Item 1. Business

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

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

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

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

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

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

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

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

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

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

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

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

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

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 .

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

Our Strategies

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Natural Gas Utility Operations

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

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

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

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

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

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

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

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

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

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

Competition

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

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

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

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

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

Other

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

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

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

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

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

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