This exhibit does not reflect events occurring after the filing of AGL Resources Inc.’s Annual Report on Form 10-K for the year ended December 31, 2013, other than to recast our segment information and to give effect to the classification of the business operations of our former cargo shipping segment (excluding Triton Container Investments, LLC) as discontinued operations, and does not modify or update the disclosures therein in any way, other than as described above.
| AGL Resources | AGL Resources Inc., together with its consolidated subsidiaries |
| Atlanta Gas Light | Atlanta Gas Light Company |
| Bcf | Billion cubic feet |
| Central Valley | Central Valley Gas Storage, LLC |
| Chattanooga Gas | Chattanooga Gas Company |
| Compass Energy | Compass Energy Services, Inc., which was sold in 2013 |
| EBIT | Earnings before interest and taxes, the primary measure of our operating segments’ profit or loss, which includes operating income and other income and excludes financing costs, including interest on debt and income tax expense |
| FERC | Federal Energy Regulatory Commission |
| GAAP | Accounting principles generally accepted in the United States of America |
| Georgia Commission | Georgia Public Service Commission, the state regulatory agency for Atlanta Gas Light |
| Golden Triangle | Golden Triangle Storage, Inc. |
| Heating Season | The period from November through March when natural gas usage and operating revenues are generally higher |
| Henry Hub | A major interconnection point of natural gas pipelines in Erath, Louisiana where NYMEX natural gas future contracts are priced |
| Illinois Commission | Illinois Commerce Commission, the state regulatory agency for Nicor Gas |
| Jefferson Island | Jefferson Island Storage & Hub, LLC |
| LNG | Liquefied natural gas |
| LOCOM | Lower of weighted average cost or current market price |
| Marketers | Marketers selling retail natural gas in Georgia and certificated by the Georgia Commission |
| New Jersey BPU | New Jersey Board of Public Utilities, the state regulatory agency for Elizabethtown Gas |
| Nicor | Nicor Inc. - an acquisition completed in December 2011 and former holding company of Nicor Gas |
| Nicor Gas | Northern Illinois Gas Company, doing business as Nicor Gas Company |
| NYMEX | New York Mercantile Exchange, Inc. |
| Operating margin | A non-GAAP measure of income, calculated as operating revenues minus cost of goods sold and revenue tax expense |
| OTC | Over-the-counter |
| PBR | Performance-based rate, a regulatory plan at Nicor Gas that provided economic incentives based on natural gas cost performance. The plan terminated in 2003 |
| PGA | Purchased Gas Adjustment |
| Piedmont | Piedmont Natural Gas Company, Inc. |
| Pivotal Home Solutions | Nicor Energy Services Company, doing business as Pivotal Home Solutions |
| Sawgrass Storage | Sawgrass Storage, LLC |
| SEC | Securities and Exchange Commission |
| Sequent | Sequent Energy Management, L.P. |
| Seven Seas | Seven Seas Insurance Company, Inc. |
| SouthStar | SouthStar Energy Services LLC |
| STRIDE | Atlanta Gas Light’s Strategic Infrastructure Development and Enhancement program |
| Tennessee Authority | Tennessee Regulatory Authority, the state regulatory agency for Chattanooga Gas |
| Triton | Triton Container Investments LLC |
| Tropical Shipping | Tropical Shipping and Construction Company Limited, and also the name used throughout this filing to describe the business operations of our former cargo shipping segment (excluding Triton), which now has been classified as discontinued operations and held for sale |
| U.S. | United States |
| Virginia Natural Gas | Virginia Natural Gas, Inc. |
| Virginia Commission | Virginia State Corporation Commission, the state regulatory agency for Virginia Natural Gas |
| WACOG | Weighted average cost of gas |
Unless the context requires otherwise, references to “we,” “us,” “our,” the “company” or “AGL Resources” mean consolidated AGL Resources Inc. and its subsidiaries. The operations and businesses described in this filing are owned and operated, and management services are provided, by distinct direct and indirect subsidiaries of AGL Resources. AGL Resources was organized and incorporated in 1995 under the laws of the State of Georgia.
Business Overview
AGL Resources, headquartered in Atlanta, Georgia, is an energy services holding company whose primary business is the distribution of natural gas through our natural gas distribution utilities. We also are involved in several other businesses that are mainly related and complementary to our primary business. Our operating segments consist of the following four operating and reporting segments which are consistent with how management views and manages our businesses. As a result of entering into a definitive agreement to sell Tropical Shipping, which was reported within our cargo shipping segment, we recast certain information in our financial statements to remove our cargo shipping segment in the second quarter of 2014. The financial results for Tropical Shipping were classified as discontinued operations as of the second quarter of 2014. The cargo shipping segment also included our investment in Triton, which has been reclassified into our other segment. For more information, see Note 15 to our consolidated financial statements under Item 8 set forth in Exhibit 99.4 to this Form 8-K.
| Distribution Operations | · Serves 4.5 million customers across 7 states · Performance driven by customer growth and/or usage, regulatory outcomes and infrastructure investment |
| | |
| Retail Operations | · Serves 620,000 energy customers and 1.1 million service contracts across 17 states · Performance driven by market leading position in Georgia as well as our June 2013 acquisition of approximately 33,000 residential and commercial relationships and our January 2013 acquisition of approximately 500,000 service contracts |
| | |
| Wholesale Services | · Engages in natural gas storage, gas pipeline arbitrage and provides natural gas asset management and/or related logistics services for most of our utilities, as well as for non-affiliated companies · Sequent’s portfolio of storage and transportation capacity is well positioned to serve customers and capture value under improving market conditions but remains subject to volatility in reported earnings due to changes in natural gas prices |
| | |
| Midstream Operations | · Consists primarily of high deliverability natural gas storage facilities · Business remains challenged due to weak seasonal spreads and continued oversupply of natural gas |
| | |
For more information on our segments, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations” under the caption “Results of Operations” and Note 13 to our consolidated financial statements set forth in Exhibit 99.3 and Exhibit 99.4, respectively, to this Form 8-K.
Merger with Nicor
On December 9, 2011, we closed our merger with Nicor and created a combined company with increased scale and scope in the distribution, storage and transportation of natural gas. As a result, we are currently one of the nation’s largest natural gas distribution companies based on customer count. The effects of Nicor’s results of operations and financial condition are reflected for the 12 months ended December 31, 2013 and 2012, while our 2011 results include activity from December 10, 2011 through December 31, 2011.
Our distribution operations segment is the largest component of our business and includes seven natural gas local distribution utilities with their primary focus being the safe and reliable delivery of natural gas. These utilities construct, manage and maintain intrastate natural gas pipelines and distribution facilities and include:
| Utility | State | | Number of customers (in thousands) | | | Approximate miles of pipe | |
| Nicor Gas | Illinois | | | 2,195 | | | | 34,000 | |
| Atlanta Gas Light | Georgia | | | 1,547 | | | | 32,600 | |
| Virginia Natural Gas | Virginia | | | 284 | | | | 5,500 | |
| Elizabethtown Gas | New Jersey | | | 279 | | | | 3,200 | |
| Florida City Gas | Florida | | | 105 | | | | 3,500 | |
| Chattanooga Gas | Tennessee | | | 63 | | | | 1,600 | |
| Elkton Gas | Maryland | | | 6 | | | | 100 | |
| Total | | | | 4,479 | | | | 80,500 | |
Competition and Customer Demand
All of our utilities face competition from other energy products. Our principal competitors are electric utilities and oil and propane providers serving the residential, commercial and industrial markets throughout our service areas. Additionally, the potential displacement or replacement of natural gas appliances with electric appliances is a competitive factor.
Competition for space heating and general household and small commercial energy needs generally occurs at the initial installation phase when the customer or builder makes decisions as to which types of equipment to install. Customers generally continue to use the chosen energy source for the life of the equipment. Customer demand for natural gas could be affected by numerous factors, including:
· | changes in the availability or price of natural gas and other forms of energy; |
· | general economic conditions; |
· | legislation and regulations; |
· | the cost and capability to convert from natural gas to alternative fuels; |
· | new commercial construction; and |
We continue to develop and grow our business through the use of a variety of targeted marketing programs designed to attract new customers and to retain existing customers. These efforts include working to add residential customers, multifamily complexes and commercial customers who use natural gas for purposes other than space heating, as well as evaluating and launching new natural gas related programs, products and services to enhance customer growth, mitigate customer attrition and increase operating revenues.
The natural gas related programs generally emphasize natural gas as the fuel of choice for customers and seek to expand the use of natural gas through a variety of promotional activities. In addition, we partner with numerous third-party entities such as builders, realtors, plumbers, mechanical contractors, architects and engineers to market the benefits of natural gas appliances and to identify potential retention options early in the process for those customers who might consider converting to alternative fuels.
Sources of Natural Gas Supply and Transportation Services
Procurement plans for natural gas supply and transportation to serve our regulated utility customers are reviewed and approved by our state utility commissions. We purchase natural gas supplies in the open market by contracting with producers, Marketers and from our wholly owned subsidiary, Sequent, under asset management agreements. We also contract for transportation and storage services from interstate pipelines that are regulated by the FERC. On occasion, when firm pipeline services are temporarily not needed, we may release the services in the secondary market under FERC-approved capacity release provisions or utilize asset management arrangements, thereby reducing the net cost of natural gas charged to customers for most of our utilities. Peak-use requirements are met through utilization of company-owned storage facilities, pipeline transportation capacity, purchased storage services, peaking facilities and other supply sources, arranged by either our transportation customers or us. We have been able to obtain sufficient supplies of natural gas to meet customer requirements. We believe natural gas supply and pipeline capacity will be sufficiently available to meet market demands in the foreseeable future.
Transportation Our utilities use firm pipeline entitlements, storage services and/or peaking capacity contracted with interstate capacity providers to serve the firm natural gas supply needs of our customers. In addition, Nicor Gas, Atlanta Gas Light, Chattanooga Gas, Elizabethtown Gas and Virginia Natural Gas operate on-system LNG facilities, underground natural gas storage fields and/or propane/air plants to meet the gas supply and deliverability requirements of their customers in the winter period. Generally, we work to build a portfolio of year-round firm transportation, seasonal storage and short-duration peaking services that will meet the needs of our customers under severe weather conditions with adequate operational flexibility to reliably manage the variability inherent in servicing customers using natural gas for space heating. Including seasonal storage and peaking services in this portfolio is more efficient and cost effective than reserving firm pipeline capacity rights all year for a limited number of cold winter days.
Typically, our firm contracts range in duration from 3 to 10 years. We work to stagger terms to maintain our ability to adjust the overall portfolio to meet changing market conditions. Our utilities have contracted for capacity that is predominately sourced from producing areas in the midcontinent and gulf coast regions, and they continue to evaluate capacity options that will provide long-term access to reliable and affordable natural gas supplies. We have and will continue to evaluate options to acquire capacity rights for shale gas being produced in close proximity to our service territories.
Given the number of agreements held by our utilities and the amount of capacity under contract, we make decisions as to the termination, extension or renegotiation of contracts every year. Slower demand and the growth in natural gas production from non-traditional supply basins have made the value assessment of capacity contracts more complex.
Supply Six of our utilities use asset management agreements with our wholly owned subsidiary, Sequent, for the primary purpose of reducing our utility customers’ gas cost recovery rates through payments to the utilities by Sequent (for Atlanta Gas Light these payments are controlled by the Georgia Commission and utilized for infrastructure improvements and to fund heating assistance programs, rather than for a reduction to gas cost recovery rates). Under these asset management agreements, Sequent supplies natural gas to the utility and markets excess capacity to improve the overall cost of supplying gas to the utility customers. At this time, the utilities primarily purchase their gas from Sequent. The purchase agreements require Sequent to provide firm gas to our utilities. However, these utilities maintain the right and ability to make their own gas supply purchases. This right allows our utilities to make long-term supply arrangements if they believe it is in the best interest of their customers. Nicor Gas has not entered into an asset management agreement with Sequent or any other parties.
Each agreement with Sequent has either an annual minimum guarantee within a profit sharing structure, a profit sharing structure without any annual minimum guarantee or a fixed fee. From the inception of these agreements in 2001 through 2013, Sequent has made sharing payments under these agreements totaling $225 million. The following table provides payments made by Sequent to our utilities under these agreements during the last three years.
| | | Total amount received | | |
| In millions | | 2013 | | | 2012 | | | 2011 | | Expiration Date |
| Atlanta Gas Light | | $ | 6 | | | $ | 5 | | | $ | 9 | | March 2017 |
| Virginia Natural Gas | | | 4 | | | | 3 | | | | 9 | | March 2016 |
| Florida City Gas | | | 1 | | | | 1 | | | | 2 | | March 2015 |
| Chattanooga Gas | | | 1 | | | | 1 | | | | 3 | | March 2015 |
| Elizabethtown Gas | | | 6 | | | | 5 | | | | 9 | | March 2014 (1) |
| Total | | $ | 18 | | | $ | 15 | | | $ | 32 | | |
| (1) | Discussions are underway with the New Jersey BPU and we expect a new agreement to be in place prior to the March 2014 expiration date. |
Utility Regulation and Rate Design
Rate Structures Our utilities operate subject to regulations and oversight of the state regulatory agencies in each of the states served by our utilities with respect to rates charged to our customers, maintenance of accounting records and various service and safety matters. Rates charged to our customers vary according to customer class (residential, commercial or industrial) and rate jurisdiction. These agencies approve rates designed to provide us the opportunity to generate revenues to recover all prudently incurred costs, including a return on rate base sufficient to pay interest on debt and provide a reasonable return for our shareholders. Rate base generally consists of the original cost of the utility plant in service, working capital and certain other assets, less accumulated depreciation on the utility plant in service and net deferred income tax liabilities, and may include certain other additions or deductions.
The natural gas market for Atlanta Gas Light was deregulated in 1997. Accordingly, Marketers, rather than a traditional utility, sell natural gas to end-use customers in Georgia and handle customer billing functions. The Marketers file their rates monthly with the Georgia Commission. As a result of operating in a deregulated environment, Atlanta Gas Light's role includes:
· | distributing natural gas for Marketers; |
· | constructing, operating and maintaining the gas system infrastructure, including responding to customer service calls and leaks; |
· | reading meters and maintaining underlying customer premise information for Marketers; and |
· | planning and contracting for capacity on interstate transportation and storage systems. |
Atlanta Gas Light earns revenue by charging rates to its customers based primarily on monthly fixed charges that are set by the Georgia Commission and periodically adjusted. The Marketers add these fixed charges to customer bills. This mechanism, called a straight-fixed-variable rate design, minimizes the seasonality of Atlanta Gas Light’s revenues since the monthly fixed charge is not volumetric or directly weather dependent.
With the exception of Atlanta Gas Light, the earnings of our regulated utilities can be affected by customer consumption patterns that are largely a function of weather conditions and price levels for natural gas. Specifically, customer demand substantially increases during the Heating Season when natural gas is used for heating purposes. We have various mechanisms, such as weather normalization mechanisms and weather derivative instruments in place at most of our utilities, which limit our exposure to weather changes within typical ranges in these utilities’ respective service areas.
All of our utilities, excluding Atlanta Gas Light, are authorized to use natural gas cost recovery mechanisms that allow them to adjust their rates to reflect changes in the wholesale cost of natural gas and to ensure they recover all of the costs prudently incurred in purchasing gas for their customers. Since Atlanta Gas Light does not sell natural gas directly to its end-use customers, it does not need nor utilize a traditional natural gas cost recovery mechanism. However, Atlanta Gas Light does maintain inventory for the Marketers in Georgia and recovers the cost of this gas through recovery mechanisms approved by the Georgia Commission specific to Georgia’s deregulated market. In addition to natural gas recovery mechanisms, we have other cost recovery mechanisms, such as regulatory riders, which vary by utility but allow us to recover certain costs, such as those related to environmental remediation and energy efficiency plans.
In traditional rate designs, utilities recover a significant portion of their fixed customer service and pipeline infrastructure costs based on assumed natural gas volumes used by our customers. Three of our utilities have decoupled regulatory mechanisms in place that encourage conservation. We believe that separating, or decoupling, the recoverable amount of these fixed costs from the customer throughput volumes, or amounts of natural gas used by our customers, allows us to encourage our customers’ energy conservation and ensures a more stable recovery of our fixed costs. The following table provides regulatory information for our six largest utilities.
| ($ in millions) | | Nicor Gas (9) | | | Atlanta Gas Light | | | Virginia Natural Gas | | | Elizabethtown Gas | | | Florida City Gas | | | Chattanooga Gas | |
Authorized return on rate base (1) | | | 8.09 | % | | | 8.10 | % | | | 7.38 | % | | | 7.64 | % | | | 7.36 | % | | | 7.41 | % |
Estimated 2013 return on rate base (2) | | | 7.55 | % | | | 8.56 | % | | | 6.85 | % | | | 8.42 | % | | | 5.90 | % | | | 8.53 | % |
Authorized return on equity (1) | | | 10.17 | % | | | 10.75 | % | | | 10.00 | % | | | 10.30 | % | | | 11.25 | % | | | 10.05 | % |
Estimated 2013 return on equity (2) | | | 8.77 | % | | | 11.65 | % | | | 10.19 | % | | | 11.92 | % | | | 10.57 | % | | | 12.46 | % |
Authorized rate base % of equity (1) | | | 51.07 | % | | | 51.00 | % | | | 45.36 | % | | | 47.89 | % | | | 36.77 | % | | | 46.06 | % |
Rate base included in 2013 return on equity (2) | | | $1,486 | | | | $2,226 | | | | $596 | | | | $496 | | | | $166 | | | | $89 | |
Weather normalization (3) | | | | | | | | | | ü | | | ü | | | | | | | ü | |
Decoupled or straight-fixed-variable rates (4) | | | | | | ü | | | ü | | | | | | | | | | | ü | |
Regulatory infrastructure program rates (5) | | ü | | | ü | | | ü | | | ü | | | | | | | | | |
Bad debt rider (6) | | ü | | | | | | | ü | | | | | | | | | | | ü | |
Synergy sharing policy (7) | | | | | | ü | | | | | | | | | | | | | | | | | |
Energy efficiency plan (8) | | ü | | | | | | | ü | | | ü | | | ü | | | ü | |
| Last decision on change in rates | | | 2009 | | | | 2010 | | | | 2011 | | | | 2009 | | | | N/A | | | | 2010 | |
(1) The authorized return on rate base, return on equity and percentage of equity were those authorized as of December 31, 2013.
| (2) | Estimates based on principles consistent with utility ratemaking in each jurisdiction. Rate base includes investments in regulatory infrastructure programs. |
| (3) | Involves regulatory mechanisms that allow us to recover our costs in the event of unseasonal weather, but are not direct offsets to the potential impacts of weather and customer consumption on earnings. These mechanisms are designed to help stabilize operating results by increasing base rate amounts charged to customers when weather is warmer-than-normal and decreasing amounts charged when weather is colder-than-normal. |
| (4) | Decoupled and straight-fixed-variable rate designs allow for the recovery of fixed customer service costs separately from assumed natural gas volumes used by our customers. Virginia Natural Gas’ request for approval of a decoupled rate design became effective June 1, 2013. |
| (5) | Includes programs that update or expand our distribution systems and liquefied natural gas facilities. Available in Illinois, but not yet effective. |
| (6) | Involves the recovery (refund) of the amount of bad debt expense over (under) an established benchmark expense. Virginia Natural Gas and Chattanooga Gas recover the gas portion of bad debt expense through PGA mechanisms. |
| (7) | Involves the recovery of 50% of net synergy savings achieved on mergers and acquisitions. |
| (8) | Includes the recovery of costs associated with plans to achieve specified energy savings goals. |
| (9) | In connection with the December 2011 Nicor merger, we agreed to (i) not initiate a rate proceeding for Nicor Gas that would increase base rates prior to December 2014, (ii) maintain 2,070 full-time equivalent employees involved in the operation of Nicor Gas for a period of three years and (iii) maintain the personnel numbers in specific areas of safety oversight of the Nicor Gas system for a period of five years. |
Current Regulatory Proceedings
Nicor Gas In June 2013, in connection with the PBR plan, the Illinois Commission issued an order requiring us to refund $72 million to Nicor Gas’ current customers over a 12-month period. In July 2013, Nicor Gas began refunding customers through our purchased gas adjustment mechanism, which is based on natural gas throughput. Through December 31, 2013, $29 million was refunded. For more information on the PBR plan, see Note 11 to our consolidated financial statements set forth in Exhibit 99.4 to this Form 8-K.
In July 2013, Illinois enacted legislation that will allow Nicor Gas to provide more widespread safety and reliability enhancements to its system. The legislation stipulates that rate increases to customer bills as a result of any infrastructure investments shall not exceed an annual average 4.0% of base rate revenues. We expect to submit a plan for approval by the Illinois Commission in mid-2014, to become effective in January 2015.
In July 2013, Illinois enacted legislation that provides a streamlined process to revise depreciation rates for natural gas utilities. On August 30, 2013, Nicor Gas filed a depreciation study with the Illinois Commission that proposed a composite depreciation rate of 3.07% compared to the prior composite rate of 4.10%. In October 2013, the Illinois Commission approved our proposed composite depreciation rate for Nicor Gas, which became effective as of the date the depreciation study was filed and had the effect of reducing our 2013 depreciation expense by $19 million. If applied to Nicor Gas’ property, plant and equipment throughout 2013, the new composite depreciation rate would have resulted in a $53 million decrease in annual depreciation expense. The lower composite depreciation rate did not impact customer rates.
In September 2013, Nicor Gas filed its second Energy Efficiency Plan, which outlines program offerings and therm reduction goals with spending of $93 million over the three-year period June 2014 through May 2017. Nicor Gas’ first Energy Efficiency Program is currently in its third year and will end in May 2014. Although there is no statutory deadline for approval of gas utility plans, Nicor Gas requested approval in the same five-month timeframe, or by March 1, 2014, as established by statute for electric utilities. The new plan must be implemented by June 1, 2014.
Atlanta Gas Light In December 2012, Atlanta Gas Light filed a petition with the Georgia Commission for approval to resolve an imbalance of approximately 4.8 Bcf of natural gas related to Atlanta Gas Light’s use of retained storage assets to operationally balance the system for the benefit of the natural gas market. We believe that any costs associated with resolving the imbalance are recoverable from Marketers. The resolution of this imbalance will be decided by the Georgia Commission and we are unable to predict the ultimate outcome.
In accordance with an order issued by the Georgia Commission, where AGL Resources makes a business acquisition that reduces the costs allocated or charged to Atlanta Gas Light for shared services, the net savings to Atlanta Gas Light will be shared equally between the firm customers of Atlanta Gas Light and our shareholders for a ten-year period. In December 2013, we filed a Report of Synergy Savings with the Georgia Commission in connection with the Nicor acquisition. If and when approved, the net savings should result in annual rate reductions to the firm customers of Atlanta Gas Light of $5 million. We expect the Georgia Commission to rule on the report in the second quarter of 2014.
Virginia Natural Gas In accordance with Virginia’s Natural Gas Conservation and Ratemaking Efficiency Act (CARE), Virginia Natural Gas filed for approval of its CARE plan with the Virginia Commission in December 2012. This plan includes a decoupling mechanism and authority to record accounting entries associated with such a mechanism. Our CARE plan has two principal components: (i) an Energy Conservation Plan component consisting of four cost-effective conservation and energy efficiency initiatives or programs plus a Community Outreach and Customer Education program; and (ii) a natural gas decoupling mechanism, Revenue Normalization Adjustment component and a rider which provides for a sales adjustment. In May 2013, the Virginia Commission approved our CARE plan, which includes a limited set of conservation programs and measures at a cost of $2 million over a three-year period. The CARE plan became effective June 1, 2013.
Chattanooga Gas In April 2013, legislation was signed into law that gives the Tennessee Authority the ability to approve alternative regulatory mechanisms. The law allows the Tennessee Authority to: (i) implement separate rate adjustment mechanisms that track specific costs, (ii) implement annual rate reviews in lieu of traditional rate cases and (iii) adopt other policies or procedures that permit a more timely review and revision of rates, streamline the regulatory process, and reduce the cost and time associated with the traditional ratemaking processes.
In April 2013, Chattanooga Gas filed a proposal with the Tennessee Authority to extend its energy conservation programs and associated rate adjustment mechanism that adjusts rates to recover reduced operating revenues as a result of reduced customer usage. In August 2013, a status conference was held by the Tennessee Authority and a procedural schedule was established whereby the Tennessee Authority’s Staff will issue a report on the evaluation of the conservation programs, which is expected in 2014. After the Tennessee Authority issues its report, Chattanooga Gas will be required to file a report on the impacts of the rate adjustment mechanism within 45 days. Interveners will then have 30 days to respond to Chattanooga Gas’s report and recommendations. The Tennessee Authority granted Chattanooga Gas an extension of its rate adjustment mechanism until the completion of the proceeding.
Capital Projects
We continue to focus on capital discipline and cost control while moving ahead with projects and initiatives that we expect will have current and future benefits to us and our customers, provide an appropriate return on invested capital and ensure the safety, reliability and integrity of our utility infrastructure. Total capital expenditures incurred during 2013 for our distribution operations segment were $684 million. The following table and discussions provide updates on some of our larger capital projects under various programs at our distribution operations segment. These programs update or expand our distribution systems to improve system reliability and meet operational flexibility and growth. Our anticipated expenditures for these programs in 2014 are discussed in “Liquidity and Capital Resources”.
| Dollars in millions | Utility | | Expenditures in 2013 | | | Expenditures since project inception | | | Miles of pipe installed | | | Year project began | | | Scheduled year of completion | |
| STRIDE program | | | | | | | | | | | | | | | | | | | | | |
Pipeline replacement program (PRP) (1) | Atlanta Gas Light | | $ | 151 | | | $ | 833 | | | | 2,708 | | | | 1998 | | | | 2013 | |
| Integrated System Reinforcement Program (i-SRP) | Atlanta Gas Light | | | 27 | | | | 251 | | | | n/a | | | | 2009 | | | | 2017 | |
| Integrated Customer Growth Program (i-CGP) | Atlanta Gas Light | | | 11 | | | | 40 | | | | n/a | | | | 2010 | | | | 2017 | |
| Integrated Vintage Plastic Replacement Program (i-VPR) | Atlanta Gas Light | | | 5 | | | | 5 | | | | 29 | | | | 2013 | | | | 2017 | |
| Enhanced infrastructure program | Elizabethtown Gas | | | 8 | | | | 116 | | | | 107 | | | | 2009 | | | | 2017 | |
| Accelerated infrastructure replacement program (SAVE) | Virginia Natural Gas | | | 24 | | | | 40 | | | | 86 | | | | 2012 | | | | 2017 | |
| Total | | | $ | 226 | | | $ | 1,285 | | | | 2,930 | | | | | | | | | |
| (1) | The mileage disclosed represents miles of pipe that have been retired. We closed the PRP on December 31, 2013. |
Atlanta Gas Light Our STRIDE program is comprised of i-SRP, i-CGP, PRP (which ended in 2013), and a new component, i-VPR. These infrastructure and replacement programs are used to update and expand distribution systems and liquefied natural gas facilities, improve system reliability and meet operations flexibility and growth. The purpose of the i-SRP is to upgrade our distribution system and liquefied natural gas facilities in Georgia, improve our peak-day system reliability and operational flexibility, and create a platform to meet long-term forecasted growth. Our i-CGP authorizes Atlanta Gas Light to extend its pipeline facilities to serve customers in areas without pipeline access and create new economic development opportunities in Georgia. The STRIDE program requires us to file an updated ten-year forecast of infrastructure requirements under i-SRP along with a new construction plan every three years for review and approval by the Georgia Commission.
In December 2013, we received approval from the Georgia Commission for a new $260 million, four-year STRIDE program, $214 million of which will be for i-SRP related projects and $46 million of which will be for i-CGP related projects. The program will be funded through a monthly rider surcharge per customer of $0.48 beginning in January 2015, which will increase to $0.96 beginning in January 2016 and to $1.43 beginning in January 2017. This surcharge will continue through 2025.
The purpose of the i-VPR program is to replace aging plastic pipe that was installed primarily in the mid-1960’s to the early 1980’s. We have identified approximately 3,300 miles of vintage plastic mains in our system that potentially should be considered for replacement over the next 15 - 20 years as it reaches the end of its useful life. In August 2013, the Georgia Commission approved i-VPR which includes the replacement of the first 756 miles of vintage plastic pipe over four years for $275 million. The program will be funded through a monthly rider surcharge per customer of $0.48 through December 2014, which will be increased to $0.96 beginning in January 2015 and to $1.45 beginning in January 2016. This surcharge will continue through 2025. If the Commission elects to extend the i-VPR program beyond 2017, the remaining vintage plastic mains in our system potentially could be considered for replacement through the program over the next 15 - 20 years as it reaches the end of its useful life.
Elizabethtown Gas In August 2013, our request to extend the enhanced infrastructure program was approved by the New Jersey BPU. The approval allows for infrastructure investment of $115 million over four years, effective as of September 2013. Carrying charges on the additional capital spend will be accrued and deferred at a weighted average cost for capital of 6.65%. Unlike the previous program, there will be no adjustment to base rates for the investments under the extended program until Elizabethtown Gas files its next rate case. We agreed to file a general rate case by September 2016. Also in August 2013, the New Jersey BPU approved the recovery of prior accelerated infrastructure investments under this program through a permanent adjustment to base rates.
In March 2013, the BPU issued an order inviting the submission of proposals from utilities in New Jersey for infrastructure upgrades designed to protect utility infrastructure from future major storm events. In September 2013, in response to this request, Elizabethtown Gas filed for a Natural Gas Distribution Utility Reinforcement Effort (ENDURE), a program that will improve our distribution system’s resiliency against coastal storms and floods. Under the proposed plan, Elizabethtown Gas will invest $15 million in infrastructure and related facilities and communication planning over a one year period beginning January 2014. Elizabethtown Gas is proposing to accrue and defer carrying charges on the investment until its next rate case proceeding.
Virginia Natural Gas In June 2012, the Virginia Commission approved Virginia Natural Gas’ SAVE program, which involves replacing aging infrastructure as prioritized through Virginia Natural Gas’ distribution integrity management program. SAVE was filed in accordance with a Virginia statute providing a regulatory cost recovery mechanism to recover the costs associated with certain infrastructure replacement programs. This is a five-year program that includes a maximum allowance for capital expenditure of $25 million per year, not to exceed $105 million in total. SAVE is subject to annual review by the Virginia Commission. We began recovering costs based on this program through a rate rider that became effective in August 2012. In May 2013, we filed our annual SAVE rate update detailing the first year performance and our expected future budget, which is subject to review and approval by the Virginia Commission. The rate update was approved with minor modifications by the Virginia Commission in July 2013 and became effective as of August 2013.
Environmental Remediation Costs
We are subject to federal, state and local laws and regulations governing environmental quality and pollution control. These laws and regulations require us to remove or remedy the effect on the environment of the disposal or release of specified substances at our current and former operating sites. As we continue to conduct the remediation and enter into cleanup contracts, we are increasingly able to provide conventional engineering estimates of the likely costs of many elements of the remediation program. These estimates contain various engineering assumptions, which we refine and update on an ongoing basis. These costs are primarily recovered through rate riders.
See “Management’s Discussion and Analysis of Financial Condition and Results of Operations” under the caption “Critical Accounting Policies and Estimates” and Note 3 to our consolidated financial statements set forth in Exhibit 99.3 and Exhibit 99.4, respectively, to this Form 8-K for additional information about our environmental remediation liabilities and efforts.
Our retail operations segment serves approximately 620,000 natural gas commodity customers and 1.1 million service contracts. Companies within our retail operations segment include SouthStar and Pivotal Home Solutions.
SouthStar markets natural gas to residential, commercial and industrial customers, primarily in Georgia and Illinois, where we capture spreads between wholesale and retail natural gas prices. Additionally, we offer our customers energy-related products that provide for natural gas price stability and utility bill management. These products mitigate and/or eliminate the risks to customers of colder-than-normal weather and/or changes in natural gas prices. We charge a fee or premium for these services. Through our commercial operations, we optimize storage and transportation assets and effectively manage commodity risk, which enables us to maintain competitive retail prices and operating margin.
SouthStar is a joint venture owned 85% by us and 15% by Piedmont and is governed by an executive committee with equal representation by both owners. After considering the relevant factors we consolidate SouthStar in our financial statements. In September 2013, we contributed our wholly owned Illinois retail energy subsidiaries to the SouthStar joint venture. Piedmont contributed $22.5 million in cash to SouthStar to maintain its 15% ownership interest. In connection with the contribution of our Illinois retail energy businesses, we provided certain limited protections to Piedmont regarding the value of the contributed businesses related to goodwill and other intangible assets. See Note 10 to our consolidated financial statements set forth in Exhibit 99.4 to this Form 8-K for more information.
In June 2013, our retail operations segment acquired approximately 33,000 residential and commercial relationships in Illinois for $32 million. The transaction significantly increases the size of our retail energy customer portfolio in Illinois with minimal incremental operating expenses.
Pivotal Home Solutions provides a suite of home protection products and services that offer homeowners additional financial stability regarding their energy service delivery, systems and appliances. We offer a proprietary line of customizable home warranty and energy efficiency plans that can be co-branded with utility and energy companies. Currently, Pivotal Home Solutions serves customers in 17 states primarily in Illinois, Indiana and Ohio.
In January 2013, our retail operations segment acquired approximately 500,000 service contracts and certain other assets for $122 million. We believe this acquisition will provide an enhanced platform for growth and continued expansion of this business in a number of key markets.
Competition and Operations Our retail operations business competes with other energy marketers to provide natural gas and related services to customers in the areas that they operate. In the Georgia market, SouthStar operates as Georgia Natural Gas and is the largest of 12 Marketers, with average customers of nearly 500,000 over the last three years and market share of approximately 31%.
In recent years, increased competition and the heavy promotion of fixed-price plans by SouthStar’s competitors have resulted in increased pressure on retail natural gas margins. In response to these market conditions, SouthStar’s residential and commercial customers have been migrating to fixed-price plans, which, combined with increased competition from other Marketers, has impacted SouthStar’s customer growth as well as margins.
In addition, similar to our natural gas utilities, our retail operations businesses face competition based on customer preferences for natural gas compared to other energy products, primarily electricity, and the comparative prices of those products. We continue to use a variety of targeted marketing programs to attract new customers and to retain existing customers.
SouthStar’s operations are sensitive to seasonal weather, natural gas prices, customer growth and consumption patterns similar to those affecting our utility operations. SouthStar’s retail pricing strategies and the use of a variety of hedging strategies, such as the use of futures, options, swaps, weather derivative instruments and other risk management tools, help to ensure retail customer costs are covered to mitigate the potential effect of these issues and commodity price risk on its operations. For more information on SouthStar’s energy marketing and risk management activities, see Item 7A, “Quantitative and Qualitative Disclosures About Market Risk” under the caption “Natural Gas Price Risk.”
Our retail operations business also experiences price, convenience and service competition from other warranty and heating, ventilation, and air conditioning (HVAC) companies. These businesses also bear risk from potential changes in the regulatory environment.
Our wholesale services segment consists of our wholly owned subsidiary Sequent that engages in asset management and optimization, storage, transportation, producer and peaking services and wholesale marketing of natural gas across the U.S. and Canada. Wholesale services utilizes a portfolio of natural gas storage assets, contracted supply from all of the major producing regions, as well as contracted storage and transportation capacity to provide these services to its customers. Its customers consist primarily of electric and natural gas utilities, power generators and large industrial customers. Our logistical expertise enables us to provide our customers with natural gas from the major producing regions and market hubs. We also leverage our portfolio of natural gas storage assets and contracted natural gas supply, transportation and storage capacity to meet our delivery requirements and customer obligations at competitive prices.
Wholesale services’ portfolio of storage and transportation capacity enables us to generate additional operating margin by optimizing the contracted assets through the application of our wholesale market knowledge and risk management skills as opportunities arise. These asset optimization opportunities focus on capturing the value from idle or underutilized assets, typically by participating in transactions that take advantage of volatility in pricing differences between varying geographic locations and time horizons (location and seasonal spreads) within the natural gas supply, storage and transportation markets to generate earnings. We seek to mitigate the commodity price and volatility risks and protect our operating margin through a variety of risk management and economic hedging activities.
In May 2013, we sold Compass Energy, which served primarily commercial and industrial customers, for an initial cash payment of $12 million, which resulted in an $11 million pre-tax gain ($5 million net of tax). We are eligible to receive contingent cash consideration up to $8 million with a guaranteed minimum receipt of $3 million that was recognized during 2013. The remaining $5 million of contingent cash consideration would be received from the buyer over a five-year earn out period based upon the financial performance of Compass Energy.
Competition and operations Wholesale services competes for asset management, long-term supply and seasonal peaking service contracts with other energy wholesalers, often through a competitive bidding process. We are able to price competitively by utilizing our portfolio of contracted storage and transportation assets and by renewing and adding new contracts at prevailing market rates. We will continue to broaden our market presence where our portfolio of contracted storage and transportation assets provides us a competitive advantage, as well as continue our pursuit of additional opportunities with power generation companies located in the areas of the country in which we operate. We are also focused on building our fee-based services in part to have a source of operating margin that is less impacted by volatility in the marketplace.
We view our wholesale margins from two perspectives. First, we base our commercial decisions on economic value for both our natural gas storage and transportation transactions. For our natural gas storage transactions, economic value is determined based on the net operating revenue to be realized at the time the physical gas is withdrawn from storage and sold and the derivative instrument used to economically hedge natural gas price risk on the physical storage that is settled. Similarly, for our natural gas transportation transactions, economic value is determined based on the net operating revenue to be realized at the time physical gas is purchased, transported, and sold utilizing our transportation capacity along with the settlement value associated with any derivative instruments.
The second perspective is the values reported in accordance with GAAP and encompassing periods prior to and in the period of physical withdrawal and sale of inventory or purchase, transportation and sale of natural gas. We enter into derivatives to hedge price risk prior to when the related physical storage withdrawal or transportation transactions occur based upon our commercial evaluation of future market prices. The reported GAAP amount is affected by the process of accounting for the financial hedging instruments in interim periods at fair value and prior to the period of the related physical storage and transportation transactions. The change in fair value of the hedging instruments is recognized in earnings in the period of change and is recorded as unrealized gains or losses. This results in reported earnings volatility during the interim periods, however, the expected margin based upon the hedged economic value is ultimately realized in the period natural gas is physically withdrawn from storage or transported and sold at market prices and the related hedging instruments are settled.
For our natural gas storage portfolio, we purchase natural gas for storage when the current market price we pay plus the cost for transportation, storage and financing is less than the market price we anticipate we could receive in the future. We attempt to mitigate substantially all of the commodity price risk associated with our storage portfolio by using derivative instruments to reduce the risk associated with future changes in the price of natural gas. We sell NYMEX futures contracts or OTC derivatives in forward months to substantially lock in the operating revenue that we will ultimately realize when the stored gas is actually sold.
We account for natural gas stored in inventory differently than the derivatives we use to mitigate the commodity price risk associated with our storage portfolio. The natural gas that we purchase and inject into storage is accounted for at the LOCOM value. The derivatives we use to mitigate commodity price risk are accounted for at fair value and marked to market each period. This difference in accounting treatment can result in volatility in wholesale services reported results, even though the expected net operating revenue and locked-in economic value is essentially unchanged since the date the transactions were initiated. These accounting timing differences also affect the comparability of wholesale services period-over-period results, since changes in forward NYMEX prices do not increase and decrease on a consistent basis from year to year.
For our natural gas transportation portfolio, we enter into transportation capacity contracts with interstate and intrastate pipelines for the delivery of natural gas between receipt and delivery points in future periods. We purchase natural gas for transportation when the market price we pay for gas at a receipt point plus the cost of transportation capacity required to deliver the gas to the delivery point is less than the sales price at the delivery point. The difference between the price at the receipt point and the delivery point is the transportation basis or location spread. Similar to our storage transactions, we attempt to mitigate the commodity price risk associated with our transportation portfolio by using derivative instruments to reduce the risk associated with future changes in the price of natural gas at the receipt and delivery points. We utilize futures contracts or OTC derivatives to hedge both the commodity price risk relative to the market price at the receipt point and the market price at the delivery point to substantially lock in the operating revenue that we will ultimately realize once the natural gas is received, delivered and sold.
Volatility in the natural gas market arises from a number of factors, such as weather fluctuations or changes in supply or demand for natural gas in different regions of the country. The volatility of natural gas commodity prices has a significant impact on our customer rates, our long-term competitive position against other energy sources and the ability of our wholesale services segment to capture value from location and seasonal spreads. During 2013, we experienced increased price volatility brought on by colder weather and supply constraints in the Northeast corridor, which enabled us to capture value under these market conditions. During 2012 and 2011, the volatility of daily Henry Hub spot market prices for natural gas in the U.S. was significantly lower than it had been for several prior years. This was the result of a robust natural gas supply, mild weather and ample storage.
It is possible the current market conditions may not continue and that natural gas prices will remain low for an extended period based on current levels of excess supply relative to market demand for natural gas, in part due to abundant sources of shale natural gas reserves, particularly in the Marcellus Shale producing region where Sequent has natural gas receipt requirements, and the lack of demand growth by commercial and industrial enterprises. However, as economic conditions improve, the demand for natural gas may increase, natural gas prices could rise and higher volatility could return to the natural gas markets. Consequently, we continue to reposition Sequent’s business model with respect to fixed costs and the types of contracts pursued and executed.
Our natural gas acquisition strategy is designed to secure sufficient supplies of natural gas to meet the needs of our utility customers and to hedge gas prices to effectively manage costs, reduce price volatility and maintain a competitive advantage. Additionally, our hedging strategies and physical natural gas supplies in storage enable us to reduce earnings risk exposure due to higher gas costs.
Sequent’s expected natural gas withdrawals from storage and expected recovery of hedge losses associated with Sequent’s transportation portfolio are presented in the following tables, along with the net operating revenues expected at the time of withdrawal from storage and the physical flow of natural gas between contracted transportation receipt and delivery points. Sequent’s expected net operating revenues exclude storage and transportation demand charges, as well as other variable fuel, withdrawal, receipt and delivery charges, but are net of the estimated impact of profit sharing under our asset management agreements. Further, the amounts that are realizable in future periods are based on the inventory withdrawal schedule, planned physical flow of natural gas between the transportation receipt and delivery points and forward natural gas prices at December 31, 2013. A portion of Sequent’s storage inventory and transportation capacity is economically hedged with futures contracts, which results in realization of substantially fixed net operating revenues, timing notwithstanding.
| In Bcf | | Storage schedule (WACOG $3.42) | | | Expected net operating revenues (in millions) | |
| First quarter - 2014 | | | 35 | | | $ | 26 | |
| Second quarter - 2014 | | | 1 | | | | 2 | |
| Total at December 31, 2013 | | | 36 | | | $ | 28 | |
| Total at December 31, 2012 | | | 51 | | | $ | 27 | |
For the year ended December 31, 2013, we have recorded $16 million in losses associated with the hedging of our storage position, compared to $14 million in storage hedge gains the same period last year. These hedge losses primarily relate to rising gas prices during the fourth quarter of 2013. If Sequent’s storage withdrawals associated with existing inventory positions are executed as planned, it expects net operating revenues from storage withdrawals of $28 million in 2014. This could change as Sequent adjusts its daily injection and withdrawal plans in response to changes in market conditions in future months and as forward NYMEX prices fluctuate.
The net operating revenues expected to be generated from the physical withdrawal of natural gas from storage do not reflect the earnings impact related to the movement in our hedges to lock in the forward location spread for the delivery of natural gas between two transportation delivery points associated with our transportation capacity portfolio.
For the year ended December 31, 2013, we have recorded $73 million in losses associated with the hedging of our transportation portfolio, or $70 million higher hedge losses as compared to the same period last year. These hedge losses are the result of widening transportation basis spreads associated with colder-than-normal weather, higher demand during the second half of 2013 and supply constraints experienced at natural gas receipt and delivery points throughout the Northeast corridor. These losses primarily relate to forward transportation and commodity positions for 2014, during which we expect to physically flow natural gas between the hedged transportation receipt and delivery points and utilize the contracted transportation capacity. The following table shows the periods associated with the transportation hedge losses during which the derivatives will be settled and the physical transportation transactions will occur that offset the hedge losses recognized in 2013.
| In millions | | Expected net operating revenues | |
| 2014 | | $ | 63 | |
| 2015 | | | 7 | |
| 2016 and thereafter | | | 3 | |
| Total at December 31, 2013 | | $ | 73 | |
| Total at December 31, 2012 | | $ | 3 | |
The unrealized storage and transportation hedge losses do not change the underlying economic value of our storage and transportation positions, and based on current expectations will largely be reversed in 2014 when the related transactions occur and are recognized. For more information on Sequent’s energy marketing and risk management activities, see Item 7A, “Quantitative and Qualitative Disclosures About Market Risk” under the caption “Natural Gas Price Risk.”
Our midstream operations segment includes a number of businesses that are related and complementary to our primary business. The most significant of these businesses is our natural gas storage business, which develops, acquires and operates high-deliverability underground natural gas storage assets in the Gulf Coast region of the U.S. and in northern California. While this business can generate additional revenue during times of peak market demand for natural gas storage services, our natural gas storage facilities have a portfolio of short, medium and long-term contracts at fixed market rates. The following table shows the working gas capacity and firm subscription amounts by storage facility as of December 31, 2013.
| | | | | | | | Subscribed (1) | |
| In Bcf | Location | Type | | Working Gas Capacity | | | Amount | | | % | |
Jefferson Island (2) (3) | Louisiana | Salt-dome | | | 7.3 | | | | 5.6 | | | | 77 | % |
Golden Triangle (3) | Texas | Salt-dome | | | 13.5 | | | | 2.0 | | | | 15 | % |
Central Valley (4) | California | Depleted field | | | 11.0 | | | | 3.0 | | | | 27 | % |
| Total | | | | | 31.8 | | | | 10.6 | | | | 33 | % |
| 1) | The amount and percentage of firm capacity under subscription does not include 3.5 Bcf of capacity subscribed by Sequent at December 31, 2013. |
| 2) | Regulated by the Louisiana Department of Natural Resources. |
| 3) | Regulated by the FERC. |
| 4) | Regulated by the California Public Utilities Commission. |
Sawgrass Storage This 50% owned joint venture between us and a privately held energy exploration and production company was granted certification from FERC in March 2012 for the development of an underground natural gas storage facility in Louisiana with 30 Bcf of working gas capacity. The FERC certificate is set to expire in March 2014. Given the current storage market conditions and the need for additional storage capacity in the future, in December 2013 the joint venture decided to terminate development of this facility and recognized an impairment loss of $16 million, which reduced the carrying amount of the joint venture’s long-lived assets to fair value. Consequently, we recognized our 50% interest in the loss during the fourth quarter of 2013, resulting in an $8 million ($5 million net of tax) charge to operating income. For more information about our investment in Sawgrass Storage, see Note 10 to the consolidated financial statements set forth in Exhibit 99.4 to this Form 8-K.
Magnolia Enterprise Holdings, Inc. This wholly owned subsidiary operates a pipeline that provides our Georgia customers access to LNG from the Elba Island terminal near Savannah, Georgia. The pipeline was completed in November 2009 and provides diversification of natural gas sources and increased reliability of service in the event that supplies coming from other supply sources are disrupted.
Competition and operations Our natural gas storage facilities primarily compete with natural gas facilities in the Gulf Coast region of the U.S. as the majority of the existing and proposed high deliverability salt-dome natural gas storage facilities in North America are located in the Gulf Coast region. Salt caverns have also been leached from bedded salt formations in the Northeastern and Midwestern states. Competition for our Central Valley storage facility primarily consists of storage facilities in northern California and western North America.
The market fundamentals of the natural gas storage business are cyclical. The abundant supply of natural gas in recent years and the resulting lack of market and price volatility have negatively impacted the profitability of our storage facilities. In 2013, expiring storage capacity contracts were re-subscribed at lower prices and we anticipate these lower natural gas prices to continue in 2014 as compared to historical averages. The prices for natural gas storage capacity are expected to increase as supply and demand quantities reach equilibrium as the economy improves, expected exports of LNG occur and/or natural gas demand increases in response to low prices and expanded uses for natural gas. We believe our storage assets are strategically located to benefit from these expected improvements in market fundamentals, including the overall growth in the natural gas market and there are significant barriers to develop new storage facilities, including time of construction and other costs, federal, state and local permitting and approvals and suitable and available sites, to capitalize on these expected improvements in market conditions.
Our other segment primarily includes our non-operating business units. AGL Services Company is a service company we established to provide certain centralized shared services to our operating segments. We allocate substantially all of AGL Services Company’s operating expenses and interest costs to our operating segments in accordance with state regulations. Our EBIT results include the impact of these allocations to the various operating segments. However, merger-related costs were not allocated to our operating segments.
AGL Capital Corporation, our wholly owned finance subsidiary, provides for our ongoing financing needs through a commercial paper program, the issuance of various debt and hybrid securities and other financing arrangements. This segment also includes intercompany eliminations for transactions between our operating business segments.
On April 4, 2014 we entered into a definitive agreement to sell Tropical Shipping, which historically operated within our cargo shipping segment. Cargo shipping also included our investment in Triton, which is not a part of the sale and has been reclassified into our other segment. Triton is a full-service global leasing company and an owner-lessor of marine cargo containers. Profits and losses are generally allocated to investors’ capital accounts in proportion to their capital contributions. Our investment in Triton is accounted for under the equity method, and our share of earnings is reported within “Other Income” on our Consolidated Statements of Income. For more information about our equity method investments, see Note 10 to the consolidated financial statements set forth in Exhibit 99.4 to this Form 8-K.
Employees
As of December 31, 2013, we had approximately 5,060 employees, all of whom were in the U.S. and does not include the 1,034 employees in discontinued operations.
The following table provides information about our natural gas utilities’ collective bargaining agreements, which represent approximately 27% of our total employees.
| | | # of Employees | | Contract Expiration Date |
Nicor Gas International Brotherhood of Electrical Workers (Local No. 19) (1) | | | 1,351 | | February 2014 |
Virginia Natural Gas International Brotherhood of Electrical Workers (Local No. 50) | | | 132 | | May 2015 |
Elizabethtown Gas Utility Workers Union of America (Local No. 424) | | | 172 | | November 2015 |
| Total | | | 1,655 | | |
(1) Contract negotiations are ongoing; however, we do not expect a new contract to be finalized prior to the expiration of the current contract. We have a continuation agreement in place and do not expect this to result in a work stoppage. |
We believe that we have a good working relationship with our unionized employees and there have been no work stoppages at Virginia Natural Gas, Elizabethtown Gas, or Nicor Gas since we acquired those operations in 2000, 2004, and 2011, respectively. As we have historically done, we remain committed to work in good faith with the unions to renew or renegotiate collective bargaining agreements that balance the needs of the Company and our employees. Our current collective bargaining agreements do not require our participation in multiemployer retirement plans and we have no obligation to contribute to any such plans.
Available Information
Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and proxy statements, and amendments to those reports that we file with, or furnish to, the SEC are available free of charge at the SEC website http://www.sec.gov and at our website, www.aglresources.com, as soon as reasonably practicable after we electronically file such reports with, or furnish such reports to, the SEC. However, our website and any contents thereof should not be considered to be incorporated by reference into this document. We will furnish copies of such reports free of charge upon written request to our Investor Relations department. You can contact our Investor Relations department at:
AGL Resources Inc.
Investor Relations
P.O. Box 4569
Atlanta, GA 30302-4569
404-584-4000
In Part III of this Form 10-K, we incorporate certain information by reference from our Proxy Statement for our 2014 annual meeting of shareholders. We expect to file that Proxy Statement with the SEC on or about March 14, 2014, and we will make it available on our website as soon as reasonably practicable. Please refer to the Proxy Statement when it is available.
Additionally, our corporate governance guidelines, code of ethics, code of business conduct and the charters of each committee of our Board of Directors are available on our website. We will furnish copies of such information free of charge upon written request to our Investor Relations department.
