Secondary Market Volumes | | | 48,835 | | | | 46,823 | | | | 46,057 | | | | 4.3 | % | | | 1.7 | % |
Customers Billed (at period end) | | | 958,307 | | | | 946,785 | | | | 937,962 | | | | 1.2 | % | | | 0.9 | % |
Gross Customer Additions | | | 10,522 | | | | 10,975 | | | | 12,608 | | | | (4.1 | )% | | | (13.0 | )% |
Degree Days | | | | | | | | | | | | | | | | | | | | |
Actual | | | 3,662 | | | | 3,535 | | | | 3,413 | | | | 3.6 | % | | | 3.6 | % |
Normal | | | 3,318 | | | | 3,321 | | | | 3,324 | | | | (0.1 | )% | | | (0.1 | )% |
Percent colder than normal | | | 10.4 | % | | | 6.4 | % | | | 2.7 | % | | | n/a | | | | n/a | |
Number of Employees (at period end) | | | 1,782 | | | | 1,788 | | | | 1,821 | | | | (0.3 | )% | | | (1.8 | )% |
Net Income
Net income decreased $28.4 million in 20112013 compared with 2010the same prior periods are presented below.
|
| | | | | | | | |
| Changes in Operating Revenue - Increase (Decrease) |
| | | 2014 vs. | | 2013 vs. |
| In millions | | 2013 | | 2012 |
| Residential and commercial customers | | $ | 201.5 |
| | $ | 136.2 |
|
| Industrial customers | | 1.4 |
| | 18.0 |
|
| Power generation customers | | 21.8 |
| | 28.1 |
|
| Secondary market | | 5.4 |
| | 23.8 |
|
| Margin decoupling mechanism | | (39.4 | ) | | (40.8 | ) |
| WNA mechanisms | | (11.4 | ) | | (10.4 | ) |
| IMR mechanisms | | 10.7 |
| | — |
|
| Other | | 1.8 |
| | 0.5 |
|
| Total | | $ | 191.8 |
| | $ | 155.4 |
|
2014 compared to 2013:
Residential and commercial customers – the increase is primarily due to
the following changes which decreased net income:$49.7 million decrease due to gain on sale of interest in equity method investment in the prior year.
$5.5 million increase in operations and maintenance expenses.
$4.8 million decrease in incomehigher consumption from equity method investments.
$4.5 million increase in general taxes.
$4.3 million increase in depreciation.
$.6 million increase in non-operating expense.
$.5 million increase in charitable contributions.
These changes were partially offset by the following changes, which increased net income:
$21 million increase in margin (operating revenues less cost of gas).
$19.6 million decrease in income taxes.
$1.1 million increase in non-operating income.
Net income increased $19.1 million in 2010 compared with 2009 primarily due to the following changes which increased net income:
$49.7 million gain on sale of interest in equity method investment.
$3 million decrease in utility interest charges.
$.9 million decrease in non-operating expense.
$.7 million decrease in general taxes.
$.6 million decrease in charitable contributions.
$.6 million increase in non-operating income.
These changes were partially offset by the following changes, which decreased net income:
$11.7 million increase in operations and maintenance expenses.
$10 million increase in income taxes.
$9 million decrease in margin.
$4.6 million decrease in income from equity method investments.
$1.1 million increase in depreciation.
Operating Revenues
Operating revenues in 2011 decreased $118.4 million compared with 2010 primarily due to the following decreases:
$150.8 million of lowercolder weather, higher wholesale gas costs passed through to customers and customer growth.
Industrial customers – the increase is primarily due to higher consumption from colder weather and higher wholesale gas costs passed through to customers, slightly offset by decreased transportation revenues.
Power generation customers – the increase is primarily due to increased transportation services.
Secondary market – the increase is due to higher margin sales customers.related to sustained colder-than-normal weather and increased wholesale market volatility. Secondary market transactions consist of off-system sales and capacity release and asset management arrangements and are part of our regulatory gas supply management program with regulatory approved sharing mechanisms between our utility customers and our shareholders.
$1.1 million from decreased revenues underMargin decoupling mechanism – the margin decoupling mechanism.decrease is primarily related to colder weather in North Carolina. As discussed in “Financial Condition and Liquidity,” the margin decoupling mechanism in North Carolina adjusts for variations in residential and commercial use per customer, including those due to conservationweather and weather.
conservation.These decreases were partially offset by
Weather normalization adjustment (WNA) mechanisms – the
following increases:$19.8 million from higher revenues in secondary market transactionsdecrease is due to increased activity and gas costs. Secondary market transactions consist of off-system sales and capacity release arrangements and are part of our regulatory gas supply management program with regulatory-approved sharing mechanisms between our utility customers and our shareholders.
$5.8 million from an increase in volumes delivered to transportation customers.
$3.9 million from increased revenues under the WNAcolder weather in South Carolina and Tennessee.
Operating revenues As discussed in 2010 decreased $85.8 million“Financial Condition and Liquidity,” the WNA mechanisms partially offset the impact of colder- or warmer-than-normal weather on bills rendered.
IMR mechanisms – the increase is due to the IMR rate adjustments in Tennessee effective January 1, 2014 and North Carolina effective February 1, 2014.
2013 compared with 2009to 2012:
Residential and commercial customers – the increase is primarily due to
the following decreases:$65.4 million of gas costs primarily from lower totalcolder weather, customer growth and higher wholesale gas costs passed through to sales customers.
$11.9 million fromIndustrial customers – the increase is primarily due to colder weather and customer growth.
Power generation customers – the increase is primarily due to increased transportation services due to new contracts that began in June 2012 and June 2013.
Secondary market – the increase is primarily due to higher commodity gas costs, partially offset by decreased revenues underactivity.
Margin decoupling mechanism – the margin decoupling mechanism.decrease is due to colder weather in North Carolina.
$7.6 million from decreased revenues underWNA mechanisms – the WNAdecrease is due to colder weather in South Carolina and Tennessee.
These decreases were partially offset by the following increases:
$3.7 million from revenues in secondary market transactions due to increased activity.
$1.2 million increase from volumes delivered to transportation customers.
Cost of Gas
Cost
Changes in cost of gas in 2011 decreased $139.4 millionfor 2014 and 2013 compared with 2010 primarily duethe same prior periods are presented below.
|
| | | | | | | | |
| Changes in Cost of Gas - Increase (Decrease) |
| | | 2014 vs. | | 2013 vs. |
| In millions | | 2013 | | 2012 |
| Commodity gas costs passed through to sales customers | | $ | 137.5 |
| | $ | 96.8 |
|
| Commodity gas costs in secondary market transactions | | (11.0 | ) | | 24.5 |
|
| Pipeline demand charges | | (7.1 | ) | | 22.3 |
|
| Regulatory approved gas cost mechanisms | | 3.6 |
| | (34.2 | ) |
| Total | | $ | 123.0 |
| | $ | 109.4 |
|
2014 compared to
the following decreases:2013: $83.2 million of decreased costs due to approved gas cost mechanisms, primarily commodity gas cost true ups.
$80.5 million of decreased commodity gas costs primarily due to lower gas costs passed through to sales customers.
These decreases were partially offset by the following increases:
$16.5 million of increased commodity gas costs in secondary marketing transactions due to increased activity and higher average gas costs.
$9 million of increased demand charges primarily due to timing of asset manager agreement terms.
Cost of gas in 2010 decreased $76.8 million compared with 2009 primarily due to $131.1 million from lower pricedCommodity gas costs passed through to sales customers partially offset by– the following increases:
$31.7 million of commodityincrease is primarily due to higher volumes sold due to colder weather and higher wholesale gas costs from increased volume deliveriespassed through to sales customers.
$4.8 million from commodityCommodity gas costs in secondary market transactions – the decrease is primarily due to decreased activity, partially offset by higher average wholesale gas costs.
Pipeline demand charges – the decrease is due to decreased demand costs and increased capacity release revenues, slightly offset by decreased asset manager payments.
Regulatory approved gas cost mechanisms – the increase is primarily due to demand cost true-ups, slightly offset by other regulatory mechanisms.
2013 compared to 2012:
Commodity gas costs passed through to sales customers – the increase is primarily due to higher volumes sold due to colder weather and slightly higher wholesale gas costs passed through to sales customers.
Commodity gas costs in secondary market transactions – the increase is primarily due to increased average wholesale gas costs, partially offset by decreased activity.
Pipeline demand charges – the increase is primarily due to increased demand costs, decreased asset manager payments and decreased capacity release revenues.
Regulatory approved gas cost mechanisms – the decrease is primarily due to commodity gas cost true-ups.
In all three states, we are authorized to recover from customers all prudently incurred gas costs.
ChangesCharges to cost of gas are based on the amount recoverable under approved rate schedules. The net of any over- or under-recoveries of gas costs are reflected in a regulatory deferred account and are added to or deducted from cost of gas and are
in current “Regulatory assets” or current “Regulatory liabilities” in the Consolidated Balance Sheets. For the amounts included in “Amounts due from customers” or “Amounts due to
customers”customers,” see “Rate-Regulated Basis of Accounting” in
Note 1 to the consolidated
balance sheets.financial statements in this Form 10-K.
Margin
Our utility margin is defined as natural gas revenues less natural gas commodity purchases and fixed gas costs for transportation and storage capacity.
Margin, rather than revenues, is used by management to evaluate utility operations due to the passthroughregulatory pass through of changes in wholesale commodity gas costs. Our utility margin is defined as natural gas revenues less natural gas
commodity costs
whichand fixed gas costs for transportation and storage capacity. It is the component of our revenues that is established in general rate cases and is designed to cover our utility operating expenses and our return of and on our utility capital investments and related taxes. Our commodity gas costs accounted for
47%41% of revenues for the
twelve monthsyears ended October 31,
2011,2014 and
2013 and 36% for the year ended October 31, 2012. Our pipeline transportation and storage costs
which accounted for
9%.10%, 12% and 11% for the years ended October 31, 2014, 2013 and 2012 respectively.
In general rate proceedings, state regulatory commissions authorize us to recover
aour margin
which is the applicable billing rate less cost of gas,in our monthly fixed demand charges and on each unit of gas
delivered. The commissions also authorizedelivered under our generally applicable sales and transportation tariffs and special service contracts. We negotiate special service contracts with some industrial customers that may include the use of volumetric rates with minimum margin commitments and fixed monthly demand charges. These individually negotiated agreements are subject to review and approval by the applicable state regulatory commission and allow us to
recover margin losses resulting from negotiating lower ratesmake an economic extension or expansion of natural gas service to
larger industrial
customers when necessary to remain competitive. The ability to recover such negotiated margin reductions is subject to continuing regulatory approvals.customers.
Our utility margin is also impacted by certain regulatory mechanisms as defined elsewhere in this document. These include the regulatory mechanisms by jurisdiction are presented below. |
| | | | | | |
| Regulatory Mechanism | | North Carolina | | South Carolina | | Tennessee |
| WNA mechanism* | | | | X | | X |
| Margin decoupling mechanism * | | X | | | | |
| Natural gas rate stabilization mechanism | | | | X | | |
| Secondary market activity ** | | X | | X | | X |
| Incentive plan for gas supply ** | | | | | | X |
| IMR mechanism | | X | | | | X |
| Negotiated margin loss treatment | | X | | X | | |
| Uncollectible gas cost recovery | | X | | X | | X |
| | | | | | |
| * Residential and commercial customers only. |
| ** In all jurisdictions, we retain 25% of secondary market margins generated through off-system sales and capacity release activity, with 75% credited to customers. Our share of net gains or losses in Tennessee is subject to an annual cap of $1.6 million. |
Changes in
Tennesseemargin for 2014 and
South Carolina, the Natural Gas Rate Stabilization Act in South Carolina, secondary market activity in North Carolina and South Carolina, the Tennessee Incentive Plan in Tennessee, the margin decoupling mechanism in North Carolina and negotiated loss treatment and the recovery of uncollectible gas costs in all three jurisdictions. We retain 25% of secondary market margins generated through off-system sales and capacity release activity in all jurisdictions, with 75% credited to customers through the incentive plans.Margin increased $21 million in 20112013 compared with 2010the same prior periods are presented below.
|
| | | | | | | | |
| Changes in Margin - Increase (Decrease) |
| |
| 2014 vs. |
| 2013 vs. |
| In millions |
| 2013 |
| 2012 |
| Residential and commercial customers |
| $ | 31.2 |
|
| $ | 15.6 |
|
| Industrial customers |
| — |
|
| 5.3 |
|
| Power generation customers | | 21.3 |
| | 24.0 |
|
| Secondary market activity | | 16.4 |
| | (0.7 | ) |
| Net gas cost adjustments | | (0.2 | ) | | 1.8 |
|
| Total | | $ | 68.7 |
| | $ | 46.0 |
|
2014 compared to 2013:
Residential and commercial customers – the increase is primarily due to the
following increases:$7.8 million from increasesgeneral rate increase in North Carolina effective January 1, 2014, the IMR rate adjustments mentioned above, customer growth in all three states and increased volumes delivered in South Carolina and servicesTennessee due to industrialcolder weather.
Power generation customers – the increase is primarily due to increased transportation services.
Secondary market activity – the increase is primarily due to higher margin sales related to increased wholesale market volatility and power generation customers.sustained colder-than-normal weather.
$5.1 million from residential
2013 compared to 2012:
Residential and commercial customers – the increase is primarily due to increased volumes delivered due to colder weather, customer growth in those markets.
$4.8 millionall three states and the general rate increase in net gas cost adjustments.
Tennessee, effective March 1, 2012.$3.3 million from increased secondary market activity and margins.
Margin decreased $9 million in 2010 compared with 2009Industrial customers – the increase is primarily due to higher consumption in the following decreases:
$6.6 millionindustrial market from net adjustmentscolder weather and customer growth.
Power generation customers – the increase is primarily due to increased transportation services due to new contracts placed in service in June 2012 and June 2013.
Secondary market activity – the decrease is primarily due to lower commodity gas costs, accounts payableprice volatility and lostdecreased activity.
Operations and unaccountedMaintenance Expenses
Changes in O&M expenses for gas.2014 and 2013 compared with the same prior periods are presented below.
$1.1 million from decreased volatility
|
| | | | | | | | |
| Changes in Operations and Maintenance Expenses - Increase (Decrease) |
| | | 2014 vs. | | 2013 vs. |
| In millions | | 2013 | | 2012 |
| Payroll | | $ | 9.6 |
| | $ | 1.8 |
|
| Regulatory | | 4.2 |
| | 1.0 |
|
| Bad debt | | 2.1 |
| | 1.4 |
|
| Contract labor | | 1.9 |
| | 2.4 |
|
| Employee benefits | | (0.3 | ) | | (1.1 | ) |
| Other | | 0.3 |
| | 5.0 |
|
| Total | | $ | 17.8 |
| | $ | 10.5 |
|
2014 compared to 2013:
Payroll – the increase is primarily due to additional employees, employee overtime because of colder-than-normal winter weather and incentive plan accruals.
Regulatory – the increase is primarily due to increased amortization of regulatory assets with approved amortization amounts established in secondary market transactions.
$the North Carolina general rate proceeding, effective January 1, million from our residential2014, and commercial marketsan increase in the North Carolina regulatory fee due to increased revenues.
Bad debt – the increase is primarily due to a $3 million negative impacthigher level of warmernet charge-offs from customer receivables due to the colder weather inexperienced this past winter and increased accruals to reflect higher aging receivables.
Contract labor – the non-weather normalized months of April and October, partially offset by customer growth.
Operations and Maintenance Expenses
Operations and maintenance expenses increased $5.5 million in 2011 compared with 2010increase is primarily due to increased call volume and collection efforts for customer receivables resulting from the following increases:
colder winter, increased process improvement projects and pipeline integrity maintenance and safety programs. 2013 compared to 2012:
Contract labor – the increase is primarily due to increased process improvement projects and pipeline integrity, maintenance and safety programs.
Payroll – the increase is due to increases in vehicle and transportation expenses.incentive plan accruals.
$2.3 million in other miscellaneous expensesBad debt – the increase is primarily due to a recovery disallowancehigher level of some prior years’ franchise fees in one of our jurisdictions andprojected charge-offs due to higher bank fees from increased activity and unused amounts ofbills.
Regulatory – the revolving syndicated credit facility.
$1.5 million in materials.
Operations and maintenance expenses increased $11.7 million in 2010 compared with 2009increase is primarily due to amortization of regulatory assets with new amortization amounts established in the following increases:
$4.2 millionTennessee general rate proceeding effective in payroll expenseMarch 2012.
Employee benefits – the decrease is 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 andreduced group medical insurance expense from higher claims.
$2.4 millionlower claims and a regulatory pension deferral in contract labor for contract billing services, telecom and activityTennessee in 2013 related to a new corporate rebranding campaign.
$.9 millionthe funding of the defined benefit plan in advertising and sales promotion relatedNovember 2012 compared to a new corporate rebranding campaign.
no plan funding in the prior year, partially offset by an increase in pension expense.
Depreciation expense increased from
$97.4$103.2 million to
$102.8$119 million over the three-year period
20092012 to
20112014 primarily due to increases in plant in
service.service, particularly related to major utility plant additions to serve new power generation customers, transmission integrity investments and upgrades to our liquefied natural gas facilities.
General taxes increased
$4.5$2.7 million in
20112014 compared with
20102013 primarily due to
the following 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 millionincreases in property and franchise taxes relatedas a result of increased property and increases to payroll taxes as a larger property baseresult of higher incentive payouts and property value reassessments by taxing authorities.
Generalan increased payroll base. Changes in general taxes decreased by an insignificant amount in 2010for 2013 compared with 2009.
the same prior period are insignificant.
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 includes non-regulated merchandising and service work, home service
warranty programs,agreements, subsidiary operations, interest income and other miscellaneous income. Non-operating expense is comprised of
othercharitable contributions and miscellaneous expenses.
The primary changes to
Changes in Other Income (Expense) in 2011for 2014 and 2013 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 discussedsame prior period are presented below. All other changes were 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.
|
| | | | | | | | |
| Changes in Other Income (Expense) - Increase (Decrease) to Income |
| | | 2014 vs. | | 2013 vs. |
| In millions | | 2013 | | 2012 |
| Income from equity method investments: | | | | |
| SouthStar | | $ | 5.0 |
| | $ | 1.3 |
|
| Constitution | | 1.7 |
| | 1.0 |
|
| Other | | — |
| | (0.1 | ) |
| Total | | 6.7 |
| | 2.2 |
|
| Non-operating income | | (1.0 | ) | | 1.5 |
|
| Non-operating expense | | 0.8 |
| | (3.3 | ) |
| Income Taxes | | (3.0 | ) | | 0.5 |
|
| Total | | $ | 3.5 |
| | $ | 0.9 |
|
2014 compared with 2013:
Income from equity method investments
decreased $4.8 million in 2011 compared with 2010from SouthStar – the increase is primarily due to
a decreasethe expansion of
$4.5 millionthe business into Illinois markets beginning in
earnings from SouthStar due to a full year of recording earnings at the lower 15% ownership interestSeptember 2013, and
unfavorable changes in SouthStar’s averagefavorable weather and customer usage
due to warmer weather and retail pricing plan mix which werein Georgia, partially offset by
decreaseshigher general and administrative expenses. For further information on the contribution of the Illinois business to SouthStar and our cash contribution in
operating expenses.Non-operating income increased $1.1 millionour equity method investment, see Note 12 to the consolidated financial statements 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.
this Form 10-K.
Income from equity method investments decreased $4.6 million in 2010 comparedfrom Constitution – the increase is primarily due to higher capitalized interest associated with 2009increased capital expenditures on the project.
Non-operating income – the decrease is primarily due to a $4.5$2 million decreasewrite-off of an investment that we accounted for on the cost basis. This investment was presented in earnings“Other noncurrent assets” in “Noncurrent Assets” in the Condensed Consolidated Balance Sheets.
2013 compared with 2012:
Income from
equity method investments from SouthStar
– the increase is primarily due to
higher average customer usage from colder weather compared to the prior year, net of weather derivatives, the recording of
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
adjustmentsadjustment in the prior year and
new margin from the Illinois business that was contributed to the venture with our sharing beginning in September 2013, partially offset by higher
gas costs, increased operating expenses and lower retail price spreads.
Utility Interest Charges
Utility interest charges increased $.3 million in 2011 compared with 2010
Income from equity method investments from Constitution – the increase is primarily due to
the following changes:recording earnings of $1
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), partially offset by operating expenses.
Non-operating income – the increase is primarily due to a $.7 million increase in non-regulated business income plus a gain from a land retirement.
Non-operating expense – the increase is primarily due to $1.8 million of cumulative amortization of non-land costs related to the allowed deferral of a regulatory asset for certain non-real estate costs, construction of which iswas suspended in March 2009, as included in the 2013 settlement agreement with the NCUC Public Staff. We had a balance of $6.7 million of capital costs held in “Plant held for future use” comprised of $3.2 million in land costs and $3.5 million in non-land development costs. Under the NCUC approved settlement of the 2013 North Carolina general rate proceeding, we agreed to the amortization and collection of $1.2 million of the non-real estate costs to be amortized over 38 months beginning January 1, 2014, which we recorded as income,a regulatory asset along with a portion of the costs that we allocated to South Carolina operations. In addition, charitable contributions increased $.8 million primarily due to the closing of approximately halffunding of our construction expenditures tocharitable foundation.
Utility Interest Charges
Changes in utility plant in service in the first half of the current year asinterest charges for 2014 and 2013 compared with the same prior year.periods are presented below.
|
| | | | | | | | |
| Changes in Utility Interest Charges - Increase (Decrease) |
| | | 2014 vs. | | 2013 vs. |
| In millions | | 2013 | | 2012 |
| Borrowed AFUDC | | $ | 14.5 |
| | $ | (5.8 | ) |
| Regulatory interest expense, net | | 8.1 |
| | 0.1 |
|
| Interest expense on long-term debt | | 7.4 |
| | 12.7 |
|
| Interest expense on short-term debt | | (0.4 | ) | | (1.5 | ) |
| Other | | 0.1 |
| | (0.7 | ) |
| Total | | $ | 29.7 |
| | $ | 4.8 |
|
2014 compared to 2013:
Borrowed AFUDC – the increase 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 decreased $3 million in 2010 compared with 2009 primarily due to the following changes:
$9.1 million increase in net interest expenseis due to a decrease in capitalized interest chargedon a lower base of construction expenditures in the current period resulting from the timing of projects being placed into service.
Regulatory interest expense, net – the increase is primarily due to the recording of interest expense on amounts due to customers compared with the recording of interest income in the prior year on amounts due from customers (receivable), which earned a carrying charge, as those balances were lowercustomers.
Interest expense on long-term debt – the increase is primarily due to higher amounts of debt outstanding in the current period.periods.
2013 compared to 2012:
Interest expense on long-term debt – the increase is primarily due to the issuance of debt in 2013 and a full year of interest expense on the debt issued in 2012.
Borrowed AFUDC – the decrease in interest expenseis due to an increase in the borrowed AFUDC, which is recorded as income,capitalized interest primarily due toresulting from increased construction expenditures.
$2.4 million decrease in interestInterest expense on long-termshort-term debt – the decrease is 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 inbalances outstanding during the current period combined with an averageat interest rate for the current period approximately 35rates that are 34 basis points lower than the prior year period.
We paid down short-term debt as we issued long-term debt and equity securities during our fiscal year.
Financial Condition and Liquidity
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 marketfinancial 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 believe that The need for long-term capital is driven by the capacitylevel of short-term credit available to us under our revolving syndicated credit facility and thetiming of capital expenditures and long-term debt maturities. Our issuance of long-term debt and equity securities together withis subject to regulation by the NCUC. For information on the issuance of long-term debt and equity securities, see Note 4 and Note 6, respectively to the consolidated financial statements in this Form 10-K.
To meet our capital and liquidity requirements outside of the long-term capital markets, we rely on certain resources, including cash
provided byflows from operating activities,
will continue to allow us to meetcash generated from our
needs for working capital, construction expenditures, investments in joint ventures
anticipated debt redemptions, dividend payments, employee benefit plan contributions, common share repurchasesand short-term debt. Operating activities primarily provides the liquidity to fund our working capital, a portion of our capital expenditures and 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 alongdebt together with long-term capital markets to provide a significant source of liquidity to meet operating requirements that are not satisfied by internally generated cash flows. Currently, cash flows from operations are not adequate to finance the full cost of planned capital expenditures, which are fundamental to support ourinvestments in customer growth, pipeline integrity programs, system infrastructure and the growth incontributions to 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 | |
joint ventures.
The level of short-term
bank borrowingsdebt can vary significantly due to changes in the wholesale cost of natural gas and the level of purchases of natural gas supplies for storage to serve customer demand. We pay our suppliers for natural gas purchases before we collect our costs from customers through their monthly bills. If wholesale gas prices increase, we may incur more short-term debt for natural gas inventory and other operating costs since collections from customers could be slower and some customers may not be able to pay their gas bills on a timely basis.
We believe that the capacity of short-term credit available to us under our revolving syndicated credit facility and our CP program and the issuance of long-term debt and equity securities, together with cash provided by operating activities, will continue to allow us to meet our needs for working capital, capital expenditures, investments in joint ventures, anticipated debt redemptions, dividend payments, employee benefit plan contributions and other cash needs. Our ability to satisfy all of these requirements is dependent upon our future operating performance and other factors, some of which we are not able to control. These factors include prevailing economic conditions, regulatory changes, the price and demand for natural gas and operational risks, among others. Liquidity has been enhanced by reduced tax payments due to the utilization of federal net operating loss (NOL) carryforwards resulting from bonus depreciation, as well as the ability to recover and earn on investments in infrastructure related to our pipeline integrity programs through IMRs in North Carolina and Tennessee. For further information on bonus depreciation, see the following discussion of “Cash Flows from Operating Activities” in this Form 10-K.
Short-Term Debt. We have an $850 million five-year revolving syndicated credit facility that expires in October 2017. We pay an annual fee of $35,000 plus 8.5 basis points for any unused amount. The five-year revolving syndicated credit facility contains normal and customary financial covenants.
We have an $850 million unsecured CP program that is backstopped by the revolving syndicated credit facility. The amounts outstanding under the revolving syndicated credit facility and the CP program, either individually or in the aggregate, cannot exceed $850 million. The notes issued under the CP program may have maturities not to exceed 397 days from the date of issuance. Any borrowings under the CP program rank equally with our other unsecured debt.
We did not have any borrowings under the revolving syndicated credit facility for the year ended October 31, 2014. Highlights for our short-term debt as of October 31, 2014 and 2013 and for the quarter and year ended October 31, 2014 and 2013 are presented below.
|
| | | | | | | | | | | | |
| | | Credit | | Commercial | | Total |
| In thousands | | Facility | | Paper | | Borrowings |
| 2014 | | | | | | |
| End of period (October 31, 2014): | | | | | | |
| Amount outstanding | | $ | — |
| | $ | 355,000 |
| | $ | 355,000 |
|
| Weighted average interest rate | | — | % | | .17 | % | | .17 | % |
| | | | | | | |
| During the period (August 1, 2014 – October 31, 2014): | | | | | | |
| Average amount outstanding | | $ | — |
| | $ | 420,900 |
| | $ | 420,900 |
|
| Minimum amount outstanding | | — |
| | 275,000 |
| | 275,000 |
|
| Maximum amount outstanding | | — |
| | 535,000 |
| | 535,000 |
|
| Minimum interest rate | | — | % | | .10 | % | | .10 | % |
| Maximum interest rate | | — | % | | .25 | % | | .25 | % |
| Weighted average interest rate | | — | % | | .17 | % | | .17 | % |
| | | | | | | |
| Maximum amount outstanding during the month: | | | | | | |
| August 2014 | | $ | — |
| | $ | 525,000 |
| | $ | 525,000 |
|
| September 2014 | | — |
| | 535,000 |
| | 535,000 |
|
| October 2014 | | — |
| | 355,000 |
| | 355,000 |
|
| | | | | | | |
| During the year ended October 31, 2014: | | | | | | |
| Average amount outstanding | | $ | — |
| | $ | 441,500 |
| | $ | 441,500 |
|
| Minimum amount outstanding | | — |
| | 275,000 |
| | 275,000 |
|
| Maximum amount outstanding | | — |
| | 625,000 |
| | 625,000 |
|
| Minimum interest rate | | — | % | | .10 | % | | .10 | % |
| Maximum interest rate | | — | % | | .43 | % | | .43 | % |
| Weighted average interest rate | | — | % | | .19 | % | | .19 | % |
|
| | | | | | | | | | | | |
|
| Credit |
| Commercial |
| Total |
| In thousands |
| Facility |
| Paper |
| Borrowings |
| 2013 |
|
|
|
|
|
|
| End of period (October 31, 2013): |
|
|
|
|
|
|
| Amount outstanding |
| $ | — |
|
| $ | 400,000 |
|
| $ | 400,000 |
|
| Weighted average interest rate |
| — | % |
| .36 | % |
| .36 | % |
| | | | | | | |
| During the period (August 1, 2013 – October 31, 2013): |
|
|
|
|
|
|
| Average amount outstanding |
| $ | — |
|
| $ | 319,700 |
|
| $ | 319,700 |
|
| Minimum amount outstanding |
| — |
|
| 220,000 |
|
| 220,000 |
|
| Maximum amount outstanding |
| — |
|
| 475,000 |
|
| 475,000 |
|
| Minimum interest rate |
| — | % |
| .23 | % |
| .23 | % |
| Maximum interest rate |
| — | % |
| .43 | % |
| .43 | % |
| Weighted average interest rate |
| — | % |
| .28 | % |
| .28 | % |
|
|
|
|
|
|
|
| Maximum amount outstanding during the month: |
|
|
|
|
|
|
| August 2013 |
| $ | — |
|
| $ | 475,000 |
|
| $ | 475,000 |
|
| September 2013 |
| — |
|
| 335,000 |
|
| 335,000 |
|
| October 2013 |
| — |
|
| 430,000 |
|
| 430,000 |
|
| | | | | | | |
| During the year ended October 31, 2013: |
|
|
|
|
|
|
Average amount outstanding (1) |
| $ | — |
|
| $ | 397,800 |
|
| $ | 397,800 |
|
Minimum amount outstanding (1) |
| — |
|
| 220,000 |
|
| 220,000 |
|
Maximum amount outstanding (1) |
| 10,000 |
|
| 555,000 |
|
| 555,000 |
|
Minimum interest rate (2) |
| 1.12 | % |
| .23 | % |
| .23 | % |
| Maximum interest rate |
| 1.12 | % |
| .45 | % |
| 1.12 | % |
| Weighted average interest rate |
| 1.12 | % |
| .32 | % |
| .32 | % |
| | | | | | | |
(1) During December 2012, we were borrowing under both the credit facility and CP program for a portion of the month. |
(2) This is the minimum rate when we were borrowing under the credit facility and/or CP program. |
As of October 31,
2011,2014, we had $10 million available for letters of credit under our
three-year revolving syndicated credit facility, of which
$3.5$1.8 million were issued and outstanding. The letters of credit are used to guarantee claims from self-insurance under our general and automobile liability policies. As of October 31,
2011,2014, unused lines of credit available under our
three-year revolving syndicated credit facility, including the issuance of the letters of credit, totaled
$315.5$493.2 million.
Cash Flows from Operating Activities. The natural gas business is seasonal in nature. Operating cash flows may fluctuate significantly during the year and from year to year due to working capital changes within our utility and non-utility operations. The major factors that affect our working capital are weather, natural gas purchases and prices, natural gas storage activity, collections from customers and deferred gas cost recoveries. We rely on operating cash flows and short-term bank borrowingsdebt to meet seasonal working capital needs. The level of short-term debt can vary significantly due to changes in the wholesale cost of natural gas and the level of purchases of natural gas supplies for storage to serve customer demand. We pay our suppliers for natural gas purchases before we collect our costs from customers through monthly bills. During our first and second quarters, we generally experience overall positive cash flows from the sale of flowing gas and gas withdrawal from storage and the collection of amounts billed to customers during the November through March winter heating season. Cash requirements generally increase during the third and fourth quarters due to increases in natural gas purchases injected into storage, seasonal construction activity and decreases in receipts from customers.
During the winter heating season, our trade accounts payable increase to reflect amounts due to our natural gas suppliers for commodity and pipeline capacity. The cost of the natural gas can vary significantly from period to period due to changes in the price of natural gas, which is a function of market fluctuations in the commodity cost of natural gas, along with our changing requirements for storage volumes. Differences between natural gas costs that we have paid to suppliers and amounts that we have collected from customers are included in regulatory deferred accounts and in amounts due to or from
customers. These natural gas costs can cause cash flows to vary significantly from period to period along with variations in the timing of collections from customers under our gas cost recovery mechanisms.
Cash flows from operations are impacted by weather, which affects gas purchases and sales. Warmer weather can lead to lower revenues from fewer volumes of natural gas sold or transported. Colder weather can increase volumes sold to weather-sensitive customers but may lead to conservation by customers in order to reduce their heating bills.
Regulatory margin stabilizing and cost recovery mechanisms, such as decoupled tariffs and those that allow us to recover the gas cost portion of bad debt expense, mitigate the impact that customer conservation and higher bad debt expense may have on our results of operations. Warmer-than-normal weather can lead to reduced operating cash flows, thereby increasing the need for short-term bank borrowings to meet current cash requirements.
Because of the weak economy, including continued high unemployment, we may incur additional bad debt expense 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, are expected to mitigate the impact these factors may have on our results of operations.
Net cash provided by operating activities was $311.2$430.6 million in 2011, $360.52014, $313.2 million in 20102013 and $344.3$304.5 million in 2009.2012. Net cash provided by operating activities reflects a $28.4$9.4 million decreaseincrease in net income for 20112014 compared with 2010, which included the gain on the sale of half our2013 primarily due to increased margin, partially offset by higher operating costs and utility 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.charges. The effect of changes in working capital on net cash provided by operating activities is described below: Trade accounts receivable and unbilled utility revenues increased $2.5decreased $17.3 million in the current period primarily due to totalthe decrease in unbilled volumes in the month of October and amounts billed to customers. Volumes sold to weather-sensitive residential and commercial customers increased 11.2 million dekatherms as compared with the same prior period primarily due to 6.2% colder weather during the current period. Total throughput which increased 27.123.1 million dekatherms as compared with the same prior period, largely from the transportation of gas for industrial customers and for10.8 million dekatherms, or 5.7% increased deliveries to 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 soldwell as increased sales to residential and commercial customers increased .2 million dekatherms as compared with the same prior period.customers.
Net amounts due from customers decreased $26.3$96.4 million in the current period primarily due to the collection ofhigher margin decoupling, WNA and deferred gas costs through rates.
cost amounts due to customers.Gas in storage decreased $10.6increased $10.2 million in the current period primarily due to a decreasean increase in the weighted average cost of gas purchased for injections as well as decreasedand increased volumes of gas in storage in 2011 as compared with 2010.
storage.Prepaid gas costs decreased $.8increased $3.5 million in the current period primarily due to loweran increase in the weighted average cost of gas in prepaid storage.purchased for injections. Under some gas supply asset management contracts, prepaid gas costs incurred during the summer months represent purchases of gas that are not available for sale, and therefore not recorded in inventory, until the start of the winter heating season.
Trade accounts payable increased $1.6decreased$11 million in the current period primarily due to decreased utility capital expenditures and natural gas purchases for storagepurchases.
Primarily due to meet customer demandbonus depreciation, we generated a federal NOL in our tax years 2012 and 2013. We filed claims to carryback a portion of the NOLs to prior federal income tax returns. We recorded approximately $27 million in “Income taxes receivable” in “Current Assets” in the Consolidated Balance Sheets for the next winter heating season.refundable income taxes from the carryback of these NOLs. Also, we utilized the carryforward of the NOLs to offset $28.6 million of federal income taxes payable in fiscal 2014. We anticipate that we will utilize the remaining portion of the NOL carryforwards prior to the expiration of the loss carryforward period.
The Tax Increase Prevention Act of 2014 (the Act) retroactively extends the 50% bonus depreciation that expired in December 2013 for a year to December 2014. Under this Act, we will be entitled to additional tax depreciation deductions for 2014. These additional deductions will result in generating a federal NOL in 2014. Our federal NOL carryforward position after considering this legislation will increase to approximately $275 million. We anticipate that we will generate future taxable income sufficient to utilize this carryforward prior to the expiration of the loss carryforward period.
Our three state regulatory commissions approve rates that are designed to give us the opportunity to generate revenues to cover our gas costs, fixed and variable non-gas costs and earn a fair return for our shareholders. We have a WNA mechanismmechanisms in South Carolina and Tennessee that partially offsetsoffset the impact of colder- or warmer-than-normal weather on bills rendered in November through March for residential and commercial customers.customers in South Carolina and in October through April for residential and commercial customers in Tennessee. The WNA mechanisms in South Carolina and Tennessee generated credits to customers of $4.9$8.4 million in 2011, $8.82014 and charges of $3 million and $13.3 million in 20102013 and $1.2 million in 2009.2012, respectively. In Tennessee, adjustments are made directly to individual customer monthly bills. In South Carolina, the adjustments are calculated at the individual customer level but are recorded in “Amounts due from customers” in “Regulatory Assets” or “Amounts due to customers” in “Regulatory Liabilities,” as presented in Note 1 to the consolidated balance sheetsfinancial statements in this Form 10-K, for subsequent collection from or refund to all customers in the class. The margin decoupling mechanism in North Carolina provides for the collection of our approved margin from residential and commercial customers independent of weather and consumption patterns. The margin decoupling mechanism reduced margin by $7$33.4 million in 2011 and $5.9 million in 20102014 and increased margin
by $6 million
and $46.8 million in
2009.2013 and 2012, respectively. Our gas costs are recoverable through
PGApurchased gas adjustment (PGA) procedures and are not affected by the WNA or the margin decoupling
mechanism.mechanisms.
The financial condition of the natural gas marketers and pipelines that supply and deliver natural gas to our distribution system can increase our exposure to supply and price fluctuations. We believe our risk exposure to the financial condition of the marketers and pipelines is not significant based on our receipt of the products and services prior to payment and the availability of other marketers of natural gas to meet our firm supply needs if necessary. We have regulatory commission approval in North Carolina, South Carolina and Tennessee that places tighter credit requirements on the retail natural gas marketers that schedule gas for transportation service on our system.
The regulated utility competes with other energy products, such as electricity and propane, in the residential and commercial customer markets. The most significant product competition is with electricity for space heating, water heating and cooking. Numerous factors can influence customer demand for natural gas, including price, value, availability, environmental attributes,
comfort, convenience, reliability and energy efficiency. Increases in the price of natural gas can negatively impact our competitive position by decreasing the price benefits of natural gas to the consumer. This can impact our cash needs if customer growth slows, resulting in reduced capital expenditures, or if customers conserve, resulting in reduced gas purchases and customer billings.
In the industrial market, many of our customers are capable of burning a fuel other than natural gas, with fuel oil being the most significant competing energy alternative. Our ability to maintain industrial market share is largely dependent on
price.the relative prices of energy. The relationship between supply and demand has the greatest impact on the price of natural gas. The price of oil depends upon a number of factors beyond our control, including the relationship between worldwide supply and demand and the policies of foreign and domestic governments and organizations, as well as the value of the
USU.S. dollar versus other currencies. Our liquidity could be impacted, either positively or negatively, as a result of alternate fuel decisions made by industrial customers.
In an effort to keep customer rates competitive and to maximize earnings, we continue to implement business process improvement and
operations and maintenanceO&M cost management programs to capture operational efficiencies while improving customer service and maintaining a safe and reliable system.
Cash Flows from Investing Activities. Net cash used in investing activities was $252.6$504.4 million in 2011, $128.62014, $663.5 million in 20102013 and $129.6$549.3 million in 2009.2012. Net cash used in investing activities was primarily for utility constructioncapital expenditures. Gross utility constructioncapital expenditures were $243.6$460.4 million in 2011, a 22% increase from the $199.12014 as compared to $600 million in 2010,2013 primarily due to $103.6 million and $52.3 million, respectively, of investments in plant to servelower power generation customers.service delivery project expenditures and lower maintenance expenditures. Gross utility constructioncapital expenditures were $129$600 million in 2009 with $2.62013 compared to $529.6 million of investments in plant2012 primarily due to serveincreased expenditures for system integrity projects, partially offset by decreased expenditures for the construction of power generation customers.service delivery projects.
We have a substantial capital expansion program for construction of transmission and distribution facilities, purchase of equipment and other general improvements.
ThisOur program
primarily supports our system infrastructure,
and the growth in our customer
base.base and large amounts for pipeline integrity, safety and compliance programs, including systems and technology infrastructure to enhance our pipeline system and integrity through a new work and asset management system. Significant utility construction expenditures are expected
to meet long-termfor growth
including the power generation market,and system integrity and are part of our long-range forecasts that are prepared at least annually and typically cover a forecast period of five years. We are contractually obligated to expend capital as the work is completed.
We anticipate making
Detail of our forecasted 2015 – 2017 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.is presented below. We intend to fund
capital expenditures
related to these projects in a manner that maintains our targeted capitalization ratio of
45-50%50 – 60% in
long-termtotal debt and
50-55%40 – 50% in common equity.
Additional detailA portion of the funding 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,is derived from operations, including lower federal income tax payments due to accelerated depreciation as well as bonus depreciation benefits.
|
| | | | | | | | | | | | |
| In millions | | 2015 | | 2016 | | 2017 |
| Customer growth and other | | $ | 230 |
| | $ | 285 |
| | $ | 295 |
|
| System integrity | | 270 |
| | 245 |
| | 295 |
|
| Total forecasted utility capital expenditures | | $ | 500 |
| | $ | 530 |
| | $ | 590 |
|
Our estimates for utility capital expenditures associated with system integrity have increased since 2013. These increases are primarily due to costs associated with the development and enhancement of programs and processes designed to mitigate risk on our system to comply with federally mandated pipeline safety and integrity requirements. Such programs
include retrofitting transmission lines to facilitate internal inspections, transmission line replacements, corrosion control, casing remediation and distribution integrity management.
During fiscal 2012, we
reached an agreement with Progress Energy Carolinas to provideplaced into service 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 withand compression facilities to provide natural gas delivery service to
the plant by June 2012. We began constructiona Duke Energy Progress, Inc. (DEP), now a subsidiary of Duke Energy Corporation (Duke Energy), power generation facility located in
February 2010. Our investment in the pipeline and compression facilities isWayne County, North Carolina. This project was supported by a long-term service
agreement. To provide the additional delivery service,agreement with fixed monthly payments. In connection with this project, we
have executed an agreement withincreased our firm capacity entitlement on Cardinal Pipeline Company,
LLCL.L.C. (Cardinal)
to expand our firm capacity requirement by 149,000 dekatherms per daypipeline to serve
this facility. This will requirethe DEP Wayne County site, requiring Cardinal to
spendinvest in a new compressor station and expanded meter stations in order to increase the capacity of its system for us and another customer. As an
estimated $48 million to expand its system. As a 21.49% equity venture partner of Cardinal, we
will invest an estimated $10.3made capital contributions of $9.8 million
in Cardinal’s system expansion. Capital contributions related to this system expansion
began in January 2011 and
will continue onreceived $5.4 million as a
periodic basis through September 2012. Aspartial return of
October 31, 2011, our
contributions to date related to this systemcapital investment with Cardinal's issuance of $45 million of long-term debt. Cardinal's expansion
were $6.2 million. For further information regarding this agreement, see Note 12 toservice for the
consolidated financial statements.In April 2010, we reached another agreement with Progress Energy Carolinas to provideproject and our natural gas delivery service to a power generation facility to be built at their existing Suttonfor DEP's Wayne County site near Wilmington, North Carolina. The agreement, also approved by the NCUCwere placed into service in May 2010, calls for us to construct approximately 130 miles of transmissionJune 2012.
During fiscal 2013, we placed into service natural gas pipeline along withand compression facilities to provide natural gas delivery service to a DEP power generation facility at their Sutton site near Wilmington, North Carolina. Our investment in the plant by June 2013. We began construction in May 2010. Our service to Progress Energy Carolinas ispipeline and compression facilities was supported by a long-term service agreement. We anticipate that a portion of the cost of thisagreement with fixed monthly payments.
Our Sutton project will be included in our North Carolina utility rate base.The Sutton facilities will also createcreated cost effective expansion capacity that we will also use to help serve the growing natural gas requirements of our customers in the eastern part of North Carolina. At the present time with the timing and design scope of the Sutton facilities, there is no current need to proceed with our previously announced Robeson liquefied natural gas storage project. The timing and design scope of the expansionapproval of our facilities2013 NCUC rate settlement provided for the inclusion of this project in Robeson County will be determined as our system infrastructure and market supply growth requirementsrate base in North Carolina dictate.
During the first quarterCarolina. Beginning in 2015, a special contracts credit, representing a portion of fiscal 2011, we placed into service natural gas pipeline and compression facilities to provide natural gas delivery service to a Progress Energy Carolinasmargin on our power generation facility located in Richmond County, North Carolina.
Duringcontracts, will reduce the first quarter of fiscal 2011,IMR revenue requirement under the IMR mechanism
.
In July 2013, 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%acquired an additional 5% membership interest in Pine Needle LNG Company, L.L.C. from Hess Corporation for $2.9 million, which increased our membership interest from 40% to 45%.
In September 2013, we made an additional $22.5 million capital contribution to our existing SouthStar
to Georgia Natural Gas Company (GNGC)investment associated with our partner contributing retail natural gas marketing assets and
retained a 15% earnings and membership sharerelated customer accounts located in
SouthStar after the sale. At closing, we received $57.5 million from GNGC.Illinois. For further information regarding
the sale,this transaction, see Note 12 to the consolidated financial
statements.statements in this Form 10-K.
In
2009,November 2012, we
contributed $.9 millionbecame a 24% equity member of Constitution, a Delaware limited liability company. The purpose of the joint venture is to construct, own and operate approximately 120 miles of interstate natural gas pipeline and related facilities connecting shale natural gas supplies and gathering systems in Susquehanna County, Pennsylvania, to the Iroquois Gas Transmission and Tennessee Gas Pipeline systems in New York. We have committed to fund an amount in proportion to our
Hardy Storage Company, LLC (Hardy Storage) joint venture as partownership interest for the development and construction of
the new pipeline. Our contributions for the year ended October 31, 2014 were $37.6 million with our
total equity contribution for
the project totaling $53.5 million as of October 31, 2014. On December 2, 2014, the FERC issued a certificate of public convenience and necessity approving construction of the
FERC regulated interstate storage facility.Constitution pipeline. The forecasted in-service date of the project is late 2015 or 2016. We
made noexpect our equity contributions
will be an estimated $86 million and $35.4 million in
2010our fiscal years 2015 and
2011 as Hardy Storage converted its construction interim notes in March 2010 into long-term project-financed debt.2016, respectively, for total equity contributions of $175 million. In November 2014, we contributed $1.9 million to the project. For further information
on Hardy Storage,regarding this agreement, see Note 12 to the consolidated financial
statements.statements in this Form 10-K.
In June 2014, we executed an agreement to construct approximately 1.5 miles of natural gas transmission pipeline and associated compression to serve Duke Energy’s W.S. Lee power generation facility near Anderson, South Carolina. Our total investment is estimated to be $38 million, with $8 million and $30 million in our fiscal years 2015 and 2016, respectively, and is included in the table above in the line “Customer growth and other.” This agreement is supported by a long-term natural gas service agreement with fixed monthly charges.
In September 2014, Piedmont, Duke Energy, Dominion Resources, Inc. (Dominion), and AGL Resources, Inc. (AGL) announced the formation of ACP, a Delaware limited liability company. ACP intends to construct, operate and maintain a 550 mile natural gas pipeline, with associated compression, from West Virginia through Virginia into eastern North Carolina. The pipeline is proposed to provide wholesale natural gas transportation services for Marcellus and Utica gas supplies into southeastern markets. ACP, which is regulated by the FERC, will be designed with an initial capacity of 1.5 billion cubic feet per day with a target in-service date of late 2018. The capacity of ACP is substantially subscribed by utilities and related companies, including us, under twenty-year contracts.
We entered into an agreement through a wholly-owned subsidiary to become a 10% equity member of ACP. The other members are subsidiaries of Duke Energy, Dominion and AGL. A Dominion subsidiary will be the operator of the pipeline. The cost for the development and construction of the pipeline is expected to be between $4.5 billion to $5 billion, excluding financing costs. Members anticipate obtaining project financing for 70% of the total costs during the construction period. As of October 31, 2014, we have made no contributions to ACP. In November 2014, we contributed $.9 million to the project.
In connection with the ACP project, we plan to make additional utility capital investments in our natural gas delivery system of approximately $190 million in order to redeliver ACP gas supplies to local North Carolina markets we serve, predominately in fiscal 2017 and 2018. Of that amount, approximately $170 million will be supported by third-party contracts.
Cash Flows from Financing Activities. Net cash used inprovided by financing activities was $57.5$75.4 million in 2011, $233.92014, $356.3 million in 20102013 and $214.1$240 million in 2009.2012. Funds are primarily provided from banklong-term debt securities, short-term borrowings and the issuance of common stock through our dividend reinvestment and stock purchase plan (DRIP) and our employee stock purchase plans.plan (ESPP). We may sell common stock and long-term debt when market and other conditions favor such long-term financing.financing to maintain our target capital structure of 40 – 50% equity to total capital. In recent years, bonus depreciation has been a source of funds in that it has decreased our federal income tax payments. Funds are primarily used to finance capital expenditures, retire long-term debt maturities, pay down outstanding short-term bank borrowings,debt, repurchase common stock under the common stock repurchase program, and pay quarterly dividends on our common stock. As of October 31, 2011,stock and general corporate purposes.
Outstanding debt under our
current assets were $286 million and our current liabilities were $534.1 million, primarily due to seasonal requirements as discussed above.Outstanding short-term bank borrowings increasedCP program decreased from $242$400 million as of October 31, 20102013 to $331$355 million as of October 31, 20112014 primarily due to highernet proceeds received from the issuance of long-term debt and our common stock, reduced utility capital expenditures and cash flow stemming from colder-than normal weather, partially offset by natural gas purchases, repayment of our long-term debt maturities. Overand investments in one of our equity method investments. On November 1, 2013, we entered into an agreement with the three-year period from 2009 to 2011, our short-term borrowings have included the replacement oflenders under our five-year revolving syndicated credit facility to increase the aggregate commitment from $650 million to $850 million with our current three-year revolving syndicatedan expiration date of October 1, 2017. Our unsecured CP program is backstopped by this credit facility and a syndicated seasonal credit facility in existence from December 3, 2008 through March 31, 2009.facility. For further information on bank borrowings,short-term debt, see Note 5 to the consolidated financial statements in this Form 10-K and the previous discussion of “Short-Term Borrowings”Debt” 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 retired our $60 million 6.55% medium-term notes, $60 million 7.8% medium-term notes and $30 million 7.35% medium-term notes in September 2011, September 2010 and September 2009, respectively, as they became due. On June 1, 2011, we redeemed all of the 6.25% insured quarterly notes with an aggregate principal balance of $196.8 million with short-term bank borrowings under the revolving syndicated credit facility. Liquidity.”
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 reduce 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, 2011,2014, we filed with the SEC a combined debt and equity shelf registration statement that became effective on the same date. Unless otherwise specified at the time such securities are offered for sale, the net proceeds from the sale of the securities will be used to finance capital expenditures, to repay outstanding short-term notes under our unsecured CP program, to refinance other indebtedness, to repurchase our common stock, to pay dividends and for general corporate purposes, including capital expenditures, additions to working capital and advances for or investments in our subsidiaries, and for repurchases of shares of our common stock.purposes. Pending such use, we may temporarily invest any net proceeds that are not applied to the purposes mentioned above in investment gradeinvestment-grade securities.
We plan to issue approximately $300 million ofnew long-term debt and equity capital in our fiscal 2012 thirdyears 2015 and 2016, at such amounts to support our capital investment program and maintain our target capital structure of 50 – 60% in total debt and 40 – 50% in common equity. In addition to issuing common stock under our DRIP and ESPP as described above, we expect to establish in the first quarter of 2015 an at-the-market equity sales program that may also include sales with a forward component. We anticipate that sales under this program would not exceed an aggregate of $170 million, as market conditions permit, and would be completed by the end of fiscal 2016. Any such shares of our common stock would be offered and sold under our shelf registration statement and related prospectuses.
On January 29, 2013, we entered into an underwriting agreement under our open combined debt and equity shelf registration statement to sell up to 4.6 million shares of our common stock of which 3 million direct shares were issued and settled on February 4, 2013 with net proceeds of $92.6 million received. The shares were purchased by the underwriters at the net price of $30.88, the offering price to the public of $32 per share per the prospectus less an underwriting discount of $1.12 per share.
Under this same underwriting agreement, we had two FSAs totaling 1.6 million shares that had to be settled no later than mid-December 2013. Under the terms of the FSAs, at our election, we could physically settle in shares, cash or net share settle for all or a portion of our obligations under the agreements. In December 2013, we physically settled the FSAs by issuing 1.6 million shares of our common stock to the forward counterparty and received net proceeds of $47.3 million based on the net settlement price of $30.88 per share, the original offering price, less certain adjustments.
We used the net proceeds from the equity transactions discussed above to finance capital expenditures, repay outstanding notes under the unsecured CP program and for general corporate purposes, includingpurposes. For further information on our common stock and for more details on these equity issuance transactions, see Note 6 to the funding of capital expenditures to serve new power generation projects. consolidated financial statements in this Form 10-K.
We continually monitor customer growth trends and
investment opportunities in our markets
along with the economic recovery of our service area forand the timing of any infrastructure investments that would require the need for additional long-term debt.
The table below presents the activity of our long-term debt during the three-year period ended October 31, 2014. For further information on our long-term debt instruments, see Note 4 to the consolidated financial statements in this Form 10-K.
|
| | | | | | | | | | |
| In millions | | Issued (Redeemed) | | Date Issued/Redeemed | | Cash Impact |
| Senior Notes: | | | | | | |
3.47%, due July 16, 2027 (1) (2) | | $ | 100 |
| | July 2012 | | $ | 100.0 |
|
3.57%, due July 16, 2027 (1) (2) | | 200 |
| | October 2012 | | 200.0 |
|
4.65%, due August 1, 2043 (3) | | 300 |
| | August 2013 | | 299.9 |
|
4.10%, due September 18, 2034 (1) | | 250 |
| | September 2014 | | 249.6 |
|
| | | | | | | |
| Medium-Term Notes: | | | | | | |
| 5.00%, due December 19, 2013 | | (100 | ) | | December 2013 | | (100 | ) |
| | | | | | | |
(1) The net proceeds were used to finance capital expenditures, to repay outstanding short-term notes under our unsecured CP program and for general corporate purposes. |
(2) In March 2012, we entered into an agreement to issue $300 million of notes in a private placement with a blended rate of 3.54%. |
(3) The net proceeds were used to finance capital expenditures, to repay the balance of $100 million of our 5% Medium-Term Notes listed below, to repay outstanding short-term notes under our unsecured CP program and for general corporate purposes. |
From time to time, we have repurchased shares of common stock under our Common Stock Open Market Purchase Program
and our ASR program as described in Note 6 to the consolidated financial
statements.statements in this Form 10-K. During
2011,2014 and 2013, we did not repurchase any of our common stock. Under our Common Stock Open Market Purchase Program, we repurchased and retired .8 million shares for
$23$26.5 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.during 2012. We
do not anticipate repurchasing
.8 million shares ofour common stock
through an ASR agreement in
the first quarter of our fiscal year
2012 with no permanent reduction in shares outstanding for fiscal year 2012.2015.
During
2011,2014, we issued
$20.2$25.6 million of common stock through
dividend reinvestmentDRIP and
stock purchaseESPP. During 2013 and
employee stock purchase plans. During 2010 and 2009,2012, we issued
$19.1$24.6 million and
$14.4$22.1 million, respectively, through these plans.
We have paid quarterly dividends on our common stock since 1956. We increased our common stock dividend on an annualized basis by $.04 per share
in 2011, 2010 and 2009.over the past three fiscal years. Dividends of
$82.9$99.2 million,
$80.3$92.1 million and
$78.4$85.7 million
for 2011, 2010in 2014, 2013 and
2009,2012, respectively, were paid on common stock. Provisions contained in certain note agreements under which
certain long-term debt was issued restrict the amount of cash dividends that may be paid. As of October 31,
2011,2014, our
retained earnings wereability to pay dividends was not restricted. On December
16, 2011,12, 2014, the Board of Directors declared a quarterly dividend on common stock of
$.29$.32 per share, payable January
13, 201215, 2015 to shareholders of record at the close of business on December
27, 2011.24, 2014. For further information, see Note 4 to the consolidated financial
statements.statements in this Form 10-K.
Our
long-term targeted capitalization ratio is
45-50%50 – 60% in
long-termtotal debt and
50-55%40 – 50% in common equity.
As of October 31, 2011, our capitalization, including current maturities of long-term debt, if any, consisted of 40% in long-term debt and 60% in common equity.The components of our total debt outstanding (short-term and long-term) to our total capitalization as of October 31, 20112014 and 20102013 are summarized in the table below.
| | | | | | | | | | | | | | | | |
| | | 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 | % |
| | | | | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | |
| | | October 31 | | October 31 |
| In thousands | | 2014 | | Percentage | | 2013 | | Percentage |
| Short-term debt | | $ | 355,000 |
| | 12 | % | | $ | 400,000 |
| | 14 | % |
| Current portion of long-term debt | | — |
| | — | % | | 100,000 |
| | 3 | % |
| Long-term debt | | 1,424,430 |
| | 46 | % | | 1,174,857 |
| | 41 | % |
| Total debt | | 1,779,430 |
| | 58 | % | | 1,674,857 |
| | 58 | % |
| Common stockholders’ equity | | 1,308,602 |
| | 42 | % | | 1,188,596 |
| | 42 | % |
| Total capitalization (including short-term debt) | | $ | 3,088,032 |
| | 100 | % | | $ | 2,863,453 |
| | 100 | % |
Credit ratings impact our ability to obtain short-term and long-term financing and the cost of such financings. The borrowing costs under our revolving syndicated credit facility and our unsecured CP program are based on our credit ratings, and consequently, any decrease in our credit ratings would increase our borrowing costs. We believe our credit ratings will allow us to continue to have access to the capital markets, as and when needed, at a reasonable cost of funds. In determining
The lenders under our
revolving syndicated credit facility and our unsecured CP program are major financial institutions, all of which have investment grade credit ratings
as of October 31, 2014. It is possible that one or more lending commitments could be unavailable to us if the
rating agencies consider various factors. The more significant quantitative factors include:Ratio of total debtlender defaulted due to total capitalization, including balance sheet leverage,
Ratio of net cash flows to capital expenditures,
Funds from operations interest coverage,
Ratiolack 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,
Consistencyor insolvency. However, based on our current assessment of our earnings over time,
Risks and controls inherent inlenders’ creditworthiness, we believe the distributionrisk of natural gas,
lender default is minimal.Predictability of cash flows,
Quality of business strategy and management,
Corporate governance guidelines and practices,
As of October 31, 2011,2014, all of our long-term debt was unsecured. Our long-term debt is rated “A” by Standard & Poor’s Ratings Services (S&P) and “A3”“A2” by Moody’s Investors Service.Service (Moody’s). Currently, with respect to our long-term debt, the credit agencies maintain their stable outlook. S&P and Moody’s have issued credit ratings on our unsecured CP program at “A1” and “P1”, respectively. Credit ratings and outlooks are opinions of the rating agencyagencies and are subject to their ongoing review. A significant decline in our operating performance, a significant negative change in our capital structure, ora change from the constructive regulatory environments in which we operate, a significant reduction in our liquidity or a methodological change at the rating agencies themselves could trigger a negative change in our ratings outlook or even a reduction in our credit ratings by ourthe rating agencies. This would mean more limited access to the private and public credit markets and an increase in the costs of such borrowings. There is no guarantee that a rating will remain in effect for any given period of time or that a rating will not be lowered or withdrawn by a rating agency if, in its judgment, circumstances warrant a change.
We are subject to default provisions related to our long-term debt and short-term borrowings. Failure to satisfy any of the default provisions may result in total outstanding issues of debt becoming due. There are cross-default provisions in all of our debt agreements. As of October 31,
2011,2014, there has been no event of default giving rise to acceleration of our debt.
The default provisions of some or all of our senior debt include:
Failure to make principal or interest payments,
Bankruptcy, liquidation or insolvency,
Final judgment against us in excess of $1 million that after 60 days is not discharged, satisfied or stayed pending appeal,
Specified events under the Employee Retirement Income Security Act of 1974,
Failure to observe or perform covenants, including:
Interest coverage of at least 1.75 times. Interest coverage was 5.784.29 times as of October 31, 2011;
2014;Funded debt cannot exceed 70% of total capitalization. Funded debt was 51%58% of total capitalization as of October 31, 2011;
2014;Funded debt of all subsidiaries in the aggregate cannot exceed 15% of total capitalization. There is no funded debt of our subsidiaries as of October 31, 2011;
2014;Restrictions on permitted liens;
Restrictions on paying dividends, on or repurchasing our stock or making investments in subsidiaries; and
Restrictions on burdensome agreements.
Contractual Obligations and Commitments
We have incurred various contractual obligations and commitments in the normal course of business. As of October 31,
2011,2014, our estimated recorded and unrecorded contractual obligations are as follows.
| | | | | | | | | | | | | | | | | | | | |
| | | 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 | |
| | | | | | | | | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | |
| | | Payments Due by Period |
| | | Less than | | 1-3 | | 3-5 | | More than | | |
| In thousands | | 1 year | | Years | | Years | | 5 Years | | Total |
| Recorded contractual obligations: | | | | | | | | | | |
| | | | | | | | | | | |
| Long-term debt (1) | | $ | — |
| | $ | 75,000 |
| | $ | — |
| | $ | 1,350,000 |
| | $ | 1,425,000 |
|
| Short-term debt (2) | | 355,000 |
| | �� |
| | — |
| | — |
| | 355,000 |
|
| Total recorded contractual obligations | | 355,000 |
| | 75,000 |
| | — |
| | 1,350,000 |
| | 1,780,000 |
|
| | | | | | | | | | | |
| Unrecorded contractual obligations and | | | | | | | | | | |
| commitments: (3) | | | | | | | | | | |
| | | | | | | | | | | |
| Pipeline and storage capacity (4) | | 158,984 |
| | 437,424 |
| | 246,091 |
| | 513,697 |
| | 1,356,196 |
|
| Gas supply reservation fees (5) | | 8,657 |
| | 272 |
| | — |
| | — |
| | 8,929 |
|
| Interest on long-term debt (6) | | 69,609 |
| | 204,949 |
| | 131,811 |
| | 736,555 |
| | 1,142,924 |
|
| Capital contributions to joint ventures (7) | | 106,734 |
| | 159,847 |
| | 88,612 |
| | — |
| | 355,193 |
|
| Telecommunications and information | | | | | | | | | | |
| technology (8) | | 14,601 |
| | 5,648 |
| | 80 |
| | — |
| | 20,329 |
|
| Qualified and nonqualified pension plan | | | | | | | | | | |
| funding (9) | | 11,821 |
| | 36,571 |
| | 2,590 |
| | — |
| | 50,982 |
|
| Postretirement benefits plan funding (9) | | 1,500 |
| | 4,000 |
| | 1,300 |
| | — |
| | 6,800 |
|
| Operating leases (10) | | 4,600 |
| | 13,013 |
| | 8,362 |
| | 23,134 |
| | 49,109 |
|
| Other purchase obligations (11) | | 41,008 |
| | — |
| | — |
| | — |
| | 41,008 |
|
| Surety bonds (10) | | 4,782 |
| | — |
| | — |
| | — |
| | 4,782 |
|
| Letters of credit (2) | | 1,797 |
| | — |
| | — |
| | — |
| | 1,797 |
|
| Total unrecorded contractual obligations | | | | | | | | | | |
| and commitments | | 424,093 |
| | 861,724 |
| | 478,846 |
| | 1,273,386 |
| | 3,038,049 |
|
| Total contractual obligations and | | | | | | | | | | |
| commitments | | $ | 779,093 |
| | $ | 936,724 |
| | $ | 478,846 |
| | $ | 2,623,386 |
| | $ | 4,818,049 |
|
| |
| (1) | See Note 4 to the consolidated financial statements.statements in this Form 10-K. |
| |
| (2) | See Note 5 to the consolidated financial statements.statements in this Form 10-K. |
| | | | | | | | | | | | | | | | | | | | |
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) | |
| (3) | In accordance with generally acceptedacceptable accounting principles in the United States (GAAP), these items are not reflected in our consolidated balance sheets.the Consolidated Balance Sheets. |
(2) | |
| (4) | Recoverable through PGA procedures. |
(3) | |
| (5) | Reservation fees are fixed payments and are recoverable through PGA procedures. |
(4) | |
| (6) | Includes accrued interest of $20.8 million as of October 31, 2014. |
| |
| (7) | See Note 412 to the consolidated financial statements.statements in this Form 10-K. |
(5) | |
| (8) | Consists primarily of maintenance fees for hardware and software applications, usage fees, local and long-distance data costs, frame relay, and cell phone and pager usage fees. |
(6) | |
| (9) | Estimated funding beyond five years is not available. See Note 9 to the consolidated financial statements.statements in this Form 10-K. |
(7) | |
| (10) | See Note 8 to the consolidated financial statements.statements in this Form 10-K. Operating lease payments do not include payment for common area maintenance, utilities or tax payments. |
(8) | |
| (11) | 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 letters of credit,
surety bonds and operating leases. The letters of credit
are discussed in Note 5 to the consolidated financial statements in this Form 10-K. The surety bonds and operating leases are discussed in Note
5 and Note 8
respectively, to the consolidated financial statements
and are reflected in
the table above.this Form 10-K.
Critical Accounting Estimates
We prepare the consolidated financial statements in conformity with accounting principles generally accepted in the United States of America. We make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the periods reported. Actual results may differ significantly from these estimates and assumptions. We base our estimates on historical experience, where applicable, and other relevant factors that we believe are reasonable under the circumstances. On an ongoing basis, we evaluate estimates and assumptions and make adjustments in subsequent periods to reflect more current information if we determine that modifications in assumptions and estimates are warranted.
Management considers an accounting estimate to be critical if it requires assumptions to be made that were uncertain at the time the estimate was made, and changes in the estimate or a different estimate that could have been used would have had a material impact on our financial condition or results of operations. We consider regulatory accounting, revenue recognition, and pension and postretirement benefits to be our critical accounting estimates. Management is responsible for the selection of these critical accounting estimates. Management has discussed these critical accounting estimates presented below with the Audit Committee of the Board of Directors.
Revenue Recognition. Utility sales and transportation revenues are based on rates approved by state regulatory commissions. Base rates charged to customers may not be changed without formal approval by the regulatory commission in that jurisdiction; however, the wholesale cost of gas component of rates may be adjusted periodically under PGA procedures. In South Carolina and Tennessee, we have WNA mechanisms that are designed to protect a portion of our residential and commercial customer revenues against warmer-than-normal weather as deviations from normal weather can affect our financial performance and liquidity. The mechanisms also serve to offset the impact of colder-than-normal weather by reducing the amounts we can charge our customers. In North Carolina, a margin decoupling mechanism provides for the recovery of our approved margin from residential and commercial customers independent of weather and consumption patterns. The margin earned monthly under the margin decoupling mechanism results in semi-annual rate adjustments to refund any over-collection or recover any under-collection. The gas cost portion of our costs is recoverable through PGA procedures and is not affected by the WNA or the margin decoupling mechanisms. Without the WNA and margin decoupling mechanisms, our operating revenues and margin would have been higher by $41.8 million in 2014 and lower by $9 million and by $60.1 million in 2013 and 2012, respectively.
New in 2014 is the IMR that was implemented in North Carolina and Tennessee to separately track and recover costs associated with capital expenditures in order to comply with pipeline safety and integrity requirements on an annual basis outside general rate cases. Under the North Carolina IMR tariff, we make annual filings each November to capture such costs closed to plant through October with revised rates effective the following February. Under the Tennessee IMR, we file to adjust rates to be effective each January 1 based on capital expenditures incurred through the previous October. Without the IMR in North Carolina, our operating revenues and margin would have been lower by $.6 million for the period February 1, 2014 through October 31, 2014. Without the IMR in Tennessee, our operating revenues and margin would have been lower by $10.1 million for the period January 1, 2014 through October 31, 2014.
Revenues are recognized monthly on the accrual basis, which includes estimated amounts for gas delivered to customers but not yet billed under the cycle-billing method from the last meter reading date to month end. Meters are read throughout the month based on an approximate 30-day usage cycle; therefore, at any point in time, volumes are delivered to customers that have not been metered and billed. The unbilled revenue estimate reflects factors requiring judgment related to estimated usage by customer class, customer mix, changes in weather during the period and the impact of the WNA or margin decoupling mechanisms, as applicable. Secondary market revenues are recognized when the physical sales are delivered based on contract or market prices.
Regulatory Accounting. Our regulated utility segment is subject to regulation by certain state and federal authorities. Our accounting policies conform to the accounting regulations required by rate regulatedrate-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 theas an adjustment to net income statementor accumulated other comprehensive income for the period in which the discontinuance of regulatory accounting treatment occurs. Such an event could have a material effect on our results of operations in the period this action was recorded.
Management continually assesses whether the regulatory assets are probable of future recovery by considering factors such as applicable regulatory environment changes, historical regulatory treatment of similar costs in our jurisdictions, recent rate orders to other regulated entities and the status of any pending or potential
deregulation legislation.legislation that would affect the regulatory environment. Based on our assessment that reflects the current political and regulatory climate at the state and federal levels, we believe that all of our regulatory assets are recoverable in current rates or future rate proceedings. However, this assessment is subject to change in the future.
Regulatory assets as of October 31,
20112014 and
20102013 totaled
$200.1$213.9 million and
$197.8$246.3 million, respectively. Regulatory liabilities as of October 31,
20112014 and
20102013 totaled
$467$604.8 million and
$439.1$541.9 million, respectively. The detail of these regulatory assets and liabilities is presented in “Rate-Regulated Basis of Accounting” in Note 1 to the consolidated financial
statements.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 commissionstatements 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 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 results in semi-annual rate adjustments to refund any over-collection or recover any under-collection. The gas cost portion of our costs is recoverable through PGA procedures and is not affected by the WNA or the margin decoupling mechanism. Without the WNA and margin decoupling mechanisms, our operating revenues in 2011 and 2010 would have been higher by $11.9 million and $14.7 million, respectively, and lower by $4.8 million 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 approximate 30-day usage cycle; therefore, at any point in time, volumes are delivered to customers that have not been metered and billed. The unbilled revenue estimate reflects factors requiring judgment related to estimated usage by customer class, customer mix, changes in weather during the period and the impact of the WNA or margin decoupling mechanism, as applicable. Secondary market revenues are recognized when the physical sales are delivered based on contract or market prices.
this Form 10-K.
Pension and Postretirement Benefits. We have a traditional defined benefit pension plan (qualified pension plan) covering eligible employees. We also provide certain other postretirement health care and life insurance benefits to eligible employees. For further information and our reported costs of providing these benefits, see Note 9 to the consolidated financial statements. statements in this Form 10-K. We recognize the funded status of our benefit plans as an asset or liability with any changes in the funded status recorded as a regulatory asset or liability as allowed by our state regulatory commissions.
The costs of providing these benefits are impacted by numerous factors, including the provisions of the plans, changing employee demographics and various actuarial calculations, assumptions and accounting mechanisms. Because of the complexity of these calculations, the long-term nature of these obligations and the importance of the assumptions used, our estimate of these costs is a critical accounting estimate.
Several statistical and other factors, which attempt to anticipate future events, are used in calculating the expenses and liabilities related to the plans. These factors include assumptions about the discount rate used in determining future benefit obligations, projected health care cost trend rates, expected long-term return on plan assets and rate of future compensation increases, within certain guidelines. In addition, we also use subjective factors such as withdrawal and mortality rates to estimate projected benefit obligations. The actuarial assumptions used may differ materially from actual results due to changing market and economic conditions, higher or
lower withdrawal rates or longer or shorter life spans of participants. These differences may result in a significant impact on the amount of pension expense or other postretirement benefit costs recorded in future periods, and we cannot predict with certainty what these factors will be in the future.
The discount rate has been separately determined for each plan by projecting the plan’s cash flows and developing a zero-coupon spot rate yield curve using non-arbitrage pricing and
Moody’s Investors Service’snon-callable bonds rated AA or
better-rated non-callable bonds.better by either Moody’s or S&P that have a yield higher than the regression mean yield curve. Based on this approach, the weighted average discount rate used in the measurement of the benefit obligation for the qualified pension plan changed from
5.47%4.55% in
20102013 to
4.67%4.13% in
2011.2014. For the nonqualified pension plans, the weighted average discount rate used in the measurement of the benefit obligation changed from
4.37%3.98% in
20102013 to
4.10%3.69% in
2011.2014. Similarly,
based on this approach, the weighted average discount rate for postretirement benefits changed from
4.85%4.44% in
20102013 to
4.36%4.03% in
2011.2014. The lower discount rates discussed above reflect the lower yields found in the AA corporate bond market where the bond price has increased. Based on our review of actual cost trend rates and projected future trends in establishing health care cost trend rates, the initial health care cost trend rate was assumed to be
7.80%7.40% in
20112014 declining gradually to 5% by 2027.
In determining our expected long-term rate of return on plan assets, we review past long-term performance, asset allocations and long-term inflation assumptions. We target our asset allocations for qualified pension plan assets and other postretirement benefit assets to be approximately
50%55% equity securities and
50%45% fixed income securities. To the extent that the actual rate of return on assets realized during the fiscal year is greater or less than the assumed rate, that year’s qualified pension plan and postretirement benefits plan costs are not affected; instead, this gain or loss reduces or increases the future costs of the plans over the average remaining service period for active employees. The expected long-term rate of return on plan assets was 8% in
2009, 20102012 and
2011.2013. The expected long-term rate of return was reduced to 7.75% for 2014. Based on a fairly constant inflation trend, our age-related assumed rate of increase in future compensation levels was
3.92%3.78% in
2009,2012, decreasing to
3.87%3.76% in
20102013, and further decreasing to
3.78%3.72% in
20112014 due to changes in the demographics of the participants.
Our market-related value of plan assets represents the fair market value of the plan’s assets as adjusted by the portion of the prior five years’ asset gains and losses that has not yet been recognized. The use of this calculation delays the impact of current market fluctuations on benefit costs for the fiscal year.
During
2011,2014, we recorded
costcosts of
$2.3$6.4 million related to our qualified pension plan and postretirement benefits plan. We estimate
20122015 expenses for these two plans to be in the range of
$5$7 to
$6$8 million representing an increase of
$3$.6 to
$4$1.6 million
over 2011.from 2014. These estimates reflect the
lower discount rates and
a 7.50% assumed rate of return on the plan
assets discussed above for each plan.assets.
The following reflects the sensitivity of pension cost to changes in certain actuarial assumptions for our qualified pension plan, assuming that the other components of the calculation are constant.
| | | | | | | | | | | | |
Actuarial Assumption | | Change in
Assumption | | | Impact on 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 | |
|
| | | | | | | | |
| | | Change in | | | Impact on 2014 | | | Impact on Projected |
| Actuarial Assumption | | Assumption | | | Benefit Cost | | | Benefit Obligation |
| | | | | | Increase (Decrease) In thousands |
| Discount rate | | (0.25)% | | $ | 594 | | $ | 7,566 |
| Rate of return on plan assets | | (0.25)% | | | 727 | | | N/A |
| Rate of increase in compensation | | 0.25% | | | 741 | | | 4,209 |
The following reflects the sensitivity of postretirement benefit cost to changes in certain actuarial assumptions, assuming that the other components of the calculation are constant.
| | | | | | | | | | | | |
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 | |
|
| | | | | | | | |
| | | | | | Impact on 2014 | | | Impact on Accumulated |
| | | Change in | | | Postretirement | | | Postretirement Benefit |
| Actuarial Assumption | | Assumption | | | Benefit Cost | | | Obligation |
| | | | | | Increase (Decrease) |
| | | | | | In thousands |
| Discount rate | | (0.25)% | | $ | — | | $ | 995 |
| Rate of return on plan assets | | (0.25)% | | | 14 | | | N/A |
| Health care cost trend rate | | 0.25% | | | 8 | | | 210 |
We utilize accounting methods consistently applied that are allowed under GAAP which reduce the volatility of reported pension costs. Differences between actuarial assumptions and actual plan results are deferred and amortized into cost when the accumulated differences exceed 10% of the greater of the projected benefit obligation or the market-related value of the plan assets. If necessary, the excess is amortized over the average remaining service period of active employees.
Gas Supply and Regulatory Proceedings
The source of our gas supply that we distribute to our customers
comes primarilyis contracted from
the Gulf Coast production region where it is purchased primarily froma diverse portfolio of major and independent producers and
marketers. As part of our long-term planmarketers and interstate and intrastate pipeline and storage operators. In November 2012, we continued to diversify our
reliance awaysupply portfolio by contracting to bring abundant and low cost natural gas supplies from the
Gulf Coast region,Marcellus supply basin to our natural gas markets in the Carolinas. We signed a long-term contract with Cabot Oil & Gas to purchase firm, price-competitive Marcellus gas supplies. We also signed a long-term firm capacity contract with Williams – Transco under its Leidy Southeast expansion project to transport the Marcellus based Cabot gas supplies to our markets. In December 2012, we
havealso signed a long-term firm capacity contract with Williams – Transco under its Virginia Southside expansion project that will also allow us to further diversify our supply portfolio with Marcellus based natural gas. These new supply arrangements are scheduled to begin in late 2015. Also, in October 2014, we contracted for
firm, long-term
market area storage servicepipeline capacity from the Marcellus and Utica shale basins in
central West Virginia
from Hardy Storage, a venture in which we have a 50% equity interest, whichunder the ACP project that is
more fully discussed in Note 12proposed to
be effective for the
consolidated financial statements.winter 2018 – 2019 season. We
have also contracted for firm, long-term transportation contract servicebelieve that
provides access to Canadian and Rocky Mountainthese new natural gas supplies
viawill provide diversification, reliability and gas cost benefits to Piedmont’s customers across the
Chicago hub, primarily to serve our Tennessee markets.Carolinas.
Natural gas demand is continuing to grow in our service area
particularly to provide natural gas delivery service to existing and future 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.10-K. For further information on our equity
ventureventures with
Cardinal to expand our firm capacity requirement in orderACP to serve
a power generation facility in Wayne County, North Carolina,our expanding markets, see Note 12 to the consolidated financial
statements.Secondarystatements in this Form 10-K.
As approved by our state regulatory commissions, secondary market transactions permit us to market gas supplies and transportation services by contract with wholesale or off-system customers. These sales contribute smaller per-unit margins to earnings; however, the
program allowsprograms allow us to act as a wholesale marketer of natural gas and transportation capacity
in orderwhen market conditions permit and when the supply and capacity are not required to
generate operating margin from sources not restricted by the capacity ofserve our retail distribution system. For further information on secondary market transactions, see Note 2 to the consolidated financial
statements.statements in this Form 10-K.
We continue to work with our regulatory commissions to earn a fair rate of return
on invested capital for our shareholders and provide safe, reliable natural gas distribution service to our customers. For further information about regulatory proceedings and other regulatory information, see Note 2 to the consolidated financial
statements.statements in this Form 10-K.
Equity Method Investments
For information about our equity method investments, see Note 12 to the consolidated financial
statements.statements in this Form 10-K.
We have developed an environmental self-assessment plan to
assessexamine our facilities and program areas for compliance with federal, state and local environmental regulations and to correct any deficiencies identified. As a member of the North Carolina MGP Initiative Group, we, along with other responsible parties, work directly with the North Carolina Department of Environment and Natural Resources to set priorities for manufactured gas plant (MGP) site remediation. For additional information on environmental matters, see Note 8 to the consolidated financial
statements.statements in this Form 10-K.
For further information regarding recently issued accounting guidance, see Note 1 to the consolidated financial
statements.International Financial Reporting Standards (IFRS)
In 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,statements 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 remaining as the U.S. accounting standard setter.
In November 2011, the SEC released two more Staff Papers as part of their work plan. The first paper was the SEC 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 accounting policy disclosures; and (2) Diversity in the application of IFRS made comparability challenging with the diversity 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 IFRS with an inventorying 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 account for transactions across industries with limited specific guidance and stated exceptions and that fundamental differences exist between conceptual frameworks, including the level of authority and the definition and recognition of assets and liabilities. The Staff Paper provided a broad comparison of the requirements of both accounting standards, highlighting notable differences, but did not provide an analysis of the impact of those differences on the quality of IFRS.
Although the SEC was expected to vote by the end 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 re-assessed when the SEC makes its final determination on the use of IFRS.
Form 10-K.
Item 7A. Quantitative and Qualitative Disclosures about Market Risk
We are exposed to various forms of market risk, including the credit risk of our suppliers and our customers, interest rate risk, commodity price risk and weather risk. We seek to identify, assess, monitor and manage all of these risks in accordance with defined policies and procedures under
anthe direction of the Treasurer and Chief Risk Officer and our Enterprise Risk Management
(ERM) program,
and with the direction of theincluding our Energy Price Risk Management Committee. Risk management is guided by senior management with Board of
Directors’Directors oversight, and senior management takes an active role in the development of policies and procedures.
During our current fiscal year, the Board of Directors delegated oversight of our ERM program to the Finance and Enterprise Risk (FER) Committee. All other committees of our Board of Directors have enhanced monitoring of those risks relating to areas where they have oversight responsibility. The Board of Directors approved risk tolerances for major areas of risk exposure and will receive quarterly reports from the FER Committee and annual reports from management.
We hold all financial instruments discussed below for purposes other than trading.
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. Incontract, or in situations where counterparties do not have
investment gradeinvestment-grade or functionally equivalent credit ratings, our policy requires credit enhancements that include letters of credit or parental guaranties. In either circumstance, the policy specifies limits on the contract amount and duration based on the counterparty’s credit rating and/or credit support. In order to minimize our exposure, we continually re-evaluate third-party creditworthiness and market conditions and modify our requirements accordingly.
We also enter into contracts with third parties to manage some of our supply and capacity assets for the purpose of maximizing their value. These arrangements include a counterparty credit evaluation according to our policy described above prior to contract execution and typically have durations of one year or less. In the event that a party is unable to perform under these arrangements, we have exposure to satisfy our underlying supply or demand contractual obligations that were incurred while under the management of this third party.
We have mitigated our exposure to the risk of non-payment of utility bills by our customers. In
North Carolina and South Carolina,all three states, 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 our high risk customers that do not satisfy our predetermined credit standards until a satisfactory payment history has been established. Significant increases in the price of natural gas
or colder-than-normal weather can
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,
2011,2014, all of our long-term debt was issued at fixed rates, and therefore not subject to interest rate risk.
We have short-term borrowing arrangements to provide working capital and general corporate liquidity. The level of borrowings under such arrangements varies from period to period depending upon many factors, including the cost of wholesale natural gas and our gas supply hedging programs, our investments in capital projects, the level and expense of our storage inventory and the collection of receivables. Future short-term interest expense and payments will be impacted by both short-term interest rates and borrowing levels.
As of October 31,
2011,2014, we had
$331$355 million of short-term debt outstanding
under our syndicated revolving credit facilityas commercial paper at an interest rate of
1.15%.17%. The carrying amount of our short-term debt approximates fair value. A change of 100 basis points in the underlying average interest rate for our short-term debt would have caused a change in interest expense of approximately
$2$4.4 million during
2011.2014.
As of October 31,
2011,2014, information about our long-term debt is presented below.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | 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 | % | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | Fair Value as |
| | | Expected Maturity Date | | | | of October 31, |
| In millions | | 2015 | | 2016 | | 2017 | | 2018 | | 2019 | | Thereafter | | Total | | 2014 |
| Fixed Rate Long-term Debt | | $ | — |
| | $ | 40 |
| | $ | 35 |
| | $ | — |
| | $ | — |
| | $ | 1,350 |
| | $ | 1,425 |
| | $ | 1,617.5 |
|
| Average Interest Rate | | — | % | | 2.92 | % | | 8.51 | % | | — | % | | — | % | | 4.88 | % | | 4.92 | % | | |
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.
As such,However, we face regulatory recovery risk associated with these costs. With regulatory commission approval, we revise rates periodically without formal rate proceedings to reflect changes in the wholesale cost of gas, including costs associated with our hedging programs under the recovery mechanism allowed by each of our state regulators. Under our PGA procedures, differences between gas costs incurred and gas costs billed to customers are deferred and any under-recoveries are included in “Amounts due from customers”
in “Regulatory Assets” or any over-recoveries are included in “Amounts due to customers” in
our“Regulatory Liabilities” as presented in Note 1 to the consolidated
balance sheetsfinancial statements in this Form 10-K, for collection or refund over subsequent periods. When we have “Amounts due from customers,” we earn a carrying charge that mitigates any incremental short-term borrowing costs. When we have “Amounts due to customers,” we incur a carrying charge that we must refund to our customers.
We manage our gas supply costs through a portfolio of short- and long-term procurement and storage contracts with various suppliers. We actively manage our supply portfolio to balance sales and delivery obligations. We inject natural gas into storage during the summer months and withdraw the gas during the winter heating season. In the normal course of business, we utilize New York Mercantile Exchange (NYMEX) exchange traded instruments
and have used over-the-counter instruments of various durations
for the forward purchase ofto hedge price volatility on a portion of our natural gas requirements, subject to regulatory review and approval.
We purchase firm gas from a diverse portfolio of suppliers at liquid exchange points. For term suppliers whose performance is greater than one month, we evaluate and monitor their creditworthiness and maintain the ability to require additional financial assurances, including deposits, letters of credit or surety bonds, in case a supplier defaults. Since most of our commodity supply contracts are at market index prices tied to liquid exchange points and with our significant storage flexibility, we believe that it is unlikely that a supplier default would have a material effect on our financial position, results of operations or cash flows.
Our gas purchasing practices are subject to regulatory reviews in all three states in which we operate. We are responsible for following competitive and reasonable practices in purchasing gas for our customers. Costs have never been disallowed on the basis of prudence in any jurisdiction.
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, thisThis risk is mitigated by
a WNA
mechanisms that aremechanism designed to offset the impact of colder-than-normal or warmer-than-normal weather
in our residential and commercial markets during the months of November through March in
our residentialSouth Carolina and
commercial markets.October through April in Tennessee. The WNA formulas do not ensure full recovery of approved margin during periods when customer consumption patterns vary from those used to establish the WNA factors. In North Carolina, we manage our weather risk through a year
aroundround margin decoupling mechanism that allows us to recover our approved margin from residential and commercial customers independent of volumes sold.
We are exposed to weather risks in our industrial markets to the extent our margin is collected through volumetric rates in all of our jurisdictions.
Additional information concerning market risk is set forth in “Financial Condition and Liquidity” in Item 7 of this Form 10-K in Management’s Discussion and Analysis of Financial Condition and Results of Operations.
Item 8. Financial Statements and Supplementary Data
Consolidated financial statements required by this item are listed in Item 15 (a) 1 in Part IV of this Form 10-K.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
Piedmont Natural Gas Company, Inc.
Charlotte, North Carolina
We have audited the accompanying consolidated balance sheets of Piedmont Natural Gas Company, Inc. and subsidiaries (the “Company”) as of October 31,
20112014 and
2010,2013, and the related consolidated statements of
comprehensive income, stockholders’ equity, and cash flows for each of the three years in the period ended October 31,
2011.2014. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on
thesethe 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,
20112014 and
2010,2013, and the results of their operations and their cash flows for each of the three years in the period ended October 31,
2011,2014, in conformity with accounting principles generally accepted in the United States of America.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of October 31, 2011,2014, based on the criteria established inInternal Control—Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated December 23, 20112014 expressed an unqualified opinion on the Company’s internal control over financial reporting.
/s/ Deloitte & Touche LLP
Charlotte, North Carolina
Consolidated Balance Sheets October 31,
20112014 and
20102013
ASSETS
| | | | | | | | |
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 | |
| | | | | | | | |
|
| | | | | | | | |
| In thousands | | 2014 | | 2013 |
| Utility Plant: | | | | |
| Utility plant in service | | $ | 5,011,497 |
| | $ | 4,421,937 |
|
| Less accumulated depreciation | | 1,166,922 |
| | 1,088,331 |
|
| Utility plant in service, net | | 3,844,575 |
| | 3,333,606 |
|
| Construction work in progress | | 141,693 |
| | 297,717 |
|
| Plant held for future use | | 3,155 |
| | 3,155 |
|
| Total utility plant, net | | 3,989,423 |
| | 3,634,478 |
|
| Other Physical Property, at cost (net of accumulated depreciation of $904 in 2014 and $876 in 2013) | | 355 |
| | 382 |
|
| Current Assets: | | | | |
| Cash and cash equivalents | | 9,643 |
| | 8,063 |
|
| Trade accounts receivable (less allowance for doubtful accounts of $2,152 in 2014 and $1,604 in 2013) | | 65,260 |
| | 79,210 |
|
| Income taxes receivable | | 36,100 |
| | 31,065 |
|
| Other receivables | | 3,361 |
| | 1,988 |
|
| Unbilled utility revenues | | 21,093 |
| | 24,967 |
|
| Inventories: | | | | |
| Gas in storage | | 84,081 |
| | 73,929 |
|
| Materials, supplies and merchandise | | 1,652 |
| | 1,725 |
|
| Gas purchase derivative assets, at fair value | | 4,898 |
| | 1,834 |
|
| Regulatory assets | | 29,088 |
| | 77,204 |
|
| Prepayments | | 39,030 |
| | 35,038 |
|
| Deferred income taxes | | 53,418 |
| | 12,695 |
|
| Other current assets | | 326 |
| | 338 |
|
| Total current assets | | 347,950 |
| | 348,056 |
|
| Noncurrent Assets: | | | | |
| Equity method investments in non-utility activities | | 170,171 |
| | 128,469 |
|
| Goodwill | | 48,852 |
| | 48,852 |
|
| Regulatory assets | | 184,779 |
| | 169,102 |
|
| Marketable securities, at fair value | | 3,727 |
| | 2,995 |
|
| Overfunded postretirement asset | | 33,757 |
| | 28,258 |
|
| Other noncurrent assets | | 5,239 |
| | 8,017 |
|
| Total noncurrent assets | | 446,525 |
| | 385,693 |
|
| Total | | $ | 4,784,253 |
| | $ | 4,368,609 |
|
See notes to consolidated financial statements.
Consolidated Balance Sheets
October 31,
20112014 and
20102013
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 | |
| | | | | | | | |
|
| | | | | | | | |
| In thousands | | 2014 | | 2013 |
| Capitalization: | | | | |
| Stockholders’ equity: | | | | |
| Cumulative preferred stock - no par value - 175 shares authorized | | $ | — |
| | $ | — |
|
| Common stock – no par value – shares authorized: 200,000; shares outstanding: 78,531 in 2014 and 76,099 in 2013 | | 636,835 |
| | 561,644 |
|
| Retained earnings | | 672,004 |
| | 627,236 |
|
| Accumulated other comprehensive loss | | (237 | ) | | (284 | ) |
| Total stockholders’ equity | | 1,308,602 |
| | 1,188,596 |
|
| Long-term debt | | 1,424,430 |
| | 1,174,857 |
|
| Total capitalization | | 2,733,032 |
| | 2,363,453 |
|
| Current Liabilities: | | | | |
| Current maturities of long-term debt | | — |
| | 100,000 |
|
| Short-term debt | | 355,000 |
| | 400,000 |
|
| Trade accounts payable | | 85,299 |
| | 96,281 |
|
| Other accounts payable | | 54,349 |
| | 43,855 |
|
| Accrued interest | | 27,982 |
| | 28,205 |
|
| Customers’ deposits | | 19,994 |
| | 19,831 |
|
| General taxes accrued | | 23,828 |
| | 21,454 |
|
| Regulatory liabilities | | 46,231 |
| | — |
|
| Other current liabilities | | 9,303 |
| | 7,024 |
|
| Total current liabilities | | 621,986 |
| | 716,650 |
|
| Noncurrent Liabilities: | | | | |
| Deferred income taxes | | 809,467 |
| | 681,369 |
|
| Unamortized federal investment tax credits | | 1,193 |
| | 1,402 |
|
| Accumulated provision for postretirement benefits | | 15,471 |
| | 12,042 |
|
| Regulatory liabilities | | 558,598 |
| | 541,897 |
|
| Conditional cost of removal obligations | | 14,647 |
| | 27,016 |
|
| Other noncurrent liabilities | | 29,859 |
| | 24,780 |
|
| Total noncurrent liabilities | | 1,429,235 |
| | 1,288,506 |
|
| Commitments and Contingencies (Note 8) | |
| |
|
| Total | | $ | 4,784,253 |
| | $ | 4,368,609 |
|
See notes to consolidated financial statements.
Page Intentionally Blank
Consolidated Statements of
Comprehensive Income
For the Years Ended October 31,
2011, 20102014, 2013 and
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 | |
2012
|
| | | | | | | | | | | | |
| In thousands, except per share amounts | | 2014 | | 2013 | | 2012 |
| Operating Revenues | | $ | 1,469,988 |
| | $ | 1,278,229 |
| | $ | 1,122,780 |
|
| Cost of Gas | | 779,780 |
| | 656,739 |
| | 547,334 |
|
| Margin | | 690,208 |
| | 621,490 |
| | 575,446 |
|
| Operating Expenses: | | | | | | |
| Operations and maintenance | | 270,877 |
| | 253,120 |
| | 242,599 |
|
| Depreciation | | 118,996 |
| | 112,207 |
| | 103,192 |
|
| General taxes | | 37,294 |
| | 34,635 |
| | 34,831 |
|
| Utility income taxes | | 83,176 |
| | 77,334 |
| | 69,101 |
|
| Total operating expenses | | 510,343 |
| | 477,296 |
| | 449,723 |
|
| Operating Income | | 179,865 |
| | 144,194 |
| | 125,723 |
|
| Other Income (Expense): | | | | | | |
| Income from equity method investments | | 32,753 |
| | 26,056 |
| | 23,904 |
|
| Non-operating income | | 1,842 |
| | 2,839 |
| | 1,288 |
|
| Non-operating expense | | (4,331 | ) | | (5,122 | ) | | (1,855 | ) |
| Income taxes | | (11,642 | ) | | (8,612 | ) | | (9,116 | ) |
| Total other income (expense) | | 18,622 |
| | 15,161 |
| | 14,221 |
|
| Utility Interest Charges: | | | | | | |
| Interest on long-term debt | | 61,562 |
| | 54,158 |
| | 41,412 |
|
| Allowance for borrowed funds used during construction | | (16,427 | ) | | (30,975 | ) | | (25,211 | ) |
| Other | | 9,551 |
| | 1,755 |
| | 3,896 |
|
| Total utility interest charges | | 54,686 |
| | 24,938 |
| | 20,097 |
|
| Net Income | | 143,801 |
| | 134,417 |
| | 119,847 |
|
| Other Comprehensive Income (Loss), net of tax: | | | | | | |
| Unrealized gain (loss) from hedging activities of equity method investments, net of tax of $225, ($69) and ($530) for the years ended October 31, 2014, 2013 and 2012, respectively | | 355 |
| | (109 | ) | | (826 | ) |
| Reclassification adjustment of realized gain (loss) from hedging activities of equity method investments included in net income, net of tax of ($177), $85 and $621 for the years ended October 31, 2014, 2013 and 2012, respectively | | (284 | ) | | 130 |
| | 973 |
|
| Net current period benefit activities of equity method investments, net of tax of ($16) for the year ended October 31, 2014 | | (24 | ) | | | | |
| Total other comprehensive income | | 47 |
| | 21 |
|
| 147 |
|
| Comprehensive Income | | $ | 143,848 |
| | $ | 134,438 |
|
| $ | 119,994 |
|
| | | | | | | |
| Average Shares of Common Stock: | | | | | | |
| Basic | | 77,883 |
| | 74,884 |
| | 71,977 |
|
| Diluted | | 78,193 |
| | 75,333 |
| | 72,278 |
|
| | | | | | | |
| Earnings Per Share of Common Stock: | | | | | | |
| Basic | | $ | 1.85 |
| | $ | 1.80 |
| | $ | 1.67 |
|
| Diluted | | $ | 1.84 |
| | $ | 1.78 |
| | $ | 1.66 |
|
See notes to consolidated financial statements.
Consolidated Statements of Cash Flows
For the Years Ended October 31,
2011, 20102014, 2013 and
2009 | | | | | | | | | | | | |
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 | ) |
| | | | | | | | | | | | |
2012
|
| | | | | | | | | | | | |
| In thousands | | 2014 | | 2013 | | 2012 |
| Cash Flows from Operating Activities: | | | | | | |
| Net income | | $ | 143,801 |
| | $ | 134,417 |
| | $ | 119,847 |
|
| Adjustments to reconcile net income to net cash provided by | | | | | | |
| operating activities: | | | | | | |
| Depreciation and amortization | | 129,343 |
| | 120,797 |
| | 109,230 |
|
| Allowance for doubtful accounts | | 548 |
| | 25 |
| | 232 |
|
| Impairment loss on investment | | 2,000 |
| | — |
| | — |
|
| Net gain on sale of property | | (817 | ) | | (349 | ) | | — |
|
| Income from equity method investments | | (32,753 | ) | | (26,056 | ) | | (23,904 | ) |
| Distributions of earnings from equity method investments | | 24,843 |
| | 22,139 |
| | 19,590 |
|
| Deferred income taxes, net | | 87,136 |
| | 57,637 |
| | 99,159 |
|
| Changes in assets and liabilities: | | | | | | |
| Gas purchase derivatives, at fair value | | (3,064 | ) | | 1,319 |
| | (381 | ) |
| Receivables | | 16,196 |
| | (23,327 | ) | | 5,403 |
|
| Inventories | | (10,079 | ) | | (2,059 | ) | | 18,897 |
|
| Settlement of legal asset retirement obligations | | (3,575 | ) | | (2,389 | ) | | (2,038 | ) |
| Regulatory assets | | 20,297 |
| | 43,338 |
| | (93,268 | ) |
| Other assets | | (2,829 | ) | | 4,629 |
| | (2,314 | ) |
| Accounts payable | | 18 |
| | 2,381 |
| | 4,283 |
|
| Provision for postretirement benefits, net | | (2,070 | ) | | (53,515 | ) | | 45,507 |
|
| Regulatory liabilities | | 49,468 |
| | 23,429 |
| | (2,990 | ) |
| Other liabilities | | 12,149 |
| | 10,831 |
| | 7,262 |
|
| Net cash provided by operating activities | | 430,612 |
| | 313,247 |
| | 304,515 |
|
| | | | | | | |
| Cash Flows from Investing Activities: | | | | | | |
| Utility capital expenditures | | (460,444 | ) | | (599,999 | ) | | (529,576 | ) |
| Allowance for borrowed funds used during construction | | (16,427 | ) | | (30,975 | ) | | (25,211 | ) |
| Contributions to equity method investments | | (37,642 | ) | | (41,348 | ) | | (3,566 | ) |
| Distributions of capital from equity method investments | | 3,929 |
| | 4,700 |
| | 5,372 |
|
| Proceeds from sale of property | | 1,883 |
| | 1,951 |
| | 1,250 |
|
| Investments in marketable securities | | (454 | ) | | (414 | ) | | (606 | ) |
| Other | | 4,708 |
| | 2,609 |
| | 3,044 |
|
| Net cash used in investing activities | | (504,447 | ) | | (663,476 | ) | | (549,293 | ) |
Consolidated Statements of Cash Flows
For the Years Ended October 31,
2011, 20102014, 2013 and
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 | | | | — | |
2012
|
| | | | | | | | | | | | |
| In thousands | | 2014 | | 2013 | | 2012 |
| Cash Flows from Financing Activities: | | | | | | |
| Borrowings under credit facility | | — |
| | 10,000 |
| | 350,000 |
|
| Repayments under credit facility | | — |
| | (10,000 | ) | | (681,000 | ) |
| Net (repayments) borrowings - commercial paper | | (45,000 | ) | | 35,000 |
| | 365,000 |
|
| Proceeds from issuance of long-term debt, net of discount | | 249,565 |
| | 299,856 |
| | 300,000 |
|
| Repayment of long-term debt | | (100,000 | ) | | — |
| | — |
|
| Expenses related to issuance of debt | | (2,871 | ) | | (3,250 | ) | | (3,908 | ) |
| Proceeds from issuance of common stock, net of expenses | | 47,290 |
| | 92,271 |
| | — |
|
| Issuance of common stock through dividend reinvestment and | | | | | | |
| employee stock plans | | 25,556 |
| | 24,610 |
| | 22,123 |
|
| Repurchases of common stock | | — |
| | — |
| | (26,528 | ) |
| Dividends paid | | (99,151 | ) | | (92,146 | ) | | (85,693 | ) |
| Other | | 26 |
| | (8 | ) | | (34 | ) |
| Net cash provided by financing activities | | 75,415 |
| | 356,333 |
| | 239,960 |
|
| Net Increase (Decrease) in Cash and Cash Equivalents | | 1,580 |
| | 6,104 |
| | (4,818 | ) |
| Cash and Cash Equivalents at Beginning of Year | | 8,063 |
| | 1,959 |
| | 6,777 |
|
| Cash and Cash Equivalents at End of Year | | $ | 9,643 |
| | $ | 8,063 |
| | $ | 1,959 |
|
| | | | | | | |
| Cash Paid During the Year for: | | | | | | |
| Interest | | $ | 64,276 |
| | $ | 50,275 |
| | $ | 44,571 |
|
| | | | | | | |
| Income Taxes: | | | | | | |
| Income taxes paid | | $ | 10,840 |
| | $ | 5,760 |
| | $ | 4,770 |
|
| Income taxes refunded | | 30 |
| | 169 |
| | 8,437 |
|
| Income taxes, net | | $ | 10,810 |
| | $ | 5,591 |
| | $ | (3,667 | ) |
| | | | | | | |
| Noncash Investing and Financing Activities: | | | | | | |
| Accrued construction expenditures | | $ | 38,869 |
| | $ | 39,389 |
| | $ | 43,643 |
|
See notes to consolidated financial statements.
Consolidated Statements of Stockholders’ Equity
For the Years Ended October 31,
2011, 20102014, 2013 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 | |
| | | | | | | | | | | | | | | | | | | | | | |
2012
|
| | | | | | | | | | | | | | | | |
| In thousands, except per share amounts | | Common Stock | | Retained Earnings | | Accumulated Other Comprehensive Income (Loss) | | Total |
| Balance, October 31, 2011 | | $ | 446,791 |
| | $ | 550,584 |
| | $ | (452 | ) | | $ | 996,923 |
|
| | | | | | | | | |
| Comprehensive Income: | | | | | | | | |
| Net income | | | | 119,847 |
| | | | 119,847 |
|
| Other comprehensive income | | | | | | 147 |
| | 147 |
|
| Total comprehensive income | | | | | | | | 119,994 |
|
| Common Stock Issued | | 22,198 |
| | | | | | 22,198 |
|
| Common Stock Repurchased | | (26,528 | ) | | | | | | (26,528 | ) |
| Tax Benefit from Dividends Paid on ESOP Shares | | | | 110 |
| | | | 110 |
|
| Dividends Declared ($1.19 per share) | | | | (85,693 | ) | | | | (85,693 | ) |
| Balance, October 31, 2012 | | 442,461 |
| | 584,848 |
| | (305 | ) | | 1,027,004 |
|
| | | | | | | | | |
| Comprehensive Income: | | | | | | | | |
| Net income | | | | 134,417 |
| | | | 134,417 |
|
| Other comprehensive income | | | |
| | 21 |
| | 21 |
|
| Total comprehensive income | | | | | | | | 134,438 |
|
| Common Stock Issued | | 119,552 |
| | | | | | 119,552 |
|
| Expenses from Issuance of Common Stock | | (369 | ) | | | | | | (369 | ) |
| Tax Benefit from Dividends Paid on ESOP Shares | | | | 117 |
| | | | 117 |
|
| Dividends Declared ($1.23 per share) | | | | (92,146 | ) | | | | (92,146 | ) |
| Balance, October 31, 2013 | | 561,644 |
| | 627,236 |
| | (284 | ) | | 1,188,596 |
|
| | | | | | | | | |
| Comprehensive Income: | | | | | | | | |
| Net income | | | | 143,801 |
| | | | 143,801 |
|
| Other comprehensive income | | | | | | 47 |
| | 47 |
|
| Total comprehensive income | | | | | | | | 143,848 |
|
| Common Stock Issued | | 75,203 |
| | | | | | 75,203 |
|
| Expenses from Issuance of Common Stock | | (12 | ) | | | | | | (12 | ) |
| Tax Benefit from Dividends Paid on ESOP Shares | | | | 118 |
| | | | 118 |
|
| Dividends Declared ($1.27 per share) | | | | (99,151 | ) | | | | (99,151 | ) |
| Balance, October 31, 2014 | | $ | 636,835 |
| | $ | 672,004 |
| | $ | (237 | ) | | $ | 1,308,602 |
|
The components of accumulated other comprehensive income (loss)
(OCI)(OCIL) as of October 31,
20112014 and
20102013 are as follows.
| | | | | | | | |
In thousands | | 2011 | | | 2010 | |
Hedging activities of equity method investments | | $ | (452 | ) | | $ | (530 | ) |
|
| | | | | | | | |
| In thousands | | 2014 | | 2013 |
| Hedging activities of equity method investments | | $ | (213 | ) | | $ | (284 | ) |
| Benefit activities of equity method investments | | (24 | ) | | |
See notes to consolidated financial statements.
Notes to Consolidated Financial Statements
1. Summary of Significant Accounting Policies
Nature of Operations and Basis of Consolidation
Piedmont
Natural Gas Company, Inc. is an energy services company primarily engaged in the distribution of natural gas to residential, commercial, industrial and power generation customers in portions of North Carolina, South Carolina and Tennessee. We are invested in joint venture, energy-related businesses, including unregulated retail natural gas marketing,
and regulated interstate natural gas
transportation and storage and
regulated intrastate natural gas transportation. Our utility operations are regulated by three state regulatory commissions.
Unless the context requires otherwise, references to “we,” “us,” “our,” “the Company” or “Piedmont” means consolidated Piedmont Natural Gas Company, Inc. and its subsidiaries. For further information on regulatory matters, see Note 2 to the consolidated financial statements.
The consolidated financial statements reflect the accounts of Piedmont and its
wholly ownedwholly-owned subsidiaries whose financial statements are prepared for the same reporting period as Piedmont using consistent accounting policies. Investments in non-utility activities, or joint ventures, are accounted for under the equity method as we do not have controlling voting interests or otherwise exercise control over the management of such companies. Our ownership interest in each entity is recorded in “Equity method investments in non-utility activities” in
“Noncurrent Assets” in the
consolidated balance sheetsConsolidated Balance Sheets at cost plus post-acquisition contributions and earnings based on our share in each of the joint ventures less any distributions received from the joint venture, and if applicable, less any impairment in value of the investment. Earnings or losses from equity method investments are recorded in “Income from equity method investments” in
“Other Income (Expense)” in the
consolidated statementsConsolidated Statements of
income. For further information on equity method investments, see Note 12 to the consolidated financial statements.Comprehensive Income. Revenues and expenses of all other non-utility activities are included in “Non-operating income” in
“Other Income (Expense)” in the
consolidated statementsConsolidated Statements of
income.Comprehensive Income. Inter-company transactions have been eliminated in consolidation where appropriate; however, we have not eliminated inter-company profit on sales to affiliates and costs from affiliates in accordance with accounting regulations prescribed under rate-based regulation.
For further information on equity method investments and related party transactions, see Note 12 to the consolidated financial statements.
We monitor significant events occurring after the balance sheet date and prior to the issuance of the financial statements to determine the impacts, if any, of events on the financial statements to be issued. All subsequent events of which we are aware
have beenwere 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.
The consolidated financial statements of Piedmont have been prepared in
accordanceconformity with generally accepted accounting principles
(GAAP) in the United States of America
(GAAP) and under the rules of the Securities and Exchange Commission (SEC). In accordance with GAAP, we make certain estimates and assumptions regarding reported amounts of assets,
liabilities, revenues and
liabilities, disclosureexpenses and the related disclosures, using historical experience and other assumptions that we believe are reasonable at the time. Our estimates may involve complex situations requiring a high degree of
contingentjudgment in the application and interpretation of existing literature or in the development of estimates that impact our financial statements. These estimates and assumptions affect the reported amounts of assets and liabilities as of the date of the consolidated financial statements and
the reported amounts of revenues and expenses during the reporting period. Actual results could differ from
estimates.these estimates and assumptions, which are evaluated on a continual basis.
Our segments are based on the components of the
companyCompany for which we produce separate financial information internally that
are evaluatedis used regularly by the chief operating decision maker in deciding how to allocate resources and in assessing performance. Our chief operating decision maker is the executive management team comprised of senior level management. Our segments are identified based on products and services, regulatory environments and our current corporate organization and business
decision makingdecision-making activities. We evaluate the performance of the regulated utility
segment based on margin, operations and maintenance
(O&M) expenses and operating income. We evaluate the performance of the
regulated non-utility activities segment and the unregulated non-utility activities segment based on earnings from
and our cash flows in the ventures.
We
Beginning with the fourth quarter of 2014, we have twothree reportable business segments, regulated utility, regulated non-utility activities and unregulated non-utility activities. The regulated utility segment is the gas distribution business, includingwhere
we include the operations of merchandising and its related service work and home
warranty programs,service agreements, with activities conducted by the
parent company.utility. Operations of our
regulated non-utility activities segment are comprised of our equity method investments in joint
ventures.ventures with regulated activities that are held by our wholly-owned subsidiaries. Operations of our unregulated non-utility activities segment are comprised primarily of our equity method investment in a joint venture with unregulated activities that is held by a wholly-owned subsidiary; activities of our other minor subsidiaries are also included. See Note 14
to the consolidated financial statements for further discussion of segments.
Rate-Regulated Basis of Accounting
Our utility operations are subject to regulation with respect to rates, service area, accounting and various other matters by the regulatory commissions in the states in which we operate. The accounting regulations provide that rate-regulated public utilities account for and report assets and liabilities consistent with the economic effect of the manner in which independent third-party regulators establish rates. In applying these regulations, we capitalize certain costs and benefits as regulatory assets and liabilities, respectively, in order to provide for recovery from or refund to utility customers in future periods.
Generally, regulatory assets are amortized to expense and regulatory liabilities are amortized to income over the period authorized by our regulators.
Our regulatory assets are recoverable through either base rates or rate riders specifically authorized by a state regulatory commission. Base rates are designed to provide both a recovery of cost and a return on investment during the period the rates are in effect. As such, all of our regulatory assets are subject to review by the respective state regulatory
commissioncommissions during any future rate proceedings. In the event that accounting for the effects of regulation were no longer applicable, we would recognize a write-off of the regulatory assets and regulatory liabilities that would result in an adjustment to net
income.income or accumulated other comprehensive income (OCI). Our utility operations continue to recover their costs through cost-based rates established by the state regulatory commissions. As a result, we believe that the accounting prescribed under rate-based regulation remains appropriate. It is our opinion that all regulatory assets are recoverable in current rates or in future rate proceedings.
Regulatory assets and liabilities in the
consolidated balance sheetsConsolidated Balance Sheets as of October 31,
20112014 and
20102013 are
presented below. | | | | | | | | |
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 noncurrent assets” in “Noncurrent Assets” and regulatory liabilities are included in “Other noncurrent liabilities” in “Noncurrent Liabilities” in the consolidated balance sheets. |
as follows.
|
| | | | | | | | |
| In thousands | | 2014 | | 2013 |
| Regulatory Assets: | | | | |
| Current: | | | | |
| Unamortized debt expense | | $ | 1,490 |
| | $ | 1,274 |
|
| Amounts due from customers | | 16,108 |
| | 66,321 |
|
| Environmental costs | | 1,568 |
| | 1,480 |
|
| Deferred operations and maintenance expenses | | 916 |
| | 739 |
|
| Deferred pipeline integrity expenses | | 3,470 |
| | 3,149 |
|
| Deferred pension and other retirement benefits costs | | 2,769 |
| | 2,768 |
|
| Robeson liquefied natural gas (LNG) development costs | | 917 |
| | 382 |
|
| Other | | 1,850 |
| | 1,091 |
|
| Total current | | 29,088 |
| | 77,204 |
|
| | | | | |
| Noncurrent: | | | | |
| Unamortized debt expense | | 15,402 |
| | 14,149 |
|
| Environmental costs | | 6,470 |
| | 7,936 |
|
| Deferred operations and maintenance expenses | | 4,721 |
| | 5,637 |
|
| Deferred pipeline integrity expenses | | 24,694 |
| | 16,300 |
|
| Deferred pension and other retirement benefits costs | | 18,799 |
| | 17,968 |
|
| Amounts not yet recognized as a component of pension and other retirement benefit costs | | 94,265 |
| | 80,604 |
|
| Regulatory cost of removal asset | | 18,275 |
| | 22,974 |
|
| Robeson LNG development costs | | 509 |
| | 1,426 |
|
| Other | | 1,644 |
| | 2,108 |
|
| Total noncurrent | | 184,779 |
| | 169,102 |
|
| Total | | $ | 213,867 |
| | $ | 246,306 |
|
|
| | | | | | | | |
| Regulatory Liabilities: | | | | |
| Current: | | | | |
| Amounts due to customers | | $ | 46,231 |
| | $ | — |
|
| | | | | |
| Noncurrent: | | | | |
| Regulatory cost of removal obligations | | 506,574 |
| | 493,111 |
|
| Deferred income taxes | | 51,930 |
| | 48,647 |
|
| Amounts not yet recognized as a component of pension and other retirement costs | | 94 |
| | 139 |
|
| Total noncurrent | | 558,598 |
| | 541,897 |
|
| Total | | $ | 604,829 |
| | $ | 541,897 |
|
As of October 31,
2011,2014, we
had regulatory assets totaling $.5 million on which we do not earn a return during the recovery period. The original amortization period for these assets is 15 years and, accordingly, $.5 million will be fully amortized by 2018. We have
$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 $81.1 million of regulatory postretirement assets, $19.3$18.3 million of asset retirement obligations (AROs) and
$9.6$98.1 million of
estimated environmental costsother regulatory assets on which we do not earn a return. Included in deferred pension and other retirement costs are amounts related to pension funding for our Tennessee jurisdiction. The recovery of these amounts is authorized by the Tennessee Regulatory Authority (TRA) on a deferred cash basis.
Utility Plant and Depreciation
Utility plant is stated at original cost, including direct labor and materials, contractor costs, allocable overhead charges, such as engineering, supervision, corporate office salaries and expenses,
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
costcosts of homogeneous assets are aggregated and depreciated by applying a rate based on the average expected useful life of the assets. Major expenditures that last longer than a year and improve or lengthen the expected useful life of the overall property from original expectations that are recoverable in regulatory rate base are capitalized while expenditures not meeting these criteria are expensed as incurred. The costs of property retired or otherwise disposed of are removed from utility plant and charged to accumulated depreciation for recovery
or refund through
future rates. On certain assets, like land, that are nondepreciable, we record a gain or loss upon the disposal of the property that is recorded in
Other“Non-operating income” in “Other Income (Expense)
” in the
consolidated statementsConsolidated Statements of
income.Comprehensive Income.
The classification of total utility plant, net, for the years ended October 31, 2014 and 2013 is presented below.
|
| | | | | | | | |
| In thousands | | 2014 | | 2013 |
| Intangible plant | | $ | 3,374 |
| | $ | 3,374 |
|
| Other storage plant | | 180,058 |
| | 171,349 |
|
| Transmission plant | | 1,787,990 |
| | 1,403,829 |
|
| Distribution plant | | 2,623,560 |
| | 2,505,160 |
|
| General plant | | 421,763 |
| | 335,847 |
|
| Asset retirement cost | | 11 |
| | 7,565 |
|
| Contributions in aid of construction | | (5,259 | ) | | (5,187 | ) |
| Total utility plant in service | | 5,011,497 |
| | 4,421,937 |
|
| Less accumulated depreciation | | (1,166,922 | ) | | (1,088,331 | ) |
| Total utility plant in service, net | | 3,844,575 |
| | 3,333,606 |
|
| Construction work in progress | | 141,693 |
| | 297,717 |
|
| Plant held for future use | | 3,155 |
| | 3,155 |
|
| Total utility plant, net | | $ | 3,989,423 |
| | $ | 3,634,478 |
|
Contributions in aid of construction represent nonrefundable donations or contributions received from third-parties for partial or full reimbursement for construction expenditures for utility plant in service.
AFUDC represents the estimated costs of funds from both debt and equity sources used to finance the construction of major projects and is capitalized for ratemaking purposes when the completed projects are placed in service. The portion of AFUDC attributable to borrowed funds is shown as a reduction of “Utility Interest Charges” in the
consolidated statementsConsolidated Statements of
income.Comprehensive Income. Any portion of AFUDC attributable to equity funds would be included in “Other Income (Expense)” in the
consolidated statementsConsolidated Statements of
income.Comprehensive Income. For the three years ended October 31, 2014, 2013 and 2012, all of our AFUDC was attributable to borrowed funds.
AFUDC for the years ended October 31,
2011, 20102014, 2013 and
20092012 is presented below.
| | | | | | | | | | | | |
In thousands | | 2011 | | | 2010 | | | 2009 | |
AFUDC | | $ | 8,619 | | | $ | 9,981 | | | $ | 2,298 | |
|
| | | | | | | | | | | | |
| In thousands |
| 2014 |
| 2013 |
| 2012 |
| AFUDC |
| $ | 16,427 |
|
| $ | 30,975 |
|
| $ | 25,211 |
|
In accordance with utility accounting practice, we have classified expendituresreal estate and development costs associated with a liquefied natural gas (LNG)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 underConsolidated Balance Sheets, due to construction will create cost effective expansion capacitybeing suspended in March 2009. As of 2012, approximately $3.2 million of the “Plant held for future use” related to land costs and approximately $3.5 million related to non-real estate costs. In May 2013, we filed a general rate application with the North Carolina Utilities Commission (NCUC) requesting rate recovery of the non-real estate costs. Under the settlement of the 2013 North Carolina general rate proceeding approved by the NCUC in December 2013, we agreed to the amortization and collection of $1.2 million of non-real estate costs that we will useis recorded as a regulatory asset to help servebe amortized over 38 months beginning January 1, 2014 through February 2017. Under the growing natural gas requirementssettlement of our customersJune 2014 rate stabilization adjustment (RSA) filing with the Public Service Commission of South Carolina (PSCSC) that was approved in October 2014, we agreed to the amortization and collection of $.5 million of non-real estate costs that is recorded as a regulatory asset to be amortized over 12 months beginning November 1, 2014. We recorded cumulative amortization of $1.8 million of non-real
estate costs in fiscal year 2013 that is included in the
eastern partConsolidated Statements of
North Carolina. The timing and design scopeComprehensive Income in “Other Income (Expense)” in “Non-operating expense.” For further information on the 2013 general rate proceeding settlement of
the expansion of our facilities in this area will be determined as our system infrastructure and market supply growth requirements inthese costs for North Carolina
dictate and such costs, approximately half being land purchase and preparation, will be movedor the 2014 RSA filing for South Carolina, see Note 2 to
any such future project.the consolidated financial statements.
We compute depreciation expense using the straight-line method over periods ranging from
45 to
8880 years. The composite weighted-average depreciation rates were
3.19%2.54% for
2011, 3.20%2014, 2.77% for
20102013 and
3.25%2.94% for
2009.2012.
Depreciation rates for utility plant are approved by our regulatory commissions. In North Carolina, we are required to conduct a depreciation study every five years and file the results with the regulatory commission. No such five-year requirement exists in South Carolina or Tennessee; however, we periodically propose revised rates in those states based on depreciation studies. Our last system-wide depreciation study based on fiscal year 2009 data was completed in 2011 and filed with the appropriate regulatory commission in all jurisdictions. New depreciation rates were approved effective November 1, 2011 for South Carolina. We have proposed the implementation of the new depreciation rates in Tennessee beginningCarolina, March 1, 2012. We anticipate new rates to become effective in2012 for Tennessee and January 1, 2014 for North Carolina in connection withCarolina.
As authorized by our
next general rate case filing.Theregulatory commissions, the estimated costs of removal on certain regulated properties are collected through depreciation expense through rates with a corresponding credit to accumulated depreciation. Our approved depreciation rates are comprised of two components, one based on average service life and one based on cost of removal for certain regulated properties. Therefore, through depreciation expense, we accruecollect and record estimated non-legal costs of removal on any depreciable asset that includes cost of removal in its depreciation rate.
Because the estimated removal costs are a non-legal obligation, we account for them as a regulatory liability and present the accumulated removal costs in “Regulatory Liabilities” in “Rate-Regulated Basis of Accounting” in this Note 1. For further discussion of this regulatory liability, see “Asset Retirement Obligations” in this Note 1.
Cash and Cash Equivalents
We consider instruments purchased with an original maturity at date of purchase of three months or less to be cash equivalents, particularly affecting the
statementsConsolidated Statements of
cash flows.Cash Flows. We have no restrictions on our cash balances that would impact the payment of dividends as of October 31,
20112014 and
2010.2013.
Trade Accounts Receivable and Allowance for Doubtful Accounts
Trade accounts receivable consist of natural gas sales and transportation services, merchandise sales and service work. We bill customers monthly with payment due within 30 days. We maintain an allowance for doubtful accounts, which we adjust periodically, based on the aging of receivables and our historical and projected charge-off activity. Our estimate of recoverability could differ from actual experience based on customer credit issues, the level of natural gas prices and general economic conditions. We write off our customers’ accounts when they are deemed to be uncollectible. Pursuant to orders issued by the
North Carolina Utilities Commission (NCUC)NCUC, the PSCSC and the
Public Service Commission of South Carolina (PSCSC),TRA, we are authorized to recover all uncollected gas costs through the purchased gas adjustment (PGA). As a result, only the portion of accounts written off relating to the non-gas costs, or margin, is included in base rates and, accordingly, only this portion is included in the provision for uncollectibles expense.
In 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 noncurrent assets” in “Noncurrent Assets” in the
consolidated balance sheets.Consolidated Balance Sheets.
We are exposed to credit risk when we enter into contracts with third parties to
buy and sell natural gas. We also enter into short-term contracts with third parties to manage some of our supply and capacity assets for the purpose of maximizing their value. Our
internal credit policies requirepolicy requires counterparties to have an investment-grade credit rating at the time of the contract.
Where the counterparty doesIn situations where counterparties do not have
an investment-gradeinvestment grade or functionally equivalent credit
rating,ratings, our policy requires credit enhancements that include letters of credit or parental guaranties. In either circumstance, the policy specifies limits on the contract amount and duration based on the counterparty’s credit rating and/or credit support.
WeIn order to minimize our exposure, we continually re-evaluate third-party credit worthiness and market conditions and modify our requirements accordingly.
Our principal business activity is the distribution of natural gas. We believe that we have provided an adequate allowance for any receivables which may not be ultimately collected. As of October 31,
20112014 and
2010,2013, 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 | |
| | | | | | | | |
|
| | | | | | | | |
| In thousands | | 2014 | | 2013 |
| Gas receivables | | $ | 64,400 |
| | $ | 78,540 |
|
| Non-regulated merchandise and service work receivables | | 3,012 |
| | 2,274 |
|
| Allowance for doubtful accounts | | (2,152 | ) | | (1,604 | ) |
| Trade accounts receivable | | $ | 65,260 |
| | $ | 79,210 |
|
A reconciliation of the changes in the allowance for doubtful accounts for the years ended October 31,
2011, 20102014, 2013 and
20092012 is presented below.
| | | | | | | | | | | | |
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 | |
| | | | | | | | | | | | |
|
| | | | | | | | | | | | |
| In thousands | | 2014 | | 2013 | | 2012 |
| Balance at beginning of year | | $ | 1,604 |
| | $ | 1,579 |
| | $ | 1,347 |
|
| Additions charged to uncollectibles expense | | 6,959 |
| | 5,314 |
| | 4,584 |
|
| Accounts written off, net of recoveries | | (6,411 | ) | | (5,289 | ) | | (4,352 | ) |
| Balance at end of year | | $ | 2,152 |
| | $ | 1,604 |
| | $ | 1,579 |
|
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 utilizeenter into service contracts, or asset management agreementsarrangements (AMAs), with counterparties to efficiently manage portions of our gas supply, transportation capacity and storage capacity to serve our customers. These AMAs are structured in compliance with Federal Energy Regulatory Commission (FERC) Order 712. Generally, under an AMA, we receive a fixed monthly payment which is set at inception of the arrangement, and in return, we may assign the gas supply and/or storage inventory and release the transportation capacity and storage capacity to the asset manager for certain natural gas storagethe term of the agreement. The inventory is assigned at no cost, and transportation assets. the same quantities are required to be returned at the expiration of the agreements. One agreement allows us to call on inventory during the summer months to satisfy operational requirements, if needed. The inventory that is assigned to the asset manager is available for our use during the winter heating season, November through March. We account for these amounts on the Consolidated Balance Sheets as a current asset in the inventories section as “Gas in storage.” From the period of April through October, the inventory that is not available for our use is reclassified on the Consolidated Balance Sheets as a current asset in “Prepayments,” and the inventory that is available for our use remains in “Gas in storage.”
At October 31,
20112014 and
2010,2013, such counterparties held natural gas storage assets
includedas recorded in
“Prepayments” in the consolidated balance sheets,“Prepayments,” with a value of
$35.8$35 million and
$36.6$31.5 million, respectively, through
capacity release and agencysuch asset management relationships. Under the terms of the
asset management agreements, we receive
capacity and storage asset management fees, which are recorded as secondary market transactions and shared between our utility customers and our shareholders. The
asset management agreementsAMAs expire at various times through March 31,
2014.2017. For further information on the revenue sharing of secondary market transactions, see Note 2 to the consolidated financial statements.
Materials, supplies and merchandise inventories are valued at the lower of average cost or market and removed from such inventory at average cost.
Fair Value Measurements
Effective November 1, 2009, we adopted the additional authoritative guidance related to nonrecurring fair value guidance for certain
We have financial and nonfinancial assets and liabilities
subject to fair value measurement. The financial assets and
the use ofliabilities measured and carried at fair value in the
impairment testing of goodwill, intangibleConsolidated Balance Sheets are cash and cash equivalents, marketable securities held in rabbi trusts established for our deferred compensation plans and derivative assets and
long-lived assets. In February 2010, we adopted the amended fair value guidance, which clarified disclosure requirementsliabilities, if any, that are held 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.utility operations. The carrying values of cash and cash equivalents, receivables, bankshort-term debt, accounts payable, accrued interest and other current assets and liabilities approximate fair value as all amounts reported are to be collected or paid within one year. Our financialnonfinancial 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 forinclude our deferred compensation plans. Ourqualified pension and postretirement plan assets and liabilities that are recorded at fair value in the consolidated balance sheetsConsolidated 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
intothat is significant to the fair value measurement, in its entirety, in the following fair value hierarchy levels as set forth in the fair value guidance.
Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities as of the reporting date. Active markets have sufficient frequency and volume to provide pricing information for the asset or liability on an ongoing basis. Our Level 1 items consist of financial instruments of exchange-traded derivatives, investments in marketable securities and benefit plan assets held in registered investment companies and individual stocks.
Level 2 inputs are inputs other than quoted prices in active markets included in Level 1 and are either directly or indirectly corroborated or observable as of the reporting date, generally using valuation methodologies. These methodologies are primarily industry-standard methodologies that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. We obtain market price data from multiple sources in order to value some of our Level 2 transactions and this data is representative of transactions that occurred in the
market place.marketplace. Our Level 2 items include non-exchange-traded derivative instruments, such as some qualified pension plan assets held in hedge fund of funds, commodities
hedge fund of funds,
common trust funds, collateralized mortgage obligations, swaps, futures, currency forwards, corporate bonds and government and agency obligations that are valued at the closing price reported in the active market for similar assets in which the individual securities are traded or based on yields currently available on comparable securities of issuers with similar credit ratings or based on the most recent available financial information for the respective funds and securities. For some qualified pension plan assets, the determination of Level 2 assets was completed through a process of reviewing each individual security while consulting research and other metrics provided by investment managers, including a pricing matrix detailing the pricing source and security type, annual audited financial statements and
a review of valuation policies and
procedures.procedures used by the investment managers as well as our investment advisor.
Level 3 inputs include significant pricing inputs that are generally less observable from objective sources and may be used with internally developed methodologies that result in management’s best estimate of fair value. Our Level 3 inputs include cost estimates for removal (contract fees or manpower/equipment estimates), inflation factors, risk premiums, the remaining
life of long-lived assets, the credit adjusted risk free rate to discount for the time value of money over an appropriate time span, and the most recent available financial information of an investment in a 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.
In determining whether to categorize the fair value measurement of an instrument as Level 2 or Level 3, we must use judgment to assess whether we have the ability as of the measurement date to redeem an investment at its net asset value per share (NAV) in the near term. We consider when we might have the ability to redeem the investment by reviewing contractual restrictions in effect as of the investment date as well as any potential restrictions that the investee may impose. Regarding our benefit plans’ investments, “near term” is the ability to redeem an investment in no more than 180 days.
Transfers between different levels of the fair value hierarchy may occur based on the level of observable inputs used to value the instruments for the period. These transfers represent existing assets or liabilities previously categorized as
a Level 1 or Level 2 for which the inputs to the estimate became less observable or assets and liabilities previously classified as Level 2 or Level 3 for which the lowest significant input became more observable during the period. Transfers into and out of each level are measured at the
endactual date of the
reporting period.event or change in circumstances causing the transfer.
For the fair value measurements of our derivatives and marketable securities, see Note 7 to the consolidated financial statements. For the fair value measurements of our benefit plan assets, see Note 9 to the consolidated financial statements.
Goodwill, Equity Method Investments and Long-Lived Assets
Goodwill is the excess of the purchase price over the fair value of identifiable net assets acquired in a business combination. We annually evaluate goodwill for impairment as of October 31, or more frequently if impairment indicators arise during the year. These indicators include, but are not limited to, a significant change in operating performance, the business climate, legal or regulatory factors, or a planned sale or disposition of a significant portion of the business. We test goodwill using a fair value approach at a reporting unit level, generally equivalent to our operating segments as discussed in Note
14.14 to the consolidated financial statements. An impairment charge would be recognized if the carrying value of the reporting unit, including goodwill, exceeded its fair value. All of our goodwill is attributable to the regulated utility segment.
We early adopted the accounting guidance issued September 2011
Our annual goodwill impairment assessment was performed as of October 31, 2014, and we determined 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 relativethere was no impairment 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.our goodwill. No impairment has beenwas recognized during the years ended October 31, 2011, 20102014, 2013 and 2009.
2012. The fair value of our regulated utility reporting unit substantially exceeds the carrying value, including goodwill.
We review our equity method investments and long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable.
In April 2014, we recorded a $2 million write-off for an investment that was accounted for on the cost basis. The write-off was recorded to "Non-operating expense" in the Consolidated Statements of Comprehensive Income. There were no events or circumstances during the years ended October 31,
2011, 20102013 and
20092012 that resulted in any impairment charges. For further information on equity method investments, see Note 12 to the consolidated financial statements.
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
trusttrusts established for our deferred compensation
plans that became effective on January 1, 2009.plans. For further information on the deferred compensation plans, see Note 9 to the consolidated financial statements.
We have classified these marketable securities as trading securities since their inception as the assets are held in
a rabbi
trust.trusts. Trading securities are recorded at fair value on the
consolidated balance sheetsConsolidated Balance Sheets with any gains or losses recognized currently in earnings. We do not intend to engage in active trading of the securities, and participants in the deferred compensation plans may redirect their
deemed investments at any time.
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
“Current Assets” in the
consolidated balance sheets.Consolidated Balance Sheets.
The money market investments in the
trusttrusts 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,
20112014 and
20102013 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 | |
| | | | | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | |
| | | 2014 | | 2013 |
| In thousands | | Cost | | Fair Value | | Cost | | Fair Value |
| Current trading securities: | | | | | | | | |
| Money markets | | $ | 22 |
| | $ | 22 |
| | $ | — |
| | $ | — |
|
| Mutual funds | | 106 |
| | 192 |
| | 134 |
| | 199 |
|
| Total current trading securities | | 128 |
| | 214 |
| | 134 |
| | 199 |
|
| Noncurrent trading securities: | | | | | | | | |
| Money markets | | 447 |
| | 447 |
| | 380 |
| | 380 |
|
| Mutual funds | | 2,598 |
| | 3,280 |
| | 1,995 |
| | 2,615 |
|
| Total noncurrent trading securities | | 3,045 |
| | 3,727 |
| | 2,375 |
| | 2,995 |
|
| Total trading securities | | $ | 3,173 |
| | $ | 3,941 |
| | $ | 2,509 |
| | $ | 3,194 |
|
Unamortized debt expense 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 haswith lives ranging from 5 to 30 years. We amortize bank debt expense over the life of the syndicated revolving credit facility, which is
threefive years.
Should we reacquire long-term debt prior to its term date and simultaneously issue new debt, we defer the gain or loss resulting from the transaction, essentially the remaining unamortized debt expense, and amortize it over the life of the new debt in accordance with established regulatory practice. Where the refunding of the debt is not simultaneous, we defer the gain or loss resulting from the reacquisition of the debt and amortize
it over the remaining life of the redeemed debt in accordance with established regulatory practice. For income tax purposes, any gain or loss would be recognized as incurred.
Issuances and Repurchases of Common Stock
As discussed in Note 6 to the consolidated financial statements,
from time to time we
may repurchase shares on the open market and such shares are then
cancelledcanceled and become authorized but unissued shares.
Currently, itIt is our policy to issue new shares for share-based employee awards and shareholder and employee investment plans.
We present net shares issued under these awards and plans in “Common Stock Issued” in the Consolidated Statements of Stockholders’ Equity. Shares withheld by us to satisfy tax withholding obligations related to the vesting of shares awarded under the Incentive Compensation Plan have been immaterial to date.
Asset Retirement Obligations
The accounting guidance for AROs addresses the financial accounting and reporting for AROs associated with the retirement of long-lived assets that result from the acquisition, construction, development and operation of the assets. The accounting guidance requires the recognition of the fair value of a liability for AROs in the period in which the liability is incurred if a reasonable estimate of fair value can be made. We have determined that
conditional AROs exist for our underground mains and services.
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 estimatedhave costs of removal
on certain regulated properties through depreciation expense, with a corresponding credit to accumulated depreciation. These removal coststhat are non-legal obligations as defined by the accounting guidance.
The costs of removal are a component of our depreciation rates in accordance with long-standing regulatory treatment. Because these estimated removal costs meet the requirements of
rate regulatedrate-regulated accounting guidance, we have accounted for these non-legal AROs
in “Regulatory Liabilities” as
a regulatory liability. We record the estimated non-legal AROspresented in
“Cost“Rate-Regulated Basis of
removal obligations”Accounting” in
“Noncurrent Liabilities” in our consolidated balance sheets.this Note 1. In the rate setting process, the liability for non-legal costs of removal is treated as a reduction to the net rate base upon which the regulated utility has the opportunity to earn its allowed rate of return.
In 2006, we applied For further discussion of these costs of removal as a component of depreciation, see “Utility Plant and Depreciation” in this Note 1.
We apply the accounting guidance for conditional AROs that requires recognition of a liability for the fair value of conditional AROs when incurred if the liability can be reasonably estimated.
At the same time, theThe NCUC, the PSCSC and the TRA
have approved placing these ARO costs in deferred accounts to preserve the regulatory treatment of these
costs.costs; therefore, accretion is not reflected in the Consolidated Statements of Comprehensive Income as the regulatory treatment provides for deferral of the accretion as a regulatory asset with a corresponding deferral of the accretion recorded as a regulatory liability. AROs
will beare capitalized concurrently by increasing the carrying amount of the related asset by the same amount as the
regulatory liability. In periods subsequent to the initial measurement, any changes in the
liability resulting from the passage of time (accretion) or due to the revisions of either timing or the amount of the originally estimated cash flows to settle conditional AROs must be recognized. The estimated cash flows to settle conditional AROs are discounted using the credit adjusted risk-free rate, which ranged from 4.5%4.40% to 5.87%5.15% with a weighted average of 5.86%5.09% for the twelve months ended October 31, 2011.2014. 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 sheetsthe Consolidated Balance Sheets as of October 31,
20112014 and
20102013 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 | |
| | | | | | | | |
|
| | | | | | | | |
| In thousands | | 2014 | | 2013 |
| Regulatory non-legal AROs | | $ | 506,574 |
| | $ | 493,111 |
|
| Conditional AROs | | 14,647 |
| | 27,016 |
|
| Total cost of removal obligations | | $ | 521,221 |
| | $ | 520,127 |
|
A reconciliation of the changes in conditional AROs for the year ended October 31,
20112014 and
20102013 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 | |
| | | | | | | | |
|
| | | | | | | | |
| In thousands | | 2014 | | 2013 |
| Beginning of period | | $ | 27,016 |
| | $ | 28,629 |
|
| Liabilities incurred during the period | | 2,108 |
| | 2,052 |
|
| Liabilities settled during the period | | (3,576 | ) | | (2,389 | ) |
| Accretion | | 1,548 |
| | 1,641 |
|
| Adjustment to estimated cash flows | | (12,449 | ) | | (2,917 | ) |
| End of period | | $ | 14,647 |
| | $ | 27,016 |
|
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
North Carolina, a margin decoupling mechanism provides for the recovery of our approved margin from residential and commercial customers on an annual basis independent of weather and consumption patterns. The margin decoupling mechanism provides for semi-annual rate adjustments to refund any over-collection of margin or to recover any under-collection of margin. In South Carolina, a RSA tariff mechanism achieves the objectives of margin decoupling for residential and commercial customers with a one year lag. Under the RSA tariff mechanism, we reset our rates in South Carolina based on updated costs and revenues on an annual basis. In South Carolina and Tennessee, a weather normalization adjustment (WNA) is calculated for residential and commercial customers during the winter heating season November through
March.March, and in Tennessee, the months of April and October. The WNA
ismechanisms are designed to
partially offset the impact that warmer-than-normal or colder-than-normal weather has on customer billings during the winter heating season.
In North Carolina, a year around margin decoupling mechanism provides for theThe WNA formulas do not ensure full recovery of
our approved margin
during periods when customer consumption patterns vary from
residential and commercial customers independent of consumption patterns. Thethose used to establish the WNA factors. In all states, the gas cost portion of our costs is recoverable through PGA procedures and is not affected by the
WNAmargin decoupling mechanism or the
margin decouplingWNA mechanism.
We have integrity management riders (IMRs) in our tariffs in North Carolina, effective February 1, 2014, and in Tennessee effective January 1, 2014, related to our ongoing system integrity programs. These IMRs provide for rate adjustments to allow us to recover and earn on those investments without the necessity of filing general rate cases. The North Carolina IMR was approved in December 2013 in the settlement of our 2013 general rate case. Under the North Carolina IMR tariff, we will make annual filings by November 30 of each year for costs closed to plant through October with revised rates effective the following February 1. The Tennessee IMR tariff was approved in December 2013 with the settlement of our August 2013 IMR filing. Under the Tennessee IMR, we will file to adjust rates to be effective each January 1 based on capital expenditures related to mandated safety and integrity programs that were incurred by the previous October 31. For further discussion of the IMRs, see Note 2 to the consolidated financial statements.
Revenues are recognized monthly on the accrual basis, which includes estimated amounts for gas delivered to customers but not yet billed under the cycle-billing method from the last meter reading date to month end. The unbilled revenue estimate reflects factors requiring judgment related to estimated usage by customer class, customer mix, changes in weather during the period and the impact of the WNA or margin decoupling
mechanism,mechanisms, as applicable.
Secondary market revenues associated with the commodity are recognized when the physical sales are delivered based on contract or market prices. Asset management fees for storage and transportation remitted on a monthly basis are recognized as earned given the monthly capacity costs associated with the contracts involved. Asset management fees remitted
in a lump sum are deferred and amortized ratably into income over the period in which they are earned, which is typically the contract term. See Note 2 to the consolidated financial statements regarding revenue sharing of secondary market transactions.
Utility sales, transportation and secondary market revenues are reported on a net of tax basis.excise taxes, sales taxes and franchise fees. For further information regarding taxes, see “Taxes” in this Note 1 to1.
Non-regulated merchandise and service work includes the
consolidated financial statements.sale, installation and/or maintenance of natural gas appliances and gas piping beyond the meter. Revenue is recognized when the sale is made or the work is performed. If the customer is eligible for and elects financing through us, the finance fee income is recognized on a monthly basis based on principal, rate and term.
Cost of Gas and Deferred Purchased Gas Adjustments
We charge our utility customers for natural gas consumed using natural gas cost recovery mechanisms as set by the regulatory commissions in states in which we operate. Rate schedules for utility sales and transportation customers include PGA provisions that provide for the recovery of prudently incurred
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.
We charge our secondary market customers for natural gas based on negotiated contract terms. Under PGA provisions, charges to cost of gas are based on the amount recoverable under approved rate schedules.
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.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.
By jurisdiction, differences between gas costs incurred and gas costs billed to customers, such that no operating margin is recognized related to these costs, are deferred and included in “Amounts due from customers” in “Regulatory Assets” or “Amounts due to customers” in “Regulatory Liabilities” as presented in “Rate-Regulated Basis of Accounting” in this Note 1. We review gas costs and deferral activity periodically (including deferrals under the margin decoupling and WNA mechanisms) and, with regulatory commission approval, increase rates to collect under-recoveries or decrease rates to refund over-recoveries over a subsequent period.
We have two categories of income taxes in
our consolidated statementsthe Consolidated Statements of
income:Comprehensive Income: current and deferred. Current income tax expense consists of federal and state income
taxtaxes less applicable tax credits related to the current year. Deferred income tax expense generally is equal to the changes in the deferred income tax liability and regulatory tax liability during the year. Deferred taxes are primarily attributable to utility plant, deferred gas costs, revenues and cost of gas, equity method investments, benefit of loss carryforwards and employee benefits and compensation. The determination of our provision for income taxes requires judgment, the use of estimates, and the interpretation and application of complex tax laws. Judgment is required in assessing the timing and amounts of deductible and taxable items.
Deferred income taxes are determined based on the estimated future tax effects of differences between the book and tax basis of assets and liabilities. We have provided valuation allowances to reduce the carrying amount of deferred tax assets to amounts that are more likely than not to be realized. To the extent that the establishment of deferred income taxes is different from the recovery of taxes through the ratemaking process, the differences are deferred in accordance with rate-regulated accounting provisions, and a regulatory asset or liability is recognized for the impact of tax expenses or benefits that will be collected from or refunded to customers in different periods pursuant to rate orders.
Deferred investment tax credits, including energy credits, associated with our utility operations are presented in
our consolidated balance sheets.the Consolidated Balance Sheets. We amortize these deferred investment and energy tax credits to income over the estimated useful lives of the property to which the credits relate.
We recognize accrued interest and penalties, if any, related to uncertain tax positions
inas operating expenses in the
consolidated statementsConsolidated Statements of
income.Comprehensive Income. This is consistent with the recognition of these items in prior reporting periods.
Excise taxes, sales taxes and franchises fees separately stated on customer bills are recorded on a net basis as liabilities payable to the applicable jurisdictions. All other taxes other than income taxes are recorded as general taxes. General taxes consist of property taxes, payroll taxes, Tennessee gross receipt taxes, franchise taxes, tax on company use
public utility fees and other miscellaneous taxes.
Consolidated Statements of Cash Flows
With respect to cash overdrafts, book overdrafts are included within operating cash flows while any bank overdrafts are included with financing cash flows.
Recently Issued Accounting Guidance
In
June 2009,July 2013, the Financial Accounting Standards Board (FASB)
amended accounting guidance to eliminate the quantitative approach that entities use to determine whether an entity has a controlling financial interest in a variable interest entity (VIE) and to require that the entity with a variable interest in a VIE qualitatively assess whether it has a controlling financial interest, and if so, determine whether it is the primary beneficiary. The guidance requires companies to continually evaluate the VIE for consolidation, rather than performing the assessment only when specific events occur. It also requires enhanced disclosures to provide more information about the entity’s involvement with the VIE. 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 position, 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.on presenting an unrecognized tax benefit when net operating loss (NOL) carryforwards exist. The guidance willwas issued in an effort to eliminate diversity in practice resulting from a lack of guidance on this topic in current US GAAP. The update provides that an unrecognized tax benefit, or a portion of an unrecognized tax benefit, should be presented in the financial statements as a reduction to a deferred tax asset for a NOL carryforward, a similar tax loss, or a tax credit carryforward, except under certain circumstances outlined in the update. The amendments in the update are effective for annual periods, and interim periods for fiscal years beginning after December 15, 2010. We will adopt the guidance for Level 3 disclosure for recurring and non-recurring items covered under the fair value guidance for the first quarter of our fiscal year ending October 31, 2012. Since the guidance addresses only disclosures related to fair value measurements under Level 3, the adoption of this guidance will not have a material impact on our financial position, results of operations or cash flows.
In July 2010, the FASB issued accounting guidance to improve disclosures about the credit quality of an entity’s financing receivables and the reserves held against them. End of reporting period disclosures are required for the reporting period ending on or after December 15, 2010. The disclosures about activity that occurred during a reporting period were effective for interim and annual periods beginning on or after December 15, 2010. We adopted the guidance for the end of period disclosures as of January 31, 2011, and the guidance for the disclosures related to activity in the reporting period during our fiscal second quarter beginning February 1, 2011. Since the guidance addresses only disclosures related to credit quality of financing receivables and the allowance for credit losses, the adoption of this guidance did not have a material impact on our financial position, results of operations or cash flows.
In 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 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 U.S. GAAP and IFRS fair value measurement and disclosure requirements are described in the same way. The guidance will be effective for interim and annualwithin those periods, beginning after December 15, 2011. We will adopt the amended fair value guidance for the second quarter of our fiscal year ending October 31, 2012. We do not expect the2013, with early adoption permitted. The adoption of this guidance 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 the unaffected provisions of OCI presentation guidance for the second quarter of our fiscal year ending October 31, 2012. The adoption of thisdisclosure guidance will have no impact on our financial position, results of operations or cash flows.
In May 2014, the FASB and the International Accounting Standards Board issued converged accounting guidance on the recognition of revenue from contracts with customers. Under the new standard, entities will recognize revenue to depict the transfer of goods and services to customers in amounts that reflect the payment to which the entity expects to be entitled in exchange for those goods or services. The disclosure requirements will provide information about the nature, amount, timing and uncertainty of revenue and cash flows from an entity’s contracts with customers. The new guidance is effective for annual periods beginning after December 15, 2016, and interim periods within those periods, which for us is our fiscal year 2018.
An accounting utility subgroup has identified five issues (scope for cost-of-service-tariff sales, contract modifications, variable consideration, multiple element arrangements and sales of real estate) that are not clear within the standard and require revenue implementation guidance. The revenue implementation guide is expected to be published prior to the standard becoming effective in 2017; however, no date has been set.
We intendare currently evaluating the effect on our financial position, results of operations and cash flows. The evaluation includes identifying revenues streams by like contracts to present net incomeallow for ease of implementation once the utility sub-group has issued the revenue implementation guide.
In June 2014, the FASB amended accounting guidance to eliminate certain financial reporting requirements for development stage entities, including an amendment to variable interest entity (VIE) guidance. The modification to the guidance may change the consolidation analysis, consolidation decision and
other comprehensive incomedisclosure requirements for a reporting entity that has an interest in
one continuous statement.an entity in the development stage. The amendments in the update are effective for annual periods, and interim periods within those periods, beginning after December 15, 2015, with early adoption permitted. We will consider this guidance regarding our current joint venture investments where the investment infrastructure is under development and any future investments that are development stage projects, particularly any disclosures about risks and uncertainties of the development of the project and our equity method investment.
In
September 2011,August 2014, the FASB issued accounting guidance
on determining when and how reporting entities must disclose going concern uncertainties in their financial statements. The new standard requires management to
simplify howperform interim and annual assessments of an
entity tests goodwill for impairment.entity's ability to continue as a going concern within one year of the date of issuance of the entity's financial statements. An entity
must provide certain disclosures if there is
allowed an optiona "substantial doubt about the entity's ability to
first assess qualitative factors to determine whether it is more likely than not (greater than 50%) that the fair value of a reporting unit is less than its carrying amountcontinue 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,going concern." The standard is effective for annual
and interim goodwill impairment tests performed for fiscal years beginningperiods ending after December 15,
2011.2016, and interim periods thereafter; early adoption is permitted. The adoption of this assessment will have no impact on our financial position, results of operations or cash flows.
Reclassifications and Changes in Presentation
Reclassifications have been made to certain prior year financial statements to conform with the current year presentation. Within “Cash Flows From Operating Activities” in the Consolidated Statements of Cash Flows, we have changed the presentation of cash flows from regulatory assets and liabilities, previously included within the line items “Other assets” and “Other liabilities,” respectively, to provide additional detail and to present such information within separate line items, “Regulatory assets” and “Regulatory liabilities.” The 2013 and 2012 presentation has been changed to conform to the current year presentation. The reclassifications had no effect on previously reported amounts for net cash flows from operating, investing or financing activities.
Our utility operations are regulated by the NCUC, PSCSC and TRA as to rates, service area, adequacy of service, safety standards, extensions and abandonment of facilities, accounting and depreciation. We are also regulated by the NCUC as to the issuance of long-term debt and equity securities.
The NCUC and the PSCSC regulate our gas purchasing practices under a standard of prudence and audit our gas cost accounting practices. The TRA regulates our gas purchasing practices under a gas supply incentive program which compares our actual costs to market pricing benchmarks. As part of this jurisdictional oversight, all three
statesregulatory commissions address our gas supply hedging activities. Additionally,
North Carolina and South Carolinaall three regulatory commissions allow for recovery of uncollectible gas costs through the PGA. The portion of uncollectibles related to gas costs is recovered through the deferred account and only the non-gas costs, or margin, portion of uncollectibles is included in base rates and uncollectibles expense.
In 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 ACA filings; if the difference is greater, there would be a charge to customers through the ACA filing.
North Carolina
Jurisdiction
The North Carolina General Assembly enacted the Clean Water and Natural Gas Critical Needs Act of 1998 which provided for the issuance of $200 million of general obligation bonds of the state for the purpose of providing grants, loans or other financing for the cost of constructing natural gas facilities in unserved areas of North Carolina. In 2000, the NCUC issued an order awarding Eastern North Carolina Natural Gas Company (EasternNC) an exclusive franchise to provide natural gas service to 14 counties in the eastern-most part of North Carolina that had not been able to obtain gas service because of the relatively small population of those counties and the resulting economic infeasibility of providing service and granted $38.7 million in state bond funding. In 2001, the NCUC issued an order granting EasternNC an additional $149.6 million, for a total of $188.3 million. With the 2003 acquisition and subsequent merger of EasternNC into our regulated utility segment, we are required to provide an accounting of the operational feasibility of this area to the NCUC every two years. Should this operational area become economically feasible and generate a profit, which we believe is unlikely, we would begin to repay the state bond funding.
The NCUC had allowed EasternNC to defer its operations and maintenanceO&M expenses during the first eight years of operation or until the first rate case order, whichever occurred first, with a maximum deferral of $15 million. Thethe deferred amounts accruedaccruing 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 maintenanceO&M expenses wasof $9 million at October 31, 2008.2008 was to be amortized over a twelve year period beginning November 1, 2008, with interest accruing at 7.84% per annum. Under the settlement of the 2013 general rate proceeding discussed below, the unamortized balance of the EasternNC deferred O&M expenses was $6.3 million as of December 31, 2013. This balance is accruing interest at a rate of 7.84%6.55% per annum and is being amortized with amortization beginning January 1, 2014over a twelve year period.an 82-month period ending October 31, 2020. As of October 31, 20112014 and 2010,2013, we had unamortized balances, including accrued interest, of $7.7$5.6 million and $8.3$6.4 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 liability for the conservation programs of $.4 million and no liability as of October 31, 2011.
We incur certain pipeline integrity management costs in compliance with the Pipeline Safety Improvement Act of 1992 and certain regulations of the United States Department of Transportation. The NCUC approved deferral treatment of the operations and maintenanceO&M costs applicable to allcertain incremental pipeline integrity external expenditures beginning November 1, 2004. Under the settlementThe approved balance for recovery of the 2008 general rate proceeding, theactual pipeline integrity management O&M costs incurred between July 1, 2005 and June 30, 2008 through August 31, 2013 as established in the settlement of $4.6the 2013 general rate proceeding discussed below was $17.3 million were fullyto be amortized over a three-yearfive-year period beginning Novemberfrom January 1, 2008.2014 through December 31, 2018. As of October 31, 2014 and 2013, we had unamortized regulatory asset balances for deferred pipeline integrity expenses of $28.2 million and $19.4 million, respectively. The existing regulatory asset treatment for ongoing pipeline integrity management costs continueswill continue until another recovery mechanism is established in a future rate proceeding. The unamortized balance as
With the approval of
October 31, 2011 that is subject to a futurethe settlement of the 2013 NCUC general rate proceeding
is $8 million.discussed below, future capital expenditures that are incurred to comply with federal pipeline safety and integrity requirements will be separately tracked and recovered on an annual basis through an IMR. The settlement also approved recovery of $6.3 million of deferred North Carolina environmental costs over a five-year period from January 2014 through December 2018.
In North Carolina, our recovery of gas costs is subject to annual gas cost proceedings to determine the prudence of our gas purchases.
CostsOur gas costs have never been disallowed on the basis of prudence.
In
February 2010,January 2012, the NCUC approved our accounting of gas costs for the twelve months ended May 31,
2009,2011, with adjustments agreed to by us as a result of the
North CarolinaNCUC Public Staff’s audit of the
20092011 gas cost review period. We were deemed prudent on our gas purchasing policies and practices during this review period and allowed 100% recovery.
In
January 2011,November 2012, the NCUC approved our accounting of gas costs for the twelve months ended May 31,
2010, with adjustments agreed to by us as a result of the North Carolina Public Staff’s audit of the 2010 gas cost review period.2012. We were deemed prudent on our gas purchasing policies and practices during this review period and allowed 100% recovery.
In August 2011, we filed testimony withNovember 2013, the NCUC in supportapproved our accounting of our gas cost purchasing and accounting practicescosts for the twelve months ended May 31, 2011. A hearing2013. We were deemed prudent on our gas purchasing policies and practices during this matter was heldreview period and allowed 100% recovery.
In November 2014, the NCUC approved our accounting of gas costs for the twelve months ended May 31, 2014. We were deemed prudent on
October 4, 2011. We are unable to predict the outcome ofour gas purchasing policies and practices during this
proceeding at this time.review period and allowed 100% recovery.
Our gas cost hedging plan for North Carolina is designed to provide
somea level of protection against significant price increases, targets a percentage range of 22.5% to 45% of annual normalized sales volumes for North Carolina and operates using historical pricing indices that are tied to future projected gas prices as traded on a national exchange. Unlike South Carolina as discussed below, recovery of costs associated with the North Carolina hedging plan is not pre-approved by the NCUC, and the costs are treated as gas costs subject to the annual gas cost prudence review. Any gain or loss recognition under the hedging program is a reduction in or an addition to gas costs, respectively, which, along with any hedging expenses, are flowed through to North Carolina customers in rates. The gas cost review orders issued
February 2010January 2012, November 2012, November 2013 and
January2011November 2014 found our hedging activities during the review periods to be reasonable and prudent. As part
In October 2012, we filed a petition with the NCUC seeking authority to transfer the total balance of $6.7 million of capital costs held in “Plant held for future use” in “Utility Plant” in the Consolidated Balance Sheets to a deferred regulatory asset account, effective November 1, 2012. This balance in “Plant held for future use” was comprised of real estate and non-real estate costs and related to the development of a LNG facility in Robeson County, North Carolina, construction of which was suspended by Piedmont in March 2009. In April 2013, we withdrew the petition, citing our intent to address the matter in a general rate application. The appropriate treatment of the February 2010Robeson County LNG costs was addressed in the general rate settlement discussed below.
In May 2013, we filed a general rate application with the NCUC requesting an increase in rates and charges. In December 2013, the NCUC approved our general rate case settlement agreement with the NCUC Public Staff with new rates effective January 2014. In its order, the NCUC approved the following:
Updated and increased rates and charges based on an adjustmentoverall rate base of $1.1$1.8 billion, an equity capital structure component of 50.7% and a return on common equity of 10% and an overall rate of return of 7.51%.
Increased total annual revenues of $30.7 million, a 3.58% increase in total revenues, or .7% annual increase, including $16.8 million related to hedging activitygas utility margin and $13.8 million related to increased fixed gas costs, and annual pre-tax income of $24.2 million after taking into account revised depreciation rates and changes to regulatory asset amortizations.
Implementation of a new IMR designed to separately track and recover annually outside of general rate cases the costs associated with capital expenditures incurred to comply with federal pipeline safety and integrity requirements.
Implementation of lower depreciation rates that decreased “Amounts dueprovide increased annual pre-tax income of $10.9 million. These new lower rates reflect the most recent study conducted in 2009, as discussed in Note 1 to the consolidated financial statements.
Amortization and collection of $1.2 million of certain non-real estate costs associated with the initial development of the Robeson County LNG facility as discussed above.
Amortization and collection of certain environmental expenses and pipeline safety and integrity compliance expenses through August 31, 2013 that had been deferred since our last general rate case in 2008.
Provision for ongoing increased annual contributions to fund pipeline safety and integrity research.
Future adjustments to rates to recognize the lower state corporate income taxes from customers”North Carolina legislation for fiscal years beginning November 1, 2014 and November 1, 2015.
In January 2014, we filed a petition with the NCUC seeking authority to adjust rates effective February 1, 2014 under the IMR mechanism approved in the general rate case settlement agreement in December 2013 discussed above. The IMR provides for annual adjustments to our rates every February 1 for capital investments in integrity and safety projects as agreedof October 31 of the preceding year. On February 5, 2014, the NCUC approved as filed the initial IMR adjustment totaling $.8 million in annual margin revenues that we reflected in our rates to customers beginning that month. In December 2014, we filed a petition with the NCUC seeking authority to adjust rates to collect an additional $26.6 million in annual IMR margin
revenues effective February 1, 2015 based on $241.9 million of capital investments in integrity and safety projects over the twelve-month period ending October 31, 2014. We are waiting on a ruling from the NCUC at this time.
In April 2014, we filed a petition with the NCUC for a limited waiver of certain billing provisions of our tariff related to emergency service and unauthorized gas taken by customers in January 2014. In August 2014, we and the NCUC Public Staff filed a joint stipulation of settlement. The terms of the settlement included the granting of a waiver of the commodity index pricing mechanism for January 2014, that we should not be penalized for our conduct in varying from the tariff in this instance as that conduct was solely for the benefit of our customers, and that we and the Public Staff would work together to develop mutually agreeable revisions to our tariff to address the situation that led to this petition. In October 2014, the NCUC issued an order rejecting the joint stipulation of settlement, finding that we must bill our customers for the higher commodity cost of gas pursuant to tariffs and assessing a $65,000 penalty against us for failure to bill and collect according to the commission-approved tariffs. The order further requires us to engage in discussions with each customer served under an interruptible rate schedule to explain the service and obligation under that rate schedule and to conduct an investigation to determine if customers are receiving service under the appropriate tariff.
In April 2014, the NCUC issued an order granting us the authority to issue up to $1 billion in the aggregate of senior or subordinated debt securities or equity securities under our open shelf registration statement. This request was made by us
to allow flexibility to access the capital markets as needed for business purposes, including for capital investments and
to fund the
North Carolina Public Staff.operations of our subsidiaries. For further information on this shelf registration statement, see Note 4 to the consolidated financial statements.
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,this act, the annual
cost and revenue filing will provide that the utility’s rate of return on equity will remain within a 50-basis point band above or below the last approved allowed rate of return on equity.
In June
2009,2012, we filed with the PSCSC a quarterly monitoring report for the twelve months ended March 31,
20092012 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
20082011 order. In October
2009,2012, the PSCSC issued an order approving a settlement
agreement between the Office of Regulatory Staff (ORS)
, the South Carolina Energy Users Committee (SCEUC) and us that resulted in a $1.1 million annual
increasedecrease in margin based on a return on equity of
11.2%11.3%, effective November 1,
2009.2012.
In June
2010,2013, we filed with the PSCSC a quarterly monitoring report for the twelve months ended March 31,
20102013 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
20092012 order. In October
2010,2013, the PSCSC issued an order approving a settlement
agreement between the ORS
the SCEUC and us that resulted in a
$.75$.1 million annual
increasedecrease in margin
based on a return on equity of 11.3%, effective November 1,
2010.2013. The PSCSC also approved the recovery of $.2 million of our deferred South Carolina environmental costs over a one-year period beginning November 2013 and ending October 2014.
In June
2011,2014, we filed with the PSCSC a quarterly monitoring report for the twelve months ended March 31,
20112014 and a cost and revenue study
as permitted byunder the RSA requesting a change in rates from those approved by the PSCSC in the October
20102013 order. In October
2011,2014, the PSCSC issued an order approving a settlement
agreement between the ORS
the SCEUC and us that resulted in a
$3.1$2.9 million annual decrease in margin based on a
stipulated allowed return on equity of
11.3% and a decrease of $1.9 million in depreciation rates for South Carolina utility plant in service,10.2%, effective November 1,
2011.2014. Also in this proceeding, the PSCSC approved the recovery of $.1 million of our deferred South Carolina environmental costs and $.5 million of certain non-real estate costs associated with the initial development of the Robeson County LNG facility located in North Carolina as discussed above, both with amortization periods of one year beginning November 2014 and ending October 2015.
In South Carolina, our recovery of gas costs is subject to annual gas cost proceedings to determine the prudence of our gas purchases. Costs have never been disallowed on the basis of prudence.
In August 2009, the PSCSC approved our PGAs and found our gas purchasing policies to be prudent for the twelve 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, 2010.
The PSCSC has approved a gas cost hedging plan for the purpose of cost stabilization for South Carolina customers. The plan targets a percentage range of 22.5% to 45% of annual normalized sales volumes for South Carolina and operates using historical pricing indices tied to future projected gas prices as traded on a national exchange. All properly accounted for costs incurred in accordance with the plan are deemed to be prudently incurred and recovered in rates as gas costs. Any gain or loss recognized under the hedging program is a reduction in or an addition to gas costs, respectively, and flows through to South Carolina customers in rates.
In Februaryan August 2011 the ORS requested thatorder, 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 theapproved a stipulation that our hedging program was requested to be effective prospectively upon the issuanceshould no longer have a required minimum volume 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.
hedging.
In August 2011,2012, 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 that2012.
In August 2013, the PSCSC approved our hedging program should no longer have a required minimum volume of hedging. AtPGAs and found our gas purchasing policies to be prudent for the PSCSC’s request,twelve months ended March 31, 2013.
In August 2014, the
ORS held a public briefing in November 2011 onPSCSC approved our PGAs and found our gas purchasing policies to be prudent for the
issue of how to measure the prudence of hedging programs in future annual review proceedings with no action taken on the matter.twelve months ended March 31, 2014.
In
October 2009,July 2014, we filed a petition with the PSCSC requesting
approvala limited waiver of certain billing provisions of our tariff related to
offer three energy efficiency programs to residential and commercialemergency service for 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.January 2014. In
May 2010,August 2014, the PSCSC
approved the energy efficiency programs on a three-year experimental basis with equipment rebates on the purchase of high-efficiency natural gas equipmentgranted our request and
weatherization assistance for low-income residential customers.Tennessee Jurisdiction
In Tennessee, the Tennessee Incentive Plan (TIP) replaced annual prudence reviews under the ACA mechanism in 1996 by benchmarking gas costs against amounts determined by published market indices and by sharing secondary market (capacity release and off-system sales) activity performance. In 2007, the TRA modified our TIPordered us to clarify and simplify the calculation of allocating gains and lossescontinue to ratepayers and shareholders by adopting a uniform 75/25 sharing ratio. The TRA also maintained the $1.6 million annual incentive cap for us on gains and losses, improved the transparency of plan operations by an agreed to request for proposal procedures for asset management transactions and provided for a triennial review of TIP operations by an independent consultant.
In December 2008, we filed an annual report for the twelve months ended December 31, 2007collaborate with the TRAORS to revise our tariff to address the situation that reflected the transactions in the deferred gas cost account for the ACA mechanism. In April 2009, the TRA staff filed its final audit report, with which we concurred. In
May 2009, the TRA issued an order adopting all findings from the staff audit. The order included cost of gas adjustments for the calendar year 2007 review period. There was no material impact from these gas cost adjustments on our financial position, results of operations or cash flows. We were foundled 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 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.
petition.
Tennessee
In February 2010, we filed a petition with the TRA to adjust the applicable rate for the collection of the Nashville franchise fee from certain customers. The proposed rate adjustment was calculated to recover the net $2.9 million of under-collected Nashville franchise fee payments as of May 31, 2009. In April 2010, the TRA passed a motion approving a new Nashville franchise fee rate designed to recover only the net under-collections that have accrued since June 1, 2005,
which would denyhave denied recovery of $1.5 million for us.million. In October 2011, the TRA issued an order denying us the recovery of $1.5 million of franchise fees consistent with its April 2010 motion, and we recorded $1.5 million in operations“Operating Expenses” as “Operations and maintenance expenses.maintenance” in the Consolidated Statements of Comprehensive Income. In November 2011, we filed for reconsideration, which was granted that month. In February 2012, a hearing on November 21, 2011.this matter was held before the TRA. In May 2012, the TRA approved the recovery of an additional $.5 million in under-collected Nashville franchise fees covering years 2002 through May 2005, which we recorded as a reduction in O&M expenses. The written order was issued by the TRA in June 2012.
In Tennessee, the Tennessee Incentive Plan (TIP) replaced annual prudence reviews under the Actual Cost Adjustment (ACA) mechanism in 1996 by benchmarking gas costs against amounts determined by published market indices and by sharing secondary market (capacity release and off-system sales) activity performance. In 2007, the TRA modified our TIP to clarify and simplify the calculation of allocating secondary marketing gains and losses to ratepayers and shareholders by adopting a uniform 75/25 sharing ratio. The TRA also maintained the $1.6 million annual incentive cap for us on gains and losses, improved the transparency of plan operations by an agreed to request for proposal procedures for asset management transactions and provided for a triennial review of TIP operations by an independent consultant.
In August 2011, we filed an annual report with the TRA reflecting the shared gas cost savings from gains and losses derived from gas purchase benchmarking and secondary market transactions for the twelve months ended June 30, 2011 under the TIP. In March 2012, the TRA approved our TIP account balance. The TRA issued its written order approving the deferred gas cost balances in April 2012.
In September 2011, we filed an annual report for the twelve months ended June 30, 2011 with the TRA that reflected the transactions in the deferred gas cost account for the ACA mechanism. In March 2012, the TRA approved the deferred gas cost account balances. The TRA issued its written order approving the deferred gas cost balances in April 2012.
In August 2012, we filed an annual report with the TRA reflecting the shared gas cost savings from gains and losses derived from gas purchase benchmarking and secondary market transactions for the twelve months ended June 30, 2012 under the TIP. In February 2013, the TRA approved the TIP account balances. The TRA issued its written order approving our TIP account balances in March 2013.
In September 2012, we filed an annual report for the twelve months ended June 30, 2012 with the TRA that reflected the transactions in the deferred gas cost account for the ACA mechanism. In February 2013, the TRA approved the deferred gas cost account balances. The TRA issued its written order approving the deferred gas cost balances in March 2013.
In December 2014, we filed an annual report for the twelve months ended June 30, 2013 with the TRA that reflected the transactions in the deferred gas cost account for the ACA mechanism. We are unable to predictwaiting on a ruling from the outcome of this proceedingTRA 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,August 2013, we filed an annual report with the TRA reflecting the shared gas cost savings from gains and losses derived from gas purchase benchmarking and secondary market transactions for the twelve months ended June 30, 2013 under
the TIP. In February 2014, the TRA Utilities Division Audit Staff (Audit Staff) submitted their report with which we concurred. In March 2014, the TRA approved and adopted the Audit Staff’s report. The TRA’s written order was issued in April 2014.
In August 2014, we filed an annual report with the TRA reflecting the shared gas cost savings from gains and losses derived from gas purchase benchmarking and secondary market transactions for the twelve months ended June 30, 2014 under the TIP. We are waiting on a ruling from the TRA at this time.
In August 2013, we filed an ACA petition with the TRA requestingto authorize us to make an adjustment to the deferred accounting treatmentgas cost account reporting for prior periods in the amount of a $3.7 million under collection. In November 2014, we filed a joint settlement agreement with the TRA staff and the Tennessee Attorney General's Consumer Advocate and Protection Division (CAD) in which the parties agreed that we may include in our next ACA filing prior period adjustments totaling $2 million in lieu of the $3.7 million as originally petitioned. In September 2014, we recorded as expense $1.7 million in the Consolidated Statements of Comprehensive Income. In December 2014, the TRA approved the settlement agreement, and we included the stipulated $2 million of prior period adjustments in the ACA annual report filed in December 2014 for the direct,twelve-month period ended June 30, 2013, as described above.
In September 2011, we filed a general rate application with the TRA requesting authority for an increase to rates and charges, proposed to be effective March 1, 2012. In addition, the petition also requested modifications of the cost allocation and rate designs underlying our existing rates, including shifting more of our cost recovery to our fixed charges and expanding the period of the WNA to October through April. We also sought approval to implement a school-based energy education program with appropriate cost recovery mechanisms, amortization of certain regulatory assets and deferred accounts, revised depreciation rates for plant and changes to the existing service regulations and tariffs. In December 2011, we and the CAD reached a stipulation and settlement agreement resolving all issues in this proceeding, including an increase in rates and charges to all customers effective March 1, 2012 designed to produce overall incremental expensesrevenues of $11.9 million annually, or 6.3% above the current annual revenue, based upon an approved rate of return on equity of 10.2%. The new cost allocation and rate designs shifted recovery of fixed charges from 29% to 37% with a resulting decrease of volumetric charges from 71% to 63%. The stipulation and settlement agreement did not include a cost recovery mechanism for a school-based energy education program. In January 2012, a hearing on this matter was held by the TRA. The TRA approved the settlement agreement at the January 2012 hearing. The TRA’s written order was issued in April 2012.
As a part of the rate case settlement mentioned above, the TRA approved the recovery of $1 million incurred as a result of our response to the severe flooding in Nashville in May 2010. The TRAThese direct incremental expenses had been approved our petitionfor deferred accounting treatment in October 2010. The balance in the deferred account is $1 million as of October 31, 2011 and 2010. We are seeking recovery of theseThese deferred expenses in the general rate applicationare being amortized over eight years beginning March 1, 2012 through February 2020.
In August 2013, we filed
a petition with the TRA
seeking authority to implement an IMR to recover the costs of our capital investments that are made in
compliance with federal and state safety and integrity management laws or regulations. We proposed that the rider be effective October 1, 2013 with an initial adjustment on January 1, 2014 of $13.1 million in annual margin revenue from tariff customers based on capital expenditures incurred through October 2013 and for rates to be updated annually outside of general rate cases for the return of and on these capital investments. In September
2011.2013, the TRA issued an order suspending this proposed tariff through December 30, 2013. In November 2013, we and the CAD filed an IMR settlement with the TRA. A hearing on this matter was held in December 2013, and the TRA approved the IMR settlement as filed for $13.1 million with the IMR rate adjustments beginning January 2014. A written order was issued in May 2014. In December 2014, we filed a petition with the TRA seeking authority to collect an additional $6.5 million in annual IMR margin revenues effective January 2015 based on $54 million of capital investments in integrity and safety projects over the twelve-month period ending October 31, 2014. We are waiting on a ruling from the TRA at this time.
In February 2014, we filed a petition with the TRA to authorize us to amortize and refund $4.7 million to customers for recorded excess deferred taxes. We proposed to refund this amount to customers over three years. We are waiting on a ruling from the TRA at this time.
In September 2014, we filed a petition with the TRA seeking authority to implement a compressed natural gas infrastructure rider to recover the costs of our capital investments in infrastructure and equipment associated with this alternative motor vehicle transportation fuel. We proposed that the tariff rider be effective October 1, 2014 with an initial rate adjustment on November 1, 2014 based on capital expenditures incurred through June 2014 and for rates to be updated annually outside of general rate cases for the return of and on these capital investments. In November 2014, the TRA consolidated this docket with a separate petition we filed seeking modifications to our tariff regarding service to customers using natural gas as a motor fuel. The TRA suspended the proposed tariffs through February 9, 2015. A hearing on this matter has been scheduled for January 12, 2015.
Due to the seasonal nature of our business, we contract with customers in the secondary market to sell supply and capacity assets when
available.market conditions permit. In North Carolina and South Carolina, we operate under sharing mechanisms approved by the NCUC and the PSCSC for secondary market transactions where 75% of the net margins are flowed through to jurisdictional customers in rates and 25% is retained by us. In Tennessee, we operate under the amended TIP where gas purchase benchmarking gains and losses are combined with secondary market transaction gains and losses and shared 75% by customers and 25% by us. Our share of net gains or losses in Tennessee is subject to an overall annual cap of $1.6 million. In all three jurisdictions for the twelve months ended October 31,
2011,2014, we generated
$56.1$97.6 million of margin from secondary market activity,
$42.1$72.2 million of which is allocated to customers as gas cost reductions and
$14$25.4 million as margin allocated to us. In all three jurisdictions for the twelve months ended October 31,
2010,2013, we generated
$42.8$35.9 million of margin from secondary market activity,
$32.1$26.9 million of which is allocated to customers as gas cost reductions and
$10.7$9 million as margin allocated to us. In all three jurisdictions for the twelve months ended October 31,
2009,2012, we generated
$46$38.7 million of margin from secondary market activity,
$34.5$29 million
of which is allocated to customers as gas cost reductions and
$11.5$9.7 million as margin allocated to us.
We currently have commission approval in all three states that place tighter credit requirements on the retail natural gas marketers that schedule gas
intofor transportation service on our system in order to mitigate the risk exposure to the financial condition of the marketers.
We compute basic earnings per share (EPS) using the
daily weighted average number of shares of common stock outstanding during each period.
SharesIn the calculation of fully diluted EPS, shares of common stock to be issued under approved incentive compensation plans are contingently issuable shares,
as determined by applying the treasury stock method, and are
includedadded to average common shares outstanding, resulting in
our calculation of fullya potential reduction in diluted
earnings per share.EPS.
A reconciliation of basic and diluted EPS,
which includes contingently issuable shares that could affect EPS if performance units ultimately vest or stock agreements settle, for the years ended October 31,
2011, 20102014, 2013 and
20092012 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 | |
|
| | | | | | | | | | | | |
| In thousands, except per share amounts | | 2014 | | 2013 | | 2012 |
| Net Income | | $ | 143,801 |
| | $ | 134,417 |
| | $ | 119,847 |
|
| | | | | | | |
| Average shares of common stock outstanding for basic earnings per share | | 77,883 |
| | 74,884 |
| | 71,977 |
|
| Contingently issuable shares under incentive compensation plans | | 310 |
| | 289 |
| | 301 |
|
| Contingently issuable shares under forward sale agreements | | — |
| | 160 |
| | — |
|
| Average shares of dilutive stock | | 78,193 |
| | 75,333 |
| | 72,278 |
|
| | | | | | | |
| Earnings Per Share of Common Stock: | | | | | | |
| Basic | | $ | 1.85 |
| | $ | 1.80 |
| | $ | 1.67 |
|
| Diluted | | $ | 1.84 |
| | $ | 1.78 |
| | $ | 1.66 |
|
Our long-term debt consists of privately placed senior notes issued under note purchase agreements, as well as publicly issued medium-term and senior notes issued under an indenture. All of our long-term debt is unsecured and is issued at fixed rates. Long-term debt as of October 31,
20112014 and
20102013 is as follows.
| | | | | | | | |
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 | |
| | | | | | | | |
|
| | | | | | | | |
| In thousands | | 2014 | | 2013 |
| Senior Notes: | | | | |
| 2.92%, due June 6, 2016 | | $ | 40,000 |
| | $ | 40,000 |
|
| 8.51%, due September 30, 2017 | | 35,000 |
| | 35,000 |
|
| 4.24%, due June 6, 2021 | | 160,000 |
| | 160,000 |
|
| 3.47%, due July 16, 2027 | | 100,000 |
| | 100,000 |
|
| 3.57%, due July 16, 2027 | | 200,000 |
| | 200,000 |
|
| 4.10%, due September 18, 2034 | | 250,000 |
| | — |
|
| 4.65%, due August 1, 2043 | | 300,000 |
| | 300,000 |
|
| Medium-Term Notes: | | | | |
| 5.00%, due December 19, 2013 | | — |
| | 100,000 |
|
| 6.87%, due October 6, 2023 | | 45,000 |
| | 45,000 |
|
| 8.45%, due September 19, 2024 | | 40,000 |
| | 40,000 |
|
| 7.40%, due October 3, 2025 | | 55,000 |
| | 55,000 |
|
| 7.50%, due October 9, 2026 | | 40,000 |
| | 40,000 |
|
| 7.95%, due September 14, 2029 | | 60,000 |
| | 60,000 |
|
| 6.00%, due December 19, 2033 | | 100,000 |
| | 100,000 |
|
| Total | | 1,425,000 |
| | 1,275,000 |
|
| Less current maturities | | — |
| | 100,000 |
|
| Less discount on issuance of notes * | | 570 |
| | 143 |
|
| Total | | $ | 1,424,430 |
| | $ | 1,174,857 |
|
* The discount on the 4.65% senior notes was $138 and $143 at October 31, 2014 and 2013, respectively. The discount on the 4.10% senior notes was $432 at October 31, 2014.
Current maturities for the next five years ending October 31 and thereafter are as follows.
| | | | |
In thousands | | | |
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 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.
|
| | | |
| In thousands | |
| 2015 | $ | — |
|
| 2016 | 40,000 |
|
| 2017 | 35,000 |
|
| 2018 | — |
|
| 2019 | — |
|
| Thereafter | 1,350,000 |
|
| Total | $ | 1,425,000 |
|
We redeemed all of the 6.25% insured quarterly notes on June 1, 2011, which had an aggregate principal balanceopen combined debt and equity shelf registration statement filed with the SEC in July 2011 that was available for future use until its expiration date of $196.8 million. We retiredJuly 6, 2014. In February 2013, we sold shares of common stock under this registration statement. For further information on this transaction, see Note 6 to the balance of $60consolidated financial statements.
On August 1, 2013, we issued $300 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 millionthirty-year, unsecured senior notes maturing in 2016 atwith an interest rate of 2.92%4.65% and $160 million unsecured seniorat a discount of .048% or $144,000, which we began to amortize ratably over the expected life of the notes, maturingunder the registration statement in 2021effect noted above. We have the option to redeem all or part of the notes before the stated maturity prior to February 1, 2043, at ana redemption price equal to the greater of a) 100% of the principal amount plus any accrued and unpaid interest rateto the date of 4.24%.redemption, or b) the sum of the present values of the remaining scheduled payments of principal and interest on the notes to be redeemed, discounted to the date of redemption on a semi-annual basis at the Treasury Rate as defined in the indenture, plus 15 basis points and any accrued and unpaid interest to the date of redemption. We have the option to redeem all or part of the notes before the stated maturity on or after February 1, 2043, at 100% of the principal amount plus any accrued and unpaid interest to the date of redemption. We used the net proceeds of $297.2 million from the sale of the senior notes to reduce our short-term borrowings usedthis issuance to finance the redemptioncapital expenditures, to repay $100 million of the 6.25% insured quarterlyour 5% medium-term notes as well asdue December 19, 2013 at maturity, to repay outstanding short-term notes under our unsecured commercial paper (CP) program and for other general corporate purposes and working capital needs.
On July 7, 2011,purposes.
In June 2014, we filed with the SEC a combined debt and equity shelf registration statement that became effective on the same date.June 6, 2014. The NCUC has approved debt and equity issuances under this shelf registration statement up to $1 billion during its three-year life. Unless otherwise specified at the time such securities are offered for sale, the net proceeds from the sale of the securities will be used to finance capital expenditures, to repay outstanding short-term, unsecured notes under our CP program, to refinance other indebtedness, to repurchase our common stock, to pay dividends and for general corporate purposes, includingpurposes.
On September 18, 2014, we issued $250 million of twenty-year, unsecured senior notes with an interest rate of 4.10% and at a discount of .174% or $435,000, which we began to amortize ratably over the expected life of the notes, under the registration statement in effect noted above. We have the option to redeem all or part of the notes before the stated maturity prior to March 18, 2034, at a redemption price equal to the greater of a) 100% of the principal amount plus any accrued and unpaid interest to the date of redemption, or b) the sum of the present values of the remaining scheduled payments of principal and interest on the notes to be redeemed, discounted to the date of redemption on a semi-annual basis at the Treasury Rate as defined in the indenture, plus 15 basis points and any accrued and unpaid interest to the date of redemption. We have the option to redeem all or part of the notes before the stated maturity on or after March 18, 2034, at 100% of the principal amount plus any accrued and unpaid interest to the date of redemption. We used the net proceeds of $247.7 million from this issuance to finance capital expenditures,
additions to
working capital and advances forrepay outstanding short-term, unsecured notes under our
investments in our subsidiaries,CP program 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.general corporate purposes.
The amount of cash dividends that may be paid on common stock is restricted by provisions contained in certain note agreements under which long-term debt was issued, with those for the senior notes being the most restrictive. We cannot pay or declare any dividends or make any other distribution on any class of stock or make any investments in subsidiaries or permit any subsidiary to do any of the above (all of the foregoing being “restricted payments”), except out of net earnings available for restricted payments. As of October 31,
2011,2014, our
retainednet earnings
were not restricted as the amount available for restricted payments
was greater than our actual retained earnings as presented below. | | | | |
In thousands | | | |
Amount available for restricted payments | | $ | 605,481 | |
Retained earnings | | | 550,584 | |
were $1.1 billion.
We are subject to default provisions related to our long-term debt and short-term
debt. Since there are cross default provisions in all of our debt agreements, failureborrowings. 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,
2011,2014, we are in compliance with all default provisions.
The default provisions of some or all of our senior debt include:
Failure to make principal or interest payments,
Bankruptcy, liquidation or insolvency,
Final judgment against us in excess of $1 million that after 60 days is not discharged, satisfied or stayed pending appeal,
Specified events under the Employee Retirement Income Security Act of 1974,
Change in control, and
Failure to observe or perform covenants, including:
Interest coverage of at least 1.75 times. Interest coverage was 4.29 times as of October 31, 2014;
Funded debt cannot exceed 70% of total capitalization. Funded debt was 58% of total capitalization as of October 31, 2014;
Funded debt of all subsidiaries in the aggregate cannot exceed 15% of total capitalization. There is no funded debt of our subsidiaries as of October 31, 2014;
Restrictions on permitted liens;
Restrictions on paying dividends, on or repurchasing our stock or making investments in subsidiaries; and
Restrictions on burdensome agreements.
5. Short-Term Debt Instruments
On January 25, 2011, we replaced our existing $450
We have an $850 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.on October 1, 2017. We pay an annual fee of $30,000$35,000 plus fifteen8.5 basis points for any unused amount up to $650 million.amount. The facility provides a line of credit for letters of credit of $10 million, of which $3.5$1.8 million wasand $2.1 million were 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 issued2014 and outstanding at October 31, 2010.2013, respectively. These letters of credit are used to guarantee claims from self-insurance under our general and automobile liability policies. The credit facility bears interest based on the 30-day LIBOR rateLondon Interbank Offered Rate (LIBOR) plus from 6575 to 150125 basis points, based on our credit ratings. Amounts borrowed remainare continuously renewable until the expiration of the facility in 2017 provided that we are in compliance with all terms of the agreement. See Note 4 to the consolidated financial statements for discussion of default provisions, including cross default provisions, in all of our debt agreements.
We have an $850 million unsecured CP program that is backstopped by the revolving syndicated credit facility. The amounts outstanding
until repaidunder the revolving syndicated credit facility and
dothe CP program, either individually or in the aggregate, cannot exceed $850 million. The notes issued under the CP program may have maturities not
mature daily.to exceed 397 days from the date of issuance and bear interest based on, among other things, the size and maturity date of the note, the frequency of the issuance and our credit ratings, plus a spread of 5 basis points. Any borrowings under the CP program rank equally with our other unsecured debt. The notes under the CP program are not registered and are offered and issued pursuant to an exemption from registration. Due to the seasonal nature of our business, amounts borrowed can vary significantly during the year.
Our
As of October 31, 2014, we had $355 million of notes outstanding short-term bank borrowings,under the CP program, as included in “Bank“Short-term debt” in “Current Liabilities” in the consolidated balance sheets, were $331 million, asConsolidated Balance Sheets, with original maturities ranging from 4 to 28 days from their dates 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 loansissuance at a weighted average interest rate of .94%.17%. As of October 31, 2013, our outstanding notes under the CP program, included in 2011 and .50% in 2010. Duringthe Consolidated Balance Sheets as stated above, were $400 million at a weighted average interest rate of .36%.
We did not have any borrowings under the revolving syndicated credit facility for the twelve months ended October 31, 2011,2014. A summary of the short-term borrowings ranged from $73.5 million to $426 million, and interest rates ranged from .51% to 1.17% when borrowing. debt activity under our CP program for the twelve months ended October 31, 2014 is as follows
|
| | | |
| In thousands | |
| Minimum amount outstanding | $ | 275,000 |
|
| Maximum amount outstanding | $ | 625,000 |
|
| Minimum interest rate | .10 | % |
| Maximum interest rate | .43 | % |
| Weighted average interest rate | .19 | % |
Our
three-yearfive-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%58% at October 31,
2011.2014.
6. Stockholders’ Equity
Capital Stock
and Accelerated Share Repurchase
Changes in common stock for the years ended October 31,
2011, 20102014, 2013 and
20092011 are as follows.
| | | | | | | | |
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 thousands | | Shares | | Amount |
| Balance, October 31, 2011 | | 72,318 |
| | $ | 446,791 |
|
| Issued to participants in the Employee Stock Purchase Plan (ESPP) | | 30 |
| | 894 |
|
| Issued to the Dividend Reinvestment and Stock Purchase Plan (DRIP) | | 677 |
| | 20,508 |
|
| Issued to participants in the Incentive Compensation Plan (ICP) | | 25 |
| | 796 |
|
| Shares repurchased under Accelerated Share Repurchase (ASR) agreement | | (800 | ) | | (26,528 | ) |
| Balance, October 31, 2012 | | 72,250 |
| | 442,461 |
|
| Issued to ESPP | | 33 |
| | 1,056 |
|
| Issued to DRIP | | 720 |
| | 22,791 |
|
| Issued to ICP | | 96 |
| | 3,065 |
|
| Issuance of common stock through public share offering, net of underwriting fees | | 3,000 |
| | 92,640 |
|
| Costs from issuance of common stock | | — |
| | (369 | ) |
| Balance, October 31, 2013 | | 76,099 |
| | 561,644 |
|
| Issued to ESPP | | 34 |
|
| 1,143 |
|
| Issued to DRIP | | 698 |
|
| 23,443 |
|
| Issued to ICP | | 100 |
|
| 3,315 |
|
| Issuance of common stock through forward sale agreements, net of expenses | | 1,600 |
|
| 47,290 |
|
| Balance, October 31, 2014 | | 78,531 |
| | $ | 636,835 |
|
In June 2004, the Board of Directors approved a Common Stock Open Market Purchase Program that authorized the repurchase of up to three million shares of currently outstanding shares of common stock. We implemented the program in
September 2004. We utilize a broker to repurchase the shares on the open market, and such shares are
cancelledcanceled and become authorized but unissued shares available for issuance under the ESPP, DRIP and ICP.
On December 16, 2005, the Board of Directors approved an increase in the number of shares in this program from three million to six million to reflect the two-for-one stock split in 2004. The Board also approved
onat that
datetime an amendment of the Common Stock Open Market Purchase Program to provide for the repurchase of up to four million additional shares of common stock to maintain our debt-to-equity capitalization ratios at target levels. These combined actions increased the total authorized share repurchases from three million to ten million shares. The additional four million shares were referred to as our ASR program. On March 6, 2009, the Board of Directors authorized the repurchase of up to an additional four million shares under the Common Stock Open Market Purchase Program and the ASR program, which were consolidated.
On January 10, 2011,29, 2013, we entered into an underwriting agreement under our open combined debt and equity shelf registration statement to sell up to 4.6 million shares of our common stock of which 3 million direct shares were issued and settled on February 4, 2013 with proceeds of $92.6 million received. The shares were purchased by the underwriters at the net price of $30.88 per share, the offering price to the public of $32 per share per the prospectus less an underwriting discount of $1.12 per share.
The remaining 1.6 million shares under this same underwriting agreement were under forward sale agreements (FSAs) with 1 million shares borrowed by a forward counterparty and sold to the underwriters for resale to the public on February 4, 2013 at the same price as the direct shares; the remaining .6 million shares were subject to a 30-day option by the underwriters to purchase these additional shares at the same price as the direct shares and would be, at our option, either issued at the time of purchase and delivered directly to the underwriters or borrowed and delivered to the underwriters by the forward counterparty. On February 19, 2013, the underwriters exercised their option to purchase the full additional .6 million shares of our common stock where the shares were borrowed from third parties and sold to the underwriters by the forward counterparty. Both of the FSAs had to be settled no later than mid-December 2013. Under the terms of these FSAs, at our election, we could physically settle in shares, cash or net share settle for all or a portion of our obligation under the agreements.
On December 16, 2013, we physically settled the FSAs by issuing 1.6 million shares of our common stock to the forward counterparty and received net proceeds of $47.3 million based on the net settlement price of $30.88 per share, the original offering price, less certain adjustments. We recorded this amount in "Stockholders' equity" as an addition to "Common stock" in the Consolidated Balance Sheets. Upon settlement, we used the net proceeds from these FSA transactions to finance capital expenditures, repay outstanding short-term, unsecured notes under our CP program and for general corporate purposes.
In accordance with ASC 815-40, Derivatives and Hedging - Contracts in Entity’s Own Equity, we classified the FSAs as equity transactions because the forward sale transactions were indexed to our own stock and physical settlement was within our control. As a result of this classification, no amounts were recorded in the consolidated financial statements until settlement of each FSA.
Upon physical settlement of the FSAs, delivery of our shares resulted in dilution to our EPS at the date of the settlement. In quarters prior to the settlement date, any dilutive effect of the FSAs on our EPS occurred during periods when the average market price per share of our common stock was above the per share adjusted forward sale price described above. See Note 3 to the consolidated financial statements for the dilutive effect of the FSAs on our EPS at October 31, 2013 with the inclusion of incremental shares in our average shares of dilutive stock as calculated under the treasury stock method.
On January 4, 2012, we entered into an ASR agreement where we purchased 800,000 shares of our common stock from an investment bank at the closing price that day of
$27.79$33.77 per share. The settlement and retirement of those shares occurred on January
11, 2011.5, 2012. Total consideration paid to purchase the shares of
$22.2$27 million was recorded in “Stockholders’ equity” as a reduction in “Common stock” in the
consolidated balance sheets.Consolidated Balance Sheets.
As part of the ASR, we simultaneously entered into a forward sale contract with the investment bank that was expected to mature in
4852 trading days, or March
18, 2011.21, 2012. Under the terms of the forward sale contract, the investment bank was required to purchase, in the open market, 800,000 shares of our common stock during the term of the contract to fulfill its obligation related to the shares it borrowed from third parties and sold to us. At settlement, we, at our option, were required to either pay cash or issue
registered or unregistered shares of our common stock to the investment bank if the investment bank’s weighted average purchase price, less a
$.10$.09 per
share discount, was higher than the initial purchaseJanuary 4, 2012 closing price. The investment bank was required to pay us either cash or shares of our common stock, at our option, if the investment bank’s weighted average price, less a $.10$.09 per share discount, for the shares purchased was lower than the initial purchase closing price. At settlement on March 21, 2011,February 28, 2012, we paid cash of $.8received $.5 million tofrom the investment bank and recorded this amount in “Stockholders’ equity” as a reduction ofan addition to “Common Stock”stock” in the consolidated balance sheets.Consolidated Balance Sheets. The $.8$.5 million was the difference between the investment bank’s
weighted average purchase price of
$28.8551$33.25 per share less a discount of
$.10$.09 per share for a settlement price of
$28.7551$33.16 per share and the initial purchase closing price of
$27.79$33.77 per share multiplied by 800,000 shares.
We had an ASR transaction in 2011 as presented in the table above with a similar structure with the investment bank, which was accounted for in the same manner.
As of October 31,
2011,2014, our shares of common stock were reserved for issuance as follows.
| |
| | |
In thousands | | | |
ESPP | 176 | | 273 |
|
DRIP | 840 | | 1,431 |
|
LTIP
ICP | 950 | | 901 |
|
ICP
Total | 1,966 | | 1,171 | |
| | | | |
Total
| | | 3,776 | |
| | | |
|
In late 2009, we discovered that we had inadvertently sold more shares under
Other Comprehensive Income (Loss)
Our OCIL is a part of our DRIP than were registered with the SECaccumulated OCIL and authorizedis comprised of hedging activities from our equity method investments. For further information on these hedging activities by our Boardequity method investments, see Note 12 to the consolidated financial statements. Beginning in 2014, another component of Directorsour accumulated OCIL is the allocation of retirement benefits to SouthStar Energy Services, LLC (SouthStar) by its majority member. Changes in each component of accumulated OCIL are presented below for issuance under the DRIP as well as having an expired registration statement. To correct these issuances, our Board of Directors ratified the authorizationyears ended October 31, 2014 and issuance2013.
|
| | | | | | | | |
Changes in Accumulated OCIL (1) |
| | | | | |
| In thousands | | 2014 | | 2013 |
| Accumulated OCIL beginning balance, net of tax | | $ | (284 | ) | | $ | (305 | ) |
| Hedging activities of equity method investments: | | | | |
| OCIL before reclassifications, net of tax | | 355 |
| | (109 | ) |
| Amounts reclassified from accumulated OCIL, net of tax | | (284 | ) | | 130 |
|
| Total current period activity of hedging activities of equity method investments, net of tax | | 71 |
| | 21 |
|
| Net current period benefit activities of equity method investments, net of tax | | (24 | ) | |
|
|
| Accumulated OCIL ending balance, net of tax | | $ | (237 | ) |
| $ | (284 | ) |
(1) Amounts in parentheses indicate debits to accumulated OCIL.
A reconciliation of the excess numbereffect on certain line items of shares, we filed a registration statementnet income on amounts reclassified out of each component of accumulated OCIL is presented below for the years ended October 31, 2014 and 2013.
|
| | | | | | | | | | |
| | | Reclassification Out of Accumulated OCIL (1) | | |
| | | |
|
| | | Years Ended | | |
| | | October 31 | | Affected Line Items on Statement of Comprehensive Income |
| In thousands | | 2014 | | 2013 | |
| Hedging activities of equity method investments | | $ | (461 | ) | | $ | 215 |
| | Income from equity method investments |
| Income tax expense | | 177 |
| | (85 | ) | | Income taxes |
| Hedging activities of equity method investments | | (284 | ) | | $ | 130 |
| | |
| Net benefit activities of equity method investments | | (40 | ) | | | | Income from equity method investments |
| Income tax expense | | 16 |
| | | | Income taxes |
| Net benefit activities of equity method investments | | (24 | ) | | | | |
| Total reclassification for the period, net of tax | | $ | (308 | ) | | $ | 130 |
| | |
(1) Amounts in 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 offeredparentheses indicate debits to rescind the purchase of the shares sold under the DRIP between December 1, 2008 and November 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 rescinded shares and consideration paid were immaterial. We reported these events to the relevant regulatory authorities, including the SEC and the NCUC. We have not been subjected to enforcement actions, penalties or fines by these regulatory authorities.accumulated OCIL.
7. Financial Instruments and Related Fair Value
Derivative Assets and Liabilities under Master Netting Arrangements
We maintain brokerage accounts to facilitate transactions that support our gas cost hedging plans. The accounting guidance related to derivatives and hedging requires that we use a gross presentation, based on our election, for the fair value amounts of our derivative
instruments and the fair value of the right to reclaim cash collateral.instruments. We use long position gas purchase options to provide some level of protection for our customers in the event of significant commodity price increases. As of October 31,
20112014 and
2010,2013, we had long gas purchase options providing total coverage of
38.129.2 million dekatherms and
33.525.4 million dekatherms, respectively. The long gas purchase options held at October 31,
20112014 are for the period from December
20112014 through
October 2012.November 2015.
We use financial instruments
that are not designated as hedges for accounting purposes to mitigate commodity price risk for our customers. We also have marketable securities that are held in
a rabbi
trusttrusts established for certain of our deferred compensation plans. In developing our fair value measurements of these financial instruments, we utilize market data or assumptions about risk and the risks inherent in the inputs to the valuation technique. Fair value refers to the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants in the market in which the entity transacts. We classify fair value balances based on the observance of those inputs into the fair value hierarchy levels as set forth in the fair value accounting guidance and fully described in “Fair Value Measurements” in Note 1 to the consolidated financial statements.
The following table sets forth, by level of the fair value hierarchy, our financial assets
and liabilities that were accounted for at fair value on a recurring basis as of October 31,
20112014 and
2010.2013. Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their consideration within the fair value hierarchy levels. We have had no transfers between any level during the years ended October 31,
20112014 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 | |
| | | | | | | | | | | | | | | | |
2013. We present our derivative positions at fair value on a gross basis and have only asset positions for all periods presented for the fair value of purchased call options held for our utility operations. There are no derivative contracts in a liability position, and we have posted no cash collateral nor received any cash collateral under our master netting arrangements. Therefore, we have no offsetting disclosures for financial assets or liabilities for our derivatives held for utility operations. Our derivatives held for utility operations are held with one broker as our counterparty.
|
| | | | | | | | | | | | | | | | | | | | |
| Recurring Fair Value Measurements as of October 31, 2014 |
| | | | | | | | | | | |
| | | | | Significant | | | | Effects of | | |
| | | Quoted Prices | | Other | | Significant | | Netting and | | |
| | | in Active | | Observable | | Unobservable | | Cash Collateral | | Total |
| | | Markets | | Inputs | | Inputs | | Receivables/ | | Carrying |
| In thousands | | (Level 1) | | (Level 2) | | (Level 3) | | Payables | | Value |
| Assets: | | | | | | | | | | |
| Derivatives held for distribution operations | | $ | 4,898 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 4,898 |
|
| Debt and equity securities held as trading securities: | | | | | | | | | | |
| Money markets | | 469 |
| | — |
| | — |
| | — |
| | 469 |
|
| Mutual funds | | 3,472 |
| | — |
| | — |
| | — |
| | 3,472 |
|
| Total fair value assets | | $ | 8,839 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 8,839 |
|
|
| | | | | | | | | | | | | | | | | | | | |
| Recurring Fair Value Measurements as of October 31, 2013 |
| | | | | | | | | | | |
| | | | | Significant | | | | Effects of | | |
| | | Quoted Prices | | Other | | Significant | | Netting and | | |
| | | in Active | | Observable | | Unobservable | | Cash Collateral | | Total |
| | | Markets | | Inputs | | Inputs | | Receivables/ | | Carrying |
| In thousands | | (Level 1) | | (Level 2) | | (Level 3) | | Payables | | Value |
| Assets: | | | | | | | | | | |
| Derivatives held for distribution operations | | $ | 1,834 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 1,834 |
|
| Debt and equity securities held as trading securities: | | | | | |
| | | | |
| Money markets | | 380 |
| | — |
| | — |
| | — |
| | 380 |
|
| Mutual funds | | 2,814 |
| | — |
| | — |
| | — |
| | 2,814 |
|
| Total fair value assets | | $ | 5,028 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 5,028 |
|
Our regulated utility segment derivative instruments are used in accordance with programs filed with or approved by the NCUC, the PSCSC and the TRA to hedge the impact of market fluctuations in natural gas prices. These derivative instruments are accounted for at fair value each reporting period. In accordance with regulatory requirements, the net
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
tofrom customers” or “Amounts due
fromto customers” in
Note 1 to the consolidated
balance sheets.financial statements. These derivative instruments
reflectare exchange-traded derivative contracts. Exchange-traded contracts are generally based on unadjusted quoted prices in active markets and are classified within Level 1.
Trading securities include assets in
a rabbi
trusttrusts established for our deferred compensation plans and are included in “Marketable securities, at fair value” in
“Noncurrent Assets” in the
consolidated balance sheets.Consolidated Balance Sheets. Securities classified within Level 1 include funds held in money market and mutual funds which are highly liquid and are actively traded on the exchanges.
Our long-term debt is recorded at unamortized cost. In developing the fair value of our long-term debt, we use a discounted cash flow technique, consistently applied, that incorporates a developed discount rate using long-term debt similarly rated by credit rating agencies combined with the U.S. Treasury
bench markbenchmark with consideration given to maturities, redemption terms and credit ratings similar to our debt issuances. The carrying amount and fair value of our long-term debt, including the current portion,
which is classified within Level 2, are shown below.
| | | | | | | | |
In thousands | | Carrying
Amount | | | Fair Value | |
As of October 31, 2011 | | $ | 675,000 | | | $ | 831,323 | |
As of October 31, 2010 | | | 731,922 | | | | 890,277 | |
|
| | | | | | | | |
| | | Carrying | | |
| In thousands | | Amount * | | Fair Value |
| As of October 31, 2014 | | $ | 1,425,000 |
| | $ | 1,617,453 |
|
| As of October 31, 2013 | | 1,275,000 |
| | 1,409,892 |
|
* Excludes discount on issuance of notes of $570 and $143 as of October 31, 2014 and 2013, respectively.
Quantitative and Qualitative Disclosures
The costs of our financial price hedging options for natural gas and all other costs related to hedging activities of our regulated gas costs are recorded in accordance with our regulatory tariffs approved by our state regulatory commissions, and thus are not accounted for as
designated hedging instruments under derivative accounting standards. As required by the accounting guidance, the fair value
amounts areof our financial options is presented on a gross basis
with only asset positions for all periods presented. There are no derivative contracts in a liability position, and
do not reflect any netting of asset and liability amounts orwe have posted no cash collateral
amountsnor received any cash collateral under
our master netting
arrangements.arrangements; therefore, we have no offsetting disclosures for financial assets or liabilities for our financial option derivatives.
The following table presents the fair value and balance sheet classification of our financial options for natural gas as of October 31,
20112014 and
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 | |
| | | | | | | | |
2013.
|
| | | | | | | | |
| Fair Value of Derivative Instruments |
| | | | | |
| In thousands | | 2014 | | 2013 |
| Derivatives Not Designated as Hedging Instruments under Derivative Accounting Standards: |
| Asset Financial Instruments: | | | | |
| Current Assets - Gas purchase derivative assets (December 2014 - November 2015) | | $ | 4,898 |
| | |
| Current Assets - Gas purchase derivative assets (December 2013 - October 2014) | | | | $ | 1,834 |
|
We purchase natural gas for our regulated operations for resale under tariffs approved by state regulatory commissions. We recover the cost of gas purchased for regulated operations through PGA procedures. Our risk management policies allow us to use financial instruments to hedge commodity price risks, but not for speculative trading. The strategy and objective of our hedging programs is to use these financial instruments to
provide some level of protection against significant price increases.reduce gas cost volatility for our customers. Accordingly, the operation of the hedging programs on the regulated utility segment as a result of the use of these financial derivatives
generally has no earnings impact.is initially deferred as amounts due from customers included as “Regulatory Assets” or amounts due to customers included as “Regulatory Liabilities” in Note 1 to the consolidated financial statements and recognized in the Consolidated Statements of Comprehensive Income as a component of “Cost of Gas” when the related costs are recovered through our rates.
The following table presents the impact that financial instruments not designated as hedging instruments under derivative accounting standards would have had on
our consolidated statementsthe Consolidated Statements of
incomeComprehensive Income for the twelve months ended October 31,
20112014 and
2010,2013, 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 |
|
| | | | | | | | | | | | | | | | | | |
| | | Amount of | | Amount of | | Location of Gain (Loss) |
| | | Gain (Loss) Recognized | | Gain (Loss) Deferred | | Recognized through |
| | | on Derivative Instruments | | Under PGA Procedures | | PGA Procedures |
| | | | | | | |
| | | Twelve Months Ended | | Twelve Months Ended | | |
| | | October 31 | | October 31 | | |
| In thousands | | 2014 | | 2013 | | 2014 | | 2013 | | |
| Gas purchase options | | $ | 6,162 |
| | $ | (6,303 | ) | | $ | 6,162 |
| | $ | (6,303 | ) | | Cost of Gas |
In Tennessee, the cost of gas purchase options and all other costs related to hedging activities up to 1% of total annual gas costs are approved for recovery under the terms and conditions of our TIP approved by the TRA. In South Carolina, the costs of gas purchase options are subject to
and are approved for recovery under the terms and conditions of our gas hedging plan approved by the PSCSC. In North Carolina,
the costs associated with our hedging program are treated as gas costs subject to an annual cost review proceeding by the NCUC.
Credit and Counterparty Risk
We are exposed to credit risk as a result of transactions for the purchase and sale of natural gas and related products and services and management agreements of our transportation capacity, storage capacity and supply contracts with major companies in the energy industry and within our utility operations serving industrial, commercial, power generation, residential and municipal energy consumers. These transactions principally occur in the eastern, gulf coast and mid-west regions of the United States. We believe that this geographic concentration does not contribute significantly to our overall exposure to credit risk. Credit risk associated with trade accounts receivable for the natural gas distribution segment is mitigated by the large number of individual customers and diversity in our customer base.
We enter into contracts with third parties to buy and sell natural gas. A significant portion of these transactions are with, or are associated with, energy producers, utility companies, off-system municipalities and natural gas marketers. The amount included in “Trade accounts receivable” in “Current Assets” in the Consolidated Balance Sheets attributable to these entities amounted to $3.5 million, or approximately 5% of our gross trade accounts receivable at October 31, 2014. Our policy requires counterparties to have an investment-grade credit rating at the time of the contract, or in situations where counterparties do not have investment-grade or functionally equivalent credit ratings, our policy requires credit enhancements that include letters of credit or parental guaranties. In either circumstance, our policy specifies limits on the contract amount and duration based on the counterparty’s credit rating and/or credit support. In order to minimize our exposure, we continually re-evaluate third-party creditworthiness and market conditions and modify our requirements accordingly.
We also enter into contracts with third parties to manage some of our supply and capacity assets for the purpose of maximizing their value. These arrangements include a counterparty credit evaluation according to our policy described above prior to contract execution and typically have durations of one year or less. In the event that a party is unable to perform under these arrangements, we have exposure to satisfy our underlying supply or demand contractual obligations that were incurred while under the management of this third party. We believe, based on our credit policies as of October 31, 2014, that our financial position, results of operations and cash flows will not be materially affected as a result of nonperformance by any single counterparty.
Natural gas distribution operating revenues and related trade accounts receivable are generated from state-regulated utility natural gas sales and transportation to over one million residential, commercial and industrial customers, including power generation and municipal customers, located in North Carolina, South Carolina and Tennessee. A change in economic conditions may affect the ability of customers to meet their obligations. We have mitigated our exposure to the risk of non-payment of utility bills by our customers. Gas costs related to uncollectible accounts are recovered through PGA procedures in all jurisdictions. To manage the non-gas cost customer credit risk, we evaluate credit quality and payment history and may require cash deposits from our high risk customers that do not satisfy our predetermined credit standards until a satisfactory payment history has been established. Significant increases in the price of natural gas and colder-than-normal weather can slow our collection efforts as customers experience increased difficulty in paying their gas bills, leading to higher than normal trade accounts receivable; however, we believe that our provision for possible losses on uncollectible trade accounts receivable is adequate for our credit loss exposure.
Our financial derivative instruments do not contain material credit-risk-related or other contingent features that could require us to make accelerated payments.
We seek to identify, assess, monitor and manage risk in accordance with defined policies and procedures under
anthe direction of the Treasurer and Chief Risk Officer and our Enterprise Risk Management
program. In addition, we have an(ERM) program, including our Energy Price Risk Management
Committee that monitors complianceCommittee. Risk management is guided by senior management with
our hedging programs,Board of Directors oversight, and senior management takes an active role in the development of policies and procedures.
8. Commitments and Contingent Liabilities
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,
2011, 20102014, 2013 and
20092012 are as follows.
| | | | | | | | | | | | | | |
In thousands | | 2011 | | | 2010 | | | 2009 | |
Operating lease payments | | $ | 4,496 | | | $ | 5,303 | | | | | $ | 6,173 | |
|
| | | | | | | | | | | | |
| In thousands |
| 2014 | | 2013 | | 2012 |
Operating lease payments (1) |
| $ | 4,701 |
| | $ | 4,729 |
| | $ | 3,712 |
|
(1) Operating lease payments do not include payments for common area maintenance, utilities or tax payments.
Future minimum lease obligations for the next five years ending October 31 and thereafter are as follows.
| | | | |
In thousands | | | |
2012 | | $ | 3,560 | |
2013 | | | 4,068 | |
2014 | | | 3,941 | |
2015 | | | 3,766 | |
2016 | | | 3,720 | |
Thereafter | | | 35,424 | |
| | | | |
Total | | $ | 54,479 | |
| | | | |
|
| | | |
| In thousands | |
| 2015 | $ | 4,600 |
|
| 2016 | 4,491 |
|
| 2017 | 4,297 |
|
| 2018 | 4,225 |
|
| 2019 | 4,137 |
|
| Thereafter | 27,359 |
|
| Total | $ | 49,109 |
|
We routinely enter into long-term gas supply commodity and capacity commitments and other agreements that commit future cash flows to acquire services we need in our business. These commitments include pipeline and storage capacity contracts and gas supply contracts to provide service to our customers and telecommunication and information technology contracts and other purchase obligations.
Costs arising from the gas supply commodity and capacity commitments, while significant, are pass-through costs to our customers and are generally fully recoverable through our PGA procedures and prudence reviews in North Carolina and South Carolina and under the TIP in Tennessee. The time periods for
fixed payments under pipeline and storage capacity contracts
range from oneare up to twenty-one years. The time periods for
fixed payments under gas supply contracts
range from oneare up to
under twothree years. The time periods for the telecommunications and technology outsourcing contracts, maintenance fees for hardware and software applications, usage fees, local and long-distance costs and wireless service
range from oneare up to
threefive years. Other purchase obligations consist primarily of commitments for pipeline products, vehicles,
equipment and contractors.
Certain storage and pipeline capacity contracts require the payment of demand charges that are based on rates approved by the
Federal Energy Regulatory Commission (FERC)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 statementsConsolidated Statements of
incomeComprehensive Income as part of gas purchases and included in
cost“Cost of
gas.Gas.”
As of October 31,
2011,2014, future unconditional purchase obligations for the next five years ending October 31 and thereafter are as follows.
| | | | | | | | | | | | | | | | | | | | |
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 | |
| | | | | | | | | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | |
| | | Pipeline | | Gas Supply | | Telecommunications | | | | |
| | | Storage | | Reservation | | and Information | | | | |
| In thousands | | Capacity | | Fees | | Technology | | Other | | Total |
| 2015 | | $ | 158,984 |
| | $ | 8,657 |
| | $ | 14,601 |
| | $ | 41,008 |
| | $ | 223,250 |
|
| 2016 | | 149,412 |
| | 137 |
| | 4,786 |
| | — |
| | 154,335 |
|
| 2017 | | 145,579 |
| | 135 |
| | 736 |
| | — |
| | 146,450 |
|
| 2018 | | 142,433 |
| | — |
| | 126 |
| | — |
| | 142,559 |
|
| 2019 | | 132,186 |
| | — |
| | 80 |
| | — |
| | 132,266 |
|
| Thereafter | | 627,602 |
| | — |
| | — |
| | — |
| | 627,602 |
|
| Total | | $ | 1,356,196 |
| | $ | 8,929 |
| | $ | 20,329 |
| | $ | 41,008 |
| | $ | 1,426,462 |
|
We have only routine litigation in the normal course of business. We do not expect any of these routine litigation matters to have a material effect,
either individually or in the aggregate, on our financial position, results of operations or cash flows.
We use letters of credit to guarantee claims from self-insurance under our general and automobile liability policies. We had
$3.5$1.8 million in letters of credit that were issued and outstanding at October 31,
2011.2014. Additional information concerning letters of credit is included in Note 5 to the consolidated financial statements.
Surety Bonds
In the normal course of business, we are occasionally required to provide financial commitments in the form of surety bonds to third parties as a guarantee of our performance on commercial obligations. We have agreements that indemnify certain issuers of surety bonds against losses that they may incur as a result of executing surety bonds on our behalf. If we were to fail to perform according to the terms of the underlying contract, any draws upon surety bonds issued on our behalf would then trigger our payment obligation to the surety bond issuer. As of October 31, 2014, we had open surety bonds with a total contingent obligation of $4.8 million.
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.recorded for manufactured gas plant (MGP) sites, LNG facilities and underground storage tanks (USTs).
In
October 1997, we entered into a settlement with a
third partythird-party with respect to nine
manufactured gas plant (MGP)MGP sites that we have owned, leased or operated that released us from any investigation and remediation liability. Although no such claims are pending or, to our knowledge, threatened, the settlement did not cover any third-party claims for personal injury, death, property damage and diminution of property value or natural resources.
There are four other MGP sites located in Hickory and Reidsville, North Carolina, Nashville, Tennessee and Anderson, South Carolina that we have owned, leased or operated. Remediation work on our Reidsville site under 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 conducted and completed the soil and groundwater remediation for 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 accordance with our site remediation plan. We have incurred $1.4 million of remediation costs on this site 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 (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 incurred $1.5 million of remediation costs through October 31, 2011.
In connection with the 2003 North Carolina Natural Gas Corporation (NCNG) acquisition, several MGP sites owned by NCNG were transferred to a
wholly ownedwholly-owned subsidiary of Progress Energy, Inc. (Progress)
, now a subsidiary of Duke Energy Corporation (Duke Energy), prior to closing. Progress has complete responsibility for performing all of NCNG’s remediation obligations to conduct testing and clean-up at these sites, including both the costs of such testing and clean-up and the implementation of any affirmative remediation obligations that NCNG has related to the sites. Progress’ responsibility does not include any third-party claims for personal injury, death, property damage, and diminution of property value or natural resources. We know of no such pending or threatened claims.
During 2008, we became aware of and began investigating soil and groundwater molecular sieve contamination concerns at
The following table summarizes information regarding 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 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 an amount that will be less than $100,000. We are currently negotiating the ACO. Plans to investigate the extent of the groundwater contamination related to the sieve burial are being developed and are tentatively scheduled to be implemented in the first quarter of our fiscal year 2012. The Huntersville LNG facility also was originally coated with lead-based paint. As a precautionary 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 twelve months ended October 31, 2011, we assessed the cost to remove lead-based paint at our Nashville LNG facility. Asenvironmental sites as of October 31, 2011,2014.
|
| | | | | | | | | | | | |
| | | | | | | Costs | | Undiscounted |
| | | Site | | | | Incurred | | Environmental |
| In thousands | | Type | | Site Status | | to Date | | Liability * |
| Anderson, SC | | MGP | | Site Investigation Work Plan submitted to the South Carolina Department of Health and Environmental Control. | | $ | 7 |
| | $ | 890 |
|
| Hickory, NC | | MGP | | Remediation complete. Land use restrictions in progress. | | 1,494 |
| | 18 |
|
| Reidsville, NC | | MGP | | Remediation complete. Land use restrictions filed. | | 641 |
| | 199 |
|
| Huntersville, NC | | LNG | | Soil remediation complete. Quarterly and semi-annual groundwater sampling in progress. Lead-based paint remediation complete. | | 4,738 |
| | 81 |
|
| Charlotte, NC | | UST | | USTs removed. Tank closure process in progress with the North Carolina Department of Environment and Natural Resources. | | 32 |
| | 33 |
|
| Clemmons, NC | | UST | | Potential responsible party for propane tank | | — |
| | 38 |
|
| Totals | | | | | | $ | 6,912 |
| | $ | 1,259 |
|
| | | | | | | | | |
| * Estimated based on assumptions using actual costs incurred, the timing of future payments and inflation factors, among others. |
We continue to expand our
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 for USTs for which we retain remediation responsibility is $.3 million.
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 UST site in Clemmons, North Carolina. We owned and operated this site from March 1986 until June 1988 in connection with a non-utility venture. There have been at least four owners of the site. We contractually transferred any clean-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 $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 liability for $36,135, one-fourth of the estimated cost.
Onesampling of our operating districts haspipelines for coatings containing asbestos on some of their pipelines. We have educatedasbestos. Additionally, we continue to educate our employees on the hazards of asbestos and implemented procedures for removing these coatings from our pipelines when we must excavate and expose 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, 2011,2014, our regulatory assets for unamortized environmental costs in our three-state territory totaled $9.6$8 million. We sought recovery ofreceived approval from the TRA to recover $2 million of our deferred Tennessee environmental costs over an eight-year period beginning March 2012, pursuant to the 2012 general rate case proceeding in the pending Tennessee rate case.Tennessee. We will seek recovery of the remaining Tennessee balance in future rate proceedings.
The approval by the NCUC in December 2013 of the settlement of the general rate proceeding allowed recovery of $6.3 million of our deferred North Carolina environmental costs over a five-year period beginning January 2014. We received approval from the PSCSC to recover $.1 million of our deferred South Carolina environmental costs over a one-year period beginning November 2014, pursuant to the annual rate stabilization order issued in October 2014.
Further evaluation of the MGP, LNG and UST sites
and removal of lead-based paint could significantly affect recorded amounts; however, we believe that the ultimate resolution of these matters will not have a material effect on our financial position, results of operations or cash flows.
9. Employee Benefit Plans
Effective January 1, 2008, we amended our noncontributory defined benefit pension plan, other postretirement employee benefits (OPEB) plan and our 401(k) plans. These amendments applied to nonunion employees and employees covered by the Carolinas bargaining unit contract. Effective January 1, 2009, these same amendments applied to all employees, including those covered by the Nashville, Tennessee bargaining unit contract.
Under
GAAP,accounting guidance, we are required to recognize all obligations related to defined benefit pension and
OPEBother postretirement employee benefits (OPEB) plans and quantify the plans’
fundingfunded status as an asset or liability on
our consolidated balance sheets.the Consolidated Balance Sheets. In accordance with accounting guidance, we measure the plans’ assets and obligations that determine our funded status as of the end of our fiscal year, October 31. We are required to recognize as a component of OCI the changes in the funded status that occurred during the year that are not recognized as part of net periodic benefit
cost under the authoritative guidance;cost; however, in 2006, we obtained regulatory treatment from the NCUC, the PSCSC and the TRA to record the amount that would have been recorded in accumulated OCI as a regulatory asset or liability as the future recovery of pension and OPEB costs is probable. To date, our regulators have allowed future recovery of our pension and
OBEBOPEB 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.
Our plans’ assets are required to be accounted for at fair value.
We have a noncontributory, tax-qualified defined benefit pension plan (qualified pension plan) for our eligible employees. A defined benefit plan specifies the amount of benefit that an eligible participant eventually will receive upon retirement using information about that participant. An employee became eligible on the January 1 or July 1 following either the date on which he or she attained age 30 or attained age 21 and completed 1,000 hours of service during the 12-month period commencing on the employment date. Plan benefits are generally based on credited years of service and the level of compensation during the five consecutive years of the last ten years prior to retirement or termination during which the participant received the highest compensation. Our policy is to fund the plan in an amount not in excess of the amount that is deductible for income tax purposes.
Effective January 1, 2008, theThe qualified pension plan
was amended for all employees not covered by the bargaining unit contract in Nashville, Tennessee to close the planis closed to employees hired after December 31,
2007 and to modify how benefits are accrued in the future for existing employees.2007. Employees hired prior to January 1, 2008 continue to participate in the
amended traditional qualified pension plan. Employees are vested after five years of service and can be credited with up to a total of 35 years of service. When a vested employee leaves the company, his benefit payment will be calculated as the greater of the accrued benefit as of December 31, 2007 under
the olda specific formula plus the accrued benefit
calculated under
the newa second formula for years of service after December 31, 2007, or the benefit for all years of service up to 35 years under the
newsecond formula.
These amendments were 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,debt, 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% withinin the fixed income portfolio
can be takenare fully collateralized. The investment guidelines limit liabilities created with derivatives
andin the
fixed income portfolio to cash equivalents plus 10% of the portfolio’s market value. The aggregate risk exposure of the plan can be no greater than that which could be achieved without using derivatives. The qualified pension plan maintains a 35% target allocation to equities, including exposure to large cap growth, large cap value and small cap domestic equity securities, as well as exposure to international equity. There is a 5% target allocation to real estate in a diversified global real estate investment trust (REIT) fund. The remaining 15% target allocation is for investments in other types of funds, including commodities, hedge funds and private equity funds that follow several diversified strategies.
Employees hired or rehired after December 31, 2007
(or December 31, 2008 for employees covered by the bargaining unit contract in Nashville, Tennessee) cannot participate in the
amended traditionalqualified pension plan but are participants in the Money Purchase Pension (MPP) plan, a defined contribution pension plan that allows the employee to direct the investments and assume the risk of investment returns. A defined contribution plan specifies the amount of the employer’s annual contribution to individual participant accounts established for the retirement benefit. Eligible employees who have completed 30 days of continuous service and have attained age 18 are eligible to participate. Under the MPP plan, we annually deposit a percentage of each participant’s pay into an account of the MPP plan. This contribution equals 4% of the participant’s compensation plus an additional 4% of compensation above the social security wage base up to the Internal Revenue Service (IRS) compensation limit. The participant is vested in this plan after three years of service. During the year ended October 31,
2011,2014, we contributed
$.3$.9 million to the MPP plan.
We provide certain postretirement health care and life insurance benefits to eligible retirees. The liability associated with such benefits is funded in irrevocable trust funds that can only be used to pay the benefits. Employees are first eligible to retire and receive these benefits at age 55 with ten or more years of service after the age of 45. Employees who met this requirement in 1993 or who retired prior to 1993 are in a “grandfathered” group for whom we pay the full cost of the retiree’s coverage. Retirees not in the grandfathered group have
80%a portion of the cost of retiree coverage paid by us, subject to certain annual contribution limits. Retirees are responsible for the full cost of dependent coverage. Effective January 1, 2008,
(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 are provided to those employees after age 65 when they are automatically eligible for Medicare benefits to
cover health costs. Our OPEB plan includes a defined dollar benefit to pay the premiums for Medicare Part D. Employees who meet the eligibility requirements to retire also receive a life insurance benefit. For employees who retire after July 1, 2005, this benefit is $15,000. The life insurance amount for employees who retired prior to this date was calculated as a percentage of their basic life insurance prior to retirement.
OPEB plan assets are comprised of mutual funds within a 401(h) and Voluntary Employees’ Beneficiary Association trusts. The investment philosophy is
the same assimilar to the qualified pension plan as discussed above. We target an OPEB allocation of 45% to fixed income securities, including U.S. treasuries, corporate bonds, high yield bonds and asset-backed securities. The OPEB plan maintains a 47% target allocation to equities, which includes exposure to large cap growth, large cap value and small cap domestic equity, as well as exposure to international equity. The OPEB plan maintains a 5% target allocation to real estate in a diversified global REIT fund and a 3% target allocation to cash. We do not have a concentration of assets in a single entity, industry, country, commodity or class of investment fund.
Supplemental Executive Retirement Plans
We have pension liabilities related to supplemental executive retirement plans (SERPs) for certain former employees, non-employee directors or
the surviving
spouse.spouses. There are no assets related to these SERPs, and no additional benefits accrue to the participants. Payments to the participants are made from operating funds during the year.
TheseActuarial information for these nonqualified plans
areis 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
We have a non-qualified defined contribution restoration plan (DCR plan)
, effective January 1, 2009. Benefits for all officers at the vice president level and above where benefits payable under the
new plan are informally funded
annually through a rabbi trust with a bank as the trustee. We contribute 13% of the total cash compensation (base salary, short-term incentive and MVP incentive) that exceeds the IRS compensation limit to the DCR plan account of each
covered executive.
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 the plan on January 1, 2009, of annual company contributions, and prospective five-year cliff vesting for the one-time opening balances of the four Vice Presidents. IfPresidents to compensate them for the officer severs employment before the expirationloss of the relevant five-year period, he or she receives nothing from that portion of thefuture benefits under this DCR plan. plan as compared with a terminated SERP.
Participants in the DCR plan may provide instructions to us for the deemed investment of their plan accounts. Distribution will occur upon separation of service or death of the participant.
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
We have a voluntary deferred compensation plan
effective January 1, 2009, for the benefit of all
director-level employees and officers,
and director-level employees.where we make no contributions to this plan. Benefits under this plan, known as the Voluntary Deferral Plan, are also informally funded
monthly through a rabbi trust with a bank as the trustee.
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,
20112014 and
2010,2013, and the amounts recorded as liabilities for these deferred compensation plans as of October 31,
20112014 and
20102013 are presented below.
| | | | | | | | |
In thousands | | 2011 | | | 2010 | |
Funding | | $ | 352 | | | $ | 444 | |
Liability: | | | | | | | | |
Current | | | 52 | | | | 5 | |
Noncurrent | | | 1,766 | | | | 1,293 | |
|
| | | | | | | | |
| In thousands | | 2014 | | 2013 |
| Funding | | $ | 524 |
| | $ | 434 |
|
| Liability: | | | | |
| Current | | 214 |
| | 199 |
|
| Noncurrent | | 4,248 |
| | 3,328 |
|
We provide term life insurance policies for
certain officers at the vice president level and above who were
former participants in
the former SERP thata terminated
on October 31, 2008;SERP; the level of the insurance benefit is dependent upon the
positionlevel of the
officer.benefit provided under the terminated SERP. These life insurance policies are owned exclusively by each officer. Premiums on these policies are paid and
expensed, as grossed up for taxes to the individual officer. Beginning on December 1, 2008, weexpensed. We also provide a term life insurance benefit equal to $200,000 to all officers and director-level employees for which we bear the cost of the policies. The cost of these premiums is presented below.
| | | | | | | | | | | | |
In thousands | | 2011 | | | 2010 | | | 2009 | |
Term life policies of former SERP officers | | $ | 56 | | | $ | 57 | | | $ | 59 | |
Officers and director-level employees | | | 24 | | | | 24 | | | | 20 | |
|
| | | | | | | | | | | | |
| In thousands | | 2014 | | 2013 | | 2012 |
| Term life policies of certain officers at the vice president level and above | | $ | 30 |
| | $ | 27 |
| | $ | 43 |
|
| Officers and director-level employees | | 32 |
| | 28 |
| | 25 |
|
Actuarial Plan Information
A reconciliation of changes in the plans’ benefit obligations and fair value of assets for the years ended October 31,
20112014 and
2010,2013, and a statement of the funded status and the amounts reflected in the
consolidated balance sheetsConsolidated Balance Sheets for the years ended October 31,
20112014 and
20102013 are presented below.
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | 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 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | Qualified Pension | | Nonqualified Pension | | Other Benefits |
| In thousands | | 2014 | | 2013 | | 2014 | | 2013 | | 2014 | | 2013 |
| Accumulated benefit obligation at year end | | $ | 252,706 |
| | $ | 230,175 |
| | $ | 5,925 |
| | $ | 4,736 |
| | N/A |
| | N/A |
|
| | | | | | | | | | | | | |
| Change in projected benefit obligation: | |
| | | |
| | | |
| | |
| Obligation at beginning of year | | $ | 272,403 |
| | $ | 293,327 |
| | $ | 4,736 |
| | $ | 5,569 |
| | $ | 33,678 |
| | $ | 34,830 |
|
| Service cost | | 10,865 |
| | 12,005 |
| | — |
| | — |
| | 1,109 |
| | 1,327 |
|
| Interest cost | | 11,781 |
| | 9,946 |
| | 200 |
| | 157 |
| | 1,448 |
| | 1,130 |
|
| Plan amendments | | — |
| | — |
| | 485 |
| | — |
| | — |
| | — |
|
| Actuarial (gain) loss | | 23,646 |
| | (24,859 | ) | | 956 |
| | (540 | ) | | 3,734 |
| | (1,094 | ) |
| Participant contributions | | — |
| | — |
| | — |
| | — |
| | 805 |
| | 641 |
|
| Administrative expenses | | (465 | ) | | (534 | ) | | — |
| | — |
| | — |
| | — |
|
| Benefit payments | | (15,544 | ) | | (17,482 | ) | | (452 | ) | | (450 | ) | | (2,957 | ) | | (3,156 | ) |
| Obligation at end of year | | 302,686 |
| | 272,403 |
| | 5,925 |
| | 4,736 |
| | 37,817 |
| | 33,678 |
|
| Change in fair value of plan assets: | |
| | | |
| | | |
| | |
| Fair value at beginning of year | | 300,661 |
| | 272,337 |
| | — |
| | — |
| | 25,961 |
| | 23,663 |
|
| Actual return on plan assets | | 31,791 |
| | 26,340 |
| | — |
| | — |
| | 1,874 |
| | 2,848 |
|
| Employer contributions | | 20,000 |
| | 20,000 |
| | 452 |
| | 450 |
| | 2,064 |
| | 1,965 |
|
| Participant contributions | | — |
| | — |
| | — |
| | — |
| | 805 |
| | 641 |
|
| Administrative expenses | | (465 | ) | | (534 | ) | | — |
| | — |
| | — |
| | — |
|
| Benefit payments | | (15,544 | ) | | (17,482 | ) | | (452 | ) | | (450 | ) | | (2,957 | ) | | (3,156 | ) |
| Fair value at end of year | | 336,443 |
| | 300,661 |
| | — |
| | — |
| | 27,747 |
| | 25,961 |
|
| Funded status at year end - over (under) | | $ | 33,757 |
| | $ | 28,258 |
| | $ | (5,925 | ) | | $ | (4,736 | ) | | $ | (10,070 | ) | | $ | (7,717 | ) |
| | | | | | | | | | | | | |
| Noncurrent assets | | $ | 33,757 |
| | $ | 28,258 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Current liabilities | | — |
| | — |
| | (521 | ) | | (445 | ) | | — |
| | — |
|
| Noncurrent liabilities | | — |
| | — |
| | (5,404 | ) | | (4,291 | ) | | (10,070 | ) | | (7,717 | ) |
| Net amount recognized | | $ | 33,757 |
| | $ | 28,258 |
| | $ | (5,925 | ) | | $ | (4,736 | ) | | $ | (10,070 | ) | | $ | (7,717 | ) |
| | | | | | �� | | | | | | | |
| Amounts Not Yet Recognized as a Component | | | | | | | | | | | | |
| of Cost and Recognized in a Deferred | | | | | | | | | | | | |
| Regulatory Account: | | | | | | | | | | | | |
| Unrecognized transition obligation | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Unrecognized prior service credit (cost) | | 15,046 |
| | 17,243 |
| | (439 | ) | | (196 | ) | | — |
| | — |
|
| Unrecognized actuarial loss | | (103,038 | ) | | (96,338 | ) | | (1,745 | ) | | (820 | ) | | (3,995 | ) | | (354 | ) |
| Regulatory asset | | (87,992 | ) | | (79,095 | ) | | (2,184 | ) | | (1,016 | ) | | (3,995 | ) | | (354 | ) |
| Cumulative employer contributions in | |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| excess of cost | | 121,749 |
| | 107,353 |
| | (3,741 | ) | | (3,720 | ) | | (6,075 | ) | | (7,363 | ) |
| Net amount recognized | | $ | 33,757 |
| | $ | 28,258 |
| | $ | (5,925 | ) | | $ | (4,736 | ) | | $ | (10,070 | ) | | $ | (7,717 | ) |
In 2006 with the implementation of accounting guidance for employers’ accounting for defined benefit pension and other postretirement plans, the NCUC, the PSCSC and the TRA approved our request to place certain defined benefit postretirement obligations in a deferred regulatory account instead of
OCIOCIL as presented above. The regulators have allowed future recovery of our pension and OPEB costs to this date.
Net periodic benefit cost for the years ended October 31,
2011, 20102014, 2013 and
20092012 includes the following components.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | 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 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Qualified Pension | | Nonqualified Pension | | Other Benefits |
| In thousands | | 2014 | | 2013 | | 2012 | | 2014 | | 2013 | | 2012 | | 2014 | | 2013 | | 2012 |
| Service cost | | $ | 10,865 |
| | $ | 12,005 |
| | $ | 9,573 |
| | $ | — |
| | $ | — |
| | $ | 39 |
| | $ | 1,109 |
| | $ | 1,327 |
| | $ | 1,387 |
|
| Interest cost | | 11,781 |
| | 9,946 |
| | 10,640 |
| | 200 |
| | 157 |
| | 203 |
| | 1,448 |
| | 1,130 |
| | 1,347 |
|
| Expected return on plan assets | | (22,530 | ) | | (21,105 | ) | | (20,289 | ) | | — |
| | — |
| | — |
| | (1,782 | ) | | (1,663 | ) | | (1,551 | ) |
| Amortization of transition obligation | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 667 |
| | 667 |
|
| Amortization of prior service cost | |
|
| | | | | |
|
| | | | | |
|
| | | | |
| (credit) | | (2,198 | ) | | (2,198 | ) | | (2,198 | ) | | 243 |
| | 81 |
| | 81 |
| | — |
| | — |
| | — |
|
| Amortization of net loss | | 7,685 |
| | 11,202 |
| | 5,966 |
| | 31 |
| | 161 |
| | 49 |
| | — |
| | — |
| | — |
|
| Net periodic benefit cost | | 5,603 |
| | 9,850 |
| | 3,692 |
| | 474 |
| | 399 |
| | 372 |
| | 775 |
| | 1,461 |
| | 1,850 |
|
| Other changes in plan assets and benefit | |
| | | | | |
| | | | | |
| | | | |
| obligation recognized through | |
| | | | | |
| | | | | |
| | | | |
| regulatory asset or liability: | |
| | | | | |
| | | | | |
| | | | |
| Prior service cost | | — |
| | — |
| | — |
| | 485 |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Net loss (gain) | | 14,385 |
| | (30,094 | ) | | 43,945 |
| | 956 |
| | (540 | ) | | 629 |
| | 3,641 |
| | (2,278 | ) | | 2,209 |
|
| Amounts recognized as a component of | |
| | | | | |
| | | | | |
| | | | |
| net periodic benefit cost: | |
| | | | | |
| | | | | |
| | | | |
| Transition obligation | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (667 | ) | | (667 | ) |
| Amortization of net loss | | (7,685 | ) | | (11,202 | ) | | (5,966 | ) | | (31 | ) | | (161 | ) | | (49 | ) | | — |
| | — |
| | — |
|
| Prior service (cost) credit | | 2,198 |
| | 2,198 |
| | 2,198 |
| | (243 | ) | | (81 | ) | | (81 | ) | | — |
| | — |
| | — |
|
| Total recognized in regulatory asset | |
|
| | | | | |
|
| | | | | |
|
| | | | |
| (liability) | | 8,898 |
| | (39,098 | ) | | 40,177 |
| | 1,167 |
| | (782 | ) | | 499 |
| | 3,641 |
| | (2,945 | ) | | 1,542 |
|
| Total recognized in net periodic benefit | |
|
| | | | | |
|
| | | | | |
|
| | | | |
| and regulatory asset (liability) | | $ | 14,501 |
| | $ | (29,248 | ) | | $ | 43,869 |
| | $ | 1,641 |
| | $ | (383 | ) | | $ | 871 |
| | $ | 4,416 |
| | $ | (1,484 | ) | | $ | 3,392 |
|
The
20122015 estimated amortization of the following items
for our plans, which are recorded as a regulatory asset or liability instead of accumulated
OCIOCIL discussed above,
and expected refunds for our plans are as follows.
| | | | | | | | | | | | |
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 | |
|
| | | | | | | | | | | | |
| | | Qualified | | Nonqualified | | Other |
| In thousands | | Pension | | Pension | | Benefits |
| Amortization of unrecognized prior service (credit) cost | | $ | (2,198 | ) | | $ | 231 |
| | $ | — |
|
| Amortization of unrecognized actuarial loss | | 8,121 |
| | 85 |
| | 29 |
|
The discount rate has been separately determined for each plan by projecting the plan’s cash flows and developing a zero-coupon spot rate yield curve using non-arbitrage pricing and
non-callable bonds rated AA or better by either Moody’s Investors Service’s
AA or
better-rated non-callable bondsStandard & Poor’s Ratings Services that
produces similar results tohave a
hypothetical bond portfolio.yield higher than the regression mean yield curve. The discount rate can vary from plan year to plan year. As of October 31,
2011,2014, the benchmark by plan was as follows.
| |
| | |
Pension plan | | | 4.674.13 | % |
NCNG SERP | | | 4.013.64 | % |
Directors’ SERP | | | 4.263.74 | % |
Piedmont SERP | | | 3.503.10 | % |
OPEB | | | 4.364.03 | % |
Equity market performance has a significant effect on our market-related value of plan assets. In determining the market-related value of plan assets, we use the following methodology: The asset gain or loss is determined each year by comparing the fund’s actual return to the expected return, based on the disclosed expected return on investment assumption. Such asset gain or loss is then recognized ratably over a five-year period. Thus, the market-related value of assets as of year end is determined by adjusting the market value of assets by the portion of the prior five years’ gains or losses that has not yet been recognized, meaning that 20% of the prior five years’ asset gains and losses are recognized each year. This method has been applied consistently in all years presented in the consolidated financial statements.
We amortize unrecognized prior-service cost over the average remaining service period for active employees. We amortize the unrecognized transition obligation over the average remaining service period for active employees expected to receive benefits under the plan as of the date of transition. We amortize gains and losses in excess of 10% of the greater of the benefit obligation and the market-related value of assets over the average remaining service period for active employees. The
amortization period used for the purposes mentioned above for the NCNG SERP and the Piedmont SERP is an expected future lifetime as there are no active members in these plans. The method of amortization in all cases is straight-line.
The weighted average assumptions used in the measurement of the benefit obligation as of October 31,
20112014 and
20102013 are presented below.
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | 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 | |
|
| | | | | | | | | | | | | | | | | | |
| | | Qualified Pension | | Nonqualified Pension | | Other Benefits |
| | | 2014 | | 2013 | | 2014 | | 2013 | | 2014 | | 2013 |
| Discount rate | | 4.13 | % | | 4.55 | % | | 3.69 | % | | 3.98 | % | | 4.03 | % | | 4.44 | % |
| Rate of compensation increase | | 3.68 | % | | 3.72 | % | | N/A |
| | N/A |
| | N/A |
| | N/A |
|
In addition to the assumptions in the above table, we also use subjective factors such as withdrawal and mortality rates in determining benefit obligations for all of our benefit plans. As of October 31, 2014, we updated our assumed mortality rates to incorporate the new set of mortality tables issued by the Society of Actuaries in October 2014.
The weighted average assumptions used to determine the net periodic benefit cost as of October 31,
2011, 20102014, 2013 and
20092012 are presented below.
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | 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 | |
|
| | | | | | | | | | | | | | | | | | |
| | | Qualified Pension | | Nonqualified Pension |
| | | 2014 | | 2013 | | 2012 | | 2014 | | 2013 | | 2012 |
| Discount rate | | 4.55 | % | | 3.51 | % | | 4.67 | % | | 3.98 | % | | 2.95 | % | | 4.10 | % |
| Expected long-term rate of return on plan assets | | 7.75 | % | | 8.00 | % | | 8.00 | % | | N/A |
| | N/A |
| | N/A |
|
| Rate of compensation increase | | 3.72 | % | | 3.76 | % | | 3.78 | % | | N/A |
| | N/A |
| | N/A |
|
| | | | | | | | | | | | | |
| | | Other Benefits | | |
| | | 2014 | | 2013 | | 2012 | |
| Discount rate | | 4.44 | % | | 3.34 | % | | 4.36 | % | |
| Expected long-term rate of return on plan assets | | 7.75 | % | | 8.00 | % | | 8.00 | % | |
| Rate of compensation increase | | N/A |
| | N/A |
| | N/A |
| |
We anticipate that we will contribute the following amounts to our plans in
2012. | | | | |
In thousands
| | | |
Qualified pension plan
| | $ | — | |
Nonqualified pension plans
| | | 517 | |
MPP plan
| | | 535 | |
OPEB plan
| | | 1,600 | |
2015.
|
| | | |
| In thousands | |
| Qualified pension plan * | $ | 10,000 |
|
| Nonqualified pension plans | 521 |
|
| MPP plan | 1,300 |
|
| OPEB plan | 1,500 |
|
* Funded in November 2014.
The Pension Protection Act of 2006 (PPA) specified funding requirements for single employer defined benefit pension plans. The PPA established a 100% funding target for plan years beginning after December 31, 2007, and we are in compliance.
Benefit payments, which reflect expected future service, as appropriate, are expected to be paid for the next ten years ending October 31 as follows.
| | | | | | | | | | | | |
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 | |
|
| | | | | | | | | | | | |
| | | Qualified | | Nonqualified | | Other |
| In thousands | | Pension | | Pension | | Benefits |
| 2015 | | $ | 29,946 |
| | $ | 521 |
| | $ | 2,409 |
|
| 2016 | | 16,794 |
| | 507 |
| | 2,449 |
|
| 2017 | | 16,332 |
| | 491 |
| | 2,527 |
|
| 2018 | | 19,197 |
| | 472 |
| | 2,606 |
|
| 2019 | | 20,685 |
| | 490 |
| | 2,682 |
|
| 2020 - 2024 | | 110,459 |
| | 2,149 |
| | 14,179 |
|
The assumed health care cost trend rates used in measuring the accumulated OPEB obligation for the medical plans for all participants as of October 31,
20112014 and
20102013 are presented below.
| | | | | | | | |
| | | 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 | |
|
| | | | | | |
| | | 2014 | | 2013 |
| Health care cost trend rate assumed for next year | | 7.40 | % | | 7.40 | % |
| Rate to which the cost trend is assumed to decline (the ultimate trend rate) | | 5.00 | % | | 5.00 | % |
| Year that the rate reaches the ultimate trend rate | | 2027 |
| | 2027 |
|
The health care cost trend rate assumptions could have a significant effect on the amounts reported. A change of 1% would have the following effects.
| | | | | | | | |
In thousands | | 1% Increase | | | 1% Decrease | |
Effect on total of service and interest cost components of net periodic postretirement health care benefit cost for the year ended October 31, 2011 | | $ | 37 | | | $ | (38 | ) |
Effect on the health care cost component of the accumulated postretirement benefit obligation as of October 31, 2011 | | | 693 | | | | (706 | ) |
|
| | | | | | | | |
| In thousands | | 1% Increase | | 1% Decrease |
| Effect on total of service and interest cost components of net periodic | | | | |
| postretirement health care benefit cost for the year ended October 31, 2014 | | $ | 31 |
| | $ | (32 | ) |
| Effect on the health care cost component of the accumulated postretirement | | | | |
| benefit obligation as of October 31, 2014 | | 829 |
| | (841 | ) |
Mutual funds are valued at the quoted NAV per share, which is computed as of the close of business on our balance sheet date. Mutual funds with a publicly quoted NAV per share are classified as Level 1; mutual funds with a NAV per share that is not publicly available are classified as Level 2.
Following is a description of the valuation methodologies used for assets measured at fair value in our qualified pension plan.
Cash and cash equivalents – These are Level 1 assets valued at face value as they are primarily cash or cash equivalents. The assets that are Level 2 assets have been valued at the market value of the shares held by the plan at the valuation date for a money market mutual fund.
U.S. treasuries – These are Level 2 assets whose values are based on observable market information including quotes from a quotation reporting system, established market makers or pricing services. This asset class includes long duration fixed income investments.
Long duration bonds – These are Level 2 assets in an actively managed private series long duration fixed income fund valued using pricing models that consider various observable inputs, such as benchmark yields, reported trades, broker quotes and issuer spreads.
Corporate bonds, collateralized mortgage obligations, municipals – These are Level 2 assets valued based on primarily observable market information or broker quotes on a non-active market. This class includes long duration fixed income investments.
High yield bonds – These are Level 1 assets valued at the quoted NAV of high yield fixed income mutual fund shares.
Derivatives – The Level 1 assets were valued using a compilation of observable market information on an active market. The Level 2 assets were valued using broker quotes on a non-active market.
Large cap core index – These are Level 1 assets valued at the quoted NAV of the low-cost equity index mutual fund that tracks the Standard & Poor’s 500 Stock Index (S&P 500 Index).
Large cap value and small cap value – These are Level 1 assets valued at the market price of the active market on which the individual security is traded.
Large cap growth and global REIT – These are Level 1 assets valued at the quoted NAV of mutual fund shares in managed equity funds.
Common trust funds – International growth and bank loans (and for 2013, international value) – These are Level 2 assets held in common trust funds in which we own interests that are valued at the NAV of the funds as traded on international exchanges. Currently there are no restrictions on redemptions for the funds.
Hedge fund of funds – This is a Level 2 asset with the value of our investment based on the estimated fair value of the underlying holdings in the portfolio at a NAV. These investments are across a variety of markets through investment funds or managed accounts that invest in equities, equity-related instruments, fixed income and other debt-related instruments. Currently there are no restrictions on redemptions for the fund.
Private equity fund of funds – This is a Level 3 asset invested in hedge fund of funds valued based on a quarterly compilation of the financial statements from the underlying partnerships in which the fund invests. There are currently redemption restrictions for this fund. The target allocation for this investment is 3.5% but is still being funded through capital calls; $5.4 million of the original $12 million subscription remains unfunded. Until a 3.5% allocation can be achieved, the balance of the 3.5% allocation is invested in a low-cost equity index fund that tracks the S&P 500 Index. Our investment is in various funds that invests in North American companies; allocate capital to private equity funds; invest in venture capital partnerships; and private equity partnerships in emerging markets.
Commodities fund of funds – This is a Level 2 asset with the value of our investment based on the estimated fair value of the various holdings in the portfolio as reported in the financial statements at a NAV. Currently there are no restrictions on redemptions for the fund. These investments are in commodities fund of funds that are actively managed through a well-diversified group of underlying managers.
As stated above, some of our investments for the qualified pension plan have redemption limitations, restrictions and notice requirements which are further explained below.
|
| | | | | | |
| | | | | | Redemptions |
| | Redemption | | | | Notice |
| Investment | | Frequency | | Other Redemption Restrictions | | Period |
Common trust fund - International growth | | Monthly | | None | | 30 days |
| | | |
| Hedge fund of funds | | Quarterly | | Redeemed in whole or part but not less than the minimum redemption amount for each currency. Redemption within one year of purchase is subject to 1.5% redemption fee. Redeemed on “first in first out” basis. None of our investment is subject to the redemption fee. Fund’s Board of Directors may limit or suspend share redemptions until a further notification ending suspension. No such notification has been received as of October 31, 2014. | | 65 days |
| | | |
| Private equity fund of funds | | Limited | | Investors have only very limited withdrawal rights for specific legal or regulatory reasons. Any transfer of interest will be subject to approval. | | (1) |
| | | |
| Commodities fund of funds | | Monthly | | Redemption within one year of purchase is subject to 1% redemption fee. None of our investment is subject to the redemption fee. If 95% or more of the balance is requested, 95% of the balance will be paid within 30 days. Any outstanding balance or interest owed will be paid after the annual audit is complete. | | 35 days |
| | | | | | |
| Bank loans | | Daily | | None | | 30 days |
(1) The investment cannot be redeemed. We receive distributions only through the liquidation of the underlying assets. The assets are expected to be liquidated over the next 10 to 12 years.
The qualified pension plan’s asset allocations by level within the fair value hierarchy at October 31, 20112014 and 20102013 are presented below. Our assessment of the significance of a particular input to the fair value measurement requires judgment
and may affect the valuation of fair value assets and their consideration within the fair value hierarchy levels. For further information on a description of the fair value hierarchy, see “Fair Value Measurements” in Note 1 to the consolidated financial statements.
|
| | | | | | | | | | | | | | | | | | | |
| | | Qualified Pension Plan as of October 31, 2014 |
| | | |
| Significant Other Observable Inputs(Level 2) |
|
|
|
|
|
|
| | | Quoted Prices In Active Markets (Level 1) |
|
| Significant Unobservable Inputs (Level 3) |
|
|
|
|
| | |
|
|
|
|
|
|
| | |
|
|
| Total Carrying Value |
| % of Total |
| In thousands | |
|
|
|
|
| Cash and cash equivalents | | $ | 27,932 |
| | $ | 435 |
| | $ | — |
| | $ | 28,367 |
| | 8 | % |
| Fixed Income Securities: | | | | | | | | | | 45 | % |
| U.S. treasuries | | — |
| | 27,224 |
| | — |
| | 27,224 |
| | 8 | % |
| Long duration bonds | | — |
| | 48,049 |
| | — |
| | 48,049 |
| | 14 | % |
| Corporate bonds | | — |
| | 49,816 |
| | — |
| | 49,816 |
| | 15 | % |
| High yield bonds | | 8,100 |
| | — |
| | — |
| | 8,100 |
| | 3 | % |
| Common trust fund - Bank loans | | — |
| | 16,187 |
| | — |
| | 16,187 |
| | 5 | % |
| Collateralized mortgage | | | | | | | | | | |
| obligations | | — |
| | 1,035 |
| | — |
| | 1,035 |
| | — | % |
| Derivatives | | 48 |
| | (49 | ) | | — |
| | (1 | ) | | — | % |
| Equity Securities: | | | | | | | | | | 31 | % |
| Large cap core index | | 9,982 |
| | — |
| | — |
| | 9,982 |
| | 3 | % |
| Large cap value | | 19,937 |
| | — |
| | — |
| | 19,937 |
| | 6 | % |
| Large cap growth | | 19,745 |
| | — |
| | — |
| | 19,745 |
| | 6 | % |
| Small cap value | | 31,329 |
| | — |
| | — |
| | 31,329 |
| | 9 | % |
| Common trust fund - International | | | | | | | | | | |
| growth | | — |
| | 22,877 |
| | — |
| | 22,877 |
| | 7 | % |
| Real Estate: | | | | | | | | | | 5 | % |
| Global REIT | | 16,675 |
| | — |
| | — |
| | 16,675 |
| | 5 | % |
| Other Investments: | | | | | | | | | | 11 | % |
| Hedge fund of funds | | — |
| | 19,829 |
| | — |
| | 19,829 |
| | 6 | % |
| Private equity fund of funds | | — |
| | — |
| | 7,158 |
| | 7,158 |
| | 2 | % |
| Commodities fund of funds | | — |
| | 10,134 |
| | — |
| | 10,134 |
| | 3 | % |
| Total assets at fair value | | $ | 133,748 |
| | $ | 195,537 |
| | $ | 7,158 |
| | $ | 336,443 |
| | 100 | % |
| Percent of fair value hierarchy | | 40 | % | | 58 | % | | 2 | % | | 100 | % | | |
|
| | | | | | | | | | | | | | | | | | | |
| | | Qualified Pension Plan as of October 31, 2013 |
| | | | | Significant Other Observable Inputs(Level 2) | | | | | | |
| | | Quoted Prices In Active Markets (Level 1) | | | Significant Unobservable Inputs (Level 3) | | | | |
| | | | | | | | |
| | | | | | Total Carrying Value | | % of Total |
| In thousands | | | | | |
| Cash and cash equivalents | | $ | 5,566 |
| | $ | 156 |
| | $ | — |
| | $ | 5,722 |
| | 2 | % |
| Fixed Income Securities: | | | | | | | | | | 38 | % |
| U.S. treasuries | | — |
| | 24,078 |
| | — |
| | 24,078 |
| | 8 | % |
| Long duration bonds | | — |
| | 34,041 |
| | — |
| | 34,041 |
| | 11 | % |
| Corporate bonds | | — |
| | 42,701 |
| | — |
| | 42,701 |
| | 14 | % |
| High yield bonds | | 14,680 |
| | — |
| | — |
| | 14,680 |
| | 5 | % |
| Collateralized mortgage | | | | | | | | | | |
| obligations | | — |
| | 1,098 |
| | — |
| | 1,098 |
| | — | % |
| Derivatives | | 6 |
| | (17 | ) | | — |
| | (11 | ) | | — | % |
| Equity Securities: | | | | | | | | | | 43 | % |
| Large cap core index | | 12,023 |
| | — |
| | — |
| | 12,023 |
| | 4 | % |
| Large cap value | | 16,908 |
| | — |
| | — |
| | 16,908 |
| | 6 | % |
| Large cap growth | | 17,823 |
| | — |
| | — |
| | 17,823 |
| | 6 | % |
| Small cap value | | 30,831 |
| | — |
| | — |
| | 30,831 |
| | 10 | % |
| Common trust fund - International | | | | | | | | | | |
| value | | — |
| | 24,460 |
| | — |
| | 24,460 |
| | 8 | % |
| Common trust fund - International | | | | | | | | | | |
| growth | | — |
| | 27,270 |
| | — |
| | 27,270 |
| | 9 | % |
| Real Estate: | | | | | | | | | | 5 | % |
| Global REIT | | 15,042 |
| | — |
| | — |
| | 15,042 |
| | 5 | % |
| Other Investments: | | | | | | | | | | 12 | % |
| Hedge fund of funds | | — |
| | 18,571 |
| | — |
| | 18,571 |
| | 6 | % |
| Private equity fund of funds | | — |
| | — |
| | 4,659 |
| | 4,659 |
| | 2 | % |
| Commodities fund of funds | | — |
| | 10,765 |
| | — |
| | 10,765 |
| | 4 | % |
| Total assets at fair value | | $ | 112,879 |
| | $ | 183,123 |
| | $ | 4,659 |
| | $ | 300,661 |
| | 100 | % |
| Percent of fair value hierarchy | | 37 | % | | 61 | % | | 2 | % | | 100 | % | | |
The following is a reconciliation of the assets in the qualified pension plan that are classified as Level 3 in the fair value hierarchy.
|
| | | | |
| | | Private |
| | | Equity Fund |
| In thousands | | of Funds |
| Balance, October 31, 2012 | | $ | 3,522 |
|
| Actual return on plan assets: | | |
| Relating to assets still held at the reporting date | | 116 |
|
| Relating to assets sold during the period | | 61 |
|
| Purchases, sales and settlements (net) | | 960 |
|
| Transfer in/out of Level 3 | | — |
|
| Balance, October 31, 2013 | | 4,659 |
|
| Actual return on plan assets: | | |
| Relating to assets still held at the reporting date | | 1,031 |
|
| Relating to assets sold during the period | | 113 |
|
| Purchases, sales and settlements (net) | | 1,355 |
|
| Transfer in/out of Level 3 | | — |
|
| Balance, October 31, 2014 | | $ | 7,158 |
|
During the year, the qualified pension plan raises cash from various plan assets in order to fund periodic and lump sum benefit payments. Cash is raised as needed primarily from investments that have exceeded their target allocation and is dependent upon the number of retirees seeking lump sum distributions.
There are significant unobservable inputs used in the fair value measurements of our investment in the private equity fund of funds’ limited partnerships. We are subject to the business risks inherent in the markets in which the partnerships are invested. The success or failure of the underlying businesses of the various partnerships that have been funded would result in a higher or lower fair value measurement.
Following is a description of the valuation methodologies used for assets measured at fair value in our OPEB plan with all of the OPEB plan’s assets invested in mutual funds.
Cash and cash equivalents – These are Level 1 assets having maturities of three months or less when purchased and are considered to be cash equivalents.
U.S. treasuries – These are Level 1 assets in an actively managed mutual fund measured at NAV.
Corporate bonds/Other fixed income securities – These are Level 1 assets valued at the quoted NAV of mutual fund investments that are primarily invested in investment grade securities that mature within ten years. The OPEB plan maintains a 5% target allocation to high yield fixed income.
Large cap value, large cap growth, small cap growth, small cap value – These are Level 1 assets valued at the quoted NAV as invested in mutual funds that invest by a specific style.
Large cap index – These are Level 1 assets valued at the NAV as invested in a low-cost equity index mutual fund that tracks the S&P 500 Index.
International blend – These are Level 1 assets valued at the quoted NAV of mutual fund shares in managed global equity funds outside of the United States whose styles include both growth and value investments.
Global REIT – These are Level 1 assets valued at the quoted NAV of mutual fund shares in a managed equity fund that invests globally but primarily in the United States.
The OPEB plan’s asset allocations by level within the fair value hierarchy at October 31, 2014 and 2013 are presented below. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and their placement within the fair value hierarchy levels. For further information on a description of the fair value hierarchy, see “Fair Value Measurements” in Note 1 to the consolidated financial statements. | | | | | | | | | | | | | | | | | | | | |
| | | 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. |
|
| | | | | | | | | | | | | | | | | | | |
| | | Other Benefits as of October 31, 2014 |
| | | |
| Significant Other Observable Inputs(Level 2) |
|
|
|
|
|
|
| | | Quoted Prices In Active Markets (Level 1) |
|
| Significant Unobservable Inputs (Level 3) |
|
|
|
|
| | |
|
|
|
|
|
|
| | |
|
|
| Total Carrying Value |
| % of Total |
| In thousands | |
|
|
|
|
| Cash and cash equivalents | | $ | 2,590 |
| | $ | — |
| | $ | — |
| | $ | 2,590 |
| | 9 | % |
| Fixed Income Securities: | | | | | | | | | | 44 | % |
| U.S. treasuries | | 2,013 |
| | — |
| | — |
| | 2,013 |
| | 7 | % |
| Corporate bonds / Other fixed income | | | | | | | | | | |
| securities | | 10,187 |
| | — |
| | — |
| | 10,187 |
| | 37 | % |
| Equity Securities: | | | | | | | | | | 42 | % |
| Large cap value | | 1,269 |
| | — |
| | — |
| | 1,269 |
| | 4 | % |
| Large cap growth | | 1,310 |
| | — |
| | — |
| | 1,310 |
| | 5 | % |
| Small cap value | | 1,336 |
| | — |
| | — |
| | 1,336 |
| | 5 | % |
| Small cap growth | | 1,319 |
| | — |
| | — |
| | 1,319 |
| | 5 | % |
| Large cap index | | 2,532 |
| | — |
| | — |
| | 2,532 |
| | 9 | % |
| International blend | | 3,846 |
| | — |
| | — |
| | 3,846 |
| | 14 | % |
| Real Estate: | | | | | | | | | | 5 | % |
| Global REIT | | 1,345 |
| | — |
| | — |
| | 1,345 |
| | 5 | % |
| Total assets at fair value | | $ | 27,747 |
| | $ | — |
| | $ | — |
| | $ | 27,747 |
| | 100 | % |
| Percent of fair value hierarchy | | 100 | % | | — | % | | — | % | | 100 | % | | |
|
| | | | | | | | | | | | | | | | | | | |
| | | Other Benefits as of October 31, 2013 |
| | | | | Significant Other Observable Inputs(Level 2) | | | | | | |
| | | Quoted Prices In Active Markets (Level 1) | | | Significant Unobservable Inputs (Level 3) | | | | |
| | | | | | | | |
| | | | | | Total Carrying Value | | % of Total |
| In thousands | | | | | |
| Cash and cash equivalents | | $ | 982 |
| | $ | — |
| | $ | — |
| | $ | 982 |
| | 4 | % |
| Fixed Income Securities: | | | | | | | | | | 46 | % |
| U.S. treasuries | | 2,582 |
| | — |
| | — |
| | 2,582 |
| | 10 | % |
| Corporate bonds / Other fixed income | | | | | | | | | | |
| securities | | 9,232 |
| | — |
| | — |
| | 9,232 |
| | 36 | % |
| Equity Securities: | | | | | | | | | | 45 | % |
| Large cap value | | 1,327 |
| | — |
| | — |
| | 1,327 |
| | 5 | % |
| Large cap growth | | 1,352 |
| | — |
| | — |
| | 1,352 |
| | 5 | % |
| Small cap value | | 1,331 |
| | — |
| | — |
| | 1,331 |
| | 5 | % |
| Small cap growth | | 1,313 |
| | — |
| | — |
| | 1,313 |
| | 5 | % |
| Large cap index | | 2,384 |
| | — |
| | — |
| | 2,384 |
| | 9 | % |
| International blend | | 4,206 |
| | — |
| | — |
| | 4,206 |
| | 16 | % |
| Real Estate: | | | | | | | | | | 5 | % |
| Global REIT | | 1,252 |
| | — |
| | — |
| | 1,252 |
| | 5 | % |
| Total assets at fair value | | $ | 25,961 |
| | $ | — |
| | $ | — |
| | $ | 25,961 |
| | 100 | % |
| Percent of fair value hierarchy | | 100 | % | | — | % | | — | % | | 100 | % | | |
We maintain a 401(k) plan that is a profit-sharing plan under Section 401(a) of the Internal Revenue Code of 1986, as amended (the Tax Code), which includes qualified cash or deferred arrangements under Tax Code Section 401(k). The 401(k) plan is subject to the provisions of the Employee Retirement Income Security Act. Eligible employees who have completed 30 days of continuous service and have attained age 18 are eligible to participate. Participants may defer a portion of their base salary and cash incentive payments to the plan, and we match a portion of their contributions. Employee contributions vest immediately, and company contributions vest after six months of service.
Beginning January 1, 2008 (January 1, 2009 for employees covered under the bargaining unit contract in Nashville, Tennessee), employees
Employees receive a company match of 100% up to 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. Employees may contribute up to 50% of eligible pay to the 401(k) on a pre-tax basis, up to the Tax Code annual contribution
limit.and compensation limits. We automatically enroll all
affectedeligible non-participating employees in the 401(k) plan at a 2% contribution rate unless the employee chooses not to participate by notifying our record keeper. For employees who are automatically enrolled in the 401(k) plan, we automatically increase their contributions by 1% each year to a maximum of 5% unless the employee chooses to opt out of the automatic increase by contacting our record keeper. If the employee does not make an investment election, employee contributions and matches are automatically invested in a diversified portfolio
of stocks and bonds. Participants may direct up to 20% of their contributions and company matching contributions as an investment in the Piedmont Stock Fund. Employees may change their contribution rate and investments at any time. For the years ended October 31, 2011, 20102014, 2013 and 2009,2012, we made matching contributions to participant accounts as follows.
| | | | | | | | | | | | | | |
In thousands | | 2011 | | | 2010 | | | 2009 | |
401(k) matching contributions | | $ | 5,203 | | | $ | 5,269 | | | | | $ | 4,698 | |
|
| | | | | | | | | | | | |
| In thousands | | 2014 | | 2013 | | 2012 |
| 401(k) matching contributions | | $ | 6,134 |
| | $ | 5,688 |
| | $ | 5,400 |
|
As a result of a plan merger effective in 2001, participants’ accounts in our employee stock ownership plan (ESOP) were transferred into the participants’ 401(k) accounts. Former ESOP participants may remain invested in Piedmont common stock in their 401(k) plan or may sell the common stock at any time and reinvest the proceeds in other available investment options. The tax benefit of any dividends paid on ESOP shares still in participants’ accounts is reflected in the
consolidated statementConsolidated Statement of
stockholders’ equityStockholders’ Equity as an increase in retained earnings.
10. Employee Share-Based Plans
Under our shareholder approved
incentive compensation plans,ICP, eligible officers and other participants are awarded units that pay out depending upon the level of performance achieved by Piedmont during three-year incentive plan performance periods. Distribution of those awards may be made in the form of shares of common stock and withholdings for payment of applicable taxes on the compensation. These plans require that a minimum threshold performance level be achieved in order for any award to be distributed. For the years ended October 31,
2011, 20102014, 2013 and
2009,2012, we recorded compensation expense, and as of October 31,
20112014 and
2010,2013, 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 re-measured to market value at the settlement date.
We have
granted three
series of awards under approved incentive compensation plans,
each with
a three-year performance
periods endingperiod (ending October 31,
2011,2014, October 31,
20122015 and October 31,
2013. 50%2016). For each of
the units awardedthese performance periods, awards will be based on achievement
ofrelative to a target annual compounded increase in basic
EPS. For thisEPS and the achievement of total shareholder returns relative to a group of peer companies that are domiciled in the United States, publicly traded in the U.S. energy industry with a primary focus on natural gas distribution and transmission businesses in multi-state territories and have similar annual revenues and market capitalization to ours, with each measure being weighted at 50%
portion,. The plans with performance periods ending October 31, 2015 (2015 plan) and October 31, 2016 (2016 plan) have an
EPSadditional performance
measure 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 subjectactual average return on equity compared to
mathematical interpolation. EPS performance below 80% of target will result in no payout of this portion.the weighted average return on equity allowed by our regulatory commissions. The
other 50%weighting of the units awarded
will beunder the 2015 plan and the 2016 plan is based on
the achievement of total annual shareholder return (increase in our common stock price plus dividends reinvested over the specified period of time) in comparison to a peer group which consists of natural gas companies. TheEPS at 37.5%, total shareholder return
performance measure will be our percentile ranking in relationship toat 37.5% and return on equity at 25% of 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.total units awarded.
In December 2010, a long-term retention
stock unit award under the
incentive compensation planICP (where a stock unit equals one share of our common stock upon vesting) was approved for eligible officers and other
participants.participants to support our succession planning and retention strategies. This retention
stock unit award
will be distributed tovested for participants who
have met the retention requirements at the end of
athe three-year period ending in
December 2013 and settled in the same month with payment in the form of shares of common stock and withholdings for payment of applicable taxes on the compensation. The Compensation Committee of our Board of Directors hashad the discretion to accelerate the vesting of all or a portion of a participant’s retention units. For the twelve months ended October 31, 2011, 2013 and 2012, we recorded compensation expense and a liability as of October 31, 2013 with compensation expense recorded in fiscal 2014 until December 2013 when the award was settled. The liability, which we accrued for this award based on the fair market value of our stock at the end of each quarter, was re-measured to market value in December 2013, the settlement date.
Also under our approved ICP, 64,700 unvested retention stock units were granted to our President and Chief Executive Officer in December 2011. During the five-year vesting period, any dividend equivalents will accrue on these stock units and be converted into additional units at the same rate and based on the closing price on the same payment date as dividends on our common stock. The stock units will vest, payable in the form of shares of common stock and withholdings for payment of applicable taxes on the compensation, over a five-year period only if he is an employee on each vesting date. In accordance with the vesting schedule, 20% of the units vested on December 15, 2014, 30% of the units vest on December 15, 2015 and 50% of the units vest on December 15, 2016. For the twelve months ended October 31, 2014, 2013 and 2012,we recorded compensation expense, and as of October 31,
2011,2014 and 2013, we
have accrued a liability for
these awardsthis award based on the fair market value of our stock at the end of each quarter. The liability is re-measured to market value at the settlement date.
Also under our approved incentive compensation plan, 65,000 unvested
The award which vested on December 15, 2014 covered 20% of the grant, including accrued dividends, for a total of 14,461 shares of our common stock were granted tostock. After the withholding of $.3 million for federal and state income taxes, our President and Chief Executive Officer in September 2006. During the five-year vesting period, any dividends paid on these shares were accrued and converted into additionalreceived 7,231 shares at the New York Stock Exchange composite closing price on December 12, 2014 of $37.89 per share.
At the
time of distribution of awards under the ICP, the number of shares issuable is reduced by the withholdings for payment of applicable income taxes for each participant. The participant may elect income tax withholdings at or above the minimum statutory withholding requirements. The maximum withholdings allowed is 50%. To date,
shares withheld for payment of
applicable income taxes have been immaterial. We present these net shares issued in the
dividend payment. In accordance withConsolidated Statements of Stockholders’ Equity and in Note 6 to the
vesting schedule 20%, 30% and 50% of the shares vested on September 1, 2009, 2010 and 2011, respectively.consolidated financial statements.
The compensation expense related to the incentive compensation plans for the years ended October 31,
2011, 20102014, 2013 and
2009,2012, and the amounts recorded as liabilities
in "Other noncurrent liabilities" in "Noncurrent Liabilities" with the current portion recorded in "Other current liabilities" in "Current Liabilities" in the Consolidated Balance Sheets as of October 31,
20112014 and
20102013 are presented below.
| | | | | | | | | | | | |
In thousands | | 2011 | | | 2010 | | | 2009 | |
Compensation expense | | $ | 2,604 | | | $ | 6,118 | | | $ | 2,487 | |
Tax benefit | | | 673 | | | | 1,756 | | | | 207 | |
Liability | | | 5,015 | | | | 9,914 | | | | | |
|
| | | | | | | | | | | | |
| In thousands | | 2014 | | 2013 | | 2012 |
| Compensation expense | | $ | 8,496 |
| | $ | 4,526 |
| | $ | 5,730 |
|
| Tax benefit | | 2,476 |
| | 1,538 |
| | 2,080 |
|
| Liability | | 15,130 |
| | 11,098 |
| | |
Based on current accrual assumptions as of October 31,
2011,2014, the expected payout for the approved incentive compensation
plans ending October 31, 2011, 2012 and 2013awards at target will occur in the following fiscal years.
| | | | | | | | | | | | | | |
In thousands | | 2012 | | | 2013 | | | 2014 | |
Amount of payout | | $ | — | | | $ | 2,719 | | | | | $ | 2,296 | |
|
| | | | | | | | | | | | |
| In thousands |
| 2015 |
| 2016 |
| 2017 |
| Amount of payout |
| $ | 7,204 |
| | $ | 4,980 |
| | $ | 2,946 |
|
On a quarterly basis, we issue shares of common stock under the ESPP and
have accountedaccount 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.
The components of income tax expense for the years ended October 31,
2011, 20102014, 2013 and
20092012 are presented below.
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | 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 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| |
| 2014 |
| 2013 |
| 2012 |
| In thousands |
| Federal |
| State |
| Federal |
| State |
| Federal |
| State |
| Charged (Credited) to operating | | | | | | | | | | | | |
| income: |
|
|
|
|
|
|
|
|
|
|
|
|
Current (1) |
| $ | (1,653 | ) |
| $ | 950 |
|
| $ | (3,032 | ) |
| $ | 919 |
|
| $ | (29,062 | ) |
| $ | 1,857 |
|
Deferred (1) |
| 70,654 |
|
| 13,434 |
|
| 67,885 |
|
| 11,829 |
|
| 86,496 |
|
| 10,144 |
|
| Tax Credits: |
|
|
|
| |
| |
| |
| |
|
| Amortization |
| (209 | ) | | — |
| | (267 | ) | | — |
| | (334 | ) | | — |
|
| Total |
| 68,792 |
| | 14,384 |
| | 64,586 |
| | 12,748 |
| | 57,100 |
| | 12,001 |
|
| | | | | | | | | | | | | |
| Charged (Credited) to other income | | | | | | | | | | | | |
| (expense): |
|
| |
| |
| |
| |
| |
|
| Current |
| 4,233 |
| | 870 |
| | 6,049 |
| | 984 |
| | 5,636 |
| | 1,027 |
|
| Deferred |
| 5,811 |
| | 728 |
| | 2,225 |
| | (646 | ) | | 2,214 |
| | 239 |
|
| Total |
| 10,044 |
| | 1,598 |
| | 8,274 |
| | 338 |
| | 7,850 |
| | 1,266 |
|
| Total |
| $ | 78,836 |
| | $ | 15,982 |
| | $ | 72,860 |
| | $ | 13,086 |
| | $ | 64,950 |
| | $ | 13,267 |
|
(1) Includes utilization of federal NOL carryforward benefit of $28.6 million for the year ended October 31, 2014 and the generation of a NOL carryforward benefit of $62.3 million for the year ended October 31, 2013.
A reconciliation of income tax expense at the federal statutory rate to recorded income tax expense for the years ended October 31,
2011, 20102014, 2013 and
20092012 is presented below.
| | | | | | | | | | | | |
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 | |
| | | | | | | | | | | | |
|
| | | | | | | | | | | | |
| In thousands |
| 2014 | | 2013 | | 2012 |
| Federal taxes at 35% |
| $ | 83,517 |
| | $ | 77,127 |
| | $ | 69,322 |
|
| State income taxes, net of federal benefit |
| 10,389 |
| | 8,506 |
| | 8,624 |
|
| Amortization of investment tax credits |
| (209 | ) | | (267 | ) | | (334 | ) |
| Other, net |
| 1,121 |
| | 580 |
| | 605 |
|
| Total |
| $ | 94,818 |
| | $ | 85,946 |
| | $ | 78,217 |
|
As of October 31,
20112014 and
2010,2013, deferred income taxes consisted of the following temporary differences.
| | | | | | | | |
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 | |
| | | | | | | | |
|
| | | | | | | | |
| In thousands |
| 2014 |
| 2013 |
| Deferred tax assets: |
|
| |
|
| Benefit of loss carryforwards |
| $ | 39,532 |
| | $ | 66,087 |
|
| Revenues and cost of gas | | 4,960 |
| | — |
|
| Employee benefits and compensation |
| 16,547 |
| | 13,834 |
|
| Revenue requirement |
| 20,320 |
| | 19,062 |
|
| Utility plant |
| 5,631 |
| | 10,386 |
|
| Other |
| 12,869 |
| | 12,796 |
|
| Total deferred tax assets |
| 99,859 |
| | 122,165 |
|
| Valuation allowance |
| (505 | ) | | (505 | ) |
| Total deferred tax assets, net |
| 99,354 |
| | 121,660 |
|
| Deferred tax liabilities: |
| | | |
| Utility plant |
| 724,172 |
| | 652,822 |
|
| Revenues and cost of gas |
| 4,340 |
| | 21,257 |
|
| Equity method investments |
| 42,998 |
| | 38,710 |
|
| Deferred costs |
| 65,828 |
| | 59,221 |
|
| Other |
| 18,065 |
| | 18,324 |
|
| Total deferred tax liabilities |
| 855,403 |
| | 790,334 |
|
| Net deferred income tax liabilities |
| $ | 756,049 |
| | $ | 668,674 |
|
As of October 31,
20112014 and
2010,2013, total net deferred income tax assets were net of a valuation allowance to reduce amounts to the amounts that we believe will be more likely than not realized. We and our
wholly ownedwholly-owned subsidiaries file a consolidated federal income tax return and various state income tax returns. As of October 31,
20112014 and
2010,2013, we
hadhave federal
net operating lossNOL carryforwards of
$6.2$97 million and
$6.5$178.1 million, respectively, which expire
from 2024 through 2026. Asin 2033. We also have $5.9 million of federal NOL carryforwards as of October 31,
20112014 and
2010, we had state net operating loss carryforwards of $7 million2013 that expire in 2021 through 2025 and
$7.1 million, respectively, which expire from 2018 through 2025. We may use the loss carryforwards to offset taxable income. Of the loss carryforwards, $6.2 million are subject to an annual limitation of $.3 million.
Our return for the tax year ended As of October 31, 2008 is currently under examination by the IRS. We do not expect the audit to2014, we have a material effect on our financial position, results$2.4 million alternative minimum tax credit carryforward.
As of operations or cash flows. October 31, 2014 and 2013, we have state NOL carryforwards of $7.2 million and $6.4 million, respectively, that expire from 2020 through 2028. We may use the carryforwards to offset taxable income.
We are no longer subject to federal income tax examinations for tax years ending before and including October 31,
2007,2009, and with few exceptions, state income tax examinations by tax authorities for years ended before and including October 31,
2007.2009. The IRS is currently auditing the federal income tax returns for years ended October 31, 2010, 2011 and 2012.
A reconciliation of changes in the deferred tax valuation allowance for the years ended October 31,
2011, 20102014, 2013 and
20092012 is presented below.
| | | | | | | | | | | | |
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
|
| | | | | | | | | | | | |
| In thousands |
| 2014 | | 2013 | | 2012 |
| Balance at beginning of year |
| $ | 505 |
| | $ | 505 |
| | $ | 505 |
|
| Credited to income tax expense |
| — |
| | — |
| | — |
|
| Balance at end of year |
| $ | 505 |
| | $ | 505 |
| | $ | 505 |
|
There were no unrecognized tax benefits for the years ended October 31, 20112014 and 20102013.
In July 2013, legislation was passed in North Carolina affecting corporate taxation. The legislation reduced the corporate income tax rate from 6.9% to 6% for tax years beginning after January 1, 2014 and to 5% for tax years beginning after January 1, 2015. It also provided for two additional 1% rate reductions if the state’s tax collections exceed certain thresholds. We record deferred income taxes on temporary tax differences using the income tax rate in effect when the temporary difference is
presented below. | | | | | | | | |
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 no interest relatedexpected to unrecognizedreverse. As a result of the rate reductions, we adjusted our noncurrent deferred income tax benefits during the year endedbalances at October 31, 20112013 by approximately $25 million for temporary differences expected to reverse at a lower rate than
under the prior law and
only immaterial amountsrecognized a tax benefit of
interest duringapproximately $1 million in net income, the
year ended October 31, 2010.majority of which relates to our regulated non-utility activities segment, with the balance of approximately $24 million recorded in deferred income taxes in “Regulatory Liabilities” as presented in Note 1 to the consolidated financial statements, reflecting a future benefit to our customers. During fiscal 2014, we recorded an additional $3 million for the difference in the tax rate included in our customers' rates and the rate at which the deferred taxes are expected to reverse. This increased our deferred income taxes recorded in “Regulatory Liabilities” to approximately $27 million. Our state regulatory commissions will determine the refund period of this regulatory liability in future proceedings.
12. Equity Method Investments
The consolidated financial statements include the accounts of
wholly ownedwholly-owned subsidiaries whose investments in joint venture, energy-related businesses are accounted for under the equity method. Our ownership interest in each entity is included in “Equity method investments in non-utility activities” in
“Noncurrent Assets” in the
consolidated balance sheets.Consolidated Balance Sheets. Earnings or losses from equity method investments are included in “Income from equity method investments” in
“Other Income (Expense)” in the
consolidated statementsConsolidated Statements of
income.Comprehensive Income.
As of October 31,
2011,2014, there were no amounts that represented undistributed earnings of our 50% or less owned equity method investments in our retained earnings.
Cardinal Pipeline Company, L.L.C.
We own 21.49% of the membership interests in Cardinal Pipeline Company, L.L.C. (Cardinal), a North Carolina limited liability company. The other members are subsidiaries of The Williams Companies, Inc., and SCANA Corporation. Cardinal owns and operates an intrastate natural gas pipeline in North Carolina and is regulated by the NCUC. Cardinal has firm, long-term service agreements with local distribution companies for 100% of the firm transportation capacity on the pipeline, of which Piedmont subscribes to approximately 37%53%. Cardinal is dependent on the Williams-TranscoWilliams – Transco pipeline system to deliver gas into its system for service to its customers.
Cardinal enters into interest-rate swap agreements to modify the interest expense characteristics of its unsecured long-term debt. Our share of movements in the market value of these agreements are recorded as a hedge in “Accumulated other comprehensive loss” in “Stockholders’ equity” in the Consolidated Balance Sheets; the detail of our share of the market value of the swap agreements is combined with our other equity method investments and presented in “Other Comprehensive Income (Loss), net of tax” in the Consolidated Statements of Comprehensive Income. Cardinal’s long-term debt is nonrecourse to the
members 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.
members.
We have related party transactions as a transportation customer of Cardinal, and we record
in cost of gas the transportation costs charged by
Cardinal.Cardinal in “Cost of Gas” in the Consolidated Statements of Comprehensive Income. For each of the years ended October 31,
2011, 20102014, 2013 and
2009,2012, these transportation costs and the amounts we owed Cardinal as of October 31,
20112014 and
20102013 are as follows.
| | | | | | | | | | | | |
In thousands | | 2011 | | | 2010 | | | 2009 | |
Transportation costs | | $ | 4,104 | | | $ | 4,104 | | | $ | 4,104 | |
Trade accounts payable | | | 349 | | | | 349 | | | | | |
|
| | | | | | | | | | | | |
| In thousands |
| 2014 | | 2013 | | 2012 |
| Transportation costs |
| $ | 8,825 |
| | $ | 8,775 |
| | $ | 6,613 |
|
| Trade accounts payable |
| 747 |
| | 755 |
| | |
Summarized financial information provided to us by Cardinal for 100% of Cardinal as of September 30,
20112014 and
2010,2013, and for the twelve months ended September 30,
2011, 20102014, 2013 and
20092012 is presented below.
| | | | | | | | | | | | |
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 | |
|
| | | | | | | | | | | | |
| In thousands |
| 2014 | | 2013 | | 2012 |
| Current assets |
| $ | 8,856 |
| | $ | 15,179 |
| | |
| Noncurrent assets |
| 111,881 |
| | 116,414 |
| | |
| Current liabilities |
| 1,468 |
| | 2,637 |
| | |
| Noncurrent liabilities |
| 45,402 |
| | 45,273 |
| | |
| Revenues |
| 16,705 |
| | 17,649 |
| | $ | 16,165 |
|
| Gross profit |
| 16,705 |
| | 17,649 |
| | 16,165 |
|
| Income before income taxes |
| 8,042 |
| | 9,361 |
| | 10,433 |
|
Pine Needle LNG Company, L.L.C.
We own
40%45% 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 Needlecompany that owns an interstate LNG storage facility in North Carolina
and is regulated by the FERC. Pine Needle has firm,
long-term service agreements for 100% of the storage capacity of the facility, of which Piedmont subscribes to approximately 64%.
Effective July 1, 2013, we acquired Hess Corporation’s 5% membership interest in Pine Needle for $2.9 million,which increased our membership interest from 40% to 45%. The other members are the Municipal Gas Authority of Georgia and subsidiaries of The Williams Companies, Inc. and SCANA Corporation.
Pine Needle enters into interest-rate swap agreements to modify the interest
expense characteristics of its long-term debt. Our share of movements in the market value of these agreements are recorded as a hedge in “Accumulated other comprehensive loss” in
“Stockholders’ equity” in the
consolidated balance sheets.Consolidated Balance Sheets; the detail of our share of the market value of the swap agreements is combined with our other equity method investments and presented in “Other Comprehensive Income (Loss), net of tax” in the Consolidated Statements of Comprehensive Income. Pine Needle’s long-term debt is nonrecourse to the
members and is secured by Pine Needle’s assets and by each member’s equity investment in Pine Needle.members.
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.Needle in “Cost of Gas” in the Consolidated Statements of Comprehensive Income. For the years ended October 31,
2011, 20102014, 2013 and
2009,2012, these gas storage costs and the amounts we owed Pine Needle as of October 31,
20112014 and
20102013 are as follows.
| | | | | | | | | | | | |
In thousands | | 2011 | | | 2010 | | | 2009 | |
Gas storage costs | | $ | 10,677 | | | $ | 12,158 | | | $ | 12,364 | |
Trade accounts payable | | | 849 | | | | 985 | | | | | |
|
| | | | | | | | | | | | |
| In thousands |
| 2014 | | 2013 | | 2012 |
| Gas storage costs |
| $ | 11,364 |
| | $ | 11,098 |
| | $ | 10,410 |
|
| Trade accounts payable |
| 989 |
| | 940 |
| | |
Summarized financial information provided to us by Pine Needle for 100% of Pine Needle as of September 30,
20112014 and
2010,2013, and for the twelve months ended September 30,
2011, 20102014, 2013 and
20092012 is presented below.
| | | | | | | | | | | | |
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 | |
|
| | | | | | | | | | | | |
| In thousands |
| 2014 | | 2013 | | 2012 |
| Current assets |
| $ | 8,812 |
| | $ | 9,225 |
| | |
| Noncurrent assets |
| 70,837 |
| | 74,710 |
| | |
| Current liabilities |
| 38,029 |
| | 3,531 |
| | |
| Noncurrent liabilities |
| — |
| | 35,391 |
| | |
| Revenues |
| 18,025 |
| | 16,810 |
| | $ | 16,390 |
|
| Gross profit |
| 18,025 |
| | 16,810 |
| | 16,390 |
|
| Income before income taxes |
| 6,011 |
| | 5,804 |
| | 5,832 |
|
SouthStar Energy Services LLC
We own 15% of the membership interests in SouthStar,
Energy Services LLC (SouthStar), a Delaware limited liability company. The other member is Georgia Natural Gas Company (GNGC), a wholly-owned subsidiary of AGL Resources, Inc.
(AGL). SouthStar primarily sells natural gas
in the unregulated retail gas market to residential, commercial and industrial customers in the
southeasterneastern United States,
primarily in Georgia and
Ohio with most of its business being conducted in the unregulated retail gas market in Georgia. On January 1, 2010, we sold half of our 30% membership interest in 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.Illinois. We
will continue to account for our
15% membership interestinvestment in SouthStar using the equity method, as we
retainhave board representation with
equal voting rights
equal to GNGC on significant governance matters and policy decisions, and thus, exercise significant influence over the operations of SouthStar.
In September 2013, GNGC contributed its retail natural gas marketing assets and customer accounts located in Illinois. AGL acquired these retail assets and customers from Nicor Inc. in December 2011 and additional retail natural gas assets and customer accounts in a separate transaction in June 2013. We made an additional $22.5 million capital contribution to SouthStar, maintaining our 15% equity ownership, related to this transaction.
SouthStar’s business is seasonal in nature as variations in weather conditions generally result in greater revenue and earnings during the winter months when weather is colder and natural gas consumption is higher. Also, because SouthStar is not a rate-regulated company, the timing of its earnings can be affected by changes in the wholesale price of natural gas. While SouthStar uses financial contracts to moderate the effect of price and weather changes on the timing of its earnings, wholesale price and weather volatility can cause variations in the timing of the recognition of earnings.
These financial contracts, in the form of futures, options and swaps, are considered to be derivatives and fair value is based on selected market indices.
Beginning in 2014, retirement benefits were allocated to SouthStar by its majority member with the activity of prescribed benefit expense items reflected in accumulated OCIL. Our share of movements in the market value of these
derivative contracts are recorded as a hedge
and the activity of the retirement benefit items are reflected in “Accumulated other comprehensive loss” in
“Stockholders’ equity” in the
consolidated balance sheets.Consolidated Balance Sheets; the detail of our share of the market value of these contracts and the retirement benefits are combined with our other equity method investments and presented in “Other Comprehensive Income (Loss), net of tax” in the Consolidated Statements of Comprehensive Income.
We have related party transactions as we sell wholesale gas supplies to SouthStar, and we record
in operating revenues the amounts billed to
SouthStar.SouthStar in “Operating Revenues” in the Consolidated Statements of Comprehensive Income. For the years ended October 31,
2011, 20102014, 2013 and
2009,2012, our operating revenues from these sales and the amounts SouthStar owed us as of October 31,
20112014 and
20102013 are as follows.
| | | | | | | | | | | | |
In thousands | | 2011 | | | 2010 | | | 2009 | |
Operating revenues | | $ | 4,961 | | | $ | 5,083 | | | $ | 8,226 | |
Trade accounts receivable | | | 736 | | | | 713 | | | | | |
|
| | | | | | | | | | | | |
| In thousands |
| 2014 | | 2013 | | 2012 |
| Operating revenues |
| $ | 3,541 |
| | $ | 3,291 |
| | $ | 2,442 |
|
| Trade accounts receivable |
| 460 |
| | 441 |
| | |
Summarized financial information provided to us by SouthStar for 100% of SouthStar as of September 30,
20112014 and
2010,2013, and for the twelve months ended September 30,
2011, 20102014, 2013 and
20092012 is presented below.
| | | | | | | | | | | | |
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 | |
|
| | | | | | | | | | | | |
| In thousands |
| 2014 | | 2013* | | 2012 |
| Current assets |
| $ | 196,286 |
| | $ | 199,425 |
| | |
| Noncurrent assets |
| 143,420 |
| | 147,571 |
| | |
| Current liabilities |
| 51,435 |
| | 76,346 |
| | |
| Noncurrent liabilities |
| 83 |
| | 31 |
| | |
| Revenues |
| 845,695 |
| | 639,426 |
| | $ | 585,291 |
|
| Gross profit |
| 234,581 |
| | 174,993 |
| | 161,122 |
|
| Income before income taxes |
| 136,569 |
| | 102,805 |
| | 94,631 |
|
* Amounts have been changed to reflect restatement of AGL's Form 10-K for the year ended December 31, 2013. The restatement had an immaterial impact on SouthStar's results.
Hardy Storage Company, LLC
Piedmont Hardy Storage Company, a wholly owned subsidiary of Piedmont, owns
We own 50% of the membership interests in Hardy Storage Company, LLC (Hardy Storage), a West Virginia limited liability company. The other owner is a subsidiary of Columbia Gas Transmission Corporation, a subsidiary of NiSource Inc. Hardy Storage owns and operates an underground interstate natural gas storage facility located in Hardy and Hampshire Counties, West Virginia, that is regulated by the FERC. Hardy Storage has firm,
long-term service
contractsagreements for 100% of the storage capacity of the facility, of which Piedmont subscribes to approximately 40%.
In June 2006, Hardy Storage signed a note purchase agreement for interim notes and a revolving equity bridge facility for construction financing. The revolving equity bridge facility was subsequently paid off in 2007. The members of Hardy Storage each agreed to guarantee 50% of the construction financing as well as a separate guaranty of 50% of construction expenditures should contingency wells be required based on the performance of the facility over the first three years after the in-service date. The Guaranty of Principal and Residual Guaranty were executed by a wholly owned subsidiary of Piedmont, Piedmont Energy Partners, Inc. Securing our guaranty was a pledge of intercompany notes issued by Piedmont to its non-utility subsidiaries held under its wholly owned subsidiary. Also pledged was our membership interest in Hardy Storage.
In March 2010, Hardy Storage paid $3.6 million on the interim notes to enable 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 conversion, our Guaranty of Principal and Residual Guaranty, as executed in connection with the interim financing, terminated 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 fair value of 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 the venture. Upon completion of the permanent financing in March 2010, the liability was reversed, and our investment account was adjusted accordingly to reflect the elimination of the guaranty.
We have related party transactions as a customer of Hardy Storage, and
we record
in cost of gas the storage costs charged by Hardy
Storage.Storage in “Cost of Gas” in the Consolidated Statements of Comprehensive Income. For the years ended October 31,
2011, 20102014, 2013 and
2009,2012, these gas storage costs and the amounts we owed Hardy Storage as of October 31,
20112014 and
20102013 are as follows.
| | | | | | | | | | | | |
In thousands | | 2011 | | | 2010 | | | 2009 | |
Gas storage costs | | $ | 9,702 | | | $ | 9,386 | | | $ | 9,340 | |
Trade accounts payable | | | 808 | | | | 808 | | | | | |
|
| | | | | | | | | | | | |
| In thousands |
| 2014 | | 2013 | | 2012 |
| Gas storage costs |
| $ | 9,461 |
| | $ | 9,702 |
| | $ | 9,702 |
|
| Trade accounts payable |
| 774 |
| | 808 |
| | |
Summarized financial information provided to us by Hardy Storage for 100% of Hardy Storage as of October 31,
20112014 and
2010,2013, and for the twelve months ended October 31,
2011, 20102014, 2013 and
20092012 is presented below.
| | | | | | | | | | | | |
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 | |
|
| | | | | | | | | | | | |
| In thousands |
| 2014 | | 2013 | | 2012 |
| Current assets |
| $ | 12,644 |
| | $ | 7,641 |
| | |
| Noncurrent assets |
| 157,861 |
| | 161,282 |
| | |
| Current liabilities |
| 17,316 |
| | 12,378 |
| | |
| Noncurrent liabilities |
| 78,830 |
| | 87,184 |
| | |
| Revenues |
| 23,804 |
| | 24,375 |
| | $ | 24,359 |
|
| Gross profit |
| 23,804 |
| | 24,375 |
| | 24,359 |
|
| Income before income taxes |
| 10,497 |
| | 10,582 |
| | 9,939 |
|
Constitution Pipeline Company, LLC
We own 24% of the membership interests of Constitution Pipeline Company, LLC (Constitution), a Delaware limited liability company. The other members are subsidiaries of The Williams Companies, Inc., Cabot Oil & Gas Corporation and WGL Holdings, Inc. A subsidiary of The Williams Companies is the operator of the project. The purpose of the joint venture is to develop, construct, own and operate approximately 120 miles of interstate natural gas pipeline and related facilities connecting shale natural gas supplies and gathering systems in Susquehanna County, Pennsylvania, to the Iroquois Gas Transmission and Tennessee Gas Pipeline systems in New York. We have committed to fund an amount in proportion to our ownership interest for the development and construction of the new pipeline, which is expected to cost approximately $730 million at the project level. As of October 31, 2014, our fiscal year contributions were $37.6 million, with our total equity contributions for the project totaling $53.5 million to date. On December 2, 2014, the FERC issued a certificate of public convenience and necessity approving construction of the Constitution pipeline. The target in-service date of the project is late 2015 or 2016. The capacity of the pipeline is 100% subscribed under fifteen year service agreements with two Marcellus producer-shippers with a negotiated rate structure.
Summarized financial information provided to us by Constitution for 100% of Constitution as of September 30, 2014 and 2013, and for the twelve months ended September 30, 2014 and 2013 is presented below.
|
| | | | | | | | |
| In thousands |
| 2014 | | 2013 (1) |
| Current assets |
| $ | 11,273 |
| | $ | 10,944 |
|
| Noncurrent assets |
| 219,208 |
| | 62,438 |
|
| Current liabilities |
| 7,667 |
| | 7,960 |
|
| Noncurrent liabilities |
| — |
| | — |
|
| Revenues |
| — |
| | — |
|
| Gross profit |
| — |
| | — |
|
| Income before income taxes |
| 10,091 |
| | 3,459 |
|
| | | | | |
(1) Presented in the period in which we have a membership interest in Constitution, and not prior periods when we had no membership interest in Constitution. Our membership in Constitution began in November 2012. |
Atlantic Coast Pipeline, LLC
On September 2, 2014, Piedmont, Duke Energy, Dominion Resources, Inc. (Dominion), and AGL announced the formation of Atlantic Coast Pipeline, LLC (ACP), a Delaware limited liability company. ACP intends to construct, operate and maintain a 550 mile natural gas pipeline, with associated compression, from West Virginia through Virginia into eastern North Carolina. The pipeline is proposed to provide interstate natural gas transportation services for Marcellus and Utica gas supplies into southeastern markets. ACP, which is regulated by the FERC, will be designed with an initial capacity of 1.5 billion cubic feet per day with a target in-service date of late 2018. The capacity of ACP is substantially subscribed by the members of ACP, other utilities and related companies under twenty-year contracts.
We entered into an agreement through a wholly-owned subsidiary to become a 10% equity member of ACP. The other members are subsidiaries of Duke Energy, Dominion and AGL. A Dominion subsidiary will be the operator of the pipeline. The cost for the development and construction of the pipeline is expected to be between $4.5 billion to $5 billion,
excluding financing costs. Members anticipate obtaining project financing for 70% of the total costs during the construction period. As of October 31, 2014, we have made no contributions to ACP.
In October 2014, ACP requested approval from the FERC to utilize the pre-filing process under which environmental review for the natural gas pipeline will commence. ACP expects to file its FERC application in the third quarter of 2015, receive the FERC certificate in the summer of 2016 and begin construction thereafter. The project is subject to FERC, state and other federal approvals.
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 a 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 or holds property whose equity, by design, has any of the following characteristics: an insufficient amount of equity at risk to finance its activities, equity owners who do not have the power to direct the significant activities of the entity (or have voting rights that are disproportionate to their ownership interest), or where equity owners do not receive expected losses or returns. An entity may have an interest in a VIE through ownership or other contractual rights or obligations and that interest changes as the entity’s net assets change. The consolidating investor,
or the primary beneficiary, is the entity that has the power to direct the activities of a VIE that most significantly impact the VIE’s economic performance,
and the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE.
On a quarterly basis, we reassess whether we have a controlling financial interest in and are the primary beneficiary of a VIE. The quarterly reassessment process considers whether we have acquired or divested the power to direct the activities of the VIE through changes in governing documents or other circumstances. The reassessment also considers whether we have acquired or disposed of a financial interest that could be significant to the VIE, or whether an interest in the VIE has become significant or is no longer significant. The consolidation status of the VIEs with which we are involved may change as a result of such reassessments. Changes in consolidation status are applied prospectively, with assets and liabilities of a newly consolidated VIE initially recorded at fair value. A gain or loss may be recognized upon deconsolidation of a VIE depending on the carrying values of deconsolidated assets and liabilities compared to the fair value of retained interests and ongoing contractual arrangements.
As of October 31,
2011,2014, we have determined that we are not the primary beneficiary
as defined by the authoritativeunder VIE accounting guidance
related to consolidations, in any of our equity method investments, as discussed in Note 12 to the consolidated financial statements. Based on our involvement in these investments, we do not have the power to direct the activities of these investments that most significantly impact the VIE’s economic performance. As we are not the consolidating investor, we will continue to apply equity method accounting to these investments, as discussed in Note 12 to the consolidated financial statements. Our maximum loss exposure related to these equity method investments is limited to our equity investment in each entity. As of October 31,
20112014 and
2010,2013, 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 | |
| | | | | | | | |
|
| | | | | | | | |
| | | October 31, | | October 31, |
| In thousands | | 2014 | | 2013 |
| Cardinal | | $ | 16,073 |
| | $ | 18,207 |
|
| Pine Needle | | 18,689 |
| | 20,270 |
|
| SouthStar | | 40,965 |
| | 38,372 |
|
| Hardy Storage | | 37,179 |
| | 34,681 |
|
| Constitution | | 57,255 |
| | 16,939 |
|
| ACP | | 10 |
| | |
| Total equity method investments in non-utility activities | | $ | 170,171 |
| | $ | 128,469 |
|
We have also reviewed various lease arrangements, contracts to purchase, sell or deliver natural gas and other agreements in which we hold a variable interest. In these cases, we have determined that we are not the primary beneficiary of the related VIE because we do not have the power to direct the activities of the VIE that most significantly impact the VIE’s economic performance, or the obligation to absorb losses of the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE.
We have three reportable business segments, regulated utility, regulated non-utility activities and unregulated non-utility activities. Our segments are identified based on products and services, regulatory environments and our current corporate organization and business decision-making activities. The regulated utility segment is the gas distribution business, where we include the operations of merchandising and its related service work and home service agreements, with activities conducted by the parent company. Although the operations of our regulated utility segment are located in three states under the jurisdiction of individual state regulatory commissions, the operations are managed as one unit having similar economic and risk characteristics within one company.
Prior to this fiscal year ended October 31, 2014, we aggregated the regulated non-utility activities and unregulated non-utility activities into one segment, the non-utility activities segment. These activities shared a majority of characteristics that permitted aggregation under relevant accounting guidance. Based on this accounting guidance, the unaggregated operating activities individually have never met the quantitative thresholds for separate disclosure. In September 2014 with the formation of ACP and our equity membership in the venture, our current and future commitment to fund construction of regulated pipelines through our equity method investments became more significant and, as a result, we have changed our segment presentation to separately disclose our non-utility activities into regulated non-utility and unregulated non-utility activities. The effect on our company's risk profile of regulation versus non-regulation of our equity method investments and management’s view that this segmentation will provide disclosures that will help users of our financial statements to better understand how management assesses organizational performance and makes decisions about the allocation of resources were key factors in our decision to modify our reportable segments. We anticipate significant growth in our regulated non-utility activities as compared to our unregulated non-utility activities. This is especially so given our equity ownership in Constitution and ACP, both FERC regulated pipelines. Once these pipelines are in operation, the earnings contribution is expected to increase for this segment.
Operations of our regulated non-utility activities segment are comprised of our equity method investments in joint ventures with regulated activities that are held by our wholly-owned subsidiaries. Operations of our unregulated non-utility activities segment are comprised primarily of our equity method investment in a joint venture with unregulated activities that is held by a wholly-owned subsidiary; activities of our other minor subsidiaries are also included.
Operations of the regulated utility segment are reflected in “Operating Income” in the
consolidated statementsConsolidated Statements of
income.Comprehensive Income. Operations of the
regulated non-utility activities
segmentand unregulated non-utility activities segments are included in the
consolidated statementsConsolidated Statements of
incomeComprehensive Income in “Other Income (Expense)” in “Income from equity method investments” and “Non-operating income.” All of our operations are within the United States. No single customer accounts for more than 10% of our consolidated revenues.
Operations by segment for the years ended October 31, 2011, 20102014, 2013 and 2009,2012, and as of October 31, 2011, 20102014, 2013 and 20092012 are presented below. | | | | | | | | | | | | |
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 | |
The information provided for fiscal years 2013 and 2012 have been restated to align with management's view of the non-utility activities.
|
| | | | | | | | | | | | | | | | |
| | | | | Regulated |
| Unregulated | | |
| | | Regulated | | Non-Utility |
| Non-Utility | | |
| In thousands | | Utility | | Activities |
| Activities | | Total |
| 2014 | | | | | | | | |
| Revenues from external customers | | $ | 1,469,988 |
|
| $ | — |
| | $ | — |
|
| $ | 1,469,988 |
|
| Margin | | 690,208 |
|
| — |
| | — |
|
| 690,208 |
|
| Operations and maintenance expenses | | 270,877 |
|
| 132 |
| | 92 |
|
| 271,101 |
|
| Depreciation | | 118,996 |
|
| — |
| | 18 |
|
| 119,014 |
|
| Operating income (loss) before income taxes | | 263,041 |
|
| (183 | ) | | (203 | ) |
| 262,655 |
|
| Income from equity method investments | | — |
|
| 12,318 |
| | 20,435 |
|
| 32,753 |
|
| Interest expense | | 54,686 |
|
| — |
| | — |
|
| 54,686 |
|
| Income before income taxes | | 206,253 |
|
| 12,135 |
| | 20,231 |
|
| 238,619 |
|
| Total assets | | 4,442,185 |
|
| 129,206 |
| | 41,309 |
|
| 4,612,700 |
|
| Equity method investments in non-utility activities | | — |
|
| 129,206 |
| | 40,965 |
|
| 170,171 |
|
| Construction expenditures | | 460,444 |
|
| — |
| | — |
|
| 460,444 |
|
| | | | | | | | | |
| | |
|
| Regulated |
| Unregulated | | |
| | | Regulated |
| Non-Utility |
| Non-Utility | | |
| In thousands | | Utility |
| Activities |
| Activities | | Total |
| 2013 | | | | | | | | |
| Revenues from external customers | | $ | 1,278,229 |
| | $ | — |
| | $ | — |
| | $ | 1,278,229 |
|
| Margin | | 621,490 |
| | — |
| | — |
| | 621,490 |
|
| Operations and maintenance expenses | | 253,120 |
| | 103 |
| | 78 |
| | 253,301 |
|
| Depreciation | | 112,207 |
| | — |
| | 18 |
| | 112,225 |
|
| Operating income (loss) before income taxes | | 221,528 |
| | (150 | ) | | (202 | ) | | 221,176 |
|
| Income from equity method investments | | — |
| | 10,584 |
| | 15,472 |
| | 26,056 |
|
| Interest expense | | 24,938 |
| | — |
| | — |
| | 24,938 |
|
| Income before income taxes | | 194,659 |
| | 10,434 |
| | 15,270 |
| | 220,363 |
|
| Total assets | | 4,053,591 |
| | 90,097 |
| | 38,735 |
| | 4,182,423 |
|
| Equity method investments in non-utility activities | | — |
| | 90,097 |
| | 38,372 |
| | 128,469 |
|
| Construction expenditures | | 599,999 |
| | — |
| | — |
| | 599,999 |
|
| | | | | | | | | |
| | | | | Regulated | | Unregulated | | |
| | | Regulated | | Non-Utility | | Non-Utility | | |
| In thousands | | Utility | | Activities | | Activities | | Total |
| 2012 | | | | | | | | |
| Revenues from external customers | | $ | 1,122,780 |
| | $ | — |
| | $ | — |
| | $ | 1,122,780 |
|
| Margin | | 575,446 |
| | — |
| | — |
| | 575,446 |
|
| Operations and maintenance expenses | | 242,599 |
| | 31 |
| | 71 |
| | 242,701 |
|
| Depreciation | | 103,192 |
| | — |
| | 18 |
| | 103,210 |
|
| Operating income (loss) before income taxes | | 194,824 |
| | (78 | ) | | (186 | ) | | 194,560 |
|
| Income from equity method investments | | — |
| | 9,709 |
| | 14,195 |
| | 23,904 |
|
| Interest expense | | 20,097 |
| | — |
| | — |
| | 20,097 |
|
| Income before income taxes | | 174,424 |
| | 9,631 |
| | 14,009 |
| | 198,064 |
|
| Total assets | | 3,475,640 |
| | 69,749 |
| | 18,498 |
| | 3,563,887 |
|
| Equity method investments in non-utility activities | | — |
| | 69,749 |
| | 18,118 |
| | 87,867 |
|
| Construction expenditures | | 529,576 |
| | — |
| | — |
| | 529,576 |
|
Reconciliations to the consolidated financial statements for the years ended October 31,
2011, 20102014, 2013 and
2009,2012, and as of October 31,
20112014 and
20102013 are as follows.
| | | | | | | | | | | | |
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 | |
| | | | | | | | |
|
| | | | | | | | | | | | |
| In thousands | | 2014 | | 2013 | | 2012 |
| Operating Income: | |
| | | | |
| Segment operating income before income taxes | | $ | 262,655 |
| | $ | 221,176 |
| | $ | 194,560 |
|
| Utility income taxes | | (83,176 | ) | | (77,334 | ) | | (69,101 | ) |
| Regulated non-utility activities operating loss before income taxes | | 183 |
| | 150 |
| | 78 |
|
| Unregulated non-utility activities operating loss before income taxes | | 203 |
| | 202 |
| | 186 |
|
| Total | | $ | 179,865 |
| | $ | 144,194 |
| | $ | 125,723 |
|
| | |
| | | | |
| Net Income: | |
| | | | |
| Income before income taxes for reportable segments | | $ | 238,619 |
| | $ | 220,363 |
| | $ | 198,064 |
|
| Income taxes | | (94,818 | ) | | (85,946 | ) | | (78,217 | ) |
| Total | | $ | 143,801 |
| | $ | 134,417 |
| | $ | 119,847 |
|
|
| | | | | | | | | | |
| In thousands | | 2014 | | 2013 | | |
| | | | | | |
| Consolidated Assets: | | | | | |
| Total assets for reportable segments | | $ | 4,612,700 |
| | $ | 4,182,423 |
| |
| Eliminations/Adjustments | | 171,553 |
| | 186,186 |
| |
| Total | | $ | 4,784,253 |
| | $ | 4,368,609 |
| |
We monitor significant events occurring after the balance sheet date and prior to the issuance of the financial statements to determine the impacts, if any, of events on the financial statements to be issued. All subsequent events of which we are aware were evaluated. For information on subsequent event disclosure items related to regulatory matters
and employee share-based plans, see Note 2
and Note 10, respectively, to the consolidated financial statements.
16. Selected Quarterly Financial Data (In thousands except per share amounts) (Unaudited)
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | Earnings (Loss)
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 | ) |
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | Earnings (Loss) |
| | | | | | |
| | Net | | Per Share of |
| | | Operating | | | | Operating | | Income | | Common Stock |
| | | Revenues | | Margin | | Income | | (Loss) | | Basic | | Diluted |
| Fiscal Year 2014 | | | | | | | | | | | | |
| January 31 | | $ | 657,733 |
| | $ | 261,512 |
| | $ | 102,319 |
| | $ | 97,572 |
| | $ | 1.27 |
| | $ | 1.26 |
|
| April 30 | | 462,247 |
| | 211,523 |
| | 67,299 |
| | 62,540 |
| | 0.80 |
| | 0.80 |
|
| July 31 | | 164,187 |
| | 104,847 |
| | 3,254 |
| | (7,344 | ) | | (0.09 | ) | | (0.09 | ) |
| October 31 | | 185,821 |
| | 112,326 |
| | 6,993 |
| | (8,967 | ) | | (0.11 | ) | | (0.11 | ) |
| | | | | | | | | | | | | |
| Fiscal Year 2013 | | | | | | | | | | | | |
| January 31 | | $ | 515,875 |
| | $ | 231,623 |
| | $ | 86,213 |
| | $ | 85,923 |
| | $ | 1.19 |
| | $ | 1.18 |
|
| April 30 | | 399,411 |
| | 183,856 |
| | 51,504 |
| | 55,790 |
| | 0.74 |
| | 0.74 |
|
| July 31 | | 162,943 |
| | 97,000 |
| | 591 |
| | (2,293 | ) | | (0.03 | ) | | (0.03 | ) |
| October 31 | | 200,000 |
| | 109,011 |
| | 5,886 |
| | (5,003 | ) | | (0.07 | ) | | (0.07 | ) |
The pattern of quarterly earnings is the result of the highly seasonal nature of the business as variations in weather conditions and our regulated utility rate designs generally result in greater earnings during the winter months. Basic earnings
per share are calculated using the weighted average number of shares outstanding during the quarter. The annual amount may differ from the total of the quarterly amounts due to changes in the number of shares outstanding during the year.
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
Item 9A. Controls and Procedures
Management’s Evaluation of Disclosure Controls and Procedures
Our management, including the President and Chief Executive Officer and the Senior Vice President and Chief Financial Officer, has evaluated the effectiveness of our disclosure controls and procedures as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act as of the end of the period covered by this Form 10-K. Such disclosure controls and procedures are designed to provide reasonable assurance that the information we are required to disclose in the reports we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods required by the United States Securities and Exchange Commission’s rules and forms and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. Based on such evaluation, the President and Chief Executive Officer and the Senior Vice President and Chief Financial Officer concluded that, as of the end of the period covered by this Form 10-K, our disclosure controls and procedures were effective at the reasonable assurance level.
We routinely review our internal control over financial reporting and from time to time make changes intended to enhance the effectiveness of our internal control over financial reporting. There were no changes to our internal control over financial reporting as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act during the fourth quarter of fiscal
20112014 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Our management is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting as that term is defined in Rules 13a-15(f) under the Securities Exchange Act of 1934 is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. The Company’s internal control over financial reporting is supported by a program of internal audits and appropriate reviews by management, written policies and guidelines, careful selection and training of qualified personnel and a written Code of Ethics and Business Conduct adopted by the Company’s Board of Directors and applicable to all Company Directors, officers and employees.
Because of the inherent limitations, any system of internal control over financial reporting, no matter how well designed, may not prevent or detect misstatements due to the possibility that a control can be circumvented or overridden or that misstatements due to error or fraud may occur that are not detected. Also, projections of the effectiveness to future periods are subject to the risk that the internal controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies and procedures included in such controls may deteriorate.
We have conducted an evaluation of the effectiveness of our internal control over financial reporting based upon the framework in “Internal
Control - Control—Integrated Framework”
(1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based upon such evaluation, our management concluded that as of October 31,
2011,2014, our internal control over financial reporting was effective.
The Company’s independent registered public accounting firm, Deloitte & Touche LLP, has issued its report on the effectiveness of the Company’s internal control over financial reporting as of October 31,
2011.2014.
|
| | | | |
| | | Piedmont Natural Gas Company, Inc. |
| | | | |
| | | | /s/ THOMAS E. SKAINS |
Thomas E. Skains |
| | | | Thomas E. Skains Chairman, President and Chief Executive Officer |
| |
| | | | /s/ KARL W. NEWLIN |
Karl W. Newlin |
| | | | Karl W. Newlin Senior Vice President and Chief Financial Officer |
| |
| | | | /s/ JOSE M. SIMON |
Jose M. Simon |
| | | | Jose M. Simon Vice President and Controller |
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, 2011,2014, based on the criteria established inInternal Control—Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of October 31, 2011,2014, based on the criteria established inInternal Control—Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended October 31,
20112014 of the Company and our report dated December 23,
20112014 expressed an unqualified opinion on those financial statements.
|
/s/ Deloitte & Touche LLP |
|
Charlotte, North Carolina |
December 23, 2011 |
/s/ Deloitte & Touche LLP
Charlotte, North Carolina
December 23, 2014
Item 9B. Other Information
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“Board of Directors” and “Executive Officers” in our Proxy Statement for the
20122015 Annual Meeting of Shareholders
(2015 Proxy Statement), which sections are incorporated in this annual report on Form 10-K by reference. Information concerning compliance with Section 16(a) of the Securities Exchange Act of 1934, as amended, is set forth in the section entitled “Section 16(a) Beneficial Ownership Reporting Compliance” in our
2015 Proxy Statement,
for the 2012 Annual Meeting of Shareholders, which section is incorporated in this annual report on Form 10-K by reference.
Information concerning our Audit Committee and our Audit Committee financial experts is set forth in the section entitled “Committees of the Board” in our
2015 Proxy Statement,
for the 2012 Annual Meeting of Shareholders, which section is incorporated in this annual report on Form 10-K by reference.
We have adopted a Code of Ethics and Business Conduct that is applicable to all our directors, officers and employees, including our principal executive officer, principal financial officer and principal accounting officer. We have also adopted Special Provisions Relating toofficer, which serves as the Company’s Principal Executive Officer and Senior Financial Officers (Special Provisions) that are partcode of our Corporate Governance Guidelines and that applyethics applicable to our principal executive officer, principal financial officer, and principal accounting officer.officer and persons performing similar functions under Item 406(b) of Regulation S-K. The Code of Ethics and Business Conduct and Special Provisions areis available on the “For Investors-Corporate Governance” section of our website atwww.piedmontng.com. If we amend or grant a waiver, including an implicit waiver, from the Code of Ethics and Business Conduct or Special Provisions that apply to the principal executive officer, principal financial officer and controllerprincipal accounting officer or persons performing similar functions and that relate to any element of the code enumerated in Item 406(b) of Regulation S-K, we will disclose the amendment or waiver on the “For Investors-Corporate Governance” section of our website within four business days of such amendment or waiver.
Item 11. Executive Compensation
Information for this item is set forth in the sections entitled “Executive Compensation,” “Director Compensation,” “Compensation Committee Interlocks and Insider Participation,” and “Compensation Committee Report” in our
2015 Proxy Statement,
for the 2012 Annual Meeting of Shareholders, which sections are incorporated in this annual report on Form 10-K by reference.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Information for this item is set forth in the section entitled “Security Ownership of Management and Certain Beneficial Owners” in our
2015 Proxy Statement,
for the 2012 Annual Meeting of Shareholders, which section is incorporated in this annual report on Form 10-K by reference.
Information concerning securities authorized for issuance under our equity compensation plans is set forth in the section entitled “Equity Compensation Plan Information” in our
2015 Proxy Statement,
for the 2012 Annual Meeting of Shareholders, which section is incorporated in this annual report on Form 10-K by reference.
Item 13. Certain Relationships and Related Transactions, and Director Independence
Information for this item is set forth in the section entitled
“Independence of Board Members“Director Independence and Related Person Transactions” in our
2015 Proxy Statement,
for the 2012 Annual Meeting of Shareholders, which section is incorporated in this annual report on Form 10-K by reference.
Item 14. Principal Accounting Fees and Services
Information for this item is set forth
in the table entitled “Fees For Services” in “Proposal 2 – Ratification of the Appointment of Deloitte & Touche LLP As Independent Registered Public Accounting Firm For Fiscal Year
2012”2015” in our
2015 Proxy Statement,
for the 2012 Annual Meeting of Shareholders, which section is incorporated in this annual report on Form 10-K by reference.
Item 15. Exhibits, Financial Statement Schedules
|
| | | | |
| (a) | | 1. | | Financial Statements |
The following consolidated financial statements for the year ended October 31, 2011,
The following consolidated financial statements for the year ended October 31, 2014, are included in Item 8 of this report as follows: | | | | Consolidated Balance Sheets -– October 31, 20112014 and 2010 | | | | 2013 Consolidated Statements of Comprehensive Income -– Years Ended October 31, 2011, 20102014, 2013 and 2009 | | | | 2012 Consolidated Statements of Cash Flows -– Years Ended October 31, 2011, 20102014, 2013 and 2009 | | | | 2012 Consolidated Statements of Stockholders’ Equity – Years Ended October 31, 2011, 20102014, 2013 and 2009 | | | | 2012 Notes to Consolidated Financial Statements | | | Report of Independent Registered Public Accounting Firm | | |
| | | | | | | (a) | | 2. | | Supplemental Consolidated Financial Statement Schedules |
None
Schedules and certain other information are omitted for the reason that they are not required or are not applicable, or the required information is shown in the consolidated financial statements or notes thereto.
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 10.2110.18 are management contracts or compensatory plans or arrangements. | | | | | | | | 3.1 | | Restated Articles of Incorporation of Piedmont Natural Gas Company, Inc., dated as of March 2009 (Exhibit(incorporated by reference to Exhibit 3.1, Form 10-Q for the quarter ended July 31, 2009). | | | | | | 3.2 | | By-lawsBylaws of Piedmont Natural Gas Company, Inc., as Amended and Restated Effective September 8, 2011 (Exhibit(incorporated by reference to Exhibit 3.1, Form 8-K dated September 13, 2011). | | | | | | 4.1 | | Note Agreement, dated as of September 21, 1992, between Piedmont and Provident Life and Accident Insurance Company (Exhibit(incorporated by reference to Exhibit 4.30, Form 10-K for the fiscal year ended October 31, 1992). |
| | | | | | | | | | 4.2 | | Amendment to September 1992 Note Agreement, dated as of September 16, 2005, by and between Piedmont and Provident Life and Accident Insurance Company (Exhibit(incorporated by reference to Exhibit 4.2, Form 10-K for the fiscal year ended October 31, 2007). | | | | | | 4.3 | | Indenture, dated as of April 1, 1993, between Piedmont and The Bank of New York Mellon Trust Company, N.A. (as successor to Citibank, N.A.), Trustee (Exhibit(incorporated by reference to Exhibit 4.1, Form S-3 Registration Statement No. 33-59369). | | | | | | 4.4 | | Medium-Term Note, Series A, dated as of October 6, 1993 (Exhibit(incorporated by reference to Exhibit 4.8, Form 10-K for the fiscal year ended October 31, 1993). |
| | | | | | | | | 4.5 | | First Supplemental Indenture, dated as of February 25, 1994, between PNG Acquisition Company, Piedmont Natural Gas Company, Inc., and Citibank, N.A., Trustee (Exhibit(incorporated by reference to Exhibit 4.2, Form S-3 Registration Statement No. 33-59369). | | | | | | 4.6 | | Medium-Term Note, Series A, dated as of September 19, 1994 (Exhibit(incorporated by reference to Exhibit 4.9, Form 10-K for the fiscal year ended October 31, 1994). | | | | | | 4.7 | | Form of Master Global Note (Exhibit(incorporated by reference to Exhibit 4.4, Form S-3 Registration Statement No. 33-59369). | | | | | | 4.8 | | Pricing Supplement of Medium-Term Notes, Series B, dated October 3, 1995 (Exhibit(incorporated by reference to Exhibit 4.10, Form 10-K for the fiscal year ended October 31, 1995). | | | | | | 4.9 | | Pricing Supplement of Medium-Term Notes, Series B, dated October 4, 1996 (Exhibit(incorporated by reference to Exhibit 4.11, Form 10-K for the fiscal year ended October 31, 1996). | | | | | | 4.10 | | Form of Master Global Note executed September 9, 1999 (Exhibit(incorporated by reference to Exhibit 4.4, Form S-3 Registration Statement No. 333-26161). | | | | | | 4.11 | | Pricing Supplement of Medium-Term Notes, Series C, dated September 15, 1999 (Rule(incorporated by reference to Rule 424(b)(3) Pricing Supplement to Form S-3 Registration Statement Nos. 33-59369 and 333-26161). | | | | | | 4.12 | | Second Supplemental Indenture, dated as of June 15, 2003, between Piedmont and Citibank, N.A., Trustee (Exhibit(incorporated by reference to Exhibit 4.3, Form S-3 Registration Statement No. 333-106268). | | | | | | 4.13 | | Form of 5% Medium-Term Note, Series E, dated as of December 19, 2003 (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(incorporated by reference to Exhibit 99.2, Form 8-K, dated December 23, 2003). |
| | | | | | | | | | 4.154.14 | | Third Supplemental Indenture, dated as of June 20, 2006, between Piedmont Natural Gas Company, Inc. and Citibank, N.A., as trustee (Exhibit(incorporated by reference to Exhibit 4.1, Form 8-K dated June 20, 2006). | | | | | | 4.164.15 | | Agreement of Resignation, Appointment and Acceptance dated as of March 29, 2007, by and among Piedmont Natural Gas Company, Inc., Citibank, N.A., and The Bank of New York Trust Company, N.A. (Exhibit(incorporated by reference to Exhibit 4.1, Form 10-Q for quarter ended April 30, 2007). | | | | | | 4.174.16 | | Note Purchase Agreement, dated as of May 6, 2011, among Piedmont Natural Gas Company, Inc. and the Purchasers party thereto (Exhibit(incorporated by reference to Exhibit 10, Form 8-K, dated May 12, 2011). | | | | | | 4.184.17 | | Form of 2.92% Series A Senior Notes due June 6, 2016 (Exhibit(incorporated by reference to Exhibit 4.1, Form 8-K dated May 12, 2011). | | | | | | 4.194.18 | | Form of 4.24% Series B Senior Notes due June 6, 2021 (Exhibit(incorporated by reference to Exhibit 4.2, Form 8-K dated May 12, 2011). | | | | | | 4.204.19 | | Fourth Supplemental Indenture, dated as of May 6, 2011, between Piedmont Natural Gas Company, Inc. and The Bank of New York Mellon Trust Company, N.A., as trustee (Exhibit(incorporated by reference to Exhibit 4.2, Form S-3-ASR Registration Statement No. 333-175386). |
| | | | | | | | | 4.214.20 | | Amendment to September 1992 Note Agreement dated as of April 15, 2011 by and between Piedmont Natural Gas Company, Inc., and Provident Life and Accident Insurance Company (Exhibit(incorporated by reference to Exhibit 10.3, Form 10-Q for the quarter ended April 30, 2011). | | | | | | 4.21 | | Note Purchase Agreement, dated as of March 27, 2012, among Piedmont Natural Gas Company, Inc. and the Purchasers party thereto (incorporated by reference to Exhibit 10.1, Form 8-K dated March 29, 2012). | | | | 4.22 | | Form of 3.47% Series A Senior Notes due July 16, 2027 (incorporated by reference to Exhibit 4.1, Form 8-K dated March 29, 2012). | | | | 4.23 | | Form of 3.57% Series B Senior Notes due July 16, 2027 (incorporated by reference to Exhibit 4.2, Form 8-K dated March 29, 2012). | | | | 4.24 | | Corporate Commercial Paper Master Note dated March 1, 2012 between U.S. Bank National Association as Paying Agent and Piedmont Natural Gas Company, Inc. as Issuer (incorporated by reference to Exhibit 4.1, Form 10-Q for the quarter ended April 30, 2012). | | | | 4.25 |
| Fifth Supplemental Indenture, dated August 1, 2013, between the Company and The Bank of New York Mellon Trust Company, N.A. (incorporated by reference to Exhibit 4.1, Form 8-K dated August 1, 2013). | |
|
| 4.26 |
| Form of 4.65% Senior Notes due 2043 (incorporated by reference to Exhibit 4.2, Form 8-K dated August 1, 2013). |
| | | 4.27 | | Sixth Supplemental Indenture, dated September 18, 2014, between the Company and The Bank of New York Mellon Trust Company, N.A. (incorporated by reference to Exhibit 4.1, Form 8-K dated September 18, 2014). | | | | | | | | 4.28 | | Form of 4.10% Senior Notes due 2034 (incorporated by reference to Exhibit 4.2, Form 8-K dated September 18, 2014). | | | | | | | | 4.29 | | Third Amendment to September 1992 Note Agreement, dated as of October 15, 2014, between the Company and Provident Life and Accident Insurance Company. | | | | | | Compensatory Contracts: | | | | | | 10.1 | | Form of Director Retirement Benefits Agreement with outside directors, dated September 1, 1999 (Exhibit(incorporated by reference to 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(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(incorporated by reference to Exhibit 10.2, Form 10-Q for the quarter ended July 31, 2007). | | | | | | 10.810.3 | | Schedule of Severance Agreements with Executives (Exhibit(incorporated by reference to Exhibit 10.2a, Form 10-Q for the quarter ended July 31, 2007). | | | | | | 10.910.4 | | Piedmont Natural Gas Company, Inc. Incentive Compensation Plan as Amended and Restated Effective December 15, 2010 (Appendix(incorporated by reference to Appendix A, Form DEF14A dated January 14, 2011). | |
| | | | | | | | 10.1010.5 | | Form of Performance Unit Award Agreement (Exhibit(incorporated by reference to Exhibit 10.1, Form 10-Q for the quarter ended January 31, 2011). | | | | | | 10.1110.6 | | Resolution of Board of Directors, June 3, 2011,7, 2013, establishing compensation for non-management directors (Exhibit(incorporated by reference to Exhibit 10.1, Form 10-Q for the quarter ended July 31, 2011)2013). | | | | | | 10.1210.7 | | Piedmont Natural Gas Company, Inc. Voluntary Deferral Plan, dated as of December 8, 2008, effective November 1, 2008 (Exhibit(incorporated by reference to Exhibit 10.1, Form 10-Q for the quarter ended January 31, 2009). | | | | | | 10.1310.8 | | Piedmont Natural Gas Company, Inc. Defined Contribution Restoration Plan, dated as of December 8, 2008, effective January 1, 2009 (Exhibit(incorporated by reference to Exhibit 10.2, Form 10-Q for the quarter ended January 31, 2009). | | | | | | 10.1410.9 | | Piedmont Natural Gas Company Employee Stock Purchase Plan, amended and restated as of April 1, 2009 (Exhibit(incorporated by reference to Exhibit 4.1, Form 8-K dated April 3, 2009). | | | | | | 10.1510.10 | | Amendment No. 1 to Director Retirement Benefits Agreements with outside directors, dated as of December 31, 2008 (Exhibit(incorporated by reference to 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). | | | | | | 10.1810.11 | | Severance Agreement between Piedmont Natural Gas Company, Inc. and Karl W. Newlin, dated as of June 4, 2010 (Exhibit(incorporated by reference to Exhibit 10.3, Form 10-Q for the quarter ended July 31, 2010). | | | | | | 10.1910.12 | | EmploymentInstrument of Amendment for Piedmont Natural Gas Company, Inc. Defined Contribution Restoration Plan dated as of January 23, 2012, by Piedmont Natural Gas Company, Inc. (incorporated by reference to Exhibit 10.1, Form 10-Q for the quarter ended January 31, 2012). | | | | 10.13 | | 2011 Retention Award Agreement dated December 15, 2011 between Piedmont Natural Gas Company, Inc. and Jane R. Lewis-Raymond, dated as of August 1, 2011. | | | | | | 10.20 | | Form of 2013 Retention Award Agreement (ExhibitThomas E. Skains (incorporated by reference to Exhibit 10.2, Form 10-Q for the quarter ended January 31, 2011)2012). | | | | 10.14 | | Severance Agreement, dated February 1, 2012, between Piedmont Natural Gas Company, Inc. and Victor M. Gaglio (incorporated by reference to Exhibit 10.2, Form 10-Q for the quarter ended April 30, 2012). | | | | 10.15 | | Amended and Restated Employment Agreement dated May 25, 2012 between Piedmont Natural Gas Company, Inc. and Thomas E. Skains (substantially identical agreements have been entered into with Victor M. Gaglio, Jane R. Lewis-Raymond, Karl W. Newlin, Kevin M. O’Hara and Franklin H. Yoho) (incorporated by reference to Exhibit 10.1, Form 10-Q for the quarter ended July 31, 2012). | | | | 10.16 | | Schedule of Amended and Restated Employment Agreements with Executives (incorporated by reference to Exhibit 10.2, Form 10-Q for the quarter ended July 31, 2012). | | | | 10.17 | | Amendment to the Piedmont Natural Gas Company Employee Stock Purchase Plan dated September 18, 2012, by Piedmont Natural Gas Company, Inc. (incorporated by reference to Exhibit 10.21, Form 10-K for the fiscal year ended October 31, 2012). | | | | 10.18 | | Resolution of Board of Directors, June 6, 2014, establishing compensation for non-management directors (incorporated by reference to Exhibit 10.1, Form 10-Q for the quarter ended July 31, 2014). | |
| | | | | | 10.21 | | Consulting Agreement dated as of November 1, 2011 between David J. Dzuricky and Piedmont Natural Gas Company, Inc. | | | | | | | | Other Contracts: | | | | | | 10.2210.19 | | Amended and Restated Limited Liability Company Agreement of SouthStar Energy Services LLC, effective January 1, 2004, between Piedmont Energy Company and Georgia Natural Gas Company (Exhibit(incorporated by reference to Exhibit 10.1, Form 10-Q for the quarter ended April 30, 2004). | | |
| | | 10.2310.20 | | First Amendment to Amended and Restated Limited Liability Company Agreement of SouthStar Energy Services LLC, dated as of July 31, 2006, between Piedmont Energy Company and Georgia Natural Gas Company (Exhibit(incorporated by reference to Exhibit 10.28, Form 10-K for the fiscal year ended October 31, 2006). | | | | | | 10.2410.21 | | Amendment by Written Consent to Amended and Restated Limited Liability Company Agreement of SouthStar Energy Services LLC, dated as of August 28, 2006, between Piedmont Energy Company and Georgia Natural Gas Company (Exhibit(incorporated by reference to Exhibit 10.29, Form 10-K for the fiscal year ended October 31, 2006). | | | | | | 10.2510.22 | | Amendment by Written Consent to Amended and Restated Limited Liability Company Agreement of SouthStar Energy Services LLC, dated as of September 20, 2006, between Piedmont Energy Company and Georgia Natural Gas Company (Exhibit(incorporated by reference to 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
10.23 | | Second Amendment to Amended and Restated Limited Liability Company Agreement of SouthStar Energy Services LLC by and between Georgia Natural Gas Company and Piedmont Energy Company, dated July 2, 2009 (Exhibit(incorporated by reference to Exhibit 10.2, Form 10-Q for the quarter ended July 31, 2009). | | | | | | 10.30
10.24 | | Settlement Agreement by and between Georgia Natural Gas Company and Piedmont Energy Company, dated July 29, 2009 (Exhibit(incorporated by reference to Exhibit 10.1, Form 8-K dated August 4, 2009). | | | | | | 10.31
10.25 | | Third Amendment to Amended and Restated Limited Liability Company Agreement of SouthStar Energy Services LLC by and between Georgia Natural Gas Company and Piedmont Energy Company, dated July 29, 2009 (Exhibit(incorporated by reference to Exhibit 10.2, Form 8-K dated August 4, 2009). | | | | | | 10.32
10.26 | | AssignmentForm of Commercial Paper Dealer Agreement between Piedmont Natural Gas Company, Inc. and Assumption between Citibank, N.A.Dealers party thereto (incorporated by reference to Exhibit 10.3, Form 10-Q for the quarter ended April 30, 2012). | | | | 10.27 | | Amended and Northern Trust Company,Restated Credit Agreement dated as of September 18, 2009 (Exhibit 10.37,October 1, 2012 among Piedmont Natural Gas Company, Inc., Wells Fargo Bank, National Association, as Administrative Agent, Swing Line Lender, L/C Issuer and a Lender, and Branch Banking and Trust Company, Bank of America, N.A., JPMorgan Chase Bank, N.A., PNC Bank, National Association, U.S. Bank National Association and Royal Bank of Canada, each a Lender (incorporated by reference to Exhibit 10.34, Form 10-K for the fiscal year ended October 31, 2009)2012). | | | | | | 10.33
10.28 | | CreditAmended and Restated Limited Liability Company Agreement of Constitution Pipeline Company, LLC dated April 9, 2012, by and among Williams Partners Operating LLC and Cabot Pipeline Holdings LLC (incorporated by reference to Exhibit 10.1, Form 10-Q for the quarter ended January 31, 2013). | | | | 10.29 | | First Amendment to Amended and Restated Limited Liability Company Agreement of Constitution Pipeline Company, LLC, dated as of 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, 2011November 9, 2012, by and among Constitution Pipeline Company, LLC, Williams Partners Operating LLC, Cabot Pipeline Holdings LLC, and Piedmont Natural GasConstitution Pipeline Company, Inc., Bank of America, N.A., as Administrative Agent, Swing Line Lender and L/C Issuer, and the Lenders thereunder (ExhibitLLC (incorporated by reference to Exhibit 10.2, Form 10-Q for the quarter ended April 30, 2011)January 31, 2013). | |
| | | | | | | | 10.30 | | Confirmation of Forward Sale Transaction dated January 29, 2013, between the Company and Morgan Stanley & Co. LLC, in its capacity as the forward counterparty (incorporated by reference to Exhibit 99.1, Form 8-K filed February 4, 2013). | | | | 10.31 | | Confirmation of Forward Sale Transaction dated February 19, 2013, between Piedmont Natural Gas Company, Inc., and Morgan Stanley & Co. LLC, in its capacity as the forward counterparty (incorporated by reference to Exhibit 99.1, Form 8-K filed February 25, 2013). | | | | 10.32 | | Second Amendment to Amended and Restated Limited Liability Company Agreement of Constitution Pipeline Company, LLC, dated as of May 29, 2013, by and among Constitution Pipeline Company, LLC, Williams Partners Operating LLC, Cabot Pipeline Holdings LLC, Piedmont Constitution Pipeline Company, LLC, and Capitol Energy Ventures Corp. (incorporated by reference to Exhibit 99.1, Form 8-K filed September 4, 2013). | | | | 10.33 | | Second Amended and Restated Limited Liability Company Agreement of SouthStar Energy Services LLC, dated as of September 1, 2013, by and between Georgia Natural Gas Company and Piedmont Energy Company (incorporated by reference to Exhibit 10.39, Form 10-K for the fiscal year ended October 31, 2013). | | | | 10.34 | | Increasing Lender Agreement dated as of November 1, 2013 among Wells Fargo Bank, National Association, Bank of America, N.A., Branch Banking and Trust Company, JPMorgan Chase Bank, N.A., PNC Bank, National Association, U.S. Bank National Association and Royal Bank of Canada, each as a Lender (incorporated by reference to Exhibit 10.1, Form 8-K dated November 4, 2013). |
| | | 10.35 * | | Limited Liability Company Agreement of Atlantic Coast Pipeline, LLC, dated as of September 2, 2014, by and between Dominion Atlantic Coast Pipeline, LLC, Duke Energy ACP, LLC, Piedmont ACP Company, LLC, and Maple Enterprise Holdings, Inc. | | | | 12 | | Computation of Ratio of Earnings to Fixed Charges. | | |
| | | 21 | | List of Subsidiaries. | | | | | | 23.1 | | Consent of Independent Registered Public Accounting Firm. |
| | | | | | | | | | 31.1 | | Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of the Chief Executive Officer. | | | | | | 31.2 | | Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of the Chief Financial Officer. | | | | | | 32.1 | | Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 of the Chief Executive Officer. | | |
| | | 32.2 | | Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 of the Chief Financial Officer. | |
| | | | | | | | 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 |
| | | * | | Certain portions of this Exhibit have been omitted pursuant to a request for confidential treatment. The non-public information has been filed separately with the SEC pursuant to Rule 24b-2 under the Securities Exchange Act of 1934, as amended. |
| | | Attached as Exhibit 101 to this Annual Report are the following documents formatted in extensible business reporting language (XBRL): (1) Document and Entity Information; (2) Consolidated Balance Sheets at October 31, 2014 and 2013; (3) Consolidated Statements of Comprehensive Income for the years ended October 31, 2014, 2013 and 2012; (4) Consolidated Statements of Cash Flows for the years ended October 31, 2014, 2013 and 2012; (5) Consolidated Statements of Stockholders’ Equity for the years ended October 31, 2014, 2013 and 2012; and Notes to Consolidated Financial Statements. |
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.
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. | | | | | | | | Piedmont Natural Gas Company, Inc. | | | (Registrant) | | | By: | | /s/ THOMASThomas E. SKAINS Skains | | | Thomas E. Skains | | | Chairman of the Board, President | | | and Chief Executive Officer | | | | Date: | | December 23, 20112014 |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. | | | | | Signature | | | | Title | | | | /s/ THOMAS E. SKAINS
Thomas E. Skains
| | | | Chairman of the Board, President and
Chief Executive Officer
(Principal Executive Officer)
| | | | Date: December 23, 2011
| | | | | | | | | | | Signature | | Title | | | /s/ KARL W. NEWLIN Thomas E. Skains | | Chairman of the Board, President and | | Thomas E. Skains | | Chief Executive Officer | | | (Principal Executive Officer) | | | | Date: December 23, 2014 | | | | | | /s/ Karl W. Newlin | | | | Senior Vice President and | | Karl W. Newlin | | Chief Financial Officer | | | (Principal Financial Officer) | | | | Date: December 23, 2011 2014 | | | | | | /s/ Jose M. Simon | | Vice President and Controller | | Jose M. Simon | | (Principal Accounting Officer) | | | | Date: December 23, 2014 | | |
| | | | /s/ JOSE M. SIMON
Jose M. Simon
| | | Signature | | Vice President and Controller
(Principal Accounting Officer)
Title | | | | /s/ E. James Burton | | Director | | E. James Burton | | | | | | /s/ Malcolm E. Everett III | | Director | | Malcolm E. Everett III | | | | | | /s/ Aubrey B. Harwell, Jr. | | Director | | Aubrey B. Harwell, Jr. | | | | | | /s/ Frank B. Holding, Jr. | | Director | | Frank B. Holding, Jr. | | | | | | /s/ Frankie T. Jones, Sr. | | Director | | Frankie T. Jones, Sr. | | | | | | /s/ Vicki McElreath | | Director | | Vicki McElreath | | | | | | | /s/ Minor M. Shaw | | Director | | Minor M. Shaw | |
| | | | /s/ Jo Anne Sanford | | Director | | Jo Anne Sanford | | | | | | /s/ David E. Shi | | Director | | David E. Shi | | | | | | /s/ Michael C. Tarwater | | Director | | Michael C. Tarwater | |
| | | | /s/ Phillip D. Wright | | Director | | Phillip D. Wright | | |
| | | | Date: December 23, 2011
| | Piedmont Natural Gas Company, Inc. | | | |
| | | | Form 10-K | Signature | | For the Fiscal Year Ended October 31, 2014 | | | | | Title | | | | /s/ E. JAMES BURTON
E. James Burton
| | Exhibits | | | Director
| | | | /s/ MALCOLM E. EVERETT III
Malcolm E. Everett III
4.29 | | | | Director
| | | | /s/ JOHN W. HARRIS
John W. Harris
| | | | Director
| | | | /s/ AUBREY B. HARWELL, JR.
Aubrey B. Harwell, Jr.
| | | | Director
| | | | /s/ FRANK B. HOLDING, JR.
Frank B. Holding, Jr.
| | | | Director
| | | | /s/ FRANKIE T. JONES, SR.
Frankie T. Jones, Sr.
| | | | Director
| | | | /s/ VICKI MCELREATH
Vicki McElreath
| | | | Director
| | | | /s/ MINOR M. SHAW
Minor M. Shaw
| | | | Director
| | | | /s/ MURIEL W. SHEUBROOKS
Muriel W. Sheubrooks
| | | | Director
| | | | /s/ DAVID E. SHI
David E. Shi
| | | | Director
|
Piedmont Natural Gas Company, Inc.
Form 10-K
For the Fiscal Year Ended October 31, 2011
Exhibits
| | | 10.19 | | EmploymentThird Amendment to September 1992 Note Agreement, between Piedmont Natural Gas Company, Inc. and Jane R. Lewis-Raymond, dated as of August 1, 2011October 15, 2014, between the Company and Provident Life and Accident Insurance Company | | | 10.21 | | Consulting | | 10.35 * | | Limited Liability Company Agreement between Piedmont Natural Gas Company, Inc. and David J. Dzuricky,of Atlantic Coast Pipeline, LLC, dated as of November 1, 2011September 2, 2014, by and between Dominion Atlantic Coast Pipeline, LLC, Duke Energy ACP, LLC, Piedmont ACP Company, LLC, and Maple Enterprise Holdings, Inc. | | | | | 12 | | Computation of Ratio of Earnings to Fixed Charges | | | | 21 | | List of Subsidiaries | | | | 23.1 | | Consent of Independent Registered Public Accounting Firm | | | | 31.1 | | Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of the Chief Executive Officer | | | | 31.2 | | Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of the Chief Financial Officer | | | | 32.1 | | Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 of the Chief Executive Officer | | | | 32.2 | | Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 of the Chief Financial Officer | | | | | * | | Certain portions of this Exhibit have been omitted pursuant to a request for confidential treatment. The non-public information has been filed separately with the SEC pursuant to Rule 24b-2 under the Securities Exchange Act of 1934, as amended. |
|
