Georgia | 58-2210952 |
(State of incorporation) | (I.R.S. Employer Identification No.) |
Securities registered pursuant to Section 12(b) of the Act: | |
Title of each class | Name of each exchange on which registered |
Common Stock, $5 Par Value | New York Stock Exchange |
Page | ||
AFUDC | Allowance for funds used during construction |
AGL Capital | AGL Capital Corporation |
AGL Credit Facility | $1.3 billion credit agreement entered into by AGL Capital to support its commercial paper program |
AGL Resources | AGL Resources Inc., together with its consolidated subsidiaries |
Atlanta Gas Light | Atlanta Gas Light Company |
Atlantic Coast Pipeline | Atlantic Coast Pipeline, LLC |
Bcf | Billion cubic feet |
Board | AGL Resources Board of Directors |
Central Valley | Central Valley Gas Storage, LLC |
Chattanooga Gas | Chattanooga Gas Company |
Chicago Hub | A venture of Nicor Gas, which provides natural gas storage and transmission-related services to marketers and gas distribution companies |
Compass Energy | Compass Energy Services, Inc., which was sold in 2013 |
CUB | Citizens Utility Board |
Dalton Pipeline | A 50% undivided ownership interest in a pipeline facility in Georgia |
EBIT | Earnings before interest and taxes, the primary measure of our reportable segments’ profit or loss, which includes operating income and other income and excludes interest on debt and income tax expense |
EPA | U.S. Environmental Protection Agency |
ERC | Environmental remediation costs |
FASB | Financial Accounting Standards Board |
FERC | Federal Energy Regulatory Commission |
Fitch | Fitch Ratings |
Florida Commission | Florida Public Service Commission, the state regulatory agency for Florida City Gas |
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 |
Georgia Natural Gas | The trade name under which SouthStar does business in Georgia |
Golden Triangle | Golden Triangle Storage, Inc. |
Heating Degree Days | A measure of weather, calculated when the average daily temperatures are less than 65 degrees Fahrenheit |
Heating Season | The period from November through March when natural gas usage and operating revenues are generally higher |
Henry Hub | An interconnection point of natural gas pipelines in Erath, Louisiana where NYMEX natural gas future contracts are priced |
Horizon Pipeline | Horizon Pipeline Company, LLC |
Illinois Commission | Illinois Commerce Commission, the state regulatory agency for Nicor Gas |
Jefferson Island | Jefferson Island Storage & Hub, LLC |
LIBOR | London Inter-Bank Offered Rate |
LIFO | Last-in, first-out |
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 |
Merger Agreement | Agreement and Plan of Merger dated August 23, 2015 by Southern Company, AMS Corp., a subsidiary of Southern Company, and AGL Resources |
MGP | Manufactured gas plant |
Moody’s | Moody’s Investors Service |
New Jersey BPU | New Jersey Board of Public Utilities, the state regulatory agency for Elizabethtown Gas |
Nicor | Nicor Inc. - former holding company of Nicor Gas |
Nicor Gas | Northern Illinois Gas Company, doing business as Nicor Gas Company |
Nicor Gas Credit Facility | $700 million credit facility entered into by Nicor Gas to support its commercial paper program |
NYMEX | New York Mercantile Exchange, Inc. |
OCI | Other comprehensive income |
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 |
Pad gas | Volumes of non-working natural gas used to maintain the operational integrity of the natural gas storage facility |
PBR | Performance-based rate |
PennEast Pipeline | PennEast Pipeline Company, LLC |
PGA | Purchased gas adjustment |
Piedmont | Piedmont Natural Gas Company, Inc. |
Pivotal Home Solutions | Nicor Energy Services Company, doing business as Pivotal Home Solutions |
PP&E | Property, plant and equipment |
PRP | Pipeline Replacement Program, Atlanta Gas Light's 15-year infrastructure replacement program, which ended in December 2013 |
S&P | Standard & Poor’s Ratings Services |
Sawgrass Storage | Sawgrass Storage, LLC |
SEC | Securities and Exchange Commission |
Sequent | Sequent Energy Management, L.P. |
Southern Company | The Southern Company |
SouthStar | SouthStar Energy Services, LLC |
STRIDE | Atlanta Gas Light’s Strategic Infrastructure Development and Enhancement program |
Triton | Triton Container Investments, LLC |
Tropical Shipping | Tropical Shipping and Construction Company Limited, which was sold in 2014 |
U.S. | The United States of America |
VaR | Value-at-risk |
VIE | Variable interest entity |
Virginia Commission | Virginia State Corporation Commission, the state regulatory agency for Virginia Natural Gas |
Virginia Natural Gas | Virginia Natural Gas, Inc. |
WACC | Weighted average cost of capital |
WACOG | Weighted average cost of gas |
WNA | Weather normalization adjustment |
Distribution Operations | • | Operates, constructs and maintains 81,300 miles of natural gas pipeline and 14 storage facilities, with total capacity of 158 Bcf, to provide natural gas to residential, commercial and industrial customers |
• | Serves 4.5 million customers across seven states | |
• | Rates of return are regulated by each individual state in return for exclusive franchises | |
Retail Operations | • | Provides natural gas commodity and related services to customers in competitive markets or markets that provide for customer choice |
• | Serves 645,000 energy customers in seven states and 1.2 million service contracts across 17 states | |
Wholesale Services | • | Engages in natural gas storage and gas pipeline arbitrage, and provides natural gas asset management and related logistics services for most of our utilities, as well as non-affiliated companies |
• | Serves a variety of customers in the natural gas value chain with operations structured to optimize storage and transportation portfolios under a wide range of market conditions through the use of hedging tools that allow us to capture additional value while limiting risk | |
Midstream Operations | • | Consists primarily of high deliverability wholly owned natural gas storage facilities as well as partnerships and joint ventures in pipelines, enabling the provision of diverse sources of natural gas supplies to our customers |
Utility | State | Number of customers (in thousands) | Approximate miles of pipe | ||||
Nicor Gas | Illinois | 2,198 | 34,300 | ||||
Atlanta Gas Light | Georgia | 1,578 | 32,900 | ||||
Virginia Natural Gas | Virginia | 290 | 5,600 | ||||
Elizabethtown Gas | New Jersey | 283 | 3,200 | ||||
Florida City Gas | Florida | 107 | 3,600 | ||||
Chattanooga Gas | Tennessee | 64 | 1,600 | ||||
Elkton Gas | Maryland | 6 | 100 | ||||
Total | 4,526 | 81,300 |
• | change in the availability or price of natural gas and other forms of energy; |
• | general economic conditions; |
• | energy conservation, including state-supported energy efficiency programs; |
• | legislation and regulations; and |
• | the cost and capability to convert from natural gas to alternative energy products. |
• | 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. |
Dollars in millions | Nicor Gas | Atlanta Gas Light | Elizabethtown Gas | Virginia Natural Gas | Florida City Gas | Chattanooga Gas | ||||||
Authorized return on rate base (1) | 8.09% | 8.10% | 7.64% | 7.38% | 7.36% | 7.41% | ||||||
Estimated 2015 return on rate base (2) | 7.20% | 7.65% | 7.83% | 5.83% | 4.40% | 6.82% | ||||||
Authorized return on equity (1) | 10.17% | 10.75% | 10.30% | 10.00% | 11.25% | 10.05% | ||||||
Estimated 2015 return on equity (2) | 9.66% | 9.86% | 10.70% | 7.43% | 5.80% | 8.74% | ||||||
Authorized rate base % of equity (1) | 51.07% | 51.00% | 47.89% | 45.36% | 36.77% | 46.06% | ||||||
Rate base included in 2015 return on equity (2) | $1,654 | $2,352 | $555 | $615 | $194 | $117 | ||||||
Weather normalization (3) | ü | ü | ü | |||||||||
Decoupled, including straight-fixed-variable rates (4) | ü | ü | ü | |||||||||
Regulatory infrastructure program rates (5) | ü | 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 (9) | 2009 | 2010 | 2009 | 2011 | 2004 | 2010 |
(1) | The authorized return on rate base, return on equity and rate base percentage of equity represent those authorized as of December 31, 2015. |
(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 on earnings of weather and customer consumption. 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) | Allows for the recovery of fixed customer service costs separately from assumed natural gas volumes used by our customers. |
(5) | Includes programs that update or expand our distribution systems and liquefied natural gas facilities. |
(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) | Elizabethtown Gas has agreed to file a general rate case with the New Jersey BPU by September 2016. |
Utility | Program | Program details | Recovery | Expenditures in 2015 (in millions) | Expenditures since project inception (in millions) | Miles of pipe installed since project inception | Scope of program (miles) | Program duration (years) | Last year of program | |||||||||||||
Nicor Gas | Investing in Illinois | (1)(2) | Rider | 252 | 273 | 164 | 800 | 9 | 2023 | |||||||||||||
Atlanta Gas Light | Integrated Vintage Plastic Replacement Program (i-VPR) | (3) | Rider | 63 | 130 | 398 | 756 | 4 | 2017 | |||||||||||||
Atlanta Gas Light | Integrated System Reinforcement Program (i-SRP) | (8) | Rider | 44 | 309 | n/a | n/a | 8 | 2017 | |||||||||||||
Atlanta Gas Light | Integrated Customer Growth Program (i-CGP) | (9) | Rider | 15 | 62 | n/a | n/a | 8 | 2017 | |||||||||||||
Florida City Gas | Safety, Access and Facility Enhancement Program (SAFE) | (4) | Rider | 1 | 1 | 4 | 254 | 10 | 2025 | |||||||||||||
Virginia Natural Gas | Steps to Advance Virginia’s Energy (SAVE) | (1) | Rider | 27 | 91 | 163 | 250 | 5 | 2017 | |||||||||||||
Elizabethtown Gas | Aging Infrastructure Replacement (AIR) | (5) | Base Rates | 39 | 77 | 75 | 130 | 4 | 2017 | |||||||||||||
Chattanooga Gas | Bare Steel & Cast Iron | (5) | Base Rates | 5 | 38 | 84 | 111 | 10 | 2020 | |||||||||||||
Florida City Gas | Galvanized Replacement Program | (6) | Base Rates | — | 15 | 79 | 111 | 17 | 2017 | |||||||||||||
Atlanta Gas Light | Savannah Backyard Main | (4) | Base Rates | 4 | 14 | 59 | 98 | 5 | 2017 | |||||||||||||
Elizabethtown Gas | Elizabethtown Natural Gas Distribution Utility Reinforcement Effort (ENDURE) | (7) | Base Rates | 11 | 14 | 12 | 13 | 1 | 2015 | |||||||||||||
Total | 461 | 1,024 | 1,038 | 2,523 |
(1) | Cast iron, bare steel, mid vintage plastic and risk based materials. |
(2) | Represents expenditures on qualifying infrastructure that have been placed into service after the rate freeze expiration date, December 9, 2014. |
(3) | Early vintage plastic, risk based mid vintage plastic, mid vintage neighborhood convenience. |
(4) | Backyard main replacement. |
(5) | Cast iron and bare steel. |
(6) | Galvanized and X-Tube steel. Reflects expenditures and miles of pipe installed since we acquired Florida City Gas in November 2004. |
(7) | Cast iron and distribution reinforcement. |
(8) | Large diameter pressure improvement and system reinforcement projects. |
(9) | New business construction and strategic line extension. |
Total amount received | ||||||||||||||
In millions | 2015 | 2014 | 2013 | Expiration Date | ||||||||||
Elizabethtown Gas | $ | 28 | $ | 18 | $ | 6 | March 2019 | |||||||
Virginia Natural Gas | 15 | 14 | 4 | March 2018 | ||||||||||
Atlanta Gas Light | 15 | 13 | 6 | March 2017 | ||||||||||
Florida City Gas | 1 | 1 | 1 | (1) | ||||||||||
Chattanooga Gas | 1 | 1 | 1 | March 2018 | ||||||||||
Total | $ | 60 | $ | 47 | $ | 18 |
Dollars in millions | Miles of pipe | Expected capital expenditures (1) | Ownership interest (1) | FERC filing | Expected FERC approval | |||||||||
Atlantic Coast Pipeline (2) | 564 | $ | 260 | 5 | % | 2015 | 2016 | |||||||
PennEast Pipeline (3) | 118 | 200 | 20 | % | 2015 | 2016 | ||||||||
Dalton Pipeline (4) | 106 | 210 | 50 | % | 2015 | 2016 | ||||||||
Total | 788 | $ | 670 |
(1) | Represents our expected capital expenditures and ownership interest, which may change. |
(2) | In September 2014, we entered into a joint venture to construct and operate a natural gas pipeline that will run from West Virginia through Virginia and into eastern North Carolina to meet the region’s growing demand for natural gas. The proposed pipeline project is expected to transport natural gas to our customers in Virginia. |
(3) | In August 2014, we entered into a joint venture to construct and operate a natural gas pipeline that will transport low-cost natural gas from the Marcellus Shale area to our customers in New Jersey. We believe this will alleviate takeaway constraints in the Marcellus region and help mitigate some of the price volatility experienced during recent winters. |
(4) | In April 2014, we entered into two agreements associated with the construction of the Dalton Lateral Pipeline, which will serve as an extension of the Transco pipeline system and provide additional natural gas supply to our customers in Georgia. The first is a construction and ownership agreement and the second is an agreement to lease our ownership in this lateral pipeline extension once it is placed in service. |
Number of employees | Contract expiration date | ||||
Nicor Gas | |||||
International Brotherhood of Electrical Workers (Local No. 19) | 1,422 | February 2017 | |||
Virginia Natural Gas | |||||
International Brotherhood of Electrical Workers (Local No. 50) (1) | 137 | May 2019 | |||
Elizabethtown Gas | |||||
Utility Workers Union of America (Local No. 424) (2) | 166 | November 2019 | |||
Total | 1,725 |
(1) | Virginia Natural Gas’ collective bargaining agreement expired in May 2015, and a new agreement was ratified in August 2015. The new agreement provides for additional operational enhancements and changes to certain benefits, but has no material effect on our consolidated financial statements. |
(2) | Elizabethtown Gas' collective bargaining agreement expired in November 2015, and a new agreement was ratified in December 2015. The new agreement provides for additional operational enhancements and changes to certain benefits, but has no material effect on our consolidated financial statements. |
• | certain risks and uncertainties associated with the proposed merger with Southern Company, including, without limitation: |
• | the possibility that the proposed merger does not close due to the failure to satisfy the closing conditions, including, but not limited to, a failure to obtain the required regulatory approvals; |
• | delays caused by required regulatory approvals, which may delay the proposed merger or cause the companies to abandon the transaction; |
• | disruption from the proposed merger making it more difficult to maintain our business and operational relationships and the risk that unexpected costs will be incurred during this process; and |
• | the diversion of management time on merger-related issues; |
• | changes in price, supply and demand for natural gas and related products; |
• | the impact of changes in state and federal legislation and regulation, including any changes related to climate matters; |
• | actions taken by government agencies on rates and other matters; |
• | concentration of credit risk; |
• | utility and energy industry consolidation; |
• | the impact on cost and timeliness of construction projects by government and other approvals, project delays, adequacy of supply of diversified vendors, and unexpected changes in project costs, including the cost of funds to finance these projects and our ability to recover our project costs from our customers; |
• | limits on pipeline capacity; |
• | the impact of acquisitions and divestitures; |
• | our ability to successfully integrate operations that we have or may acquire or develop in the future; |
• | direct or indirect effects on our business, financial condition or liquidity resulting from a change in our credit ratings or the credit ratings of our counterparties or competitors; |
• | interest rate fluctuations; |
• | financial market conditions, including disruptions in the capital markets and lending environment; |
• | general economic conditions; |
• | uncertainties about environmental issues and the related impact of such issues, including our environmental remediation plans; |
• | the capacity of our gas storage caverns, which are subject to natural settling and other occurrences; |
• | contracting rates at our midstream operations storage business; |
• | the impact of our construction projects and related capital expenditures, including our pipeline projects; |
• | the development, timing and anticipated costs relating to our pipeline projects; |
• | the impact of changes in weather on the temperature-sensitive portions of our business; |
• | the impact of natural disasters, such as hurricanes, on the supply and price of natural gas; |
• | acts of war or terrorism; |
• | the outcome of litigation; |
• | the effect of accounting pronouncements issued periodically by standard-setting bodies; and |
• | the other factors discussed elsewhere herein and in our other filings with the SEC. |
• | result in increased costs associated with our operations, |
• | increase other costs to our business, |
• | affect the demand for natural gas (positively or negatively), and |
• | impact the prices we charge our customers and affect the competitive position of natural gas. |
• | adverse economic conditions; |
• | adverse general capital market conditions; |
• | poor performance and health of the utility industry in general; |
• | bankruptcy or financial distress of unrelated energy companies or marketers; |
• | significant decrease in the demand for natural gas; |
• | adverse regulatory actions that affect our local gas distribution companies and our natural gas storage business; |
• | terrorist attacks on our facilities or our suppliers; or |
• | extreme weather conditions. |
• | we will have paid certain significant transaction costs, including legal, financial advisory and filing, printing and mailing fees, and in certain circumstances, a termination fee to Southern Company of $201 million; |
• | the attention of our management may have been diverted to the merger rather than to our operations and the pursuit of other opportunities that could have been beneficial to us; |
• | the potential loss of key personnel during the pendency of the merger as employees may experience uncertainty about their future roles with the combined company; |
• | we will have been subject to certain restrictions on the conduct of our business, which may prevent us from making certain acquisitions or dispositions or pursuing certain business opportunities while the merger is pending; and |
• | the trading price of our common stock may decline to the extent that the current market price reflects a market assumption that the merger will be completed. |
Sales price of common stock | Cash dividend per common share | Sales price of common stock | Cash dividend per common share | |||||||||||||||||||||||
Quarter ended: | High | Low | Quarter ended: | High | Low | |||||||||||||||||||||
March 31, 2015 | $ | 57.75 | $ | 46.50 | $ | 0.51 | March 31, 2014 | $ | 49.84 | $ | 45.17 | $ | 0.49 | |||||||||||||
June 30, 2015 | 51.88 | 46.45 | 0.51 | June 30, 2014 | 55.10 | 48.29 | 0.49 | |||||||||||||||||||
September 30, 2015 (1) | 63.37 | 46.36 | 0.51 | September 30, 2014 | 55.30 | 48.72 | 0.49 | |||||||||||||||||||
December 31, 2015 | 63.99 | 60.55 | 0.51 | December 31, 2014 | 56.67 | 50.10 | 0.49 | |||||||||||||||||||
$ | 2.04 | $ | 1.96 |
Dollars and shares in millions, except per share amounts | 2015 | 2014 | 2013 | 2012 | 2011 | |||||||||||||||
Income statement data | ||||||||||||||||||||
Operating revenues | $ | 3,941 | $ | 5,385 | $ | 4,209 | $ | 3,562 | $ | 2,305 | ||||||||||
Income from continuing operations | 373 | 580 | 308 | 274 | 179 | |||||||||||||||
(Loss) income from discontinued operations, net of tax | — | (80 | ) | 5 | 1 | — | ||||||||||||||
Net income | 373 | 500 | 313 | 275 | 179 | |||||||||||||||
Less net income attributable to the noncontrolling interest | 20 | 18 | 18 | 15 | 14 | |||||||||||||||
Net income attributable to AGL Resources | $ | 353 | $ | 482 | $ | 295 | $ | 260 | $ | 165 | ||||||||||
Net income attributable to AGL Resources | ||||||||||||||||||||
Income from continuing operations attributable to AGL Resources | $ | 353 | $ | 562 | $ | 290 | $ | 259 | $ | 165 | ||||||||||
(Loss) income from discontinued operations, net of tax | — | (80 | ) | 5 | 1 | — | ||||||||||||||
Net income attributable to AGL Resources | $ | 353 | $ | 482 | $ | 295 | $ | 260 | $ | 165 | ||||||||||
Per common share information | ||||||||||||||||||||
Diluted weighted average common shares outstanding | 119.9 | 119.2 | 118.3 | 117.5 | 80.9 | |||||||||||||||
Diluted earnings (loss) per common share | ||||||||||||||||||||
Continuing operations | $ | 2.94 | $ | 4.71 | $ | 2.45 | $ | 2.20 | $ | 2.04 | ||||||||||
Discontinued operations | — | (0.67 | ) | 0.04 | 0.01 | — | ||||||||||||||
Diluted earnings per common share attributable to AGL Resources common shareholders | $ | 2.94 | $ | 4.04 | $ | 2.49 | $ | 2.21 | $ | 2.04 | ||||||||||
Cash dividends declared per common share | $ | 2.04 | $ | 1.96 | $ | 1.88 | $ | 1.74 | $ | 1.90 | ||||||||||
Dividend payout ratio | 69 | % | 49 | % | 76 | % | 79 | % | 93 | % | ||||||||||
Dividend yield (1) | 3.2 | % | 3.6 | % | 4.0 | % | 4.4 | % | 4.5 | % | ||||||||||
Price range: | ||||||||||||||||||||
High | $ | 63.99 | $ | 56.67 | $ | 49.31 | $ | 42.88 | $ | 43.69 | ||||||||||
Low | $ | 46.36 | $ | 45.17 | $ | 38.86 | $ | 36.59 | $ | 34.08 | ||||||||||
Close (2) | $ | 63.81 | $ | 54.51 | $ | 47.23 | $ | 39.97 | $ | 42.26 | ||||||||||
Market value (2) | $ | 7,681 | $ | 6,522 | $ | 5,615 | $ | 4,711 | $ | 4,946 | ||||||||||
Balance sheet data (2) | ||||||||||||||||||||
Total assets (3) (4) | $ | 14,754 | $ | 14,888 | $ | 14,528 | $ | 14,051 | $ | 13,841 | ||||||||||
Property, plant and equipment, net | 9,791 | 9,090 | 8,643 | 8,205 | 7,741 | |||||||||||||||
Long-term debt (4) | 3,820 | 3,781 | 3,791 | 3,533 | 3,555 | |||||||||||||||
Total equity | 3,975 | 3,828 | 3,613 | 3,391 | 3,305 | |||||||||||||||
Financial ratios (2) | ||||||||||||||||||||
Debt | 55 | % | 56 | % | 58 | % | 59 | % | 60 | % | ||||||||||
Equity | 45 | % | 44 | % | 42 | % | 41 | % | 40 | % | ||||||||||
Total | 100 | % | 100 | % | 100 | % | 100 | % | 100 | % | ||||||||||
Return on average equity | 9.0 | % | 13.0 | % | 8.4 | % | 7.8 | % | 6.4 | % |
(1) | Dividends declared per common share during the fiscal period divided by market value per common share as of the last day of the fiscal period. |
(2) | As of the last day of the fiscal period. |
(3) | Total assets for 2011-2013 include assets held for sale, which reflect the assets of our former Tropical Shipping business. |
(4) | Total assets and long-term debt for 2011-2014 have been adjusted to reflect the netting of debt issuance costs with its debt carrying amount in accordance with our 2015 adoption of new accounting guidance related to this balance sheet presentation. |
EBIT | Assets | Capital expenditures | |||||||||||||||||||||||||
2015 | 2014 | 2013 | 2015 | 2014 | 2013 | 2015 | 2014 | 2013 | |||||||||||||||||||
Distribution operations | 76 | % | 52 | % | 84 | % | 85 | % | 81 | % | 82 | % | 93 | % | 93 | % | 93 | % | |||||||||
Retail operations | 20 | 12 | 20 | 5 | 5 | 5 | 1 | 1 | 1 | ||||||||||||||||||
Wholesale services | 14 | 38 | — | 6 | 9 | 8 | — | — | — | ||||||||||||||||||
Midstream operations | (3 | ) | (1 | ) | (2 | ) | 5 | 5 | 5 | 3 | 2 | 2 | |||||||||||||||
Other/intercompany eliminations | (7 | ) | (1 | ) | (2 | ) | (1 | ) | — | — | 3 | 4 | 4 | ||||||||||||||
Total | 100 | % | 100 | % | 100 | % | 100 | % | 100 | % | 100 | % | 100 | % | 100 | % | 100 | % |
• | Distribution Operations: Invest necessary capital to enhance and maintain safety and reliability in delivering natural gas; remain an efficiency leader within the industry while maintaining a focus on customer satisfaction; expand the natural gas distribution system and educate energy consumers on the benefits of converting to natural gas. We intend to continue investing in our regulatory infrastructure programs to minimize the lag in recovery of our capital. We continue to effectively manage costs and leverage our shared services model across our businesses to combat inflationary effects. |
• | Retail Operations: Maintain our current customer base in Georgia and Illinois while continuing to expand into other profitable retail markets and expand our warranty businesses through partnership opportunities with affiliates and third parties. We will focus on products that are responsive to our customers' needs. |
• | Wholesale Services: We continue to position our business to secure sufficient supplies of natural gas to meet the needs of our utility and third-party customers and to hedge natural gas prices to manage costs effectively, reduce price volatility and maintain a competitive advantage relative to other marketers. |
• | Midstream Operations: Invest in natural gas based projects, some of which remain subject to regulatory approvals, along with our existing pipelines and storage to support our efforts to provide diverse sources of natural gas supplies to our customers, resolve current and long-term supply planning for new capacity, enhance system reliability and generate economic development in the areas served. For additional information on our pipeline projects, see Note 3 and Note 11 to our consolidated financial statements under Item 8 herein and Item 1, “Business” under the caption “Midstream Operations.” |
In millions, except per share amounts | 2015 | 2014 | 2013 | |||||||||
Operating revenues (1) | $ | 3,941 | $ | 5,385 | $ | 4,209 | ||||||
Cost of goods sold | (1,645 | ) | (2,765 | ) | (2,110 | ) | ||||||
Revenue tax expense (2) | (101 | ) | (130 | ) | (110 | ) | ||||||
Operating margin | 2,195 | 2,490 | 1,989 | |||||||||
Operating expenses (3) | (1,550 | ) | (1,527 | ) | (1,471 | ) | ||||||
Revenue tax expense (2) | 101 | 130 | 110 | |||||||||
Gain on disposition of assets | — | 2 | 11 | |||||||||
Operating income | 746 | 1,095 | 639 | |||||||||
Other income | 13 | 14 | 16 | |||||||||
EBIT | 759 | 1,109 | 655 | |||||||||
Interest expense, net | (173 | ) | (179 | ) | (170 | ) | ||||||
Income before income taxes | 586 | 930 | 485 | |||||||||
Income tax expense | (213 | ) | (350 | ) | (177 | ) | ||||||
Income from continuing operations | 373 | 580 | 308 | |||||||||
(Loss) income from discontinued operations, net of tax | — | (80 | ) | 5 | ||||||||
Net income | 373 | 500 | 313 | |||||||||
Less net income attributable to the noncontrolling interest | 20 | 18 | 18 | |||||||||
Net income attributable to AGL Resources | $ | 353 | $ | 482 | $ | 295 | ||||||
Net income attributable to AGL Resources | ||||||||||||
Income from continuing operations attributable to AGL Resources | $ | 353 | $ | 562 | $ | 290 | ||||||
(Loss) income from discontinued operations, net of tax (4) | — | (80 | ) | 5 | ||||||||
Net income attributable to AGL Resources | $ | 353 | $ | 482 | $ | 295 | ||||||
Per common share data | ||||||||||||
Diluted earnings per common share from continuing operations | $ | 2.94 | $ | 4.71 | $ | 2.45 | ||||||
Diluted (loss) earnings per common share from discontinued operations (4) | — | (0.67 | ) | 0.04 | ||||||||
Merger-related expenses | 0.23 | — | — | |||||||||
Goodwill impairment | 0.07 | — | — | |||||||||
Diluted earnings per share - as adjusted | $ | 3.24 | $ | 4.04 | $ | 2.49 |
(1) | Our revenues declined significantly in 2015 compared to 2014 primarily due to lower natural gas prices and lower volumes of gas sold to customers due to weather in 2015 that was warmer than the extreme cold experienced in 2014. |
(2) | Adjusted for Nicor Gas’ revenue tax expenses, which are passed through directly to customers. |
(3) | Operating expenses for 2015 include $44 million of merger-related expenses and a $14 million goodwill impairment charge. |
(4) | In September 2014, we sold Tropical Shipping. See Note 15 to our consolidated financial statements under Item 8 herein for additional information. |
• | $34 million in additional operating margin at distribution operations from regulatory infrastructure programs, partially offset by $19 million in higher depreciation expense. |
• | $19 million in additional operating margin at retail operations due to the recovery of prior year hedge losses and lower current year derivative losses resulting from changes in natural gas prices. |
• | These increases were partially offset by weather at distribution operations and retail operations due to significantly warmer temperatures in 2015, compared to 2014. |
• | Significantly higher commercial activity primarily in the first quarter of 2014, and mark-to-market hedge gains, net of LOCOM adjustments at wholesale services in 2014 from price volatility generated by colder-than-normal weather, which increased operating margin by $462 million compared to 2013. |
• | Increased operating margin at distribution operations and retail operations of $50 million mainly due to significantly colder-than-normal weather in 2014 as well as customer usage and customer growth. We also achieved growth as a result of our 2013 acquisitions and expansion into additional markets at retail operations. |
• | These increases were partially offset by a decrease in margin of $10 million at midstream operations primarily due to a retained fuel true-up at one of our storage facilities from a reduction in the estimated cavern capacity as a result of naturally occurring shrinkage, as well as lower contracted firm rates at Jefferson Island and Central Valley. |
• | Favorability year-over-year was negatively impacted by higher incentive compensation expenses primarily related to higher earnings in 2014 and increased outside services expenses of $49 million, and an $8 million higher pre-tax gain in 2013 related to the sale of Compass Energy. |
• | Our income tax expense from continuing operations increased by $173 million for 2014 compared to 2013, primarily due to higher consolidated earnings. The increase was primarily a result of increased earnings at wholesale services. |
In millions | 2015 | 2014 | 2013 | |||||||||
Residential | $ | 2,129 | $ | 2,877 | $ | 2,422 | ||||||
Commercial | 617 | 861 | 696 | |||||||||
Transportation | 526 | 458 | 487 | |||||||||
Industrial | 203 | 242 | 180 | |||||||||
Other (1) | 466 | 947 | 424 | |||||||||
Total operating revenues | $ | 3,941 | $ | 5,385 | $ | 4,209 |
(1) | Includes significantly higher-than-normal revenues at wholesale services in 2014, which are not indicative of future performance. |
Years ended December 31, | 2015 vs. 2014 | 2014 vs. 2013 | 2015 vs. normal | 2014 vs. normal | 2013 vs. normal | ||||||||||||||||||||||
Normal (1) | 2015 | 2014 | 2013 | (warmer) | colder | (warmer) | colder | colder | |||||||||||||||||||
Illinois (2) | 5,845 | 5,433 | 6,556 | 6,305 | (17 | )% | 4 | % | (7 | )% | 12 | % | 8 | % | |||||||||||||
Georgia | 2,628 | 2,204 | 2,882 | 2,689 | (24 | )% | 7 | % | (16 | )% | 10 | % | 2 | % |
(1) | Normal represents the 10-year average from January 1, 2005 through December 31, 2014, for Illinois at Chicago Midway International Airport and for Georgia at Atlanta Hartsfield-Jackson International Airport, as obtained from the National Oceanic and Atmospheric Administration, National Climatic Data Center. |
(2) | The 10-year average Heating Degree Days established by the Illinois Commission in our last rate case is 5,600 for the 12 months from 1998 through 2007. |
Years ended December 31, | 2015 vs. 2014 change | 2014 vs. 2013 change | |||||||||||||||||||
In thousands | 2015 | 2014 | 2013 | # | % | # | % | ||||||||||||||
Distribution operations customers (1) | 4,526 | 4,497 | 4,479 | 29 | 0.6 | % | 18 | 0.4 | % | ||||||||||||
Retail operations | |||||||||||||||||||||
Energy customers (2) | 645 | 628 | 619 | 17 | 3 | % | 9 | 1 | % | ||||||||||||
Service contracts (3) | 1,171 | 1,182 | 1,127 | (11 | ) | (1 | )% | 55 | 5 | % | |||||||||||
Market share in Georgia | 29.7 | % | 30.6 | % | 31.4 | % | (0.9 | )% | (0.8 | )% |
(1) | In 2014, we implemented a process change at Nicor Gas that adversely impacted our customer count. This had the effect of immaterial growth for Nicor Gas compared to 2013. |
(2) | The increase from 2013 to 2014 is primarily due to the addition of approximately 33,000 residential and commercial customer relationships acquired in Illinois in June 2013. |
(3) | Includes approximately 43,000 customer warranty contracts acquired in Connecticut and Massachusetts in the second half of 2015. |
Year ended December 31, | 2015 vs. 2014 % change | 2014 vs. 2013 % change | |||||||||||||
Distribution operations (In Bcf) | 2015 | 2014 | 2013 | ||||||||||||
Firm | 695 | 766 | 720 | (9 | )% | 6 | % | ||||||||
Interruptible | 99 | 106 | 111 | (7 | ) | (5 | ) | ||||||||
Total | 794 | 872 | 831 | (9 | )% | 5 | % | ||||||||
Retail operations (In Bcf) | |||||||||||||||
Georgia firm | 35 | 41 | 38 | (15 | )% | 8 | % | ||||||||
Illinois | 13 | 17 | 9 | (24 | ) | 89 | |||||||||
Other (includes Florida, Maryland, Michigan, New York and Ohio) | 11 | 10 | 8 | 10 | 25 | ||||||||||
Wholesale services | |||||||||||||||
Daily physical sales (Bcf/day) | 6.79 | 6.32 | 5.73 | 7 | % | 10 | % |
December 31, 2015 | December 31, 2014 | |||||||||||||
Average rates (per dekatherm) | Firm capacity under subscription (Bcf) | Average rates (per dekatherm) | Firm capacity under subscription (Bcf) | |||||||||||
Jefferson Island | $ | 0.092 | 4.2 | $ | 0.108 | 4.6 | ||||||||
Golden Triangle | 0.041 | 5.0 | 0.114 | 5.0 | ||||||||||
Central Valley | 0.047 | 4.0 | 0.062 | 2.5 |
Percent generated during Heating Season | ||||||
Revenues | EBIT | |||||
2015 | 70 | % | 80 | % | ||
2014 | 73 | 81 | ||||
2013 | 68 | 72 |
Operating Margin (1) (2) | Operating Expenses (2) | EBIT (1) | ||||||||||||||||||||||||||||||||||
In millions | 2015 | 2014 | 2013 | 2015 (3) | 2014 | 2013 | 2015 | 2014 | 2013 (4) | |||||||||||||||||||||||||||
Distribution operations | $ | 1,657 | $ | 1,648 | $ | 1,615 | $ | 1,086 | $ | 1,075 | $ | 1,083 | $ | 580 | $ | 581 | $ | 546 | ||||||||||||||||||
Retail operations | 317 | 311 | 294 | 165 | 179 | 162 | 152 | 132 | 132 | |||||||||||||||||||||||||||
Wholesale services | 183 | 501 | 39 | 71 | 79 | 53 | 108 | 422 | (3 | ) | ||||||||||||||||||||||||||
Midstream operations | 36 | 31 | 41 | 62 | 50 | 46 | (23 | ) | (17 | ) | (10 | ) | ||||||||||||||||||||||||
Other | 7 | 7 | 8 | 70 | 22 | 25 | (58 | ) | (9 | ) | (10 | ) | ||||||||||||||||||||||||
Intercompany eliminations | (5 | ) | (8 | ) | (8 | ) | (5 | ) | (8 | ) | (8 | ) | — | — | — | |||||||||||||||||||||
Consolidated | $ | 2,195 | $ | 2,490 | $ | 1,989 | $ | 1,449 | $ | 1,397 | $ | 1,361 | $ | 759 | $ | 1,109 | $ | 655 |
(1) | Operating margin is a non-GAAP measure. A reconciliation of operating margin to operating revenues and operating income, and a reconciliation of EBIT to income before income taxes and net income is contained in “Results of Operations” herein. |
(2) | Operating margin and operating expenses are adjusted for revenue tax expenses, which are passed through directly to our customers. |
(3) | Operating expenses for 2015 include a $14 million goodwill impairment charge recorded during the third quarter at midstream operations and $44 million of merger-related expenses recorded within our other segment. |
(4) | EBIT for 2013 includes an $11 million pre-tax gain on the sale of Compass Energy in wholesale services and an $8 million pre-tax loss associated with the termination of the Sawgrass Storage project within midstream operations. |
In millions | 2015 | 2014 | ||||||
EBIT - prior year | $ | 581 | $ | 546 | ||||
Operating margin | ||||||||
Increase from regulatory infrastructure programs, primarily at Atlanta Gas Light and Nicor Gas | 34 | 10 | ||||||
Increase mainly driven by non-weather-related customer usage and growth | 13 | 22 | ||||||
Decrease in rider program recoveries at Nicor Gas, offset by operating expenses below | (18 | ) | (12 | ) | ||||
(Decrease) increase in weather-related customer usage, net of weather hedging | (20 | ) | 13 | |||||
Increase in operating margin | 9 | 33 | ||||||
Operating expenses | ||||||||
Increase in depreciation expense primarily due to additional assets placed in service during 2015 and 2014. 2014 was offset by the impact of Nicor Gas’ new composite depreciation rate that became effective August 30, 2013 | 19 | (22 | ) | |||||
Increase in benefit expenses primarily related to higher pension costs and health benefits in 2015 and lower pension costs in 2014 due to changes in actuarial gains and losses | 12 | (13 | ) | |||||
Increase in payroll and variable compensation costs as a result of merit increases in 2015 and 2014 as well as higher incentive compensation in 2014 | 9 | 19 | ||||||
Increase due to write-off PRP-related costs from the global settlement | 5 | — | ||||||
(Decrease) increase in bad debt expenses due to changes in natural gas consumption and prices | (2 | ) | 4 | |||||
(Decrease) increase in weather-related expenses | (4 | ) | 5 | |||||
(Decrease) increase in outside services and other expenses primarily due to maintenance programs | (5 | ) | 11 | |||||
Decrease in fleet expenses from lower fuel prices | (5 | ) | — | |||||
Decrease in rider program recoveries at Nicor Gas, offset by operating margin above | (18 | ) | (12 | ) | ||||
Increase (decrease) in operating expenses | 11 | (8 | ) | |||||
Decrease in other income in 2014 primarily relates to STRIDE projects at Atlanta Gas Light | 1 | (6 | ) | |||||
EBIT - current year | $ | 580 | $ | 581 |
In millions | 2015 | 2014 | ||||||
EBIT - prior year | $ | 132 | $ | 132 | ||||
Operating margin | ||||||||
Recovery of hedge losses (gains) | 12 | (1 | ) | |||||
Increase (decrease) in value of unrealized derivatives as a result of NYMEX natural gas prices | 7 | (13 | ) | |||||
LOCOM adjustments, net of recoveries | 3 | (5 | ) | |||||
Improved warranty margins | 2 | 6 | ||||||
Decrease in 2015 due to customer mix. Increase in 2014 due primarily to lower gas costs and customer count | (8 | ) | 13 | |||||
(Decrease) increase in weather-related customer usage, net of weather hedging | (9 | ) | 8 | |||||
Increase due to 2013 acquisitions | — | 9 | ||||||
Other | (1 | ) | — | |||||
Increase in operating margin | 6 | 17 | ||||||
Operating expenses | ||||||||
(Decrease) increase in outside services, variable compensation costs and marketing expenses | (8 | ) | 14 | |||||
(Decrease) increase in depreciation and amortization | (3 | ) | 1 | |||||
(Decrease) increase in bad debt expenses | (1 | ) | 1 | |||||
Other | (2 | ) | 1 | |||||
(Decrease) increase in operating expenses | (14 | ) | 17 | |||||
EBIT - current year | $ | 152 | $ | 132 |
In millions | 2015 | 2014 | ||||||
EBIT - prior year | $ | 422 | $ | (3 | ) | |||
Operating margin | ||||||||
(Decrease) increase in commercial activity largely driven by the transportation and storage portfolios in the Northeast and Midwest | (304 | ) | 319 | |||||
(Decrease) increase in value of storage derivatives as a result of fluctuations in NYMEX natural gas prices | (41 | ) | 102 | |||||
(Decrease) increase in value of transportation and forward commodity derivatives from price movements related to natural gas transportation positions | (27 | ) | 111 | |||||
LOCOM adjustments, net of recoveries | 54 | (66 | ) | |||||
Decrease due to sale of Compass Energy in May 2013 | — | (4 | ) | |||||
(Decrease) increase in operating margin | (318 | ) | 462 | |||||
Operating expenses | ||||||||
(Decrease) increase related to incentive compensation expenses driven by higher earnings and other costs in 2014 | (8 | ) | 28 | |||||
Decrease due to sale of Compass Energy in May 2013 | — | (2 | ) | |||||
(Decrease) increase in operating expenses | (8 | ) | 26 | |||||
Decrease in other income, primarily related to the gain on sale of Compass Energy | (4 | ) | (11 | ) | ||||
EBIT - current year | $ | 108 | $ | 422 |
In millions | 2015 | 2014 | 2013 | |||||||||
Commercial activity recognized | $ | 140 | $ | 444 | $ | 129 | ||||||
Gain (loss) on storage derivatives | 45 | 86 | (16 | ) | ||||||||
Inventory LOCOM adjustment, net of estimated current period recoveries | (13 | ) | (67 | ) | (1 | ) | ||||||
Gain (loss) on transportation and forward commodity derivatives | 11 | 38 | (73 | ) | ||||||||
Operating margin | $ | 183 | $ | 501 | $ | 39 |
Storage withdrawal schedule | |||||||||||
Dollars in millions | Total storage (in Bcf) (WACOG $2.27) | Expected net operating gains (1) | Physical transportation transactions – expected net operating gains (losses) (2) | ||||||||
2016 | 70 | $ | 6 | $ | (17 | ) | |||||
2017 and thereafter | 5 | 2 | 6 | ||||||||
Total at December 31, 2015 | 75 | $ | 8 | $ | (11 | ) |
(1) | Represents expected operating gains from planned storage withdrawals associated with existing inventory positions and could change as wholesale services adjusts its daily injection and withdrawal plans in response to changes in future market conditions and forward NYMEX price fluctuations. |
(2) | Represents the periods associated with the transportation derivative (gains) losses during which the derivatives will be settled and the physical transportation transactions will occur that offset the derivative (gains) losses recognized in 2014 and 2015. |
In millions | 2015 | 2014 | ||||||
EBIT - prior year | $ | (17 | ) | $ | (10 | ) | ||
Operating margin | ||||||||
Retained fuel true-up recorded in 2014 due to naturally occurring cavern shrinkage | 11 | (10 | ) | |||||
Lower firm revenues due to recontracting expiring contracts at lower subscription rates and lower interruptible revenue in 2014 compared to 2013 | (2 | ) | (6 | ) | ||||
Decrease in revenue from dewater activity at Golden Triangle in 2014 | (5 | ) | 6 | |||||
Other | 1 | — | ||||||
Increase (decrease) in operating margin | 5 | (10 | ) | |||||
Operating expenses | ||||||||
Goodwill impairment | 14 | — | ||||||
(Decrease) increase in operating expenses largely due to a favorable property tax settlement in 2015, outside service cost, depreciation expense and other | (2 | ) | 4 | |||||
Increase in operating expenses | 12 | 4 | ||||||
Increase in other income, 2014 primarily related to the impairment loss at Sawgrass Storage in December 2013 | 1 | 7 | ||||||
EBIT - current year | $ | (23 | ) | $ | (17 | ) |
In millions | Year-end balance outstanding (1) | Daily average balance outstanding (2) | Minimum balance outstanding (2) | Largest balance outstanding (2) | ||||||||||||
Commercial paper - AGL Capital | $ | 471 | $ | 382 | $ | 106 | $ | 787 | ||||||||
Commercial paper - Nicor Gas | 539 | 349 | 133 | 585 | ||||||||||||
Current portion of long-term debt | 545 | 270 | — | 545 | ||||||||||||
Total | $ | 1,555 | $ | 1,001 | $ | 239 | $ | 1,917 |
(1) | As of December 31, 2015. |
(2) | For the twelve months ended December 31, 2015. |
Issuance / refinance date | Amount (in millions) | Term (in years) | Interest rate | |||||||||
Senior notes (1) | November 2015 | $ | 250 | 10 | 3.9 | % | ||||||
Senior notes (2) | May 2013 | $ | 500 | 30 | 4.4 | % | ||||||
Gas facility revenue bonds (3) | March 2013 | $ | 200 | 10-20 | Floating rate |
(1) | The net proceeds were used to repay a portion of AGL Capital's commercial paper, including $200 million we borrowed to repay senior notes that matured on January 15, 2015. |
(2) | The net proceeds were used to repay a portion of AGL Capital’s commercial paper, including $225 million we borrowed to repay senior notes that matured on April 15, 2013. |
(3) | There were no cash receipts or payments in connection with the refinancing of these gas facility revenue bonds. |
AGL Resources | Nicor Gas | |||||||||||
S&P (1) | Moody’s (2) (3) | Fitch (1) | S&P (1) | Moody’s | Fitch | |||||||
Corporate rating | BBB+ | n/a | BBB+ | BBB+ | n/a | A | ||||||
Commercial paper | A-2 | P-2 | F2 | A-2 | P-1 | F1 | ||||||
Senior unsecured | BBB+ | Baa1 | BBB+ | BBB+ | A2 | A+ | ||||||
Senior secured | n/a | n/a | n/a | A | Aa3 | AA- | ||||||
Ratings outlook | Positive | Stable | Positive | Positive | Stable | Stable |
(1) | During the third quarter of 2015, S&P revised both AGL Resources' and Nicor Gas' ratings outlooks to positive from stable and Fitch revised AGL Resources' outlook to positive. |
(2) | Credit ratings are for AGL Capital, whose obligations are fully and unconditionally guaranteed by AGL Resources. |
(3) | Moody's downgraded AGL Capital's senior unsecured rating to Baa1 from A3 during the third quarter of 2015. |
• | Our credit facilities contain customary events of default, including but not limited to the failure to comply with certain affirmative and negative covenants, cross-defaults to certain other material indebtedness and a change of control; |
• | Our credit facilities contain certain non-financial covenants that, among other things, restrict liens and encumbrances, loans and investments, acquisitions, dividends and other restricted payments, asset dispositions, mergers and consolidations, and other matters customarily restricted in such agreements; and |
• | Our credit facilities each include a financial covenant that requires us to maintain a ratio of total debt to total capitalization of no more than 70% at the end of any fiscal month. However, we typically seek to maintain these ratios at levels between 50% and 60%, except for temporary increases related to the timing of acquisition and financing activities. |
In millions | 2015 | 2014 | 2013 | |||||||||
Net cash provided by (used in) (1): | ||||||||||||
Operating activities | $ | 1,381 | $ | 655 | $ | 971 | ||||||
Investing activities | (1,027 | ) | (505 | ) | (876 | ) | ||||||
Financing activities | (366 | ) | (224 | ) | (121 | ) | ||||||
Net decrease in cash and cash equivalents - continuing operations | (12 | ) | (51 | ) | (26 | ) | ||||||
Net decrease in cash and cash equivalents - discontinued operations | — | (23 | ) | — | ||||||||
Cash and cash equivalents (including held for sale) at beginning of period | 31 | 105 | 131 | |||||||||
Cash and cash equivalents (including held for sale) at end of period | 19 | 31 | 105 | |||||||||
Less cash and cash equivalents held for sale at end of period | — | — | 24 | |||||||||
Cash and cash equivalents (excluding held for sale) at end of period | $ | 19 | $ | 31 | $ | 81 |
(1) | Amounts for 2014 and 2013 include activity for discontinued operations. |
In millions | Description | 2016 | 2015 | 2014 | 2013 | |||||||||||||
Distribution business | New construction and infrastructure improvements | $ | 486 | $ | 440 | $ | 475 | $ | 421 | |||||||||
Regulatory infrastructure programs (1) | Programs that update or expand our distribution systems to improve system reliability | 531 | 461 | 180 | 226 | |||||||||||||
Storage, pipelines and LNG facilities | Underground natural gas storage facilities, pipeline infrastructure and LNG production and transportation | 143 | 27 | 15 | 8 | |||||||||||||
Other | Primarily includes information technology and building and leasehold improvements | 116 | 99 | 99 | 76 | |||||||||||||
Total | $ | 1,276 | $ | 1,027 | $ | 769 | $ | 731 |
(1) | Includes Investing in Illinois at Nicor Gas, STRIDE at Atlanta Gas Light, SAVE at Virginia Natural Gas, AIR at Elizabethtown Gas and SAFE at Florida City Gas. |
In millions | Total | 2016 | 2017 | 2018 | 2019 | 2020 | 2021 & thereafter | |||||||||||||||||||||
Recorded contractual obligations: | ||||||||||||||||||||||||||||
Long-term debt | $ | 3,756 | $ | 545 | $ | 22 | $ | 155 | $ | 350 | $ | — | $ | 2,684 | ||||||||||||||
Short-term debt | 1,010 | 1,010 | — | — | — | — | — | |||||||||||||||||||||
Environmental remediation liabilities (1) | 431 | 67 | 79 | 70 | 61 | 52 | 102 | |||||||||||||||||||||
Total | $ | 5,197 | $ | 1,622 | $ | 101 | $ | 225 | $ | 411 | $ | 52 | $ | 2,786 | ||||||||||||||
Unrecorded contractual obligations and commitments (2) (7): | ||||||||||||||||||||||||||||
Pipeline charges, storage capacity and gas supply (3) | $ | 5,007 | $ | 795 | $ | 536 | $ | 392 | $ | 370 | $ | 318 | $ | 2,596 | ||||||||||||||
Interest charges (4) | 2,418 | 181 | 158 | 156 | 151 | 133 | 1,639 | |||||||||||||||||||||
Operating leases (5) | 159 | 31 | 26 | 18 | 16 | 15 | 53 | |||||||||||||||||||||
Asset management agreements (6) | 28 | 11 | 9 | 6 | 2 | — | — | |||||||||||||||||||||
Standby letters of credit, performance/surety bonds (7) | 73 | 73 | — | — | — | — | — | |||||||||||||||||||||
Other | 5 | 3 | 1 | 1 | — | — | — | |||||||||||||||||||||
Total | $ | 7,690 | $ | 1,094 | $ | 730 | $ | 573 | $ | 539 | $ | 466 | $ | 4,288 |
(1) | Includes charges recoverable through base rates or rate rider mechanisms. |
(2) | In accordance with GAAP, these items are not reflected on our Consolidated Balance Sheets. |
(3) | Includes charges recoverable through a natural gas cost recovery mechanism or alternatively billed to marketers and demand charges associated with Sequent. The gas supply balance includes amounts for Nicor Gas and SouthStar gas commodity purchase commitments of 37 Bcf at floating gas prices calculated using forward natural gas prices as of December 31, 2015, and is valued at $76 million. As we do for certain of our affiliates, we provide guarantees to certain gas suppliers for SouthStar in support of payment obligations. |
(4) | Floating rate interest charges are calculated based on the interest rate as of December 31, 2015 and the maturity date of the underlying debt instrument. As of December 31, 2015, we have $49 million of accrued interest on our Consolidated Balance Sheets that will be paid in 2016. |
(5) | We have certain operating leases with provisions for step rent or escalation payments and certain lease concessions. We account for these leases by recognizing the future minimum lease payments on a straight-line basis over the respective minimum lease terms, in accordance with GAAP. However, this lease accounting treatment does not affect the future annual operating lease cash obligations as shown herein. Our operating leases are primarily for real estate. |
(6) | Represent fixed-fee minimum payments for Sequent’s affiliated asset management agreements. |
(7) | We provide guarantees to certain municipalities and other agencies and certain gas suppliers of SouthStar in support of payment obligations. |
In millions | Distribution operations | Retail operations | Midstream operations | Consolidated | ||||||||||||
Goodwill - December 31, 2014 | $ | 1,640 | $ | 173 | $ | 14 | $ | 1,827 | ||||||||
Impairment | — | — | (14 | ) | (14 | ) | ||||||||||
Goodwill - December 31, 2015 | $ | 1,640 | $ | 173 | $ | — | $ | 1,813 |
• | the creditworthiness of the counterparties involved and the impact of credit enhancements (such as cash deposits and letters of credit); |
• | events specific to a given counterparty; and |
• | the impact of our nonperformance risk on our liabilities. |
• | expected return on plan assets; |
• | the market value of plan assets; |
• | assumed discount rates; |
• | assumed mortality table; and |
• | assumed health care costs. |
Pension plans | Welfare plans | |||||
Discount rate - service cost | 4.6 | % | 4.4 | % | ||
Expected return on plan assets | 7.75 | 7.75 |
Dollars in millions | Percentage-point change in assumption | Increase (decrease) in PBO / APBO | Increase (decrease) in cost | |||
Expected long-term return on plan assets | + / - 1% | - / - | (9) / 9 | |||
Discount rate | + / - 1% | (157) / 193 | (14) / 15 |
Derivative instruments average values at December 31, (1) | ||||||||
In millions | 2015 | 2014 | ||||||
Asset | $ | 187 | $ | 152 | ||||
Liability | 88 | 101 |
(1) | Excludes cash collateral amounts. |
Derivative instruments fair values netted with cash collateral at December 31, | ||||||||
In millions | 2015 | 2014 | ||||||
Asset | $ | 218 | $ | 287 | ||||
Liability | 46 | 93 |
In millions | 2015 | 2014 | 2013 | |||||||||
Net fair value of derivative instruments outstanding at beginning of period | $ | 61 | $ | (82 | ) | $ | 36 | |||||
Derivative instruments realized or otherwise settled during period | (17 | ) | 38 | (62 | ) | |||||||
Change in net fair value of derivative instruments | 32 | 105 | (56 | ) | ||||||||
Net fair value of derivative instruments outstanding at end of period | 76 | 61 | (82 | ) | ||||||||
Netting of cash collateral | 96 | 133 | 121 | |||||||||
Cash collateral and net fair value of derivative instruments outstanding at end of period (1) | $ | 172 | $ | 194 | $ | 39 |
(1) | Net fair value of derivative instruments outstanding includes $10 million premium and associated intrinsic value at December 31, 2015, and $3 million at December 31, 2014 and 2013 associated with weather derivatives. |
In millions | Prices actively quoted (Level 1) (1) | Significant other observable inputs (Level 2) (2) | ||||||
Mature 2016 | $ | 8 | $ | 78 | ||||
Mature 2017 – 2018 | (13 | ) | 9 | |||||
Mature 2019 and thereafter | (5 | ) | (1 | ) | ||||
Total derivative instruments (3) | $ | (10 | ) | $ | 86 |
(1) | Valued using NYMEX futures prices. |
(2) | Valued using transactions that represent the cost to transport natural gas from a NYMEX delivery point to the contract delivery point. These transactions are based on quotes obtained either through electronic trading platforms or directly from brokers. |
(3) | Excludes cash collateral amounts. |
In millions | 2015 | 2014 | 2013 | |||||||||
Period end | $ | 2.4 | $ | 4.7 | $ | 4.7 | ||||||
12-month average | 3.0 | 4.3 | 2.3 | |||||||||
High | 7.3 | 19.7 | 4.9 | |||||||||
Low | 1.6 | 1.8 | 1.2 |
Gross receivables | Gross payables | |||||||||||||||
In millions | 2015 | 2014 | 2015 | 2014 | ||||||||||||
Netting agreements in place: | ||||||||||||||||
Counterparty is investment grade | $ | 299 | $ | 482 | $ | 136 | $ | 276 | ||||||||
Counterparty is non-investment grade | 8 | 4 | 17 | 7 | ||||||||||||
Counterparty has no external rating | 133 | 263 | 265 | 494 | ||||||||||||
No netting agreements in place: | ||||||||||||||||
Counterparty is investment grade | 5 | 30 | — | — | ||||||||||||
Amount recorded on Consolidated Balance Sheets | $ | 445 | $ | 779 | $ | 418 | $ | 777 |
As of December 31, | ||||||||
In millions | 2015 | 2014 | ||||||
Current assets | ||||||||
Cash and cash equivalents | $ | 19 | $ | 31 | ||||
Short-term investments | 8 | 8 | ||||||
Receivables | ||||||||
Energy marketing | 445 | 779 | ||||||
Natural gas | 266 | 391 | ||||||
Unbilled revenues | 140 | 256 | ||||||
Other | 110 | 150 | ||||||
Less allowance for uncollectible accounts | 29 | 35 | ||||||
Total receivables, net | 932 | 1,541 | ||||||
Inventories | ||||||||
Natural gas | 622 | 694 | ||||||
Other | 29 | 22 | ||||||
Total inventories | 651 | 716 | ||||||
Prepaid expenses | 218 | 223 | ||||||
Derivative instruments | 206 | 245 | ||||||
Regulatory assets | 68 | 83 | ||||||
Other | 13 | 39 | ||||||
Total current assets | 2,115 | 2,886 | ||||||
Long-term assets and other deferred debits | ||||||||
Property, plant and equipment | 12,566 | 11,552 | ||||||
Less accumulated depreciation | 2,775 | 2,462 | ||||||
Property, plant and equipment, net | 9,791 | 9,090 | ||||||
Goodwill | 1,813 | 1,827 | ||||||
Regulatory assets | 670 | 631 | ||||||
Intangible assets | 109 | 125 | ||||||
Long-term investments | 103 | 105 | ||||||
Pension assets | 78 | 97 | ||||||
Derivative instruments | 12 | 42 | ||||||
Other | 63 | 85 | ||||||
Total long-term assets and other deferred debits | 12,639 | 12,002 | ||||||
Total assets | $ | 14,754 | $ | 14,888 |
As of December 31, | ||||||||
In millions, except share and per share amounts | 2015 | 2014 | ||||||
Current liabilities | ||||||||
Short-term debt | $ | 1,010 | $ | 1,175 | ||||
Current portion of long-term debt | 545 | 200 | ||||||
Energy marketing trade payables | 418 | 777 | ||||||
Other accounts payable – trade | 255 | 312 | ||||||
Customer deposits and credit balances | 165 | 125 | ||||||
Regulatory liabilities | 134 | 112 | ||||||
Accrued wages and salaries | 92 | 97 | ||||||
Accrued environmental remediation liabilities | 67 | 87 | ||||||
Accrued taxes | 59 | 79 | ||||||
Accrued interest | 49 | 53 | ||||||
Derivative instruments | 44 | 88 | ||||||
Current deferred income taxes | 31 | 2 | ||||||
Other | 131 | 112 | ||||||
Total current liabilities | 3,000 | 3,219 | ||||||
Long-term liabilities and other deferred credits | ||||||||
Long-term debt | 3,275 | 3,581 | ||||||
Accumulated deferred income taxes | 1,912 | 1,724 | ||||||
Regulatory liabilities | 1,611 | 1,601 | ||||||
Accrued pension and retiree welfare benefits | 515 | 525 | ||||||
Accrued environmental remediation liabilities | 364 | 327 | ||||||
Other | 102 | 83 | ||||||
Total long-term liabilities and other deferred credits | 7,779 | 7,841 | ||||||
Total liabilities and other deferred credits | 10,779 | 11,060 | ||||||
Commitments, guarantees and contingencies (see Note 12) | ||||||||
Equity | ||||||||
Common stock, $5 par value; 750,000,000 shares authorized; outstanding: 120,376,721 shares at December 31, 2015 and 119,647,149 shares at December 31, 2014 | 603 | 599 | ||||||
Additional paid-in capital | 2,099 | 2,087 | ||||||
Retained earnings | 1,421 | 1,312 | ||||||
Accumulated other comprehensive loss | (186 | ) | (206 | ) | ||||
Treasury shares, at cost: 216,523 shares at December 31, 2015 and 2014 | (8 | ) | (8 | ) | ||||
Total common shareholders’ equity | 3,929 | 3,784 | ||||||
Noncontrolling interest | 46 | 44 | ||||||
Total equity | 3,975 | 3,828 | ||||||
Total liabilities and equity | $ | 14,754 | $ | 14,888 |
Years ended December 31, | ||||||||||||
In millions, except per share amounts | 2015 | 2014 | 2013 | |||||||||
Operating revenues (includes revenue taxes of $103 for 2015, $133 for 2014 and $112 for 2013, respectively) | $ | 3,941 | $ | 5,385 | $ | 4,209 | ||||||
Operating expenses | ||||||||||||
Cost of goods sold | 1,645 | 2,765 | 2,110 | |||||||||
Operation and maintenance | 914 | 939 | 887 | |||||||||
Depreciation and amortization | 397 | 380 | 397 | |||||||||
Taxes other than income taxes | 181 | 208 | 187 | |||||||||
Merger-related expenses | 44 | — | — | |||||||||
Goodwill impairment | 14 | — | — | |||||||||
Total operating expenses | 3,195 | 4,292 | 3,581 | |||||||||
Gain on disposition of assets | — | 2 | 11 | |||||||||
Operating income | 746 | 1,095 | 639 | |||||||||
Other income | 13 | 14 | 16 | |||||||||
Interest expense, net | (173 | ) | (179 | ) | (170 | ) | ||||||
Income before income taxes | 586 | 930 | 485 | |||||||||
Income tax expense | 213 | 350 | 177 | |||||||||
Income from continuing operations | 373 | 580 | 308 | |||||||||
(Loss) income from discontinued operations, net of tax | — | (80 | ) | 5 | ||||||||
Net income | 373 | 500 | 313 | |||||||||
Less net income attributable to the noncontrolling interest | 20 | 18 | 18 | |||||||||
Net income attributable to AGL Resources | $ | 353 | $ | 482 | $ | 295 | ||||||
Net income attributable to AGL Resources | ||||||||||||
Income from continuing operations attributable to AGL Resources | $ | 353 | $ | 562 | $ | 290 | ||||||
(Loss) income from discontinued operations, net of tax | — | (80 | ) | 5 | ||||||||
Net income attributable to AGL Resources | $ | 353 | $ | 482 | $ | 295 | ||||||
Per common share information | ||||||||||||
Basic earnings (loss) per common share | ||||||||||||
Continuing operations | $ | 2.95 | $ | 4.73 | $ | 2.46 | ||||||
Discontinued operations | — | (0.67 | ) | 0.04 | ||||||||
Basic earnings per common share attributable to AGL Resources common shareholders | $ | 2.95 | $ | 4.06 | $ | 2.50 | ||||||
Diluted earnings (loss) per common share | ||||||||||||
Continuing operations | $ | 2.94 | $ | 4.71 | $ | 2.45 | ||||||
Discontinued operations | — | (0.67 | ) | 0.04 | ||||||||
Diluted earnings per common share attributable to AGL Resources common shareholders | $ | 2.94 | $ | 4.04 | $ | 2.49 | ||||||
Cash dividends declared per common share | $ | 2.04 | $ | 1.96 | $ | 1.88 | ||||||
Weighted average number of common shares outstanding | ||||||||||||
Basic | 119.6 | 118.8 | 117.9 | |||||||||
Diluted | 119.9 | 119.2 | 118.3 |
Years Ended December 31, | ||||||||||||
In millions | 2015 | 2014 | 2013 | |||||||||
Net income | $ | 373 | $ | 500 | $ | 313 | ||||||
Other comprehensive income (loss), net of tax | ||||||||||||
Retirement benefit plans, net of tax | ||||||||||||
Actuarial (loss) gain arising during the period (net of income tax of $0, $48 and $46) | — | (71 | ) | 66 | ||||||||
Reclassification of actuarial loss to net benefit cost (net of income tax of $9, $6 and $10) | 14 | 9 | 15 | |||||||||
Reclassification of prior service cost to net benefit cost (net of income tax of $0, $1 and $2) | (2 | ) | (1 | ) | (3 | ) | ||||||
Retirement benefit plans, net | 12 | (63 | ) | 78 | ||||||||
Cash flow hedges, net of tax | ||||||||||||
Net derivative instrument (loss) gain arising during the period (net of income tax of $3, $2 and $1) | — | (6 | ) | 1 | ||||||||
Reclassification of realized derivative loss (gain) to net income (net of income tax of $1, $2 and $1) | 8 | (3 | ) | 3 | ||||||||
Cash flow hedges, net | 8 | (9 | ) | 4 | ||||||||
Other comprehensive income (loss), net of tax | 20 | (72 | ) | 82 | ||||||||
Comprehensive income | 393 | 428 | 395 | |||||||||
Less comprehensive income attributable to noncontrolling interest | 20 | 16 | 18 | |||||||||
Comprehensive income attributable to AGL Resources | $ | 373 | $ | 412 | $ | 377 |
AGL Resources Inc. Shareholders | |||||||||||||||||||||||||||||||
Common stock | Additional paid-in capital | Retained earnings | Accumulated other comprehensive loss | Treasury shares | Noncontrolling interest | ||||||||||||||||||||||||||
In millions, except per share amounts | Shares | Amount | Total | ||||||||||||||||||||||||||||
As of December 31, 2012 | 117.9 | $ | 590 | $ | 2,015 | $ | 990 | $ | (218 | ) | $ | (8 | ) | $ | 22 | $ | 3,391 | ||||||||||||||
Net income | — | — | — | 295 | — | — | 18 | 313 | |||||||||||||||||||||||
Other comprehensive income | — | — | — | — | 82 | — | — | 82 | |||||||||||||||||||||||
Dividends on common stock ($1.88 per share) | — | — | — | (222 | ) | — | — | — | (222 | ) | |||||||||||||||||||||
Distribution to noncontrolling interest | — | — | — | — | — | — | (17 | ) | (17 | ) | |||||||||||||||||||||
Contribution from noncontrolling interest | — | — | — | — | — | — | 22 | 22 | |||||||||||||||||||||||
Stock granted, share-based compensation, net of forfeitures | — | — | (6 | ) | — | — | — | — | (6 | ) | |||||||||||||||||||||
Stock issued, dividend reinvestment plan | 0.3 | 1 | 10 | — | — | — | — | 11 | |||||||||||||||||||||||
Stock issued, share-based compensation, net of forfeitures | 0.7 | 4 | 24 | — | — | — | — | 28 | |||||||||||||||||||||||
Stock-based compensation expense, net of tax | — | — | 11 | — | — | — | — | 11 | |||||||||||||||||||||||
As of December 31, 2013 | 118.9 | $ | 595 | $ | 2,054 | $ | 1,063 | $ | (136 | ) | $ | (8 | ) | $ | 45 | $ | 3,613 | ||||||||||||||
Net income | — | — | — | 482 | — | — | 18 | 500 | |||||||||||||||||||||||
Other comprehensive loss | — | — | — | — | (70 | ) | — | (2 | ) | (72 | ) | ||||||||||||||||||||
Dividends on common stock ($1.96 per share) | — | — | — | (233 | ) | — | — | — | (233 | ) | |||||||||||||||||||||
Distribution to noncontrolling interest | — | — | — | — | — | — | (17 | ) | (17 | ) | |||||||||||||||||||||
Stock granted, share-based compensation, net of forfeitures | — | — | (11 | ) | — | — | — | — | (11 | ) | |||||||||||||||||||||
Stock issued, dividend reinvestment plan | 0.2 | 1 | 11 | — | — | — | — | 12 | |||||||||||||||||||||||
Stock issued, share-based compensation, net of forfeitures | 0.5 | 3 | 19 | — | — | — | — | 22 | |||||||||||||||||||||||
Stock-based compensation expense, net of tax | — | — | 14 | — | — | — | — | 14 | |||||||||||||||||||||||
As of December 31, 2014 | 119.6 | $ | 599 | $ | 2,087 | $ | 1,312 | $ | (206 | ) | $ | (8 | ) | $ | 44 | $ | 3,828 | ||||||||||||||
Net income | — | — | — | 353 | — | — | 20 | 373 | |||||||||||||||||||||||
Other comprehensive income | — | — | — | — | 20 | — | — | 20 | |||||||||||||||||||||||
Dividends on common stock ($2.04 per share) | — | — | — | (244 | ) | — | — | — | (244 | ) | |||||||||||||||||||||
Distribution to noncontrolling interest | — | — | — | — | — | — | (18 | ) | (18 | ) | |||||||||||||||||||||
Stock granted, share-based compensation, net of forfeitures | — | — | (14 | ) | — | — | — | — | (14 | ) | |||||||||||||||||||||
Stock issued, dividend reinvestment plan | 0.3 | 1 | 11 | — | — | — | — | 12 | |||||||||||||||||||||||
Stock issued, share-based compensation, net of forfeitures | 0.5 | 3 | 13 | — | — | — | — | 16 | |||||||||||||||||||||||
Stock-based compensation expense, net of tax | — | — | 2 | — | — | — | — | 2 | |||||||||||||||||||||||
As of December 31, 2015 | 120.4 | $ | 603 | $ | 2,099 | $ | 1,421 | $ | (186 | ) | $ | (8 | ) | $ | 46 | $ | 3,975 |
Years ended December 31, | ||||||||||||
In millions | 2015 | 2014 | 2013 | |||||||||
Cash flows from operating activities | ||||||||||||
Net income | $ | 373 | $ | 500 | $ | 313 | ||||||
Adjustments to reconcile net income to net cash flow provided by operating activities | ||||||||||||
Depreciation and amortization | 397 | 380 | 397 | |||||||||
Deferred income taxes | 211 | 201 | (16 | ) | ||||||||
Change in derivative instrument assets and liabilities | 22 | (155 | ) | 66 | ||||||||
Goodwill impairment | 14 | — | — | |||||||||
Gain on disposition of assets | — | (2 | ) | (11 | ) | |||||||
Loss (income) from discontinued operations, net of tax | — | 80 | (5 | ) | ||||||||
Changes in certain assets and liabilities | ||||||||||||
Receivables, other than energy marketing | 275 | (55 | ) | (74 | ) | |||||||
Inventories | 65 | (58 | ) | 41 | ||||||||
Prepaid and miscellaneous taxes | 3 | (244 | ) | 103 | ||||||||
Accrued/deferred natural gas costs | (6 | ) | (67 | ) | 2 | |||||||
Accrued expenses | (9 | ) | 32 | 39 | ||||||||
Energy marketing receivables and trade payables, net | (25 | ) | 113 | (54 | ) | |||||||
Trade payables, other than energy marketing | (75 | ) | (81 | ) | 89 | |||||||
Other, net | 136 | 21 | 70 | |||||||||
Net cash flow (used in) provided by operating activities of discontinued operations | — | (10 | ) | 11 | ||||||||
Net cash flow provided by operating activities | 1,381 | 655 | 971 | |||||||||
Cash flows from investing activities | ||||||||||||
Expenditures for property, plant and equipment | (1,027 | ) | (769 | ) | (731 | ) | ||||||
Disposition of assets | — | 230 | 12 | |||||||||
Acquisitions of assets | — | — | (154 | ) | ||||||||
Other, net | — | 47 | 8 | |||||||||
Net cash flow used in investing activities of discontinued operations | — | (13 | ) | (11 | ) | |||||||
Net cash flow used in investing activities | (1,027 | ) | (505 | ) | (876 | ) | ||||||
Cash flows from financing activities | ||||||||||||
Issuance of senior notes | 248 | — | 494 | |||||||||
Benefit, dividend reinvestment and stock purchase plan | 13 | 22 | 33 | |||||||||
Distribution to noncontrolling interest | (18 | ) | (17 | ) | (17 | ) | ||||||
Net (repayments) issuances of commercial paper | (165 | ) | 4 | (206 | ) | |||||||
Payment of senior notes | (200 | ) | — | (225 | ) | |||||||
Dividends paid on common shares | (244 | ) | (233 | ) | (222 | ) | ||||||
Contribution from noncontrolling interest | — | — | 22 | |||||||||
Net cash flow used in financing activities | (366 | ) | (224 | ) | (121 | ) | ||||||
Net decrease in cash and cash equivalents - continuing operations | (12 | ) | (51 | ) | (26 | ) | ||||||
Net decrease in cash and cash equivalents - discontinued operations | — | (23 | ) | — | ||||||||
Cash and cash equivalents (including held for sale) at beginning of period | 31 | 105 | 131 | |||||||||
Cash and cash equivalents (including held for sale) at end of period | 19 | 31 | 105 | |||||||||
Less cash and cash equivalents held for sale at end of period | — | — | 24 | |||||||||
Cash and cash equivalents (excluding held for sale) at end of period | $ | 19 | $ | 31 | $ | 81 | ||||||
Cash paid (received) during the period for | ||||||||||||
Interest | $ | 181 | $ | 187 | $ | 175 | ||||||
Income taxes | (26 | ) | 422 | 120 | ||||||||
Non cash financing transaction | ||||||||||||
Refinancing of gas facility revenue bonds | $ | — | $ | — | $ | 200 |
In millions | 2015 | 2014 | 2013 | |||||||||
Retail operations | $ | 3 | $ | 4 | $ | 1 | ||||||
Wholesale services (1) | 19 | 73 | 8 | |||||||||
Other | 1 | — | — | |||||||||
Total | $ | 23 | $ | 77 | $ | 9 |
(1) | The increase in 2014 was due to a significant decline in natural gas prices in December 2014. |
In millions | 2015 | 2014 | ||||||
Transportation and distribution | $ | 9,912 | $ | 9,105 | ||||
Storage facilities | 1,255 | 1,202 | ||||||
Other | 985 | 919 | ||||||
Construction work in progress | 414 | 326 | ||||||
PP&E, gross | 12,566 | 11,552 | ||||||
Less accumulated depreciation | 2,775 | 2,462 | ||||||
PP&E, net | $ | 9,791 | $ | 9,090 |
• | material and labor; |
• | contractor costs; |
• | construction overhead costs; |
• | AFUDC; and, |
• | Nicor Gas’ pad gas - the portion considered to be non-recoverable is recorded as depreciable PP&E, while the portion considered to be recoverable is recorded as non-depreciable PP&E. |
2015 | 2014 | 2013 | |||||||
Atlanta Gas Light (1) | 2.4 | % | 2.3 | % | 2.6 | % | |||
Chattanooga Gas (1) | 2.5 | 2.5 | 2.5 | ||||||
Elizabethtown Gas (2) | 2.4 | 2.5 | 2.4 | ||||||
Elkton Gas (2) | 2.7 | 2.8 | 2.4 | ||||||
Florida City Gas (2) | 3.9 | 3.9 | 3.8 | ||||||
Nicor Gas (2) (3) | 3.1 | 3.1 | 3.1 | ||||||
Virginia Natural Gas (1) | 2.5 | 2.5 | 2.5 |
(1) | Average composite straight-line depreciation rates for depreciable property, excluding transportation equipment, which may be depreciated in excess of useful life and recovered in rates. |
(2) | Composite straight-line depreciation rates. |
(3) | In October 2013, the Illinois Commission approved a composite depreciation rate of 3.07%. The depreciation rate was effective as of August 30, 2013, the date the depreciation study was filed, and had the effect of reducing our 2014 and 2013 depreciation expense by $51 million and $19 million, respectively. |
In years | Estimated useful life | |
Transportation equipment | 5 – 10 | |
Storage caverns | 40 – 60 | |
Other | up to 40 |
2015 | 2014 | 2013 | ||||||||||
Atlanta Gas Light | 8.10 | % | 8.10 | % | 8.10 | % | ||||||
Nicor Gas (1) | 0.82 | % | 0.24 | % | 0.31 | % | ||||||
Chattanooga Gas | 7.41 | % | 7.41 | % | 7.41 | % | ||||||
Elizabethtown Gas (1) | 1.69 | % | 0.44 | % | 0.41 | % | ||||||
AFUDC (in millions) (2) | $ | 6 | $ | 7 | $ | 18 |
(1) | Variable rate is determined by FERC method of AFUDC accounting. |
(2) | Amount recorded on the Consolidated Statements of Income. |
In millions | Distribution operations | Retail operations | Midstream operations | Consolidated | ||||||||||||
Goodwill - December 31, 2014 | $ | 1,640 | $ | 173 | $ | 14 | $ | 1,827 | ||||||||
Impairment | — | — | (14 | ) | (14 | ) | ||||||||||
Goodwill - December 31, 2015 | $ | 1,640 | $ | 173 | $ | — | $ | 1,813 |
December 31, 2015 | December 31, 2014 | |||||||||||||||||||||||||
In millions | Weighted average amortization period (in years) | Gross | Accumulated amortization | Net | Gross | Accumulated amortization | Net | |||||||||||||||||||
Customer relationships | 13 | $ | 132 | $ | (57 | ) | $ | 75 | $ | 130 | $ | (42 | ) | $ | 88 | |||||||||||
Trade names | 13 | 45 | (11 | ) | 34 | 45 | (8 | ) | 37 | |||||||||||||||||
Total | $ | 177 | $ | (68 | ) | $ | 109 | $ | 175 | $ | (50 | ) | $ | 125 |
In millions | Amortization Expense | |||
2016 | $ | 17 | ||
2017 | 15 | |||
2018 | 14 | |||
2019 | 12 | |||
2020 | 11 |
In millions | 2015 | 2014 | 2013 | |||||||||
Equity investment income | $ | 6 | $ | 8 | $ | 3 | ||||||
AFUDC - equity | 4 | 5 | 12 | |||||||||
Other, net | 3 | 1 | 1 | |||||||||
Total other income | $ | 13 | $ | 14 | $ | 16 |
In millions (except per share amounts) | 2015 | 2014 | 2013 | |||||||||
Income from continuing operations attributable to AGL Resources | $ | 353 | $ | 562 | $ | 290 | ||||||
(Loss) income from discontinued operations, net of tax | — | (80 | ) | 5 | ||||||||
Net income attributable to AGL Resources | $ | 353 | $ | 482 | $ | 295 | ||||||
Denominator: | ||||||||||||
Basic weighted average number of common shares outstanding (1) | 119.6 | 118.8 | 117.9 | |||||||||
Effect of dilutive securities | 0.3 | 0.4 | 0.4 | |||||||||
Diluted weighted average number of common shares outstanding (2) | 119.9 | 119.2 | 118.3 | |||||||||
Basic earnings (loss) per common share | ||||||||||||
Continuing operations | $ | 2.95 | $ | 4.73 | $ | 2.46 | ||||||
Discontinued operations | — | (0.67 | ) | 0.04 | ||||||||
Basic earnings per common share attributable to AGL Resources | $ | 2.95 | $ | 4.06 | $ | 2.50 | ||||||
Diluted earnings (loss) per common share | ||||||||||||
Continuing operations | $ | 2.94 | $ | 4.71 | $ | 2.45 | ||||||
Discontinued operations | — | (0.67 | ) | 0.04 | ||||||||
Diluted earnings per common share attributable to AGL Resources | $ | 2.94 | $ | 4.04 | $ | 2.49 |
(2) | All outstanding stock options for whose effect would have been anti-dilutive were excluded from the computation of diluted earnings per common share. |
In millions | 2015 | 2014 | ||||||
Regulatory assets | ||||||||
Recoverable ERC | $ | 31 | $ | 49 | ||||
Recoverable pension and retiree welfare benefit costs | 12 | 12 | ||||||
Recoverable seasonal rates | 10 | 10 | ||||||
Deferred natural gas costs | 6 | 3 | ||||||
Other | 9 | 9 | ||||||
Regulatory assets - current | 68 | 83 | ||||||
Recoverable ERC | 370 | 329 | ||||||
Recoverable pension and retiree welfare benefit costs | 113 | 110 | ||||||
Recoverable regulatory infrastructure program costs | 83 | 69 | ||||||
Long-term debt fair value adjustment | 66 | 74 | ||||||
Other | 38 | 49 | ||||||
Regulatory assets - long-term | 670 | 631 | ||||||
Total regulatory assets | $ | 738 | $ | 714 | ||||
Regulatory liabilities | ||||||||
Accumulated removal costs | $ | 53 | $ | 25 | ||||
Bad debt over collection | 42 | 33 | ||||||
Accrued natural gas costs | 24 | 27 | ||||||
Other | 15 | 27 | ||||||
Regulatory liabilities - current | 134 | 112 | ||||||
Accumulated removal costs | 1,538 | 1,520 | ||||||
Regulatory income tax liability | 27 | 34 | ||||||
Bad debt over collection | 21 | 12 | ||||||
Unamortized investment tax credit | 20 | 22 | ||||||
Other | 5 | 13 | ||||||
Regulatory liabilities - long-term | 1,611 | 1,601 | ||||||
Total regulatory liabilities | $ | 1,745 | $ | 1,713 |
In millions | Atlanta Gas Light | Virginia Natural Gas | Elizabethtown Gas | Nicor Gas | Total | |||||||||||||||
December 31, 2015 | $ | 103 | (1) | $ | 12 | $ | 4 | $ | 3 | $ | 122 | |||||||||
December 31, 2014 | 113 | 12 | 2 | — | 127 |
(1) | In October 2015, Atlanta Gas Light received an order from the Georgia Commission, which included a final determination of the true-up recovery related to the PRP. The order allows Atlanta Gas Light to recover $144 million of the $178 million of incurred and allowed costs that were deferred for future recovery. These deferred costs were originally requested in a February 2015 filing for a true-up of unrecovered revenue. See Note 12 for additional information on Atlanta Gas Light's global resolution of this and other matters that were previously raised before the Georgia Commission. |
In millions | # of sites | Probabilistic model cost estimates (1) | Engineering-based estimates (1) | Amount recorded | Expected costs over next 12 months | Cost recovery period | |||||||||||||
Illinois (2) | 26 | $200 - $457 | $ | 50 | $ | 250 | $ | 32 | As incurred | ||||||||||
New Jersey | 6 | 115 - 195 | 7 | 122 | 18 | 7 years | |||||||||||||
Georgia and Florida | 13 | 29 - 52 | 23 | 52 | 12 | 5 years | |||||||||||||
North Carolina (3) | 1 | n/a | 7 | 7 | 5 | No recovery | |||||||||||||
Total | 46 | $344 - $704 | $ | 87 | $ | 431 | $ | 67 |
(1) | The year-end ERC cost estimates were completed as of November 30, 2015. The liability recorded reflects a reduction of these cost estimates for expenses incurred during December. |
(2) | Nicor Gas is responsible in whole or in part for 26 MGP sites, two of which have been remediated and their use is no longer restricted by the environmental condition of the property. Nicor Gas and Commonwealth Edison Company are parties to an agreement to cooperate in cleaning up residue at 23 of the sites. Nicor Gas’ allocated share of cleanup costs for these sites is 52%. |
(3) | We have no regulatory recovery mechanism for the site in North Carolina and there is no amount included within our regulatory assets. Changes in estimated costs are recognized in income during the period of change. |
Actual | Total | Amount refunded in | Amount to be refunded in | |||||||||||||||||||||||||
In millions | Benchmark | bad debt | refund | 2014 | 2015 | 2016 | 2017 | |||||||||||||||||||||
2015 | $ | 63 | $ | 12 | $ | 51 | $ | — | $ | — | $ | 30 | $ | 21 | ||||||||||||||
2014 | 63 | 35 | 28 | — | 16 | 12 | — | |||||||||||||||||||||
2013 | 63 | 21 | 42 | 25 | 17 | — | — |
December 31, 2015 | ||||||||||||||||||||||||||||||||||||||
Pension plans (1) | Welfare plans | |||||||||||||||||||||||||||||||||||||
In millions | Level 1 | Level 2 | Level 3 | Total | % of total | Level 1 | Level 2 | Level 3 | Total | % of total | ||||||||||||||||||||||||||||
Cash | $ | 4 | $ | — | $ | — | $ | 4 | — | % | $ | 1 | $ | — | $ | — | $ | 1 | 1 | % | ||||||||||||||||||
Equity securities: | ||||||||||||||||||||||||||||||||||||||
U.S. large cap (2) | $ | 75 | $ | 199 | $ | — | $ | 274 | 32 | % | $ | — | $ | 52 | $ | — | $ | 52 | 58 | % | ||||||||||||||||||
U.S. small cap (2) | 57 | 24 | — | 81 | 9 | % | — | — | — | — | — | |||||||||||||||||||||||||||
International companies (3) | — | 125 | — | 125 | 15 | % | — | 15 | — | 15 | 17 | % | ||||||||||||||||||||||||||
Emerging markets (4) | — | 28 | — | 28 | 3 | % | — | — | — | — | — | |||||||||||||||||||||||||||
Total equity securities | $ | 132 | $ | 376 | $ | — | $ | 508 | 59 | % | $ | — | $ | 67 | $ | — | $ | 67 | 75 | % | ||||||||||||||||||
Fixed income securities: | ||||||||||||||||||||||||||||||||||||||
Corporate bonds (5) | $ | — | $ | 91 | $ | — | $ | 91 | 11 | % | $ | — | $ | 22 | $ | — | $ | 22 | 24 | % | ||||||||||||||||||
Other (or gov’t/muni bonds) | — | 151 | — | 151 | 18 | % | — | — | — | — | — | |||||||||||||||||||||||||||
Total fixed income securities | $ | — | $ | 242 | $ | — | $ | 242 | 29 | % | $ | — | $ | 22 | $ | — | $ | 22 | 24 | % | ||||||||||||||||||
Other types of investments: | ||||||||||||||||||||||||||||||||||||||
Global hedged equity (6) | $ | — | $ | — | $ | 40 | $ | 40 | 5 | % | $ | — | $ | — | $ | — | $ | — | — | |||||||||||||||||||
Absolute return (7) | — | — | 42 | 42 | 5 | % | — | — | — | — | — | |||||||||||||||||||||||||||
Private capital (8) | — | — | 20 | 20 | 2 | % | — | — | — | — | — | |||||||||||||||||||||||||||
Total other investments | $ | — | $ | — | $ | 102 | $ | 102 | 12 | % | $ | — | $ | — | $ | — | $ | — | — | |||||||||||||||||||
Total assets at fair value | $ | 136 | $ | 618 | $ | 102 | $ | 856 | 100 | % | $ | 1 | $ | 89 | $ | — | $ | 90 | 100 | % | ||||||||||||||||||
% of fair value hierarchy | 16 | % | 72 | % | 12 | % | 100 | % | 1 | % | 99 | % | — | 100 | % |
December 31, 2014 | ||||||||||||||||||||||||||||||||||||||
Pension plans (1) | Welfare plans | |||||||||||||||||||||||||||||||||||||
In millions | Level 1 | Level 2 | Level 3 | Total | % of total | Level 1 | Level 2 | Level 3 | Total | % of total | ||||||||||||||||||||||||||||
Cash | $ | 4 | $ | 1 | $ | — | $ | 5 | 1 | % | $ | 1 | $ | — | $ | — | $ | 1 | 1 | % | ||||||||||||||||||
Equity securities: | ||||||||||||||||||||||||||||||||||||||
U.S. large cap (2) | $ | 95 | $ | 203 | $ | — | $ | 298 | 33 | % | $ | — | $ | 51 | $ | — | $ | 51 | 57 | % | ||||||||||||||||||
U.S. small cap (2) | 76 | 24 | — | 100 | 11 | % | — | — | — | — | — | % | ||||||||||||||||||||||||||
International companies (3) | — | 123 | — | 123 | 13 | % | — | 16 | — | 16 | 18 | % | ||||||||||||||||||||||||||
Emerging markets (4) | — | 31 | — | 31 | 3 | % | — | — | — | — | — | % | ||||||||||||||||||||||||||
Total equity securities | $ | 171 | $ | 381 | $ | — | $ | 552 | 60 | % | $ | — | $ | 67 | $ | — | $ | 67 | 75 | % | ||||||||||||||||||
Fixed income securities: | ||||||||||||||||||||||||||||||||||||||
Corporate bonds (5) | $ | — | $ | 233 | $ | — | $ | 233 | 25 | % | $ | — | $ | 22 | $ | — | $ | 22 | 24 | % | ||||||||||||||||||
Other (or gov’t/muni bonds) | — | 33 | — | 33 | 4 | % | — | — | — | — | — | % | ||||||||||||||||||||||||||
Total fixed income securities | $ | — | $ | 266 | $ | — | $ | 266 | 29 | % | $ | — | $ | 22 | $ | — | $ | 22 | 24 | % | ||||||||||||||||||
Other types of investments: | ||||||||||||||||||||||||||||||||||||||
Global hedged equity (6) | $ | — | $ | — | $ | 29 | $ | 29 | 3 | % | $ | — | $ | — | $ | — | $ | — | — | % | ||||||||||||||||||
Absolute return (7) | — | — | 42 | 42 | 5 | % | — | — | — | — | — | % | ||||||||||||||||||||||||||
Private capital (8) | — | — | 20 | 20 | 2 | % | — | — | — | — | — | % | ||||||||||||||||||||||||||
Total other investments | $ | — | $ | — | $ | 91 | $ | 91 | 10 | % | $ | — | $ | — | $ | — | $ | — | — | % | ||||||||||||||||||
Total assets at fair value | $ | 175 | $ | 648 | $ | 91 | $ | 914 | 100 | % | $ | 1 | $ | 89 | $ | — | $ | 90 | 100 | % | ||||||||||||||||||
% of fair value hierarchy | 19 | % | 71 | % | 10 | % | 100 | % | 1 | % | 99 | % | — | % | 100 | % |
(1) | Includes $9 million at December 31, 2015 and $9 million at December 31, 2014 of medical benefit (health and welfare) component for 401h accounts to fund a portion of the other retirement benefits. |
(2) | Includes funds that invest primarily in U.S. common stocks. |
(3) | Includes funds that invest primarily in foreign equity and equity-related securities. |
(4) | Includes funds that invest primarily in common stocks of emerging markets. |
(5) | Includes funds that invest primarily in investment grade debt and fixed income securities. |
(6) | Includes funds that invest in limited / general partnerships, managed accounts, and other investment entities issued by non-traditional firms or “hedge funds.” |
(7) | Includes funds that invest primarily in investment vehicles and commodity pools as a “fund of funds.” |
(8) | Includes funds that invest in private equity and small buyout funds, partnership investments, direct investments, secondary investments, directly / indirectly in real estate and may invest in equity securities of real estate related companies, real estate mortgage loans, and real estate mezzanine loans. |
Fair value measurements using significant unobservable inputs - Level 3 (1) | ||||||||||||||||
In millions | Global hedged equity | Absolute return | Private capital | Total | ||||||||||||
Balance at December 31, 2013 | $ | 43 | $ | 39 | $ | 22 | $ | 104 | ||||||||
Actual return on plan assets | 1 | 3 | 2 | 6 | ||||||||||||
Sales | (15 | ) | — | (4 | ) | (19 | ) | |||||||||
Balance at December 31, 2014 | $ | 29 | $ | 42 | $ | 20 | $ | 91 | ||||||||
Actual return on plan assets | (1 | ) | — | 3 | 2 | |||||||||||
Purchases | 12 | — | — | 12 | ||||||||||||
Sales | — | — | (3 | ) | (3 | ) | ||||||||||
Balance at December 31, 2015 | $ | 40 | $ | 42 | $ | 20 | $ | 102 |
2015 | 2014 | |||||||||||||||
In millions | Assets (1) | Liabilities | Assets (1) | Liabilities | ||||||||||||
Natural gas derivatives | ||||||||||||||||
Quoted prices in active markets (Level 1) | $ | 53 | $ | (63 | ) | $ | 58 | $ | (80 | ) | ||||||
Significant other observable inputs (Level 2) | 122 | (46 | ) | 174 | (94 | ) | ||||||||||
Netting of cash collateral | 33 | 63 | 52 | 81 | ||||||||||||
Total carrying value (2) | $ | 208 | $ | (46 | ) | $ | 284 | $ | (93 | ) |
(1) | Balances of $10 million and $3 million at December 31, 2015 and 2014, respectively, associated with certain weather derivatives have been excluded, as they are accounted for based on intrinsic value rather than fair value. |
(2) | There were no significant unobservable inputs (Level 3) or significant transfers between Level 1, Level 2, or Level 3 for any of the dates presented. |
In millions | 2015 | 2014 | ||||||
Long-term debt carrying amount (1) | $ | 3,820 | $ | 3,781 | ||||
Long-term debt fair value (2) | 4,066 | 4,231 |
(1) | The change in the December 31, 2014 balance is related to our adoption of new accounting guidance in 2015 that resulted in the reclassification of debt issuance costs from other long-term assets to offset the related debt balances in long-term debt. See Note 9 for additional information. |
(2) | Fair value determined using Level 2 inputs. |
• | forward, futures and options contracts; |
• | financial swaps; |
• | treasury locks; |
• | weather derivative contracts; |
• | storage and transportation capacity contracts; and |
• | foreign currency forward contracts |
Recognition and Measurement | ||
Accounting Treatment | Balance Sheets | Income Statements |
Cash flow hedge | Derivative carried at fair value | Ineffective portion of the gain or loss realized and unrealized on the derivative instrument is recognized in earnings |
Effective portion of the gain or loss on the derivative instrument is reported initially as a component of accumulated OCI (loss) | Effective portion of the gain or loss realized and unrealized on the derivative instrument is reclassified out of accumulated OCI (loss) and into earnings when the hedged transaction affects earnings | |
Fair value hedge | Derivative carried at fair value | Gains or losses realized and unrealized on the derivative instrument and the hedged item are recognized in earnings. As a result, to the extent the hedge is effective, the gains or losses will offset and there is no impact on earnings. Any hedge ineffectiveness will impact earnings |
Changes in fair value of the hedged item are recorded as adjustments to the carrying amount of the hedged item | ||
Not designated as hedges | Derivative carried at fair value | Gains or losses realized and unrealized on the derivative instrument are recognized in earnings |
Distribution operations’ gains and losses on derivative instruments are deferred as regulatory assets or liabilities until included in cost of goods sold | Gains or losses realized and unrealized on the derivative instruments are ultimately included in billings to customers and are recognized in cost of goods sold in the same period as the related revenues |
In Bcf (1) | 2015 (2) | 2014 | ||||
Cash flow hedges | 5 | 9 | ||||
Not designated as hedges | (14 | ) | 75 | |||
Total volumes | (9 | ) | 84 | |||
Short position – cash flow hedges | (6 | ) | (4 | ) | ||
Short position – not designated as hedges | (3,089 | ) | (2,828 | ) | ||
Long position – cash flow hedges | 11 | 13 | ||||
Long position – not designated as hedges | 3,075 | 2,903 | ||||
Net (short) long position | (9 | ) | 84 |
(1) | Volumes related to Nicor Gas exclude variable-priced contracts, which are carried at fair value, but whose fair values are not directly impacted by changes in commodity prices. |
(2) | Approximately 96% of these contracts have durations of two years or less and approximately 4% expire between two and five years. |
In millions | 2015 | 2014 | ||||||
Nicor Gas | $ | (47 | ) | $ | 10 | |||
Elizabethtown Gas | (20 | ) | 2 |
2015 | 2014 | ||||||||||||||||
In millions | Classification | Assets | Liabilities | Assets | Liabilities | ||||||||||||
Designated as cash flow or fair value hedges | |||||||||||||||||
Natural gas contracts | Current | $ | 3 | $ | (5 | ) | $ | 6 | $ | (11 | ) | ||||||
Natural gas contracts | Long-term | — | (2 | ) | — | (1 | ) | ||||||||||
Interest rate swap agreements | Current | 9 | — | — | — | ||||||||||||
Total designated as cash flow or fair value hedges | $ | 12 | $ | (7 | ) | $ | 6 | $ | (12 | ) | |||||||
Not designated as hedges | |||||||||||||||||
Natural gas and weather contracts | Current | $ | 751 | $ | (672 | ) | $ | 1,061 | $ | (1,020 | ) | ||||||
Natural gas contracts | Long-term | 179 | (187 | ) | 145 | (119 | ) | ||||||||||
Total not designated as hedges | $ | 930 | $ | (859 | ) | $ | 1,206 | $ | (1,139 | ) | |||||||
Gross amount of recognized assets and liabilities (1) (2) | 942 | (866 | ) | 1,212 | (1,151 | ) | |||||||||||
Gross amounts offset on our Consolidated Balance Sheets (2) | (724 | ) | 820 | (925 | ) | 1,058 | |||||||||||
Net amounts of assets and liabilities presented on our Consolidated Balance Sheets (3) | $ | 218 | $ | (46 | ) | $ | 287 | $ | (93 | ) |
(1) | The gross amounts of recognized assets and liabilities are netted on our Consolidated Balance Sheets to the extent that we have netting arrangements with the counterparties. |
(2) | As required by the authoritative guidance related to derivatives and hedging, the gross amounts of recognized assets and liabilities do not include cash collateral held on deposit in broker margin accounts of $96 million as of December 31, 2015 and $133 million as of December 31, 2014. Cash collateral is included in the “Gross amounts offset on our Consolidated Balance Sheets” line of this table. |
(3) | As of December 31, 2015 and 2014, we held letters of credit from counterparties that under master netting arrangements would offset an insignificant portion of these assets. |
In millions | 2015 | 2014 | 2013 | |||||||||
Designated as cash flow or fair value hedges | ||||||||||||
Natural gas contracts – net gain (loss) reclassified from OCI into cost of goods sold | $ | (10 | ) | $ | 4 | $ | (1 | ) | ||||
Natural gas contracts – net gain (loss) reclassified from OCI into operation and maintenance expense | (1 | ) | 1 | — | ||||||||
Interest rate swaps – net gain (loss) reclassified from OCI into interest expense | 2 | — | (3 | ) | ||||||||
Income tax | 1 | (2 | ) | 1 | ||||||||
Total designated as cash flow or fair value hedges, net of tax | $ | (8 | ) | $ | 3 | $ | (3 | ) | ||||
Not designated as hedges (1) | ||||||||||||
Natural gas contracts - net fair value adjustments recorded in operating revenues | $ | 56 | $ | 149 | $ | (90 | ) | |||||
Natural gas contracts - net fair value adjustments recorded in cost of goods sold (2) | (6 | ) | (7 | ) | 2 | |||||||
Income tax | (19 | ) | (54 | ) | 34 | |||||||
Total not designated as hedges, net of tax | $ | 31 | $ | 88 | $ | (54 | ) | |||||
Total gains (losses) on derivative instruments, net of tax | $ | 23 | $ | 91 | $ | (57 | ) |
(1) | Associated with the fair value of derivative instruments held at December 31, 2015, 2014 and 2013. |
(2) | Excludes (gains) and losses recorded in cost of goods sold associated with weather derivatives of $(12) million, $7 million and $5 million for the years ended December 31, 2015, 2014 and 2013, respectively. |
• | Generate investment returns that, in combination with our funding contributions, provide adequate funding to meet all current and future benefit obligations of the plans. |
• | Provide investment results that meet or exceed the assumed long-term rate of return, while maintaining the funded status of the plans at acceptable levels. |
• | Improve funded status over time. |
• | Decrease contribution and expense volatility as funded status improves. |
Pension plans | Welfare plans | |||||||||||||||||||||||
Dollars in millions | 2015 | 2014 | 2013 | 2015 | 2014 | 2013 | ||||||||||||||||||
Service cost | $ | 28 | $ | 24 | $ | 29 | $ | 2 | $ | 2 | $ | 3 | ||||||||||||
Interest cost | 45 | 47 | 43 | 13 | 15 | 14 | ||||||||||||||||||
Expected return on plan assets | (65 | ) | (65 | ) | (62 | ) | (7 | ) | (7 | ) | (6 | ) | ||||||||||||
Net amortization of prior service cost | (2 | ) | (2 | ) | (2 | ) | (3 | ) | (3 | ) | (5 | ) | ||||||||||||
Recognized actuarial loss | 31 | 22 | 35 | 6 | 6 | 8 | ||||||||||||||||||
Net periodic benefit cost | $ | 37 | $ | 26 | $ | 43 | $ | 11 | $ | 13 | $ | 14 | ||||||||||||
Assumptions used to determine benefit costs | ||||||||||||||||||||||||
Discount rate (1) | 4.2 | % | 5.0 | % | 4.2 | % | 4.0 | % | 4.7 | % | 4.0 | % | ||||||||||||
Expected return on plan assets (1) | 7.8 | % | 7.8 | % | 7.8 | % | 7.8 | % | 7.8 | % | 7.8 | % | ||||||||||||
Rate of compensation increase (1) | 3.7 | % | 3.7 | % | 3.7 | % | 3.7 | % | 3.7 | % | 3.8 | % | ||||||||||||
Pension band increase (2) | 2.0 | % | 2.0 | % | 2.0 | % | n/a | n/a | n/a |
(1) | Rates are presented on a weighted average basis on a before tax basis for the Welfare plans. |
(2) | Only applicable to the Nicor Gas union employees. The pension bands for the former Nicor Plan have been updated to reflect the new negotiated rates for 2016 and 2017 of 2.0% and 2.0%, respectively, as indicated in the union agreement dated March 2014. |
Pension plans | Welfare plans | |||||||||||||||
Dollars in millions | 2015 | 2014 | 2015 | 2014 | ||||||||||||
Change in plan assets | ||||||||||||||||
Fair value of plan assets, January 1, | $ | 906 | $ | 907 | $ | 99 | $ | 93 | ||||||||
Actual return on plan assets | (12 | ) | 68 | 1 | 5 | |||||||||||
Employee contributions | — | — | 1 | 2 | ||||||||||||
Employer contributions | 2 | 1 | 17 | 17 | ||||||||||||
Benefits paid | (49 | ) | (70 | ) | (20 | ) | (19 | ) | ||||||||
Medicare Part D reimbursements | — | — | 1 | 1 | ||||||||||||
Fair value of plan assets, December 31, | $ | 847 | $ | 906 | $ | 99 | $ | 99 | ||||||||
Change in benefit obligation | ||||||||||||||||
Benefit obligation, January 1, | $ | 1,098 | $ | 960 | $ | 334 | $ | 326 | ||||||||
Service cost | 28 | 24 | 2 | 2 | ||||||||||||
Interest cost | 45 | 47 | 13 | 15 | ||||||||||||
Actuarial loss (gain) | (55 | ) | 137 | (13 | ) | 8 | ||||||||||
Medicare Part D reimbursements | — | — | 1 | 1 | ||||||||||||
Benefits paid | (49 | ) | (70 | ) | (20 | ) | (19 | ) | ||||||||
Employee contributions | — | — | 1 | 1 | ||||||||||||
Benefit obligation, December 31, | $ | 1,067 | $ | 1,098 | $ | 318 | $ | 334 | ||||||||
Funded status at end of year | $ | (220 | ) | $ | (192 | ) | $ | (219 | ) | $ | (235 | ) | ||||
Amounts recognized on the Consolidated Balance Sheets | ||||||||||||||||
Long-term asset (2) | $ | 78 | $ | 97 | $ | — | $ | — | ||||||||
Current liability | (4 | ) | (2 | ) | — | — | ||||||||||
Long-term liability | (294 | ) | (287 | ) | (219 | ) | (235 | ) | ||||||||
Net liability at December 31, | $ | (220 | ) | $ | (192 | ) | $ | (219 | ) | $ | (235 | ) | ||||
Accumulated benefit obligation (1) | $ | 1,002 | $ | 1,027 | n/a | n/a | ||||||||||
Assumptions used to determine benefit obligations | ||||||||||||||||
Discount rate | 4.6 | % | 4.2 | % | 4.4 | % | 4.0 | % | ||||||||
Rate of compensation increase | 3.7 | 3.7 | 3.7 | 3.7 | ||||||||||||
Pension band increase (3) | 2.0 | 2.0 | n/a | n/a |
(1) | APBO differs from the projected benefit obligation in that APBO excludes the effect of salary and wage increases. |
(2) | As a result of historically having multiple plans, a portion of our obligation is in an asset position. |
(3) | Only applicable to the Nicor Gas union employees. |
2015 | 2014 | |||||
Health care cost trend rate assumed for next year | 7.9 | % | 8.1 | % | ||
Ultimate rate to which the cost trend rate is assumed to decline | 4.5 | % | 4.5 | % | ||
Year that reaches ultimate trend rate | 2030 | 2030 |
In millions | Effect on benefit obligation | |||
1% Health care cost trend rate increase | $ | 13 | ||
1% Health care cost trend rate decrease | (11 | ) |
Net regulatory assets | Accumulated OCI | Total | ||||||||||||||||||||||
In millions | Pension plans | Welfare plans | Pension plans | Welfare plans | Pension plans | Welfare plans | ||||||||||||||||||
December 31, 2015 | ||||||||||||||||||||||||
Prior service credit | $ | — | $ | (15 | ) | $ | (4 | ) | $ | — | $ | (4 | ) | $ | (15 | ) | ||||||||
Net loss | 88 | 45 | 286 | 36 | 374 | 81 | ||||||||||||||||||
Total | $ | 88 | $ | 30 | $ | 282 | $ | 36 | $ | 370 | $ | 66 | ||||||||||||
December 31, 2014 | ||||||||||||||||||||||||
Prior service credit | $ | — | $ | (18 | ) | $ | (6 | ) | $ | — | $ | (6 | ) | $ | (18 | ) | ||||||||
Net loss | 76 | 57 | 307 | 36 | 383 | 93 | ||||||||||||||||||
Total | $ | 76 | $ | 39 | $ | 301 | $ | 36 | $ | 377 | $ | 75 |
Net regulatory assets | Accumulated OCI | Total | ||||||||||||||||||||||
In millions | Pension plans | Welfare plans | Pension plans | Welfare plans | Pension plans | Welfare plans | ||||||||||||||||||
Amortization of prior service credit | $ | — | $ | (3 | ) | $ | (2 | ) | $ | — | $ | (2 | ) | $ | (3 | ) | ||||||||
Amortization of net loss | 7 | 2 | 17 | 3 | 24 | 5 |
In millions | Pension plans | Welfare plans | ||||||
2016 | $ | 79 | $ | 20 | ||||
2017 | 68 | 20 | ||||||
2018 | 70 | 21 | ||||||
2019 | 73 | 22 | ||||||
2020 | 75 | 23 | ||||||
2021-2025 | 374 | 116 |
• | stock options; |
• | stock and restricted stock awards; and |
• | performance units (restricted stock units, performance share units and performance cash units). |
In millions | 2015 | 2014 | 2013 | |||||||||
Compensation costs (1) | $ | 40 | $ | 24 | $ | 22 | ||||||
Income tax benefits (1) | 1 | 1 | 1 | |||||||||
Excess tax benefits (2) | — | — | — |
(1) | Recorded in our Consolidated Statements of Income. |
(2) | Recorded in our Consolidated Balance Sheets. |
Stock Options | Number of options | Weighted average exercise price | Weighted average remaining life (in years) | Aggregate intrinsic value (in millions) | ||||||||||
Outstanding | December 31, 2012 | 1,528,590 | $ | 36.09 | ||||||||||
Exercised | (617,358 | ) | 35.37 | |||||||||||
Forfeited | (12,500 | ) | 38.36 | |||||||||||
Outstanding (1) | December 31, 2013 | 898,732 | $ | 36.55 | ||||||||||
Exercised | (267,182 | ) | 36.84 | |||||||||||
Forfeited | (4,000 | ) | 39.71 | |||||||||||
Outstanding (1) | December 31, 2014 | 627,550 | $ | 36.41 | 2.2 | $ | 11 | |||||||
Exercised | (523,400 | ) | 36.00 | 1.1 | ||||||||||
Outstanding (1) (2) | December 31, 2015 | 104,150 | $ | 38.46 | 1.3 | $ | 3 |
(1) | All options outstanding at December 31, 2015, 2014 and 2013 were exercisable. |
(2) | The range of exercise prices for the options outstanding at December 31, 2015 was $31.09 to $43.54. |
In millions | Measurement period end date | Fair value accrued at December 31, 2015 | Maximum aggregate payout | |||||||
Granted in 2013 | December 31, 2015 | $ | 18 | $ | 24 | |||||
Granted in 2014 | December 31, 2016 | 13 | 28 | |||||||
Granted in 2015 | December 31, 2017 | 7 | 29 |
Shares of restricted stock | Weighted average remaining vesting period (in years) | Weighted average fair value (per share) | |||||||||
Outstanding (1) | December 31, 2012 | 503,091 | $ | 39.44 | |||||||
Issued | 175,935 | 42.41 | |||||||||
Forfeited | (33,352 | ) | 40.64 | ||||||||
Vested | (204,421 | ) | 38.71 | ||||||||
Outstanding (1) | December 31, 2013 | 441,253 | $ | 40.82 | |||||||
Issued | 262,235 | 47.03 | |||||||||
Forfeited | (14,895 | ) | 43.41 | ||||||||
Vested | (225,683 | ) | 42.31 | ||||||||
Outstanding (1) | December 31, 2014 | 462,910 | 1.8 | $ | 43.54 | ||||||
Issued | 274,012 | 3.1 | 51.38 | ||||||||
Forfeited | (13,390 | ) | 2.5 | 45.60 | |||||||
Vested | (324,700 | ) | — | 51.68 | |||||||
Outstanding (1) | December 31, 2015 | 398,832 | 1.4 | $ | 46.92 |
2015 | 2014 | 2013 | ||||||||||
Shares purchased on the open market | 106,994 | 100,199 | 97,734 | |||||||||
Average purchase price (per share) | $ | 55.47 | $ | 51.60 | $ | 42.96 | ||||||
Total purchase price discount (in dollars) | $ | 793,931 | $ | 739,598 | $ | 628,358 |
December 31, 2015 | December 31, 2014 | |||||||||||||||
Dollars in millions | Year(s) due | Weighted average interest rate (1) | Outstanding | Weighted average interest rate (1) | Outstanding | |||||||||||
Short-term debt | ||||||||||||||||
Commercial paper - AGL Capital (2) | 2016 | 0.5 | % | $ | 471 | 0.3 | % | $ | 590 | |||||||
Commercial paper - Nicor Gas (2) | 2016 | 0.4 | 539 | 0.2 | 585 | |||||||||||
Total short-term debt | 0.4 | % | $ | 1,010 | 0.3 | % | $ | 1,175 | ||||||||
Current portion of long-term debt | 2016 | 4.9 | % | $ | 545 | 5.0 | % | $ | 200 | |||||||
Long-term debt - excluding current portion | ||||||||||||||||
Senior notes | 2018-2043 | 5.0 | % | $ | 2,455 | 5.0 | % | $ | 2,625 | |||||||
First mortgage bonds | 2019-2038 | 5.9 | 375 | 5.6 | 500 | |||||||||||
Gas facility revenue bonds | 2022-2033 | 0.9 | 200 | 0.9 | 200 | |||||||||||
Medium-term notes | 2017-2027 | 7.8 | 181 | 7.8 | 181 | |||||||||||
Total principal long-term debt | 4.9 | % | $ | 3,211 | 4.9 | % | $ | 3,506 | ||||||||
Unamortized fair value adjustment of long-term debt (3) | 2016-2038 | n/a | 68 | n/a | 80 | |||||||||||
Unamortized debt premium, net | n/a | n/a | 16 | n/a | 16 | |||||||||||
Unamortized debt issuance costs | n/a | n/a | (20 | ) | n/a | (21 | ) | |||||||||
Total non-principal long-term debt | n/a | 64 | n/a | 75 | ||||||||||||
Total long-term debt - excluding current portion | $ | 3,275 | $ | 3,581 | ||||||||||||
Total debt | $ | 4,830 | $ | 4,956 |
(1) | Interest rates are calculated based on the daily weighted average balance outstanding for the years ended December 31, 2015 and 2014. |
(2) | As of December 31, 2015, the effective interest rates on our commercial paper borrowings were 0.7% for AGL Capital and 0.5% for Nicor Gas. |
(3) | See Note 5 herein for additional information on our fair value measurements. |
Year | Amount (in millions) | |||
2016 | $ | 545 | ||
2017 | 22 | |||
2018 | 155 | |||
2019 | 350 | |||
2020 | — | |||
Thereafter | 2,684 | |||
Total | $ | 3,756 |
AGL Resources | Nicor Gas | |||||||||||
2015 | 2014 | 2015 | 2014 | |||||||||
Debt covenants (1) | 54 | % | 55 | % | 56 | % | 62 | % |
(1) | As defined in our credit facilities, includes standby letters of credit and performance/surety bonds and excludes accumulated OCI items related to non-cash pension adjustments, welfare benefits liability adjustments and accounting for cash flow hedges. |
• | a maximum leverage ratio; |
• | insolvency events and/or nonpayment of scheduled principal or interest payments; |
• | acceleration of other financial obligations; and |
• | change of control provisions. |
In millions (1) | Cash flow hedges | Retirement benefit plans | Total | |||||||||
Balance at December 31, 2012 | $ | (3 | ) | $ | (215 | ) | $ | (218 | ) | |||
OCI, before reclassifications | 1 | 66 | 67 | |||||||||
Amounts reclassified from accumulated OCI | 3 | 12 | 15 | |||||||||
Balance at December 31, 2013 | 1 | (137 | ) | (136 | ) | |||||||
OCI, before reclassifications | (6 | ) | (71 | ) | (77 | ) | ||||||
Amounts reclassified from accumulated OCI | (1 | ) | 8 | 7 | ||||||||
Balance at December 31, 2014 | (6 | ) | (200 | ) | (206 | ) | ||||||
OCI, before reclassifications | — | — | — | |||||||||
Amounts reclassified from accumulated OCI | 8 | 12 | 20 | |||||||||
Balance at December 31, 2015 | $ | 2 | $ | (188 | ) | $ | (186 | ) |
(1) | All amounts are net of income taxes and noncontrolling interest. Amounts in parentheses indicate debits to accumulated other comprehensive loss. |
December 31, | ||||||||
In millions (1) | 2015 | 2014 | ||||||
Cash flow hedges | ||||||||
Cost of goods sold (natural gas contracts) | $ | (10 | ) | $ | 4 | |||
Operation and maintenance expense (natural gas contracts) | (1 | ) | 1 | |||||
Interest expense (interest rate contracts) | 2 | — | ||||||
Total before income tax | (9 | ) | 5 | |||||
Income tax | 1 | (2 | ) | |||||
Cash flow hedges, net of income tax | (8 | ) | 3 | |||||
Less noncontrolling interest | — | 2 | ||||||
Total cash flow hedges, net of income tax | (8 | ) | 1 | |||||
Retirement benefit plans | ||||||||
Operation and maintenance expense (actuarial losses) (2) | (22 | ) | (15 | ) | ||||
Operation and maintenance expense (prior service credits) (2) | 2 | 2 | ||||||
Total before income tax | (20 | ) | (13 | ) | ||||
Income tax | 8 | 5 | ||||||
Total retirement benefit plans, net of income tax | (12 | ) | (8 | ) | ||||
Total reclassification | $ | (20 | ) | $ | (7 | ) |
(1) | Amounts in parentheses indicate debits, or reductions, to our net income and credits to accumulated other comprehensive loss. Except for retirement benefit plan amounts, the net income impacts are immediate. |
(2) | Amortization of these accumulated other comprehensive loss components is included in the computation of net periodic benefit cost. See Note 7 for additional details about net periodic benefit cost. |
• | meter reading for SouthStar’s customers in Illinois and Georgia; |
• | maintenance and expansion of the natural gas infrastructure in Illinois and Georgia; and |
• | assignment of storage and transportation capacity used in delivering natural gas to SouthStar’s customers. |
• | guarantees of SouthStar’s activities with, and its credit exposure to, its counterparties and to certain natural gas suppliers in support of SouthStar’s payment obligations; and |
• | support of SouthStar’s daily cash management activities and assistance ensuring SouthStar has adequate liquidity and working capital resources by allowing SouthStar to utilize the AGL Capital commercial paper program for its liquidity and working capital requirements in accordance with our services agreement. |
• | accounting, information technology, legal, human resources, credit and internal controls services in accordance with our services agreement. |
2015 | 2014 | |||||||||||||||||||||
In millions | Consolidated | SouthStar | % | Consolidated | SouthStar | % | ||||||||||||||||
Current assets | $ | 2,115 | $ | 245 | 12 | % | $ | 2,886 | $ | 236 | 8 | % | ||||||||||
Goodwill and other intangible assets | 1,922 | 114 | 6 | 1,952 | 125 | 6 | ||||||||||||||||
Long-term assets and other deferred debits | 10,717 | 16 | — | 10,050 | 17 | — | ||||||||||||||||
Total assets | $ | 14,754 | $ | 375 | 3 | % | $ | 14,888 | $ | 378 | 3 | % | ||||||||||
Current liabilities | $ | 3,000 | $ | 54 | 2 | % | $ | 3,219 | $ | 71 | 2 | % | ||||||||||
Long-term liabilities and other deferred credits | 7,779 | — | — | 7,841 | — | — | ||||||||||||||||
Total liabilities | 10,779 | 54 | 1 | 11,060 | 71 | 1 | ||||||||||||||||
Equity | 3,975 | 321 | 8 | 3,828 | 307 | 8 | ||||||||||||||||
Total liabilities and equity | $ | 14,754 | $ | 375 | 3 | % | $ | 14,888 | $ | 378 | 3 | % |
In millions | 2015 | 2014 | ||||||
Operating revenues | $ | 711 | $ | 866 | ||||
Operating expenses | ||||||||
Cost of goods sold | 490 | 645 | ||||||
Operation and maintenance | 81 | 87 | ||||||
Depreciation and amortization | 10 | 11 | ||||||
Taxes other than income taxes | 1 | 1 | ||||||
Total operating expenses | 582 | 744 | ||||||
Operating income | $ | 129 | $ | 122 |
In millions | 2015 | 2014 | ||||||
Triton | $ | 49 | $ | 62 | ||||
Horizon Pipeline | 14 | 14 | ||||||
PennEast Pipeline | 9 | 1 | ||||||
Atlantic Coast Pipeline | 7 | 2 | ||||||
Other | 1 | 1 | ||||||
Total | $ | 80 | $ | 80 |
In millions | 2015 | 2014 | 2013 | |||||||||
Triton | $ | 4 | $ | 6 | $ | 9 | ||||||
Horizon Pipeline | 2 | 2 | 2 | |||||||||
Other | — | — | (8 | ) |
In millions | Total | 2016 | 2017 | 2018 | 2019 | 2020 | 2021 & thereafter | |||||||||||||||||||||
Recorded contractual obligations: | ||||||||||||||||||||||||||||
Long-term debt | $ | 3,756 | $ | 545 | $ | 22 | $ | 155 | $ | 350 | $ | — | $ | 2,684 | ||||||||||||||
Short-term debt | 1,010 | 1,010 | — | — | — | — | — | |||||||||||||||||||||
Environmental remediation liabilities (1) | 431 | 67 | 79 | 70 | 61 | 52 | 102 | |||||||||||||||||||||
Total | $ | 5,197 | $ | 1,622 | $ | 101 | $ | 225 | $ | 411 | $ | 52 | $ | 2,786 | ||||||||||||||
Unrecorded contractual obligations and commitments (2) (7): | ||||||||||||||||||||||||||||
Pipeline charges, storage capacity and gas supply (3) | $ | 5,007 | $ | 795 | $ | 536 | $ | 392 | $ | 370 | $ | 318 | $ | 2,596 | ||||||||||||||
Interest charges (4) | 2,418 | 181 | 158 | 156 | 151 | 133 | 1,639 | |||||||||||||||||||||
Operating leases (5) | 159 | 31 | 26 | 18 | 16 | 15 | 53 | |||||||||||||||||||||
Asset management agreements (6) | 28 | 11 | 9 | 6 | 2 | — | — | |||||||||||||||||||||
Standby letters of credit, performance/surety bonds (7) | 73 | 73 | — | — | — | — | — | |||||||||||||||||||||
Other | 5 | 3 | 1 | 1 | — | — | — | |||||||||||||||||||||
Total | $ | 7,690 | $ | 1,094 | $ | 730 | $ | 573 | $ | 539 | $ | 466 | $ | 4,288 |
(1) | Includes charges recoverable through base rates or rate rider mechanisms. |
(2) | In accordance with GAAP, these items are not reflected on our Consolidated Balance Sheets. |
(3) | Includes charges recoverable through a natural gas cost recovery mechanism or alternatively billed to marketers and demand charges associated with Sequent. The gas supply balance includes amounts for Nicor Gas and SouthStar gas commodity purchase commitments of 37 Bcf at floating gas prices calculated using forward natural gas prices as of December 31, 2015, and is valued at $76 million. As we do for certain of our affiliates, we provide guarantees to certain gas suppliers for SouthStar in support of payment obligations. |
(4) | Floating rate interest charges are calculated based on the interest rate as of December 31, 2015 and the maturity date of the underlying debt instrument. As of December 31, 2015, we have $49 million of accrued interest on our Consolidated Balance Sheets that will be paid in 2016. |
(5) | We have certain operating leases with provisions for step rent or escalation payments and certain lease concessions. We account for these leases by recognizing the future minimum lease payments on a straight-line basis over the respective minimum lease terms, in accordance with GAAP. However, this lease accounting treatment does not affect the future annual operating lease cash obligations as shown herein. Our operating leases are primarily for real estate. |
(6) | Represent fixed-fee minimum payments for Sequent’s affiliated asset management agreements. |
(7) | We provide guarantees to certain municipalities and other agencies and certain gas suppliers of SouthStar in support of payment obligations. |
In millions | 2015 | 2014 | 2013 | |||||||||
Current income taxes | ||||||||||||
Federal (1) | $ | (11 | ) | $ | 113 | $ | 164 | |||||
State | 10 | 38 | 35 | |||||||||
Deferred income taxes | ||||||||||||
Federal | 198 | 184 | (8 | ) | ||||||||
State | 18 | 17 | (11 | ) | ||||||||
Amortization of investment tax credits | (2 | ) | (2 | ) | (3 | ) | ||||||
Total income tax expense | $ | 213 | $ | 350 | $ | 177 |
(1) | We incurred an $11 million federal net operating loss in 2015, which will be carried back and fully utilized against prior year income tax. |
In millions | 2015 | 2014 | 2013 | |||||||||
Computed tax expense at statutory rate | $ | 205 | $ | 325 | $ | 165 | ||||||
State income tax, net of federal income tax benefit | 21 | 36 | 20 | |||||||||
Tax effect of net income attributable to the noncontrolling interest | (8 | ) | (7 | ) | (7 | ) | ||||||
Amortization of investment tax credits | (2 | ) | (2 | ) | (3 | ) | ||||||
Affordable housing credits | (1 | ) | (2 | ) | (2 | ) | ||||||
Flexible dividend deduction | (2 | ) | (2 | ) | (2 | ) | ||||||
Sale of Compass Energy | — | — | 6 | |||||||||
Other | — | 2 | — | |||||||||
Total income tax expense | $ | 213 | $ | 350 | $ | 177 |
As of December 31, | ||||||||
In millions | 2015 | 2014 | ||||||
Current accumulated deferred income tax liabilities | ||||||||
Mark-to-market | $ | 37 | $ | 33 | ||||
Inventory | 53 | 26 | ||||||
Total current accumulated deferred income tax liabilities | 90 | 59 | ||||||
Current accumulated deferred income tax assets | ||||||||
Compensation accruals | 30 | 30 | ||||||
Lower of cost or market | 6 | 26 | ||||||
Allowance for doubtful accounts | 8 | 12 | ||||||
Other | 19 | 21 | ||||||
Total current accumulated deferred income tax assets | 63 | 89 | ||||||
Valuation allowances (1) | (4 | ) | (6 | ) | ||||
Total current accumulated deferred income tax assets, net of valuation allowances | 59 | 83 | ||||||
Net current accumulated deferred income tax (liability) asset | $ | (31 | ) | $ | 24 | |||
Long-term accumulated deferred income tax liabilities | ||||||||
Property - accelerated depreciation and other property-related items | $ | 2,019 | $ | 1,801 | ||||
Investments in partnerships | 12 | 16 | ||||||
Acquisition intangibles | 12 | 14 | ||||||
Mark-to-market | 1 | 12 | ||||||
Other | 102 | 85 | ||||||
Total long-term accumulated deferred income tax liabilities | 2,146 | 1,928 | ||||||
Long-term accumulated deferred income tax assets | ||||||||
Unfunded pension and retiree welfare benefit obligation | 120 | 117 | ||||||
Deferred investment tax credits | 5 | 6 | ||||||
Other | 124 | 95 | ||||||
Total long-term accumulated deferred income tax assets | 249 | 218 | ||||||
Valuation allowances (1) | (15 | ) | (14 | ) | ||||
Total long-term accumulated deferred income tax assets, net of valuation allowances | 234 | 204 | ||||||
Net long-term accumulated deferred income tax liability | $ | 1,912 | $ | 1,724 |
(1) | The total valuation allowance in 2015 and 2014 is $19 million and $20 million, respectively. For 2015, the valuation allowance is related to our investment in Triton. For 2014, the total is composed of $1 million due to net operating losses in New Jersey of a former non-operating facility that are not allowed in New Jersey and $19 million related to our investment in Triton. New Jersey net operating losses expired in 2014, resulting in a reduction of the valuation allowance. |
2015 | ||||||||||||||||||||||||||||
In millions | Distribution operations | Retail operations | Wholesale services (1) | Midstream operations | Other | Intercompany eliminations | Consolidated | |||||||||||||||||||||
Operating revenues from external parties | $ | 2,880 | $ | 835 | $ | 202 | $ | 55 | $ | 11 | $ | (42 | ) | $ | 3,941 | |||||||||||||
Intercompany revenues | 169 | — | — | — | — | (169 | ) | — | ||||||||||||||||||||
Total operating revenues | 3,049 | 835 | 202 | 55 | 11 | (211 | ) | 3,941 | ||||||||||||||||||||
Operating expenses | ||||||||||||||||||||||||||||
Cost of goods sold | 1,291 | 518 | 19 | 19 | 4 | (206 | ) | 1,645 | ||||||||||||||||||||
Operation and maintenance | 687 | 137 | 67 | 25 | 3 | (5 | ) | 914 | ||||||||||||||||||||
Depreciation and amortization | 336 | 25 | 1 | 18 | 17 | — | 397 | |||||||||||||||||||||
Taxes other than income taxes | 164 | 3 | 3 | 5 | 6 | — | 181 | |||||||||||||||||||||
Merger-related expenses | — | — | — | — | 44 | — | 44 | |||||||||||||||||||||
Goodwill impairment | — | — | — | 14 | — | — | 14 | |||||||||||||||||||||
Total operating expenses | 2,478 | 683 | 90 | 81 | 74 | (211 | ) | 3,195 | ||||||||||||||||||||
Operating income (loss) | 571 | 152 | 112 | (26 | ) | (63 | ) | — | 746 | |||||||||||||||||||
Other income (expense) | 9 | — | (4 | ) | 3 | 5 | — | 13 | ||||||||||||||||||||
EBIT | $ | 580 | $ | 152 | $ | 108 | $ | (23 | ) | $ | (58 | ) | $ | — | $ | 759 | ||||||||||||
Total assets | $ | 12,517 | $ | 686 | $ | 935 | $ | 692 | $ | 9,664 | $ | (9,740 | ) | $ | 14,754 | |||||||||||||
Capital expenditures | $ | 957 | $ | 7 | $ | 2 | $ | 27 | $ | — | $ | 34 | $ | 1,027 |
2014 | ||||||||||||||||||||||||||||
In millions | Distribution operations | Retail operations | Wholesale services (1) | Midstream operations | Other | Intercompany eliminations | Consolidated | |||||||||||||||||||||
Operating revenues from external parties | $ | 3,802 | $ | 994 | $ | 578 | $ | 88 | $ | 7 | $ | (84 | ) | $ | 5,385 | |||||||||||||
Intercompany revenues | 199 | — | — | — | — | (199 | ) | — | ||||||||||||||||||||
Total operating revenues | 4,001 | 994 | 578 | 88 | 7 | (283 | ) | 5,385 | ||||||||||||||||||||
Operating expenses | ||||||||||||||||||||||||||||
Cost of goods sold | 2,223 | 683 | 77 | 57 | — | (275 | ) | 2,765 | ||||||||||||||||||||
Operation and maintenance | 699 | 147 | 75 | 26 | — | (8 | ) | 939 | ||||||||||||||||||||
Depreciation and amortization | 317 | 28 | 1 | 18 | 16 | — | 380 | |||||||||||||||||||||
Taxes other than income taxes | 189 | 4 | 3 | 6 | 6 | — | 208 | |||||||||||||||||||||
Total operating expenses | 3,428 | 862 | 156 | 107 | 22 | (283 | ) | 4,292 | ||||||||||||||||||||
Gain (loss) on disposition of assets | — | — | 3 | — | (1 | ) | — | 2 | ||||||||||||||||||||
Operating income (loss) | 573 | 132 | 425 | (19 | ) | (16 | ) | — | 1,095 | |||||||||||||||||||
Other income (expense) | 8 | — | (3 | ) | 2 | 7 | — | 14 | ||||||||||||||||||||
EBIT | $ | 581 | $ | 132 | $ | 422 | $ | (17 | ) | $ | (9 | ) | $ | — | $ | 1,109 | ||||||||||||
Total assets | $ | 12,037 | $ | 670 | $ | 1,402 | $ | 694 | $ | 9,706 | $ | (9,621 | ) | $ | 14,888 | |||||||||||||
Capital expenditures | $ | 715 | $ | 11 | $ | 2 | $ | 15 | $ | 26 | $ | — | $ | 769 |
2013 | ||||||||||||||||||||||||||||
In millions | Distribution operations | Retail operations | Wholesale services (1) | Midstream operations | Other | Intercompany eliminations | Consolidated | |||||||||||||||||||||
Operating revenues from external parties | $ | 3,230 | $ | 858 | $ | 60 | $ | 74 | $ | 8 | $ | (21 | ) | $ | 4,209 | |||||||||||||
Intercompany revenues | 182 | — | — | — | — | (182 | ) | — | ||||||||||||||||||||
Total operating revenues | 3,412 | 858 | 60 | 74 | 8 | (203 | ) | 4,209 | ||||||||||||||||||||
Operating expenses | ||||||||||||||||||||||||||||
Cost of goods sold | 1,687 | 564 | 21 | 33 | — | (195 | ) | 2,110 | ||||||||||||||||||||
Operation and maintenance | 687 | 132 | 49 | 24 | 3 | (8 | ) | 887 | ||||||||||||||||||||
Depreciation and amortization | 339 | 27 | 1 | 17 | 13 | — | 397 | |||||||||||||||||||||
Taxes other than income taxes | 167 | 3 | 3 | 5 | 9 | — | 187 | |||||||||||||||||||||
Total operating expenses | 2,880 | 726 | 74 | 79 | 25 | (203 | ) | 3,581 | ||||||||||||||||||||
Gain on disposition of assets | — | — | 11 | — | — | — | 11 | |||||||||||||||||||||
Operating income (loss) | 532 | 132 | (3 | ) | (5 | ) | (17 | ) | — | 639 | ||||||||||||||||||
Other income (expense) | 14 | — | — | (5 | ) | 7 | — | 16 | ||||||||||||||||||||
EBIT | $ | 546 | $ | 132 | $ | (3 | ) | $ | (10 | ) | $ | (10 | ) | $ | — | $ | 655 | |||||||||||
Total assets (2) | $ | 11,629 | $ | 685 | $ | 1,163 | $ | 713 | $ | 10,426 | $ | (10,088 | ) | $ | 14,528 | |||||||||||||
Capital expenditures | $ | 684 | $ | 9 | $ | 2 | $ | 12 | $ | 24 | $ | — | $ | 731 |
(1) | The revenues for wholesale services are netted with costs associated with its energy and risk management activities. A reconciliation of our operating revenues and our intercompany revenues for the years ended December 31, are shown in the following table. Wholesale services 2014 operating revenues are related to colder-than-normal weather and extreme volatility and are not indicative of future performance. |
In millions | Third party gross revenues | Intercompany revenues | Total gross revenues | Less gross gas costs | Operating revenues | ||||||||||||
2015 | $ | 6,286 | 408 | 6,694 | 6,492 | $ | 202 | ||||||||||
2014 | $ | 10,709 | 718 | 11,427 | 10,849 | $ | 578 | ||||||||||
2013 | $ | 7,681 | 417 | 8,098 | 8,038 | $ | 60 |
(2) | Total assets reported as of December 31, 2013 exclude assets held for sale. |
In millions | 2014 | 2013 | ||||||
Operating revenues | $ | 243 | $ | 365 | ||||
Operating expenses | ||||||||
Cost of goods sold | 149 | 222 | ||||||
Operation and maintenance (1) | 75 | 110 | ||||||
Depreciation and amortization (2) | 5 | 19 | ||||||
Taxes other than income taxes | 5 | 6 | ||||||
Loss on sale and goodwill impairment (3) | 28 | — | ||||||
Total operating expenses | 262 | 357 | ||||||
Operating (loss) income | (19 | ) | 8 | |||||
(Loss) income before income taxes | (19 | ) | 8 | |||||
Income tax expense (4) | (61 | ) | (3 | ) | ||||
(Loss) income from discontinued operations, net of tax | $ | (80 | ) | $ | 5 |
(1) | Includes $1 million for another business not related to Tropical Shipping that we discontinued in 2014 and was included in our other segment. |
(2) | We ceased depreciating and amortizing Tropical Shipping’s assets on April 4, 2014. |
(3) | Primarily relates to the suspension of depreciation and amortization during 2014 totaling $7 million, and $19 million of goodwill attributable to Tropical Shipping that was impaired as of March 31, 2014, based on the negotiated sales price. |
(4) | Includes $60 million that was recorded in 2014 related to the cumulative foreign earnings for which no tax liabilities had been previously recorded. |
In millions, except per share amounts | March 31 | June 30 | September 30 | December 31 | ||||||||||||
2015 | ||||||||||||||||
Operating revenues | $ | 1,721 | $ | 674 | $ | 584 | $ | 962 | ||||||||
Operating income | 364 | 107 | 59 | 216 | ||||||||||||
EBIT | 367 | 111 | 61 | 220 | ||||||||||||
Net income | 205 | 44 | 12 | 112 | ||||||||||||
Net income attributable to AGL Resources | 193 | 42 | 11 | 107 | ||||||||||||
Basic earnings (loss) per common share | 1.62 | 0.35 | 0.09 | 0.89 | ||||||||||||
Diluted earnings (loss) per common share | 1.62 | 0.35 | 0.09 | 0.89 | ||||||||||||
2014 | ||||||||||||||||
Operating revenues | $ | 2,462 | $ | 889 | $ | 589 | $ | 1,445 | ||||||||
Operating income | 592 | 139 | 78 | 286 | ||||||||||||
EBIT | 595 | 141 | 81 | 292 | ||||||||||||
Income from continuing operations | 346 | 59 | 23 | 152 | ||||||||||||
Income from continuing operations attributable to AGL Resources | 334 | 57 | 23 | 148 | ||||||||||||
(Loss) income from discontinued operations, net of tax | (50 | ) | 1 | (31 | ) | — | ||||||||||
Net income (loss) attributable to AGL Resources | 284 | 58 | (8 | ) | 148 | |||||||||||
Basic earnings (loss) per common share: | ||||||||||||||||
Continuing operations | 2.82 | 0.48 | 0.19 | 1.24 | ||||||||||||
Discontinued operations | (0.43 | ) | 0.01 | (0.25 | ) | — | ||||||||||
Diluted earnings (loss) per common share: | ||||||||||||||||
Continuing operations | 2.81 | 0.48 | 0.19 | 1.24 | ||||||||||||
Discontinued operations | (0.43 | ) | 0.01 | (0.25 | ) | — |
Name, age and position with the company | Periods served |
Andrew W. Evans, Age 49 | |
President and Chief Executive Officer | January 2016 - Present |
President and Chief Operating Officer | May 2015 - December 2015 |
Executive Vice President and Chief Financial Officer | May 2006 - May 2015 |
Elizabeth W. Reese, Age 47 | |
Executive Vice President and Chief Financial Officer | May 2015 - Present |
Senior Vice President and President of Nicor Gas | June 2012 - May 2015 |
Senior Vice President and President of Retail Services | December 2011 - June 2012 |
Vice President, Operational Planning and Analysis | June 2010 - December 2011 |
Vice President, Finance | July 2007 - June 2010 |
Henry P. Linginfelter, Age 55 | |
Executive Vice President, Distribution Operations | December 2011 - Present |
Executive Vice President, Utility Operations | June 2007 - December 2011 |
Melanie M. Platt, Age 61 | |
Executive Vice President, Chief People Officer | December 2011 - Present |
Senior Vice President, Human Resources and Marketing Communications | November 2008 - December 2011 |
Paul R. Shlanta, Age 58 | |
Executive Vice President, General Counsel and Chief Ethics and Compliance Officer | September 2005 - Present |
Peter I. Tumminello, Age 53 | |
Executive Vice President, Nonregulated Businesses and President Sequent | May 2015 - Present |
Executive Vice President, Wholesale Services, and President Sequent | December 2011 - May 2015 |
President Sequent | April 2010 - December 2011 |
2015 Non-Employee Director Compensation | ||||||||||||||||
Name | Fees Earned or Paid in Cash | Stock Awards (1) | All Other Compensation | Total | ||||||||||||
Sandra N. Bane (2)(3) | $ | 110,000 | $ | 105,000 | $ | — | $ | 215,000 | ||||||||
Thomas D. Bell, Jr. (2) | 110,000 | 105,000 | — | 215,000 | ||||||||||||
Norman R. Bobins | 95,000 | 105,000 | — | 200,000 | ||||||||||||
Charles R. Crisp (2) | 110,000 | 105,000 | — | 215,000 | ||||||||||||
Brenda J. Gaines | 95,000 | 105,000 | — | 200,000 | ||||||||||||
Arthur E. Johnson (3) | 95,000 | 105,000 | — | 200,000 | ||||||||||||
Wyck A. Knox, Jr. | 95,000 | 105,000 | — | 200,000 | ||||||||||||
Dennis M. Love (4) | 95,000 | 105,000 | — | 200,000 | ||||||||||||
Dean R. O’Hare | 95,000 | 105,000 | — | 200,000 | ||||||||||||
Armando J. Olivera (3) | 95,000 | 105,000 | — | 200,000 | ||||||||||||
John E. Rau (2)(4)(5) | 110,000 | 105,000 | — | 215,000 | ||||||||||||
James A. Rubright (2)(6) | 135,000 | 105,000 | — | 240,000 | ||||||||||||
Bettina M. Whyte (3)(7) | 95,000 | 105,000 | — | 200,000 | ||||||||||||
Henry C. Wolf (4) | 95,000 | 105,000 | — | 200,000 |
(1) | The aggregate grant date fair value of stock awards, which includes shares of our common stock and common stock equivalents, was computed in accordance with FASB ASC Topic 718 without regard to estimated forfeitures related to service-based vesting conditions. The assumptions used in calculating these amounts are incorporated by reference to Note 8 to our consolidated financial statements under Item 8 herein. |
(2) | Fees earned include a committee chair retainer of $15,000. |
(3) | This director elected to defer the Equity Portion of the annual retainer under the Common Stock Equivalent Plan. |
(4) | This director elected to receive the Cash Portion of the annual retainer in the form of stock. |
(5) | This director elected to receive the committee chair retainer in the form of stock. |
(6) | Fees earned include a lead director retainer of $25,000. |
(7) | This director elected to defer $20,000 of the Cash Portion under the Common Stock Equivalent Plan. |
Name | Shares Outstanding | Common Stock Equivalents Outstanding (1) | Total Stock Awards Outstanding (1) | ||||
Sandra N. Bane | 3,410 | 17,302 | 20,712 | ||||
Thomas D. Bell, Jr. | 32,558 | — | 32,558 | ||||
Norman R. Bobins | 12,565 | — | 12,565 | ||||
Charles R. Crisp | 16,739 | 14,589 | 31,328 | ||||
Brenda J. Gaines | 12,510 | — | 12,510 | ||||
Arthur E. Johnson | 4,338 | 52,113 | 56,451 | ||||
Wyck A. Knox, Jr. | 14,193 | 48,159 | 62,352 | ||||
Dennis M. Love | 41,937 | 42,169 | 84,106 | ||||
Dean R. O’Hare | 22,572 | 931 | 23,503 | ||||
Armando J. Olivera | 1,875 | 14,466 | 16,341 | ||||
John E. Rau | 25,080 | — | 25,080 | ||||
James A. Rubright | 22,235 | 26,230 | 48,465 | ||||
Bettina M. Whyte | 14,782 | 21,204 | 35,986 | ||||
Henry C. Wolf | 31,031 | 13,309 | 44,340 |
(1) | Includes dividend equivalents. |
Name | Title | |
John W. Somerhalder II | Former Chairman and Chief Executive Officer | |
Andrew W. Evans | President and Chief Executive Officer | |
Elizabeth W. Reese | Executive Vice President and Chief Financial Officer | |
Henry P. Linginfelter | Executive Vice President, Distribution Operations | |
Paul R. Shlanta | Executive Vice President, General Counsel and Chief Ethics and Compliance Officer | |
Peter I. Tumminello | Executive Vice President, Nonregulated Businesses and President Sequent |
• | align executives’ interests with those of our shareholders by creating a strong focus on stock ownership and basing pay on performance measures that are expected to drive long-term, sustained shareholder value growth; |
• | include a strong link between pay and performance by placing a significant portion of compensation “at risk” based on corporate and business segment performance; |
• | assure our access to top executive talent and protect against competitor recruitment through compensation opportunities that are market competitive and commensurate with the executives’ responsibilities, experience and demonstrated performance; and |
• | reinforce our business strategies and reflect our core values by rewarding desired performance, promoting desired competencies and recognizing contributions to business success that are consistent with those core values. |
• | Corporate Plan EPS (described under the caption "Annual Incentive Awards - Corporate Measure"), |
• | EBIT, safety and customer service metrics for our regulated business segment (distribution operations) (described under the caption "Annual Incentive Awards - Business Segment Measures"), and |
• | EBITDA metrics for our non-regulated business segments (described under the caption "Annual Incentive Awards - Business Segment Measures"). |
• | Effective February 23, 2015, base salaries were increased by 3% for each of the named executive officers, which was consistent with increases for other salaried employees. |
• | The financial measure for our distribution operations business segment was changed from margin (weighted at 20%) to EBIT (weighted at 36%). The Compensation Committee considers EBIT to be more closely correlated to distribution operations’ achievement of its allowed return and to the manner in which the business segment is managed, by focusing on customer margins, operations and maintenance expense, and depreciation (including capital deployment management). |
• | The performance measure relating to operations and maintenance expense less benefits and incentives for each named executive officer was eliminated because expense management is incorporated in the new EBIT measure. The Compensation Committee also believes that focus on EBIT aligns the goals more closely to the performance of the business segment. |
• | Mr. Evans’ base salary was increased to $700,000, with a target annual cash incentive of 80% of base salary and a target long-term incentive award opportunity of $1,750,000. |
• | Ms. Reese’s base salary was increased to $440,000, with a target annual cash incentive of 65% of base salary and a long-term incentive award opportunity of 160% of base salary. |
• | Mr. Tumminello’s base salary was increased to $430,000, his annual cash incentive remained unchanged and linked to Sequent’s Plan Earnings, with a smaller component based on the performance of midstream operations (storage and fuels), and his long-term incentive award opportunity remained unchanged at 75% of base salary. |
• | We do not provide excessive executive perquisites or extraordinary relocation benefits to our named executive officers. |
• | We do not provide tax gross-ups on compensation paid to our named executive officers, or on “golden parachute” excise taxes. |
• | Our Omnibus Performance Incentive Plan (OPIP) has double-trigger vesting for equity awards in the context of a change in control if the awards are assumed by the acquiring company. |
• | Our OPIP expressly prohibits repricing of options (directly or indirectly) without prior shareholder approval. |
• | The Compensation Committee engages an independent compensation consultant. |
• | Our stock ownership policy requires that each executive must retain at least 75% of net shares from his or her equity awards until the ownership requirement is met. |
• | Our policy prohibits directors and executive officers from engaging in hedging activities involving our stock. |
• | Our policy requires the recovery of certain incentive-based compensation paid to current or former executive officers in the event of an accounting restatement. |
Parties | Roles and Responsibilities | |
Compensation Committee | • | Approves incentive programs and sets performance goals. |
• | Determines appropriate levels of compensation for our executives, other than our chief executive officer. | |
• | Recommends to independent Board members compensation opportunities and awards for our chief executive officer. | |
FW Cook | • | Provides a competitive assessment of our executives’ compensation levels and programs. |
• | Provides advice, research and analytical services on a variety of subjects, including compensation trends, best practices, peer group comparisons and the compensation of our non-employee directors. | |
Independent directors on full Board | • | Evaluates chief executive officer performance. |
• | Approves compensation for our chief executive officer. | |
Chief executive officer | • | Develops an assessment of individual performance for each other named executive officer. |
• | Provides recommendations to the Compensation Committee regarding individual compensation levels for such executives. | |
• | Provides recommendations to the Compensation Committee regarding goals for the performance measures in the incentive plans. | |
Other members of management | • | Our human resources staff provides data and information relating to our compensation programs to the Compensation Committee and FW Cook to help facilitate the Compensation Committee’s review of competitive compensation practices. |
• | Our chief financial officer provides the Compensation Committee with reports on financial performance as it relates to key business drivers and performance measures included in incentive program designs. |
Size Requirements | Industry Requirements | ||
Must be roughly one-third to three times our size in at least two of the following categories: | Must be a traditional natural gas local distribution company and must meet at least one of the following: | ||
• | assets; | • | includes non-regulated businesses such as storage, pipeline or construction services; |
• | revenue; or | • | includes asset management/trading business similar to Sequent; or |
• | market capitalization | • | conducts business in three or more states |
(1) | At the time the peer group was approved, Laclede and Piedmont did not meet all three size requirements, but the Compensation Committee decided to include these companies due to overall similarities in business characteristics with us. |
Compensation Element | Overview/Objectives | |
Base salary | • | Fixed portion of an executive’s annual compensation; is intended to recognize fundamental market value for the skills and experience of the individual relative to the responsibilities of his or her position. |
• | Foundation of our program; most other elements are determined as a percentage of base salary. | |
Annual incentive award (1) | • | Annual cash incentive award is intended to vary as a direct reflection of corporate and business segment performance. |
• | Target opportunities are a percentage of base salary and represent the amount of money to be paid if expected performance is achieved. | |
• | Achievement of a performance hurdle based on Plan EPS is required for any payout. | |
• | Performance measures include Plan EPS for corporate performance and a combination of EBIT and safety and customer service measures for business segment performance. | |
• | Payouts are subject to reduction pursuant to an affordability factor based on the performance of distribution operations against an EBIT target. | |
• | Actual awards may range between 0% and 200% of target, based on performance against goals. | |
• | To achieve a 200% award, performance must meet or exceed the maximum performance levels for all performance measures, including the affordability factor. | |
Long-term incentive awards (RSUs and PSUs) | • | Stock-based incentives reward performance over a multi-year period, link executives’ interests to those of shareholders, and encourage retention. |
• | Performance measures include EBITDA achievement for performance-based RSU's and, for PSUs, Cumulative Core EPS and total shareholder return relative to the performance of the executive compensation peer group, over a three-year period. | |
• | Vesting schedules serve to encourage retention and further tie an executive’s compensation to stock price appreciation during the vesting period. | |
Employee health and welfare and retirement benefit plans | • | Competitive levels of medical, retirement and income protection, such as life and disability insurance coverage, are provided. |
• | Executives participate in the same programs offered to all of our eligible employees. | |
• | To maintain consistent retirement benefit levels, we also provide non-qualified retirement benefits to executives and other highly-compensated employees who are adversely affected by tax limits imposed on contributions and total benefits under our retirement plans. | |
Severance and other termination payments | • | Severance benefits are provided in the event an executive’s employment is terminated in certain circumstances in connection with a change in control. |
• | Agreements provide security to executives so that they may focus on business objectives and the best interests of our shareholders during a transaction or potential transaction. | |
Financial planning / tax return preparation perquisite | • | We reimburse executives for up to $18,000 per year for tax return preparation. We require professional tax return preparation as a means of ensuring tax compliance by our executives. To the extent that the entire amount is not used for tax preparation, the remainder may be applied to financial or estate planning. |
(1) | Mr. Tumminello’s incentive program is described under the caption "Annual Incentive Award for Mr. Tumminello." |
Fiscal 2015 Target Compensation Elements | ||||||||||||
Name | Base Salary | Target Annual Incentive ($ or % of Base Salary) | Target Long-Term Incentive ($ or % of Base Salary) | |||||||||
John W. Somerhalder II | $ | 1,004,216 | 110 | % | $ | 3,500,000 | ||||||
Andrew W. Evans | 700,000 | 65%/80% (prorated) | 184%/$1,750,000 (prorated) | |||||||||
Elizabeth W. Reese | 440,000 | 45%/65% (prorated) | 65%/160% (prorated) | |||||||||
Henry P. Linginfelter | 563,705 | 65 | % | 160 | % | |||||||
Paul R. Shlanta | 462,617 | 55 | % | 120 | % | |||||||
Peter I. Tumminello | 430,000 | $ | 537,500 | 75 | % |
• | 60% corporate performance, measured by Plan EPS and described below; and |
• | 40% business segment performance, measured as described below. |
• | the effect of non-cash losses, including asset or goodwill impairment charges and loss on the sale of assets or subsidiaries; |
• | transaction costs associated with business combinations and related integration costs; |
• | changes in estimates or adjustments to actual settlement amounts equal to $100,000 or more related to legal issues existing at and prior to the closing date of an acquisition; and |
• | adjustments resulting from changes in GAAP. |
• | was based on an amount equal to $2.76 per share for 2015, consistent with the 2015 consolidated EPS budget approved by the Board, plus an adjustment to add $0.28 of expected EPS value to be generated by Sequent during 2015; |
• | was expected to be an appropriate target when considering our 2015 business objectives; and |
• | took into consideration the anticipated volatility and treatment of earnings from Sequent. |
2015 Corporate Measure - Goals and Results | |||||||||||||||||
Performance Hurdle 162(m) Qualifier | Threshold (50%) | Target (100%) | 150% | Maximum (200%) | Actual Plan EPS | ||||||||||||
GAAP EPS (1) | $2.56 | $2.66 | $2.76 | $2.86 | $2.96 | $2.94 | |||||||||||
Adjusted for the net economic value generated by wholesale services to be recognized on a GAAP basis in future periods | 0.28 | 0.28 | 0.28 | 0.28 | 0.28 | 0.20 | |||||||||||
Adjusted for goodwill impairment, merger-related expenses and change in a pre-Nicor acquisition legal reserve | — | — | — | — | — | 0.30 | |||||||||||
Plan EPS | $2.84 | $2.94 | $3.04 | $3.14 | $3.24 | $3.44 |
(1) | Diluted EPS from continuing operations attributable to AGL Resources Inc. |
Regulated | Non-Regulated | |
Distribution operations | Wholesale services | |
Retail operations | ||
Midstream operations |
2015 Business Performance Measure - Goals and Weightings | ||||||||
Name | Regulated Segment (Distribution Operations) (1) | Non-Regulated Segments (2) | Total | |||||
John W. Somerhalder II | 75 | % | 25% | 100% | ||||
Andrew W. Evans | 75 | % | 25% | 100% | ||||
Elizabeth W. Reese | 75 | % | 25% | 100% | ||||
Henry P. Linginfelter | 100 | % | — | 100% | ||||
Paul R. Shlanta | 75 | % | 25% | 100% |
(1) | Performance for the regulated segment was based on composite results. |
(2) | Performance for the non-regulated segments was weighted as follows: |
Non-Regulated Business Segment Weightings | ||
Wholesale services | 45% | |
Retail operations | 45% | |
Midstream operations | 10% |
Distribution Operations Performance (EBIT) - Affordability Factor | ||||||||
EBIT | < $535 million | $535 million | $555 million | $575 million | ||||
Affordability Factor (level of funding) | — | 50% | 75% | 100% |
Business Performance Score Achieved | Payout % (1) | |||
Minimum | 50% | 0% | ||
60% | 20% | |||
70% | 40% | |||
80% | 60% | |||
90% | 80% | |||
Target | 100% | 100% | ||
110% | 120% | |||
120% | 140% | |||
130% | 160% | |||
140% | 180% | |||
Maximum | 150% | 200% |
(1) | As noted above, the final payout amount for the business performance component for each named executive officer, other than Mr. Tumminello, was conditioned on the $2.84 Plan EPS performance hurdle being met and was subject to the affordability factor based on EBIT of distribution operations. |
2015 Annual Incentive Award - Composite Performance and Results | ||||||||||||
Name | Corporate Payout Percentage (60% weighting) | Business Segment Payout Percentage (40% weighting) | Total Payout Percentage | 2015 Target Opportunity (% of Base Salary) | 2015 Annual Incentive Payout | |||||||
John W. Somerhalder II | 200% | 160.77% | 184.3% | 110% | $ | 2,024,521 | ||||||
Andrew W. Evans (1) | 200% | 160.77% | 184.3% | 80% | $ | 895,370 | ||||||
Elizabeth W. Reese (2) | 200% | 160.80% | 183.3% | 65% | $ | 420,659 | ||||||
Henry P. Linginfelter | 200% | 160.90% | 184.4% | 65% | $ | 671,721 | ||||||
Paul R. Shlanta | 200% | 160.77% | 184.3% | 55% | $ | 466,323 |
(1) | The annual incentive award for Mr. Evans was prorated between a target of 65% for his prior position as executive vice president and chief financial officer and a target of 80% for his position as president and chief operating officer. |
(2) | The annual incentive award for Ms. Reese was prorated between a target of 45% for her prior position as president of Nicor Gas and a target of 65% for her position as executive vice president and chief financial officer. In Ms. Reese’s prior position, there was also an individual performance component (weighted at 15%), in addition to the corporate component (weighted at 50%) and the business performance component (weighted at 35%). |
2015 Annual Incentive Award for Mr. Tumminello - Composite Performance and Results | |||
8.125% of Sequent Pool | $1,728,887 | ||
Individual Performance | 265,983 | ||
Midstream Operations Performance (Storage and Fuels Component) | 100,000 | ||
Total Incentive Award | $2,094,870 |
• | the impact each type of award has on shareholder value creation and executive motivation and retention; |
• | competitive practice; and |
• | balancing the cost of equity awards and the projected impact on shareholder dilution. |
Performance Threshold (Corporate EBITDA) | Actual Result (Corporate EBITDA Achieved) | |
$911 million | $1.16 billion |
TSR Rank | Percentile Rank | Shares Earned as % of Target Shares (75% Weighting) | ||||
1 | 100% | 200% | Maximum | |||
2 | 92% | 184% | ||||
3 | 83% | 166% | ||||
4 | 75% | 150% | ||||
5 | 67% | 134% | ||||
6 | 58% | 116% | ||||
7 | 50% | 100% | Target | |||
8 | 42% | 84% | ||||
9 | 33% | 66% | ||||
10 | 25% | 50% | Threshold | |||
>10 | 0% | 0% |
Performance | Cumulative Core EPS Performance | Shares Earned as % of Target Shares (25% Weighting) | ||
Threshold (2% CAGR) | $7.84 | 50% | ||
Target (5.7% CAGR) | $8.30 | 100% | ||
Maximum (8% CAGR) | $8.80 | 200% |
Payout of 2013 PSUs (2013-2015 Performance Period) | ||||||
Name | Number of Shares | Cash Payout | ||||
John W. Somerhalder II | 40,847 | $ | 2,636,201 | |||
Andrew W. Evans | 10,150 | 655,081 | ||||
Elizabeth W. Reese | 2,212 | 142,698 | ||||
Henry P. Linginfelter | 9,926 | 640,560 | ||||
Paul R. Shlanta | 6,286 | 405,698 | ||||
Peter I. Tumminello | 3,205 | 206,786 |
• | Effective January 1, 2016, Mr. Evans received a base pay increase to $800,000, in recognition of his new position as president and chief executive officer. |
• | Effective February 22, 2016, base salaries will be increased by 3% for each of the remaining named executive officers. |
• | The PSUs granted in 2016 will have one metric: Cumulative Core EPS, which will be measured over a three-year performance period. |
Summary Compensation Table | |||||||||||||||||||||||||
Name and Principal Position | Year | Salary (1) | Bonus | Stock Awards (3) | Option Awards | Non-Equity Incentive Plan Compensation(4) | Change in Pension Value and Nonqualified Deferred Compensation Earnings (5) | All Other Compensation (6) | Total | ||||||||||||||||
John W. Somerhalder II | 2015 | $ | 1,037,215 | $ | — | $ | 4,593,217 | $ | — | $ | 2,024,521 | $ | 1,519,154 | $ | 136,515 | $ | 9,310,622 | ||||||||
Former Chairman and Chief Executive Officer | 2014 | 969,506 | — | 4,372,269 | — | 1,352,563 | 970,956 | 159,041 | 7,824,335 | ||||||||||||||||
2013 | 931,725 | — | 3,671,374 | — | 1,921,067 | — | 64,050 | 6,588,216 | |||||||||||||||||
Andrew W. Evans | 2015 | 675,136 | — | 1,962,397 | — | 895,370 | 38,664 | 67,283 | 3,638,850 | ||||||||||||||||
President and Chief Executive Officer | 2014 | 553,349 | — | 1,286,041 | — | 462,102 | 351,600 | 75,687 | 2,728,779 | ||||||||||||||||
2013 | 517,524 | — | 912,260 | — | 632,932 | — | 40,482 | 2,103,198 | |||||||||||||||||
Elizabeth W. Reese | |||||||||||||||||||||||||
Executive Vice President and Chief Financial Officer | 2015 | 410,903 | — | 697,896 | — | 420,659 | 23,922 | 108,037 | 1,661,417 | ||||||||||||||||
Henry P. Linginfelter | 2015 | 582,229 | — | 1,149,475 | — | 671,721 | 47,834 | 70,994 | 2,522,253 | ||||||||||||||||
Executive Vice President, Distribution Operations | 2014 | 541,329 | — | 1,094,114 | — | 594,383 | 449,150 | 71,654 | 2,750,630 | ||||||||||||||||
2013 | 508,211 | — | 892,180 | — | 617,334 | — | 39,356 | 2,057,081 | |||||||||||||||||
Paul R. Shlanta | 2015 | 477,819 | — | 707,577 | — | 466,323 | 50,055 | 65,491 | 1,767,265 | ||||||||||||||||
Executive Vice President, General Counsel and Chief Ethics and Compliance Officer | 2014 | 446,627 | — | 673,292 | — | 435,470 | 363,058 | 64,234 | 1,982,681 | ||||||||||||||||
2013 | 424,917 | — | 565,129 | — | 442,494 | — | 39,475 | 1,472,015 | |||||||||||||||||
Peter I. Tumminello | 2015 | 423,631 | — | 692,317 | — | 2,094,870 | 271,968 | 143,554 | 3,626,340 | ||||||||||||||||
Executive Vice President, Nonregulated Businesses | 2014 | 363,961 | — | 343,157 | — | 3,550,000 | 297,880 | 58,092 | 4,613,090 | ||||||||||||||||
2013 | 349,777 | 200,000 (2) | 488,412 | — | 798,076 | — | 45,560 | 1,881,825 |
(1) | For each of the named executive officers, includes earnings that were eligible for deferral, at the election of the named executive officer, under our Retirement Savings Plus Plan and Nonqualified Savings Plan. |
(2) | Reflects the cash portion of a special award granted to Mr. Tumminello in connection with the sale of Compass Energy in 2013. |
(3) | Reflects the aggregate grant date fair value of stock awards, which was computed in accordance with FASB ASC Topic 718 without regard to estimated forfeitures related to service-based vesting conditions. The assumptions used in calculating these amounts are discussed in Note 8 to our consolidated financial statements under Item 8 herein. The grant date fair value of the restricted stock units granted in 2015 was determined by reference to the closing price of the shares on the grant date. The grant date fair value of the performance unit awards granted in 2015 was computed by multiplying (i) the target number of units awarded to each named executive officer, which was the assumed probable outcome as of the grant date, by (ii) the closing price of the underlying shares on the grant date. Assuming, instead, that the highest level of performance conditions would be achieved, the grant date fair values of these performance unit awards would have been $7,099,501 for Mr. Somerhalder, $3,030,975 for Mr. Evans, $1,077,113 for Ms. Reese, $1,776,470 for Mr. Linginfelter, $1,093,703 for Mr. Shlanta and $1,069,456 for Mr. Tumminello. |
(4) | Reflects annual incentive compensation earned under our annual incentive plan (or Mr. Tumminello’s annual incentive arrangement). |
(5) | Reflects the aggregate change in the actuarial present value of the named executive officer’s accumulated benefit under the Retirement Plan, which we refer to as the Pension Plan, and the Excess Plan, both of which are defined benefit plans, and, in addition, for Mr. Somerhalder, under the terms set forth in an individual agreement. None of the named executive officers received any interest on deferred compensation at an above-market rate of interest. |
(6) | The following table reflects the items that are included in the “All Other Compensation” column for 2015. |
All Other Compensation Detail | ||||||||||||||||||||
Name | Our Contributions to the Retirement Savings Plus Plan (1) | Our Contributions to the Nonqualified Savings Plan (1) | Perquisites (2) | Other Income (3) | Total All Other Compensation | |||||||||||||||
John W. Somerhalder II | $ | 13,780 | $ | 108,735 | $ | 14,000 | $ | — | $ | 136,515 | ||||||||||
Andrew W. Evans | 11,700 | 41,583 | 14,000 | — | 67,283 | |||||||||||||||
Elizabeth W. Reese | 11,700 | 22,055 | 14,000 | 60,282 | 108,037 | |||||||||||||||
Henry P. Linginfelter | 13,780 | 47,404 | 9,810 | — | 70,994 | |||||||||||||||
Paul R. Shlanta | 13,780 | 33,711 | 18,000 | — | 65,491 | |||||||||||||||
Peter I. Tumminello | 13,780 | 115,774 | 14,000 | — | 143,554 |
(1) | Amounts of matching contributions contributed by us to the Retirement Savings Plus Plan and Nonqualified Savings Plan are calculated on the same basis for all plan participants in the relevant plan, including the named executive officers. |
(2) | Reflects our incurred cost in connection with tax return preparation, financial and estate planning benefits. |
(3) | In conjunction with her appointment to executive vice president and chief financial officer, Ms. Reese received relocation benefits that were consistent with our relocation policy. |
2015 Grants of Plan-Based Awards | ||||||||||||||||||||
Name | Estimated Future Payouts Under Non-Equity Incentive Plan Awards (1)(2) | Estimated Future Payouts Under Equity Incentive Plan Awards | Grant Date Fair Value of Stock and Option Awards (5) | |||||||||||||||||
Grant Date | Approval Date | Threshold | Target | Maximum | Threshold | Target | Maximum | |||||||||||||
John W. Somerhalder II | 02/11/15 | 02/11/15 | $ | — | $ | 1,104,638 | $ | 2,209,275 | — | — | — | $ | — | |||||||
02/17/15 (3) | 02/11/15 | — | — | — | 27,815 | 55,630 | 111,260 | 3,549,750 | ||||||||||||
02/17/15 (4) | 02/11/15 | — | — | — | — | 20,970 | — | 1,043,467 | ||||||||||||
Andrew W. Evans | 02/11/15 | 02/11/15 | — | 497,501 | 995,002 | — | — | — | — | |||||||||||
02/17/15 (3) | 02/11/15 | — | — | — | 8,180 | 16,360 | 32,720 | 1,043,932 | ||||||||||||
02/17/15 (4) | 02/11/15 | — | — | — | — | 6,170 | — | 307,019 | ||||||||||||
05/28/15 (3) | 05/28/15 | — | — | — | 3,695 | 7,390 | 14,780 | 471,556 | ||||||||||||
05/28/15 (4) | 05/28/15 | — | — | — | — | 2,780 | — | 139,890 | ||||||||||||
Elizabeth W. Reese | 02/11/15 | 02/11/15 | — | 240,176 | 480,352 | — | — | — | — | |||||||||||
02/17/15 (3) | 02/11/15 | — | — | — | 1,610 | 3,220 | 6,440 | 205,468 | ||||||||||||
02/17/15 (4) | 02/11/15 | — | — | — | — | 1,210 | — | 60,210 | ||||||||||||
05/28/15 (3) | 05/28/15 | — | — | — | 2,610 | 5,220 | 10,440 | 333,088 | ||||||||||||
05/28/15 (4) | 05/28/15 | — | — | — | — | 1,970 | — | 99,130 | ||||||||||||
Henry P. Linginfelter | 02/11/15 | 02/11/15 | — | 366,408 | 732,817 | — | — | — | — | |||||||||||
02/17/15 (3) | 02/11/15 | — | — | — | 6,960 | 13,920 | 27,840 | 888,235 | ||||||||||||
02/17/15 (4) | 02/11/15 | — | — | — | — | 5,250 | — | 261,240 | ||||||||||||
Paul R. Shlanta | 02/11/15 | 02/11/15 | — | 254,440 | 508,879 | — | — | — | — | |||||||||||
02/17/15 (3) | 02/11/15 | — | — | — | 4,285 | 8,570 | 17,140 | 546,852 | ||||||||||||
02/17/15 (4) | 02/11/15 | — | — | — | — | 3,230 | — | 160,725 | ||||||||||||
Peter I. Tumminello | 02/11/15 | 02/11/15 | — | 537,500 | 662,500 | — | — | — | — | |||||||||||
02/17/15 (3) | 02/11/15 | — | — | — | 2,180 | 4,360 | 8,720 | 278,212 | ||||||||||||
02/17/15 (4) | 02/11/15 | — | — | — | — | 1,640 | — | 81,606 | ||||||||||||
05/28/15 (3) | 05/28/15 | — | — | — | 2,010 | 4,020 | 8,040 | 256,516 | ||||||||||||
05/28/15 (4) | 05/28/15 | — | — | — | — | 1,510 | — | 75,983 |
(1) | Reflects annual incentive opportunity for 2015 under the annual incentive plan and the OPIP. |
(2) | The annual incentive award includes a corporate component and a business performance component. The threshold payout amount for the 2015 corporate component was as follows: $331,391 for Mr. Somerhalder; $149,250 for Mr. Evans; $69,525 for Ms. Reese; $109,922 for Mr. Linginfelter; and $76,332 for Mr. Shlanta. The 2015 business performance component consisted of a series of differently-weighted metrics and could pay out anywhere from 0% to 200% of target. Accordingly, the business performance component did not include a threshold amount. |
The annual incentive award for Mr. Tumminello is not subject to a true maximum as it is based on an incentive pool. For additional detail, refer to the caption "Annual Incentive Award for Mr. Tumminello" herein. |
(3) | Reflects performance share units granted under the OPIP with a three-year performance measurement period that ends December 31, 2017. These units are payable 50% in shares of our common stock and 50% in cash. |
(4) | Reflects restricted stock units granted under the OPIP with a 12-month performance measurement period that ended December 31, 2015. |
(5) | Reflects the aggregate grant date fair value of stock awards, which are based on target-level award and computed in accordance with FASB ASC Topic 718. The assumptions used in calculating these amounts are discussed in Note 8 of our consolidated financial statements under Item 8 herein. |
Outstanding Equity Awards at 2015 Fiscal Year End | |||||||||||||||||||||
Option Awards | Stock Awards | ||||||||||||||||||||
Name | Date of Grant | Number of Securities Underlying Unexercised Options Exercisable | Number of Securities Underlying Unexercised Options Unexercisable | Option Exercise Price | Option Expiration Date | Number of Shares or Units of Stock that Have Not Vested | Market Value of Shares or Units of Stock that Have Not Vested | Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights that Have Not Vested | Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, or Units or Other Rights that Have Not Vested | ||||||||||||
John W. Somerhalder II | (1) | 02/05/13 | — | — | $ | — | — | 16,100 | $ | 1,027,341 | — | $ | — | ||||||||
(2) | 02/05/13 | — | — | — | — | 56,340 | 3,595,055 | — | — | ||||||||||||
(5) | 02/10/14 | — | — | — | — | — | — | 17,115 | 1,092,108 | ||||||||||||
(8) | 02/10/14 | — | — | — | — | — | — | 61,020 | 3,893,686 | ||||||||||||
(9) | 02/17/15 | — | — | — | — | — | — | 20,970 | 1,338,096 | ||||||||||||
(12) | 02/17/15 | — | — | — | — | — | — | 55,630 | 3,549,750 | ||||||||||||
Andrew W. Evans | (1) | 02/04/13 | — | — | — | — | 4,000 | 255,240 | — | — | |||||||||||
(2) | 02/04/13 | — | — | — | — | 14,000 | 893,340 | — | — | ||||||||||||
(6) | 02/10/14 | — | — | — | — | 5,033 | 321,156 | — | — | ||||||||||||
(8) | 02/10/14 | — | — | — | — | — | — | 17,950 | 1,145,390 | ||||||||||||
(10) | 02/17/15 | — | — | — | — | 6,170 | 393,708 | — | — | ||||||||||||
(12) | 02/17/15 | — | — | — | — | — | — | 16,360 | 1,043,932 | ||||||||||||
(13) | 05/28/15 | — | — | — | — | 2,780 | 177,392 | — | — | ||||||||||||
(14) | 05/28/15 | — | — | — | — | — | — | 7,390 | 471,556 | ||||||||||||
Elizabeth W. Reese | (2) | 02/04/13 | — | — | — | — | 3,050 | 194,621 | — | — | |||||||||||
(3) | 02/04/13 | — | — | — | — | 873 | 55,706 | — | — | ||||||||||||
(7) | 02/10/14 | — | — | — | — | 900 | 57,429 | — | — | ||||||||||||
(8) | 02/10/14 | — | — | — | — | — | — | 3,210 | 204,830 | ||||||||||||
(11) | 02/17/15 | — | — | — | — | 1,210 | 77,210 | — | — | ||||||||||||
(12) | 02/17/15 | — | — | — | — | — | — | 3,220 | 205,468 | ||||||||||||
(13) | 05/28/15 | — | — | — | — | 1,970 | 125,706 | — | — | ||||||||||||
(14) | 05/28/15 | — | — | — | — | — | — | 5,220 | 333,088 | ||||||||||||
Henry P. Linginfelter | (1) | 02/04/13 | — | — | — | — | 3,913 | 249,689 | — | — | |||||||||||
(2) | 02/04/13 | — | — | — | — | 13,690 | 873,559 | — | — | ||||||||||||
(6) | 02/10/14 | — | — | — | — | 4,283 | 273,298 | — | — | ||||||||||||
(8) | 02/10/14 | — | — | — | — | — | — | 15,270 | 974,379 | ||||||||||||
(10) | 02/17/15 | — | — | — | — | 5,250 | 335,003 | — | — | ||||||||||||
(12) | 02/17/15 | — | — | — | — | — | — | 13,920 | 888,235 | ||||||||||||
Paul R. Shlanta | (1) | 02/04/13 | — | — | — | — | 2,480 | 158,249 | — | — | |||||||||||
(2) | 02/04/13 | — | — | — | — | 8,670 | 553,233 | — | — | ||||||||||||
(6) | 02/10/14 | — | — | — | — | 2,633 | 168,012 | — | — | ||||||||||||
(8) | 02/10/14 | — | — | — | — | — | — | 9,400 | 599,814 | ||||||||||||
(10) | 02/17/15 | — | — | — | — | 3,230 | 206,106 | — | — | ||||||||||||
(12) | 02/17/15 | — | — | — | — | — | — | 8,570 | 546,852 | ||||||||||||
Peter I. Tumminello | (1) | 02/04/13 | — | — | — | — | 1,260 | 80,401 | — | — | |||||||||||
(2) | 02/04/13 | — | — | — | — | 4,420 | 282,040 | — | — | ||||||||||||
(4) | 05/03/13 | — | — | — | — | 1,523 | 97,183 | — | — | ||||||||||||
(6) | 02/10/14 | — | — | — | — | 1,343 | 85,697 | — | — | ||||||||||||
(8) | 02/10/14 | — | — | — | — | — | — | 4,790 | 305,650 | ||||||||||||
(10) | 02/17/15 | — | — | — | — | 1,640 | 104,648 | — | — | ||||||||||||
(12) | 02/17/15 | — | — | — | — | — | — | 4,360 | 278,212 | ||||||||||||
(13) | 05/28/15 | — | — | — | — | 1,510 | 96,353 | — | — | ||||||||||||
(14) | 05/28/15 | — | — | — | — | — | — | 4,020 | 256,516 |
(1) | Restricted stock units having satisfied the criteria for the applicable performance measurement period, converted into an equal number of shares of restricted stock and vesting at the rate of one-third per year, with vesting dates on March 1, 2015, March 1, 2016 and March 1, 2017. |
(2) | Performance share unit awards having a performance measurement period related to our RTSR, with the measurement period ended December 31, 2015. Awards shall be payable 50% in shares of our common stock and 50% in cash. |
(3) | A four-year restricted stock award with a three-year ratable vesting requirement with vesting dates of March 1, 2015, March 1, 2016 and March 1, 2017. |
(4) | A restricted stock award with a three-year ratable vesting requirement with vesting dates of May 3, 2014, May 3, 2015 and May 3, 2016. |
(5) | Restricted stock units having satisfied the criteria for the applicable performance measurement period that remain restricted stock units until the vesting dates and then converting into an equal number of shares of restricted stock and vesting at the rate of one-fourth per year, with vesting dates on March 1, 2015, March 1, 2016, March 1, 2017 and March 1, 2018. |
(6) | Restricted stock units having satisfied the criteria for the applicable performance measurement period, converted into an equal number of shares of restricted stock and vesting at the rate of one-fourth per year, with vesting dates on March 1, 2015, March 1, 2016, March 1, 2017 and March 1, 2018. |
(7) | A restricted stock award with a four-year ratable vesting requirement with vesting dates on March 1, 2015, March 1, 2016, March 1, 2017 and March 1, 2018. |
(8) | Performance share unit awards having a performance measurement period related to our RTSR, with the measurement period ending on December 31, 2016. Awards shall be payable 50% in shares of our common stock and 50% in cash. |
(9) | Restricted stock units having satisfied the criteria for the applicable performance measurement period that remain restricted stock units until the vesting dates and then converting into an equal number of shares of restricted stock and vesting at the rate of one-fourth per year, with vesting dates on March 1, 2016, March 1, 2017, March 1, 2018 and March 1, 2019. |
(10) | Restricted stock units having satisfied the criteria for the applicable performance measurement period, and then converting into an equal number of shares of restricted stock and vesting at the rate of one-fourth per year, with vesting dates on March 1, 2016, March 1, 2017, March 1, 2018 and March 1, 2019. |
(11) | A restricted stock award with a four-year ratable vesting requirement with vesting dates of March 1, 2016, March 1, 2017, March 1, 2018 and March 1, 2019. |
(12) | Performance share unit awards having a performance measurement period related to our RTSR and Cumulative Core EPS, with the measurement period ending on December 31, 2017. Awards shall be payable 50% in shares of our common stock and 50% in cash. |
(13) | Restricted stock units having satisfied the criteria for the applicable performance measurement period, and then converting into an equal number of shares of restricted stock and vesting at the rate of one-fourth per year, with vesting dates on March 1, 2016, March 1, 2017, March 1, 2018 and March 1, 2019. |
(14) | Performance share unit awards have a performance measurement period related to our RTSR and Cumulative Core EPS, with the measurement period ending on December 31, 2017. Awards shall be payable 50% in shares of our common stock and 50% in cash. |
2015 Stock Option Exercises and Stock Vested | |||||||||||||
Name | Option Awards | Stock Awards | |||||||||||
Number of Shares Acquired on Exercise | Value Realized on Exercise | Number of Shares Acquired on Vesting (1) | Value Realized on Vesting (1) | ||||||||||
John W. Somerhalder II | 384,400 | $ | 9,820,071 | 42,383 | $ | 2,206,359 | |||||||
Andrew W. Evans | — | — | 25,995 | 1,285,836 | |||||||||
Elizabeth W. Reese | — | — | 2,745 | 147,383 | |||||||||
Henry P. Linginfelter | — | — | 25,533 | 1,262,452 | |||||||||
Paul R. Shlanta | 20,540 | 532,744 | 6,593 | 343,019 | |||||||||
Peter I. Tumminello | 12,870 | 348,508 | 19,851 | 965,060 |
(1) | Represents the number of shares that vested in 2015 and the aggregate value of such shares based upon the fair market value of our common stock on the applicable vesting date. |
2015 Pension Benefits | ||||||||
Name | Plan Name (1)(2) | Number of Years Credited Service | Present Value of Accumulated Benefit | Payments During Last Fiscal Year | ||||
John W. Somerhalder II | Pension Plan | 10 | $ | 325,903 | $ | — | ||
Excess Plan | 10 | 2,208,630 | — | |||||
Individual Agreement (3) | 10(4) | 2,140,242 | — | |||||
Andrew W. Evans | Pension Plan | 14 | 343,710 | — | ||||
Excess Plan | 14 | 701,560 | — | |||||
Elizabeth W. Reese | Pension Plan | 15 | 353,918 | — | ||||
Excess Plan | 15 | 145,533 | — | |||||
Henry P. Linginfelter | Pension Plan | 35 | 758,324 | — | ||||
Excess Plan | 35 | 816,848 | — | |||||
Paul R. Shlanta | Pension Plan | 18 | 550,201 | — | ||||
Excess Plan | 18 | 828,124 | — | |||||
Peter I. Tumminello | Pension Plan | 12 | 309,261 | — | ||||
Excess Plan | 12 | 874,060 | — |
(1) | The AGL Resources Inc. Retirement Plan, which we refer to as the Pension Plan, is a broad-based, tax-qualified defined benefit plan. Generally, union employees who have a hire date on, or before, December 31, 2012, and non-union employees who have a hire date on, or before, December 31, 2011, are eligible to participate in the Pension Plan, upon completion of one year of service and attainment of age 21. Pension Plan benefits are determined, generally, by a “career average” earnings formula. Generally, the Pension Plan provides that the term “compensation” means base pay, overtime and bonuses. Benefits vest upon completion of five years of service. A participant’s accrued benefit is calculated based upon the normal form of benefits for that participant, as of the date the participant will reach the Pension Plan’s normal retirement age of 65. The normal form of benefits for a participant who is single is a life annuity. The normal form for a married participant is a joint and 50% survivor annuity. The Pension Plan provides for the payment of benefits in other forms, if the participant so elects. These other forms include various annuities, and (for a broad class of employees, including the named executive officers) only in cases where a participant’s benefit is less than $10,000, a single lump sum payment. Other employee groups may elect an unlimited lump sum. A participant may elect to receive benefits earlier than normal retirement age, once the participant has reached the early retirement age of 55. If a participant elects to commence benefits earlier than normal retirement age, the monthly payments will be reduced to reflect the fact that payments may continue over a longer period of time than if the employee had retired at normal retirement age. If the participant satisfies the Pension Plan’s requirements for early retirement (age 55 with 5 years of service), the reduced amount is subsidized so that the reduction from the full normal retirement benefit is less severe than a full actuarial reduction. If the participant does not satisfy the early retirement criteria, the reduced payments represent the actuarial equivalent of the full normal retirement benefit. |
(2) | The AGL Resources Inc. Excess Benefit Plan, which we refer to as the Excess Plan, is a non-qualified, and unfunded, defined benefit plan designed for the benefit of a select group of management or highly compensated employees. Specifically, the Excess Plan is available to certain of our employees who have a hire date on, or before, December 31, 2011, who are adversely affected by limitations set forth in the U.S. tax code, imposed on benefits under a tax-qualified plan, such as the Pension Plan. Benefits under the Excess Plan are calculated pursuant to a formula that first determines what the participant’s benefit would be under the Pension Plan, but for the imposition of the U.S. tax code limits and then subtracts from that figure, the amount the participant will actually be entitled to under the Pension Plan. Benefits under the Excess Plan are paid in the same forms available under the Pension Plan, and are distributed at the later of separation from service or age 62. |
(3) | Mr. Somerhalder’s individual agreement provides for one additional year of benefit accrual credit under the Pension Plan and Excess Plan for each year of service completed, up to a maximum of five additional years, using the eligible compensation for the year prior to the separation of service. |
(4) | In accordance with the terms of Mr. Somerhalder’s individual agreement, a maximum of five years of credited service is used in this calculation. |
Retirement age | Earliest unreduced | |
Payment form | Life annuity | |
Discount rate | 4.61% at December 31, 2015 | |
Postretirement mortality | RP-2014 mortality table, backed up to 2007 by Scale MP2014 and projected forward with the Mercer SSA intermediate alternative mortality improvement scale | |
Salary scale | None | |
Preretirement decrements: (mortality, withdrawals, disability) | None |
Nonqualified Deferred Compensation | ||||||||||||||||||||
Name | Executive Contributions in Last FY (1) | Registrant Contributions in Last FY (2) | Aggregate Earnings in Last FY | Aggregate Withdrawals/ Distributions | Aggregate Balance at Last FYE (3) | |||||||||||||||
John W. Somerhalder II | $ | 167,285 | $ | 108,735 | $ | 602,924 | $ | — | $ | 3,523,639 | ||||||||||
Andrew W. Evans | 63,974 | 41,582 | (226) | — | 1,194,907 | |||||||||||||||
Elizabeth W. Reese | 45,439 | 22,055 | 133,666 | — | 811,869 | |||||||||||||||
Henry P. Linginfelter | 76,905 | 47,404 | 3,003 | — | 1,058,890 | |||||||||||||||
Paul R. Shlanta | 53,950 | 33,711 | (5,894 | ) | — | 1,408,828 | ||||||||||||||
Peter I. Tumminello | 222,421 | 115,774 | (53,441) | — | 1,890,195 |
(1) | All amounts set forth in this column are included in the Summary Compensation Table as a component of the Salary column. |
(2) | All amounts set forth in this column represent our contributions to our Nonqualified Savings Plan and are included in the Summary Compensation Table as a component of the All Other Compensation column. |
(3) | Amounts set forth in this column for each named executive officer include amounts previously reported in the Summary Compensation Table, in the previous years when earned if that officer’s compensation was required to be disclosed in a previous year. Amounts previously reported in such years include previously earned, but deferred, salary and annual incentive and our matching contributions. This total reflects each named executive officer’s deferrals, matching contributions and investment experience. |
Executive Benefits and Payments Upon Termination (1) | Potential Payments Upon Termination Other Than in Connection with a Change in Control | Potential Payments Upon Termination Following a Change in Control | Disability (6) | Death (6) | |||||||||||||
Voluntary Termination(2) | Involuntary Not for Cause Termination (3) | For Cause Termination (4) | Voluntary, Involuntary or Good Reason Termination (5) | ||||||||||||||
Cash Severance: | |||||||||||||||||
Base Salary | $ | — | (3) | $ | — | $ | 2,008,432 | $ | — | $ | — | ||||||
Short-term Incentive | 2,024,521 | (3) | — | 4,206,941 | 2,024,521 | 2,024,521 | |||||||||||
Long-term Incentives: | |||||||||||||||||
Unvested Restricted Stock | — | (3) | — | 1,027,341 | 970,295 | 970,295 | |||||||||||
Unvested Restricted Stock Units | 2,430,204 | (3) | — | 2,430,204 | 1,644,830 | 2,369,584 | |||||||||||
Unvested Performance Share Units | 12,656,267 | (3) | — | 12,656,267 | 8,991,914 | 11,358,371 | |||||||||||
Unvested Stock Options | — | — | — | — | — | — | |||||||||||
Benefits & Perquisites: | |||||||||||||||||
Post-retirement/Post-termination Health Care and Life Insurance | — | — | — | 123,218 | (6) | (6) | |||||||||||
Disability Benefits | — | — | — | — | (6) | (6) | |||||||||||
Death Benefit | — | — | — | — | (6) | (6 | ) | ||||||||||
Accrued Vacation Pay | 19,312 | 19,312 | 19,312 | 19,312 | 19,312 | 19,312 | |||||||||||
Outplacement Assistance | — | (3) | — | — | — | — | |||||||||||
Sub-Total: | (2) | (3) | 19,312 | 22,471,715 | (6) | (6 | ) | ||||||||||
280G Cutback: | N/A | N/A | N/A | (1,129,395 | ) | N/A | N/A | ||||||||||
TOTAL: | (2) | (3) | $ | 19,312 | $ | 21,342,320 | (6) | (6) |
Executive Benefits and Payments Upon Termination (1) | Potential Payments Upon Termination Other than in Connection with a Change in Control | Potential Payments Upon Termination Following a Change in Control | Disability (6) | Death (6) | |||||||||||||
Voluntary Termination (2) | Involuntary Not for Cause Termination (3) | For Cause Termination (4) | Involuntary or Good Reason Termination (5) | ||||||||||||||
Cash Severance: | |||||||||||||||||
Base Salary | $ | — | (3) | $ | — | $ | 1,400,000 | $ | — | $ | — | ||||||
Short-term Incentive: | — | (3) | — | 1,625,393 | 895,370 | 895,370 | |||||||||||
Long-term Incentives: | |||||||||||||||||
Unvested Restricted Stock | — | (3) | — | 576,396 | 388,284 | 388,284 | |||||||||||
Unvested Restricted Stock Units | (2) | (3) | — | 571,100 | 247,009 | 571,100 | |||||||||||
Unvested Performance Share Units | (2) | (3) | — | 2,563,056 | 2,564,205 | 3,574,445 | |||||||||||
Unvested Stock Options | — | — | — | — | — | — | |||||||||||
Benefits & Perquisites: | |||||||||||||||||
Post-retirement/Post-termination Health Care and Life Insurance | — | — | — | 64,116 | (6) | (6) | |||||||||||
Disability Benefits | — | — | — | — | (6) | (6) | |||||||||||
Death Benefit | — | — | — | — | (6) | (6 | ) | ||||||||||
Accrued Vacation Pay | 15,385 | 15,385 | 15,385 | 15,385 | 15,385 | 15,385 | |||||||||||
Outplacement Assistance | — | (3) | — | 175,000 | — | — | |||||||||||
Sub-Total: | (2) | (3) | 15,385 | 6,990,446 | (6) | (6 | ) | ||||||||||
280G Cutback: | N/A | N/A | N/A | — | N/A | N/A | |||||||||||
TOTAL | (2) | (3) | $ | 15,385 | $ | 6,990,446 | (6) | (6) |
Executive Benefits and Payments Upon Termination (1) | Potential Payments Upon Termination Other than in Connection with a Change in Control | Potential Payments Upon Termination Following a Change in Control | Disability (6) | Death (6) | |||||||||||||
Voluntary Termination (2) | Involuntary Not for Cause Termination (3) | For Cause Termination (4) | Involuntary or Good Reason Termination (5) | ||||||||||||||
Cash Severance: | |||||||||||||||||
Base Salary | $ | — | (3) | $ | — | $ | 880,000 | $ | — | $ | — | ||||||
Short-term Incentive: | — | (3) | — | 730,069 | 420,659 | 420,659 | |||||||||||
Long-term Incentives: | |||||||||||||||||
Unvested Restricted Stock | — | (3) | — | 190,345 | 129,151 | 129,151 | |||||||||||
Unvested Restricted Stock Units | (2) | (3) | — | 125,706 | 47,156 | 125,706 | |||||||||||
Unvested Performance Share Units | (2) | (3) | — | 598,155 | 598,346 | 957,341 | |||||||||||
Unvested Stock Options | — | — | — | — | — | — | |||||||||||
Benefits & Perquisites: | |||||||||||||||||
Post-retirement/Post-termination Health Care and Life Insurance | — | — | — | 66,504 | (6) | (6) | |||||||||||
Disability Benefits | — | — | — | — | (6) | (6) | |||||||||||
Death Benefit | — | — | — | — | (6) | (6 | ) | ||||||||||
Accrued Vacation Pay | 7,192 | 7,192 | 7,192 | 7,192 | 7,192 | 7,192 | |||||||||||
Outplacement Assistance | — | (3) | — | 110,000 | — | — | |||||||||||
Sub-Total: | (2) | (3) | 7,192 | 2,707,971 | (6) | (6 | ) | ||||||||||
280G Cutback: | N/A | N/A | N/A | (312,335 | ) | N/A | N/A | ||||||||||
TOTAL | (2) | (3) | $ | 7,192 | $ | 2,395,636 | (6) | (6) |
Executive Benefits and Payments Upon Termination (1) | Potential Payments Upon Termination Other than in Connection with a Change in Control | Potential Payments Upon Termination Following a Change in Control | Disability (6) | Death (6) | |||||||||||||
Voluntary Termination (2) | Involuntary Not for Cause Termination (3) | For Cause Termination (4) | Involuntary or Good Reason Termination (5) | ||||||||||||||
Cash Severance: | |||||||||||||||||
Base Salary | $ | — | (3) | $ | — | $ | 1,127,410 | $ | — | $ | — | ||||||
Short-term Incentive | — | (3) | — | 1,479,532 | 671,721 | 671,721 | |||||||||||
Long-term Incentives: | |||||||||||||||||
Unvested Restricted Stock | — | (3) | — | 522,987 | 361,165 | 361,165 | |||||||||||
Unvested Restricted Stock Units | (2) | (3) | — | 335,003 | 153,591 | 335,003 | |||||||||||
Unvested Performance Share Units | (2) | (3) | — | 2,211,527 | 2,212,357 | 2,804,513 | |||||||||||
Unvested Stock Options | — | — | — | — | — | — | |||||||||||
Benefits & Perquisites: | |||||||||||||||||
Post-retirement/Post-termination Health Care and Life Insurance | — | — | — | 111,321 | (6) | (6) | |||||||||||
Disability Benefits | — | — | — | — | (6) | (6) | |||||||||||
Death Benefit | — | — | — | — | (6) | (6 | ) | ||||||||||
Accrued Vacation Pay | 4,607 | 4,607 | 4,607 | 4,607 | 4,607 | 4,607 | |||||||||||
Outplacement Assistance | — | (3) | — | 140,926 | — | — | |||||||||||
Sub-Total: | (2) | (3) | 4,607 | 5,933,313 | (6) | (6 | ) | ||||||||||
280G Cutback: | N/A | N/A | N/A | — | N/A | N/A | |||||||||||
TOTAL | (2) | (3) | $ | 4,607 | $ | 5,933,313 | (6) | (6) |
Executive Benefits and Payments Upon Termination (1) | Potential Payments Upon Termination Other than in Connection with a Change in Control | Potential Payments Upon Termination Following a Change in Control | Disability (6) | Death (6) | |||||||||||||
Voluntary Termination (2) | Involuntary Not for Cause Termination (3) | For Cause Termination (4) | Involuntary or Good Reason Termination (5) | ||||||||||||||
Cash Severance: | |||||||||||||||||
Base Salary | $ | — | (3) | $ | — | $ | 925,235 | $ | — | $ | — | ||||||
Short-term Incentive | 466,323 | (3) | — | 1,051,632 | 466,323 | 466,323 | |||||||||||
Long-term Incentives: | |||||||||||||||||
Unvested Restricted Stock | — | (3) | — | 326,261 | 226,526 | 226,526 | |||||||||||
Unvested Restricted Stock Units | 44,750 | (3) | — | 206,106 | 94,503 | 206,106 | |||||||||||
Unvested Performance Share Units | 1,312,276 | (3) | — | 1,383,911 | 1,384,422 | 1,748,968 | |||||||||||
Unvested Stock Options | — | — | — | — | — | — | |||||||||||
Benefits & Perquisites: | |||||||||||||||||
Post-retirement/Post-termination Health Care and Life Insurance | — | — | — | 122,865 | (6) | (6) | |||||||||||
Disability Benefits | — | — | — | — | (6) | (6) | |||||||||||
Death Benefit | — | — | — | — | (6) | (6 | ) | ||||||||||
Accrued Vacation Pay | — | — | — | — | — | — | |||||||||||
Outplacement Assistance | — | (3) | — | 115,654 | — | — | |||||||||||
Sub-Total: | (2) | (3) | — | 4,131,664 | (6) | (6 | ) | ||||||||||
280G Cutback: | N/A | N/A | N/A | — | N/A | N/A | |||||||||||
TOTAL | (2) | (3) | $ | — | $ | 4,131,664 | (6) | (6) |
Executive Benefits and Payments Upon Termination (1) | Potential Payments Upon Termination Other than in Connection with a Change in Control | Potential Payments Upon Termination Following a Change in Control | Disability (6) | Death (6) | |||||||||||||
Voluntary Termination (2) | Involuntary Not for Cause Termination (3) | For Cause Termination (4) | Involuntary or Good Reason Termination (5) | ||||||||||||||
Cash Severance: | |||||||||||||||||
Base Salary | $ | — | (3) | $ | — | $ | 860,000 | $ | — | $ | — | ||||||
Short-term Incentive | — | (3) | — | 5,157,089 | 2,094,870 | 2,094,870 | |||||||||||
Long-term Incentives: | |||||||||||||||||
Unvested Restricted Stock | — | (3) | — | 263,280 | 184,092 | 184,092 | |||||||||||
Unvested Restricted Stock Units | (2) | (3) | — | 201,002 | 84,165 | 201,002 | |||||||||||
Unvested Performance Share Units | (2) | (3) | — | 790,734 | 791,053 | 1,147,495 | |||||||||||
Unvested Stock Options | — | — | — | — | — | — | |||||||||||
Benefits & Perquisites: | |||||||||||||||||
Post-retirement/Post-termination Health Care and Life Insurance | — | — | — | 96,167 | (6) | (6) | |||||||||||
Disability Benefits | — | — | — | — | (6) | (6) | |||||||||||
Death Benefit | — | — | — | — | (6) | (6 | ) | ||||||||||
Accrued Vacation Pay | — | — | — | — | — | — | |||||||||||
Outplacement Assistance | — | (3) | — | 107,500 | — | — | |||||||||||
Sub-Total: | (2) | (3) | — | 7,475,772 | (6) | (6 | ) | ||||||||||
280G Cutback: | N/A | N/A | N/A | — | N/A | N/A | |||||||||||
TOTAL | (2) | (3) | $ | — | $ | 7,475,772 | (6) | (6) |
(1) | For purposes of this analysis, we assumed the executive’s compensation as current base salary, target annual incentive opportunity and target long-term incentive opportunity, each as of December 31, 2015. Each column assumes the named executive officer’s date of termination is December 31, 2015 and the price per share of our common stock on the date of termination is $63.81. |
(2) | If the executive leaves voluntarily prior to retirement eligibility, compensation stops as of the termination date. All outstanding and unvested long-term incentive awards would be forfeited. No further benefits would be earned under ERISA-qualified plans. Balances related to compensation deferred under the Nonqualified Savings Plan, if any, would be paid out in the year following the year of termination and at least six months following the date of termination, or later if the executive had timely elected. Prorated accrued and unused vacation would be paid. If the executive was retirement-eligible at the time of voluntary termination and elected to retire, in addition to commencing retirement benefits, he or she would be entitled to a prorated annual incentive under the annual incentive plan, conditioned on our satisfaction of applicable performance goals, and prorated vesting of unvested RSUs and PSUs, conditioned on our satisfaction of applicable performance goals. Only Messrs. Somerhalder and Shlanta were retirement eligible on December 31, 2015. Mr. Somerhalder retired on December 31, 2015, and his retirement has been treated as a Qualifying Retirement for purposes of the RSUs and PSUs awarded to him in 2014 and 2015. Accordingly, Mr. Somerhalder is entitled to receive the full value of such RSUs on the scheduled vesting dates and the value of such PSUs on the scheduled vesting dates conditioned only on our satisfaction of applicable performance goals. The satisfaction of such goals would be measured at the end of the performance period, and any payment would be made at that time. For those who are retirement eligible, the value of the unvested performance-based awards is not currently calculable but has been included based on our share price and actual performance as of December 31, 2015. |
(3) | If the executive is terminated without cause, a severance agreement may be executed based upon the facts and circumstances of the termination and in exchange for a release of any future liabilities which might otherwise be claimed by the executive. Due to the wide range and variety of circumstances, there is no preset policy governing involuntary severance compensation. However, any terms of such a special agreement would be subject to the review and approval of |
(4) | If the executive is terminated for cause, compensation stops as of the termination date. All outstanding long-term incentive awards would be forfeited. No further benefits would be earned under ERISA-qualified plans. Balances related to compensation deferred under the Nonqualified Savings Plan, if any, would be paid out in the year following the year of termination and at least six months following the date of termination, or later if the executive had timely elected. The prorated value of accrued but unused vacation would be paid. |
(5) | If within two years of a change in control (as described below) the executive is terminated without cause, or resigns for good reason, the terms and conditions described below under the caption “Payments upon a Termination in connection with a Change in Control” would apply. The Board determined that Mr. Somerhalder’s retirement will be treated as a qualifying termination for purposes of his continuity agreement. Accordingly, if a change in control occurs, the terms and conditions described below under “Payments upon a Termination in connection with a Change in Control” also would apply to Mr. Somerhalder. |
(6) | If the executive’s employment terminates as a result of death, a death benefit would be paid to the executive’s estate under our death benefit plan in an amount equal to one year’s base salary or such multiple of base salary (up to five) as elected and paid for, in part, by the executive. This plan covers all employees and does not discriminate in favor of executives or highly compensated employees. Upon a determination of long-term disability, payments would be made, based on the level of coverage elected and paid for, in part, by the executive, under our group disability plan. Our disability plan is also a plan that does not discriminate in favor of executives, or highly compensated employees. In the event of death or disability, the executive (or the executive’s designated beneficiary) also would receive a prorated annual incentive under the annual incentive plan, conditioned on our satisfaction of applicable performance goals. In addition, long-term incentive awards granted prior to 2015 would vest on a pro rata basis with performance conditioned on our satisfaction of applicable performance goals. The satisfaction of such goals would be measured at the end of the performance period, and any payment would be made at that time. Upon a termination due to death, stock options and long-term incentive awards granted in 2015 would vest and become non-forfeitable in full conditioned on our satisfaction of applicable performance goals. The satisfaction of such goals would be measured at the end of the performance period, and any payment would be made at that time. Due to the future performance measurement, the value of the unvested performance-based awards is not currently calculable but has been included based on our share price and actual performance as of December 31, 2015. |
• | the acquisition by a person or group of persons of more than 50% of our voting securities, based upon total fair market value or total voting power; |
• | the acquisition, within a 12-month period by a person or group of more than 35% of the total voting power of our stock; |
• | the replacement, during a 12-month period of a majority of members of our Board with directors not endorsed by a majority of the incumbent directors; or |
• | the acquisition by a person or group of persons of our assets which have a fair market value of at least 50% of the fair market value of all of our assets, immediately before such acquisition. |
• | a severance benefit equal to two times the sum of his or her base salary plus the average annual incentive compensation actually paid during the three years prior to the year of the qualifying termination; |
• | a prorated annual incentive compensation payment for the year of the qualifying termination, based on the number of days the named executive officer was employed by us during that year and the greater of the target annual incentive for the officer or the incentive that would be paid based upon actual performance through the date of termination; |
• | two-year continuation of medical, dental and life insurance benefits; |
• | potential vesting of long-term incentive compensation, pursuant to the terms of the plan the awards were granted under; and |
• | outplacement assistance. |
John W. Somerhalder II | Andrew W. Evans | Elizabeth W. Reese | Henry P. Linginfelter | Paul R. Shlanta | Peter I. Tumminello | |||||||||||||
Unvested Restricted Stock | $ | 1,027,341 | $ | 576,396 | $ | 190,345 | $ | 522,987 | $ | 326,261 | $ | 263,280 | ||||||
Unvested Restricted Stock Units | 2,430,204 | 571,100 | 125,706 | 335,003 | 206,106 | 201,002 | ||||||||||||
Unvested Performance Share Units | 12,656,267 | 2,563,056 | 598,155 | 2,211,527 | 1,383,911 | 790,734 | ||||||||||||
Total | $ | 16,113,812 | $ | 3,710,552 | $ | 914,206 | $ | 3,069,517 | $ | 1,916,278 | $ | 1,255,016 |
Plan Category | Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants and Rights (1)(a) | Weighted Average Exercise Price of Outstanding Options, Warrants and Rights (b) | Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (Excluding Securities Reflected in Column) (1)(a)(c) | |||
Equity compensation plans approved by security holders | 440,186 | $ | 39.24 | 2,327,332 | ||
Equity compensation plans not approved by security holders | — | — | 1,514,116 | |||
Total | 440,186 | — | 3,841,448 |
Name of Plan | Approved by Security Holders | Active/ Inactive Plan (a) | Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants and Rights | Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (Excluding Outstanding Options) | ||
Omnibus Performance Incentive Plan, as Amended and Restated | ü | Active | 359,586 | 1,999,876 (b) | ||
Long-Term Incentive Plan (1999) | ü | Inactive | 80,600 | — | ||
2006 Directors Plan | ü | Active | N/A | 11,886 | ||
Employee Stock Purchase Plan | ü | Active | N/A | 315,570 | ||
Subtotal-Approved Plans | 440,186 | 2,327,332 | ||||
Assumed Nicor Inc. Plan Shares under OPIP (c) | No | Active | — | 1,514,116 | ||
Subtotal-Not Approved Plans | — | 1,514,116 | ||||
Total | 440,186 | 3,841,448 |
(a) | No further grants will be made under the inactive plan except for reload options that may be granted under outstanding option agreements under the 1999 Long-Term Incentive Plan. |
(b) | The OPIP includes separate pools of shares for share counting purposes. The amount shown in the table above includes 1 million shares, which are available for future issuance as awards pursuant to stock options or stock appreciation rights under the “Remainder Reserve.” If issued pursuant to full value awards (which include awards other than stock options or stock appreciation rights), only 200,000 shares could be issued under the Remainder Reserve. In such event, the number of securities remaining available for future issuance under the OPIP, the subtotal for approved plans, and the total each would decrease by 800,000 shares. |
(c) | In accordance with the terms of the OPIP, which was approved by our shareholders, shares available under a shareholder-approved plan of a company acquired by us (as appropriately adjusted to reflect the transaction) may be issued under the OPIP pursuant to awards granted to individuals who were not our employees or employees of a related company immediately before such transaction. These assumed shares do not count against the maximum share limitation specified in the OPIP. Such assumption of shares in a merger does not require approval of our shareholders under the rules of the New York Stock Exchange or otherwise. The shares designated as “Assumed Nicor Inc. Plan Shares” in the table above remained available under the Nicor Inc. 2006 Long-Term Incentive Plan, as amended, at the time of our merger with Nicor Inc. These shares were assumed under the OPIP and are available for future issuance to persons who were not our employees or employees of a related company immediately prior to our merger with Nicor Inc. |
Name | Shares of Common Stock Beneficially Owned | |||||
Owned Shares | Option Shares (1) | Shares and Share Equivalents Held Under Deferral Plans (2) | Total | |||
Sandra N. Bane | 3,410 | — | 17,302 | 20,712 | ||
Thomas D. Bell, Jr. | 32,558 | — | — | 32,558 | ||
Norman R. Bobins (3) | 12,565 | — | — | 12,565 | ||
Charles R. Crisp | 16,739 | — | 14,589 | 31,328 | ||
Brenda J. Gaines | 12,510 | — | — | 12,510 | ||
Arthur E. Johnson | 4,338 | — | 52,113 | 56,451 | ||
Wyck A. Knox, Jr. | 14,193 | — | 48,159 | 62,352 | ||
Dennis M. Love | 41,937 | — | 42,169 | 84,106 | ||
Dean R. O’Hare | 22,572 | — | 931 | 23,503 | ||
Armando J. Olivera | 1,875 | — | 14,466 | 16,341 | ||
John E. Rau (4) | 25,080 | — | — | 25,080 | ||
James A. Rubright | 22,235 | — | 26,230 | 48,465 | ||
John W. Somerhalder II (5) | 201,174 | — | 52,759 | 253,933 | ||
Bettina M. Whyte | 14,782 | — | 21,204 | 35,986 | ||
Henry C. Wolf | 31,031 | — | 13,309 | 44,340 | ||
Andrew W. Evans | 72,791 | — | — | 72,791 | ||
Elizabeth W. Reese | 3,411 | — | 11,726 | 15,137 | ||
Henry P. Linginfelter | 82,150 | — | 44 | 82,194 | ||
Paul R. Shlanta | 54,543 | — | — | 54,543 | ||
Peter I. Tumminello | 35,049 | — | — | 35,049 | ||
All executive officers and directors as a group (21 persons) (6) | 744,333 | — | 315,001 | 1,059,334 |
(1) | Reflects the shares that may be acquired upon exercise of stock options granted under the OPIP, the Long-Term Incentive Plan (1999) (which we refer to as the Long-Term Incentive Plan) and which was the predecessor plan to the OPIP, or under the Officer Incentive Plan. |
(2) | Represents shares of common stock, common stock equivalents and accrued dividend credits held for non-employee directors under the Amended and Restated Common Stock Equivalent Plan for Non-Employee Directors, which we refer to as the Common Stock Equivalent Plan, and, for the named executive officers, under the Nonqualified Savings Plan. The common stock equivalents track the performance of our common stock and are payable in cash. The shares and share equivalents may not be voted or transferred by the participants. |
(3) | Includes 502 shares held in a trust for which Mr. Bobins has sole voting and investment power with respect to the shares. |
(4) | Includes 4,610 shares held in a trust for which Mr. Rau has sole voting and investment power with respect to the shares. |
(5) | Includes 9,711 shares held in a trust for which Mr. Somerhalder has sole voting and investment power with respect to the shares. |
(6) | Includes 39,390 shares of a member of the group who is not a named executive officer. |
Name and Address of Beneficial Owner | Shares of Common Stock Beneficially Owned | Percent of Class | ||
BlackRock, Inc. 55 East 52nd Street New York, NY 10055 | 10,333,756 (1) | 8.6% | ||
The Vanguard Group, Inc. 100 Vanguard Blvd. Malvern, PA 19355 | 10,344,726 (2) | 8.6% |
(1) | Based on the Schedule 13G/A filed with the SEC on January 25, 2016, in which BlackRock, Inc. reported that it holds all of its shares as a parent holding company or control person in accordance with Rule 13d-1(b)(1)(ii)(G) of the Exchange Act and has sole voting power with respect to 9,339,720 of its shares and sole dispositive power with respect to all of its shares. |
(2) | Based on the Schedule 13G/A filed with the SEC on February 10, 2016, in which The Vanguard Group, Inc. (“Vanguard”) reported that it holds all of its shares as an investment advisor in accordance with Rule 13d-1(b)(1)(ii)(E) of the Exchange Act and has sole voting power of 231,808 of the total shares, shared voting power of 11,000 of the total shares, sole dispositive power of 10,109,211 of the total shares and shared dispositive power of 235,515 of the total shares. Based on the Schedule 13G/A, (i) Vanguard Fiduciary Trust Company (“VFTC”), a wholly-owned subsidiary of Vanguard, is the beneficial owner of 186,315 shares or 0.15% of our common stock outstanding as a result of its serving as investment manager of collective trust accounts, and as such, VFTC directs the voting of these 186,315 shares; and (ii) Vanguard Investments Australia, Ltd. (“VIA”), a wholly-owned subsidiary of Vanguard, is the beneficial owner of 94,693 shares or 0.07% of our common stock outstanding as a result of its serving as investment manager of Australian investment offerings, and as such, VIA directs the voting of these 94,693 shares. |
Fee Category | 2015 | 2014 | ||||||
Audit fees | $ | 3,967,025 | $ | 4,247,068 | ||||
Audit-related fees | 88,000 | 275,000 | ||||||
Tax fees | 75,000 | 43,200 | ||||||
Total fees | $ | 4,130,025 | $ | 4,565,268 |
• | Report of Independent Registered Public Accounting Firm |
• | Management’s Report on Internal Control Over Financial Reporting |
• | Report of Independent Registered Public Accounting Firm |
• | Management’s Report on Internal Control Over Financial Reporting |
• | Consolidated Balance Sheets as of December 31, 2015 and 2014 |
• | Consolidated Statements of Income for the years ended December 31, 2015, 2014 and 2013 |
• | Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2015, 2014 and 2013 |
• | Consolidated Statements of Equity for the years ended December 31, 2015, 2014 and 2013 |
• | Consolidated Statements of Cash Flows for the years ended December 31, 2015, 2014 and 2013 |
• | Notes to Consolidated Financial Statements |
Exhibit Number | Description of Exhibit | Filer | The Filings Referenced for Incorporation by Reference | |
2.1 | Agreement and Plan of Merger, dated August 23, 2015, by and among The Southern Company, AMS Corp. and AGL Resources Inc. | AGL Resources | August 24, 2015, Form 8-K, Exhibit 2.1 | |
3.1 | Amended and Restated Articles of Incorporation | AGL Resources | May 4, 2015, Form 8-K, Exhibit 3.1 | |
3.2 | Bylaws, as amended | AGL Resources | May 4, 2015, Form 8-K, Exhibit 3.2 | |
4.1 | Specimen Form of Common Stock certificate | AGL Resources | September 30, 2007, Form 10-Q, Exhibit 4.1 | |
4.2.a | Form of AGL Capital Corporation 6.00% Senior Notes due 2034 | AGL Resources | September 27, 2004, Form 8-K, Exhibit 4.1 | |
4.2.b | Form of Guarantee of AGL Resources Inc. dated September 27, 2004 | AGL Resources | September 27, 2004, Form 8-K, Exhibit 4.3 | |
4.3.a | AGL Capital Corporation 6.375% Senior Notes due 2016 | AGL Resources | December 14, 2007, Form 8-K, Exhibit 4.1 | |
4.3.b | Guarantee of AGL Resources Inc. dated December 14, 2007 | AGL Resources | December 14, 2007, Form 8-K, Exhibit 4.2 | |
4.4.a | AGL Capital Corporation 5.25% Senior Notes due 2019 | AGL Resources | August 10, 2009, Form 8-K, Exhibit 4.1 | |
4.4.b | Guarantee of AGL Resources Inc. dated August 10, 2009 | AGL Resources | August 10, 2009, Form 8-K, Exhibit 4.2 | |
4.5.a | AGL Capital Corporation 5.875% Senior Notes due 2041 | AGL Resources | March 21, 2011, Form 8-K, Exhibit 4.1 | |
4.5.b | Guarantee of AGL Resources Inc. dated March 21, 2011 | AGL Resources | March 21, 2011, Form 8-K, Exhibit 4.2 | |
4.6.a | Form of AGL Capital Corporation 3.50% Senior Notes due 2021 | AGL Resources | September 20, 2011, Form 8-K, Exhibit 4.1 | |
4.6.b | Form of Guarantee of AGL Resources Inc. dated September 2011 | AGL Resources | September 20, 2011, Form 8-K, Exhibit 4.2 | |
4.7.a | Form of AGL Capital Corporation Series A Senior Notes due 2016 | AGL Resources | September 7, 2011, Form 8-K, Exhibit 4.1 | |
4.7.b | Form of AGL Capital Corporation Series B Senior Notes due 2018 | AGL Resources | September 7, 2011, Form 8-K, Exhibit 4.2 | |
4.8.a | AGL Capital Corporation 4.40% Senior Notes due 2043 | AGL Resources | May 16, 2013, Form 8-K, Exhibit 4.2 | |
4.8.b | AGL Resources Inc. Guarantee related to the 4.40% Senior Notes due 2043 | AGL Resources | May 16, 2013, Form 8-K, Exhibit 4.2 | |
4.8.c | AGL Capital Corporation 3.875% Senior Notes due 2025 | AGL Resources | November 18, 2015, Form 8-K, Exhibit 4.2 | |
4.8.d | AGL Resources Inc. Guarantee related to the 3.875% Senior Notes due 2025 | AGL Resources | November 18, 2015, Form 8-K, Exhibit 4.3 | |
4.9.a | Indenture dated December 1, 1989 | Atlanta Gas Light | File No. 33-32274, Form S-3, Exhibit 4(a) | |
4.9.b | First Supplemental Indenture dated March 16, 1992 | Atlanta Gas Light | File No. 33-46419, Form S-3, Exhibit 4(a) |
4.10 | Indenture dated February 20, 2001 | AGL Resources | September 17, 2001, File No. 333-69500, Form S-3, Exhibit 4.2 | |
4.11.a | Indenture dated January 1, 1954 | Nicor Gas | December 31, 1995, Form 10-K, Exhibit 4.01 | |
4.11.b | Indenture of adoption dated February 9, 1954 | Nicor Gas | December 31, 1995, Form 10-K, Exhibit 4.02 | |
4.11.c | Supplemental Indenture dated February 15, 1998 | Nicor Gas | December 31, 1997, Form 10-K, Exhibit 4.19 | |
4.11.d | Supplemental Indenture dated May 15, 2001 | Nicor Gas | July 20, 2001, File No. 333-65486, Form S-3, Exhibit 4.18 | |
4.11.e | Supplemental Indenture dated December 1, 2003 | Nicor Gas | December 31, 2003, Form 10-K, Exhibit 4.09 | |
4.11.f | Supplemental Indenture dated December 1, 2003 | Nicor Gas | December 31, 2003, Form 10-K, Exhibit 4.10 | |
4.11.g | Supplemental Indenture dated December 1, 2003 | Nicor Gas | December 31, 2003, Form 10-K, Exhibit 4.11 | |
4.11.h | Supplemental Indenture dated December 1, 2006 | Nicor Gas | December 31, 2006, Form 10-K, Exhibit 4.11 | |
4.11.i | Supplemental Indenture dated August 1, 2008 | Nicor Gas | September 30, 2008, Form 10-Q, Exhibit 4.01 | |
4.11.j | Supplemental Indenture dated July 23, 2009 | Nicor Gas | June 30, 2009, Form 10-Q, Exhibit 4.01 | |
4.11.k | Supplemental Indenture dated February 1, 2011 | Nicor Gas | December 31, 2010, Form 10-K, Exhibit 4.12 | |
4.11.l | Supplemental Indenture dated October 26, 2012 | Nicor Gas | September 30, 2012, Form 10-Q, Exhibit 4 | |
10.1.a+ | 2006 Non-Employee Directors Equity Compensation Plan, amended and restated as of December 9, 2011 | AGL Resources | December 15, 2011, Form 8-K, Exhibit 10.2 | |
10.1.b+ | Amended and Restated Common Stock Equivalent Plan for Non-Employee Directors | AGL Resources | June 30, 2015, Form 10-Q, Exhibit 10.3 | |
10.1.c+ | Form of Stock Award Agreement for Non-Employee Directors | AGL Resources | December 31, 2004, Form 10-K, Exhibit 10.1.aj | |
10.1.d+ | Form of Nonqualified Stock Option Agreement for Non-Employee Directors | AGL Resources | December 31, 2004, Form 10-K, Exhibit 10.1.ak | |
10.1.e+ | Form of Director Indemnification Agreement dated April 28, 2004 | AGL Resources | June 30, 2004, Form 10-Q, Exhibit 10.3 | |
10.1.f+ | Long-Term Incentive Plan, as amended and restated as of January 1, 2002 | AGL Resources | March 31, 2002, Form 10-Q, Exhibit 99.2 | |
10.1.g+ | First amendment to the Long-Term Incentive Plan, as amended and restated | AGL Resources | December 31, 2004, Form 10-K, Exhibit 10.1.b | |
10.1.h+ | Second amendment to the Long-Term Incentive Plan, as amended and restated | AGL Resources | June 30, 2007, Form 10-Q, Exhibit 10.1.l | |
10.1.i+ | Third amendment to the Long-Term Incentive Plan, as amended and restated | AGL Resources | December 31, 2008, Form 10-K, Exhibit 10.1.ad | |
10.1.j+ | Omnibus Performance Incentive Plan, as amended and restated | AGL Resources | March 14, 2011, Schedule 14A, Annex A | |
10.1.k+ | Form of Restricted Stock Unit Agreement under Omnibus Performance Incentive Plan, as amended and restated | AGL Resources | December 31, 2011, Form 10-K, Exhibit 10.1.ae | |
10.1.l+ | Form of Restricted Stock Agreement under Omnibus Performance Incentive Plan, as amended and restated | AGL Resources | December 31, 2011, Form 10-K, Exhibit 10.1.af | |
10.1.m+ | Form of Performance Share Unit Award under Omnibus Performance Incentive Plan, as amended and restated | AGL Resources | December 31, 2013, Form 10-K, Exhibit 10.1r | |
10.1.n+ | 2007 Omnibus Performance Incentive Plan | AGL Resources | March 19, 2007, Schedule 14A, Annex A | |
10.1.o+ | First Amendment to the 2007 Omnibus Performance Incentive Plan, as amended and restated | AGL Resources | December 31, 2008, Form 10-K, Exhibit 10.1.ai | |
10.1.p+ | Form of Incentive Stock Option Agreement – 2007 Omnibus Performance Incentive Plan | AGL Resources | June 30, 2007, Form 10-Q, Exhibit 10.1.b | |
10.1.q+ | Form of Nonqualified Stock Option Agreement – 2007 Omnibus Performance Incentive Plan | AGL Resources | June 30, 2007, Form 10-Q, Exhibit 10.1.c | |
10.1.r+ | Form of Incentive Stock Option Agreement and Nonqualified Stock Option Agreement for key employees (LTIP) | AGL Resources | September 30, 2004, Form 10-Q, Exhibit 10.1 | |
10.1.s+ | Forms of Nonqualified Stock Option Agreement without the reload provision (LTIP) | AGL Resources | March 18, 2005, Form 8-K, Exhibit 10.1 | |
10.1.t+ | Form of Nonqualified Stock Option Agreement with the reload provision (Officer Incentive Plan) | AGL Resources | March 18, 2005, Form 8-K, Exhibit 10.2 | |
10.1.u+ | Nonqualified Savings Plan as amended and restated as of January 1, 2009 | AGL Resources | December 31, 2008, Form 10-K, Exhibit 10.1.av | |
10.1.v+ | First Amendment to the Nonqualified Savings Plan | AGL Resources | December 31, 2013, Form 10-K, Exhibit 10.1.aa | |
10.1.w+ | Second Amendment to the Nonqualified Savings Plan | AGL Resources | December 31, 2013, Form 10-K, Exhibit 10.1.ab |
10.1.x+ | Third Amendment to the Nonqualified Savings Plan | AGL Resources | December 31, 2013, Form 10-K, Exhibit 10.1.ac | |
10.1.y+ | Description of Supplemental Executive Retirement Plan for John W. Somerhalder II | AGL Resources | December 31, 2008, Form 10-K, Exhibit 10.1.ay | |
10.1.z+ | Excess Benefit Plan as amended and restated as of January 1, 2009 | AGL Resources | December 31, 2008, Form 10-K, Exhibit 10.1.az | |
10.1.aa+ | Form of Continuity Agreement dated December 19, 2013 | AGL Resources | December 19, 2013, Form 8-K, Exhibit 10.1 | |
10.1.ab+ | Description of compensation for each of John W. Somerhalder II, Andrew W. Evans, Elizabeth W. Reese, Henry P. Linginfelter, Paul R. Shlanta and Peter I. Tumminello (our Named Executive Officers for the year ended December 31, 2015) | AGL Resources | Compensation Discussion and Analysis section under Item 11 of the Form 10-K for December 31, 2015. | |
10.2.a | Form of Commercial Paper Dealer Agreement | AGL Resources | September 30, 2000, Form 10-K, Exhibit 10.79 | |
10.2.b | Guarantee dated October 5, 2000 of payments on promissory notes | AGL Resources | September 30, 2000, Form 10-K, Exhibit 10.80 | |
10.4 | Note Purchase Agreement dated August 31, 2011 | AGL Resources | September 7, 2011, Form 8-K, Exhibit 10.1 | |
10.5 | Final Allocation Agreement dated January 3, 2008 | Nicor | December 31, 2007, Form 10-K, Exhibit 10.64 | |
10.6 | Second Amended and Restated Limited Liability Company Agreement of SouthStar Energy Services LLC dated September 6, 2013 by and between Georgia Natural Gas Company and Piedmont Energy Company | AGL Resources | September 30, 2013, Form 10-Q, Exhibit 10 | |
10.7 | Credit Agreement dated as of December 15, 2011 | AGL Resources | December 15, 2011, Form 8-K, Exhibit 10.1 | |
10.7a | First Amendment to Credit Agreement, dated as of February 26, 2013 | AGL Resources | June 30, 2015, Form 10-Q, Exhibit 10.2 | |
10.8 | Amended and Restated Credit Agreement dated as of November 10, 2011 | AGL Resources | November 17, 2011, Form 8-K, Exhibit 10.1 | |
10.8.b | Second Amendment and Extension Agreement dated as of October 30, 2015 | AGL Resources | November 5, 2015, Form 8-K, Exhibit 10.1 | |
10.8.c | Guarantee Agreement dated as of November 10, 2011 | AGL Resources | November 17, 2011, Form 8-K, Exhibit 10.2 | |
10.9 | Bank Rate Mode Covenants Agreement, dated as of February 26, 2013 | AGL Resources | March 1, 2013, Form 8-K, Exhibit 10.1 | |
10.9.a | First Amendment to Bank Rate Mode Covenants Agreement dated as of October 30, 2015 | AGL Resources | November 5, 2015, Form 8-K, Exhibit 10.3 | |
10.10 | Loan Agreement dated as of February 1, 2013 | AGL Resources | March 1, 2013, Form 8-K, Exhibit 10.2 | |
10.11 | Loan Agreement dated as of March 1, 2013 | AGL Resources | March 27, 2013, Form 8-K, Exhibit 10.1 | |
10.12 | Amended and Restated Loan Agreement dated as of March 1, 2013 | AGL Resources | March 27, 2013, Form 8-K, Exhibit 10.2 | |
10.13 | Amended and Restated Loan Agreement dated as of March 1, 2013 | AGL Resources | March 27, 2013, Form 8-K, Exhibit 10.3 | |
10.14 | Amended and Restated Loan Agreement dated as of March 1, 2013 | AGL Resources | March 27, 2013, Form 8-K, Exhibit 10.4 | |
12 | Statement of Computation of Ratio of Earnings to Fixed Charges | AGL Resources | Filed herewith | |
14 | Code of Ethics for the Chief Executive Officer and Senior Financial Officers | AGL Resources | December 31, 2004, Form 10-K, Exhibit 14 | |
21 | Subsidiaries of AGL Resources Inc. | AGL Resources | Filed herewith | |
23 | Consent of PricewaterhouseCoopers LLP | AGL Resources | Filed herewith | |
24 | Powers of Attorney | AGL Resources | Included on signature page hereto | |
31.1 | Certification of Andrew W. Evans | AGL Resources | Filed herewith | |
31.2 | Certification of Elizabeth W. Reese | AGL Resources | Filed herewith | |
32.1 | Certification of Andrew W. Evans | AGL Resources | Filed herewith | |
32.2 | Certification of Elizabeth W. Reese | AGL Resources | Filed herewith | |
101.INS | XBRL Instance Document | AGL Resources | Filed herewith | |
101.SCH | XBRL Taxonomy Extension Schema | AGL Resources | Filed herewith | |
101.CAL | XBRL Taxonomy Extension Calculation Linkbase | AGL Resources | Filed herewith | |
101.DEF | XBRL Taxonomy Definition Linkbase | AGL Resources | Filed herewith | |
101.LAB | XBRL Taxonomy Extension Labels Linkbase | AGL Resources | Filed herewith | |
101.PRE | XBRL Taxonomy Extension Presentation Linkbase | AGL Resources | Filed herewith |
Signatures | Title |
/s/ Andrew W. Evans | President, Chief Executive Officer and Director (Principal Executive Officer) |
Andrew W. Evans | |
/s/ Elizabeth W. Reese | Executive Vice President and Chief Financial Officer (Principal Financial Officer) |
Elizabeth W. Reese | |
/s/ Bryan E. Seas | Senior Vice President and Chief Accounting Officer (Principal Accounting Officer) |
Bryan E. Seas | |
/s/ Sandra N. Bane | Director |
Sandra N. Bane | |
/s/ Thomas D. Bell, Jr. | Director |
Thomas D. Bell, Jr. | |
/s/ Norman R. Bobins | Director |
Norman R. Bobins | |
/s/ Charles R. Crisp | Director |
Charles R. Crisp | |
/s/ Brenda J. Gaines | Director |
Brenda J. Gaines | |
/s/ Arthur E. Johnson | Director |
Arthur E. Johnson | |
/s/ Wyck A. Knox, Jr. | Director |
Wyck A. Knox, Jr. | |
/s/ Dennis M. Love | Director |
Dennis M. Love | |
/s/ Dean R. O’Hare | Director |
Dean R. O’Hare | |
/s/ Armando J. Olivera | Director |
Armando J. Olivera | |
/s/ John E. Rau | Director |
John E. Rau | |
/s/ James A. Rubright | Director |
James A. Rubright | |
/s/ Bettina M. Whyte | Director |
Bettina M. Whyte | |
/s/ Henry C. Wolf | Director |
Henry C. Wolf |
Additions | ||||||||||||||||||||
In millions | Balance at beginning of period | Charged to costs and expenses | Charged to other accounts | Deductions | Balance at end of period | |||||||||||||||
2013 | ||||||||||||||||||||
Allowance for uncollectible accounts | $ | 28 | $ | 37 | $ | — | $ | (36 | ) | $ | 29 | |||||||||
Income tax valuation | 22 | — | — | — | 22 | |||||||||||||||
2014 | ||||||||||||||||||||
Allowance for uncollectible accounts | $ | 29 | $ | 54 | $ | 2 | $ | (50 | ) | $ | 35 | |||||||||
Income tax valuation | 22 | — | — | (2 | ) | 20 | ||||||||||||||
2015 | ||||||||||||||||||||
Allowance for uncollectible accounts | $ | 35 | $ | 27 | $ | 3 | $ | (36 | ) | $ | 29 | |||||||||
Income tax valuation | 20 | — | — | (1 | ) | 19 |
Twelve months ended December 31, | Fiscal | Fiscal | Fiscal | Fiscal | |||||||||||
Dollars in millions | 2015 | 2014 | 2013 | 2012 | 2011 | ||||||||||
Earnings from continuing operations before income taxes (1) | $ | 580 | $ | 922 | $ | 482 | $ | 418 | $ | 300 | |||||
Add: | |||||||||||||||
Fixed charges (see “B” below) | 184 | 188 | 189 | 202 | 146 | ||||||||||
Amortization of capitalized interest (2) | — | — | — | — | 1 | ||||||||||
Distributed income of equity investees | 6 | 8 | 3 | 13 | — | ||||||||||
Less: | |||||||||||||||
Interest capitalized (2) | 2 | — | — | 1 | 1 | ||||||||||
Noncontrolling interest in pre-tax income of subsidiaries that have not incurred fixed charges | 20 | 18 | 18 | 15 | 14 | ||||||||||
Adjusted earnings (A) | $ | 748 | $ | 1,100 | $ | 656 | $ | 617 | $ | 432 | |||||
Fixed charges | |||||||||||||||
Interest on long-term debt | $ | 176 | $ | 185 | $ | 182 | $ | 177 | $ | 101 | |||||
Other interest, including amortized premiums, discounts and capitalized expenses related to indebtedness liability | 2 | (4 | ) | (5 | ) | 12 | 38 | ||||||||
Estimated interest components of rentals | 6 | 7 | 12 | 13 | 7 | ||||||||||
Total fixed charges (B) | $ | 184 | $ | 188 | $ | 189 | $ | 202 | $ | 146 | |||||
Ratio of earnings to fixed charges (A)/(B) | 4.07 | 5.85 | 3.47 | 3.05 | 2.96 |
(1) | Excludes distributed income of equity investees. |
(2) | Includes interest capitalized and related amortization for our nonregulated segments. |
Name of Subsidiary | State of Incorporation | |
AGL Capital Corporation | Nevada | |
AGL Investments Inc. | Georgia | |
Sequent LLC | Georgia | |
Atlanta Gas Light Company | Georgia | |
Georgia Natural Gas Company | Georgia | |
SouthStar Energy Services LLC (2) | Delaware | |
NUI Corporation | New Jersey | |
Pivotal Utility Holdings Inc. (3) | New Jersey | |
Ottawa Acquisition LLC | Illinois | |
Northern Illinois Gas Company (4) | Illinois |
(1) | The names of certain subsidiaries have not been included because, considered in the aggregate as a single subsidiary, they would not constitute a significant subsidiary. |
(2) | 85% owned by Georgia Natural Gas Company. |
(3) | Includes operations of three natural gas utilities: Elizabethtown Gas (New Jersey), Florida City Gas (Florida) and Elkton Gas (Maryland). |
(4) | Doing business as Nicor Gas Company. |
1. | I have reviewed this annual report on Form 10-K of AGL Resources Inc.; |
2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; |
4. | The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: |
(a) | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
(b) | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
(c) | Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
(d) | Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and |
5. | The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): |
(a) | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and |
(b) | Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. |
Date: February 11, 2016 | /s/ Andrew W. Evans |
President and Chief Executive Officer |
1. | I have reviewed this annual report on Form 10-K of AGL Resources Inc.; |
2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; |
4. | The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: |
(a) | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
(b) | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
(c) | Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
(d) | Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and |
5. | The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): |
(a) | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and |
(b) | Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. |
Date: February 11, 2016 | /s/ Elizabeth W. Reese |
Executive Vice President and Chief Financial Officer |
(1) | the Form 10-K for the year ended December 31, 2015 (the “Report”), which accompanies this certification, fully complies with the requirements of Section 13(a) or 15(d), as applicable, of the Securities Exchange Act of 1934; and |
(2) | the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of AGL Resources Inc. |
Date: February 11, 2016 | /s/ Andrew W. Evans |
President and Chief Executive Officer |
(1) | the Form 10-K for the year ended December 31, 2015 (the “Report”), which accompanies this certification, fully complies with the requirements of Section 13(a) or 15(d), as applicable, of the Securities Exchange Act of 1934; and |
(2) | the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of AGL Resources Inc. |
Date: February 11, 2016 | /s/ Elizabeth W. Reese |
Executive Vice President and Chief Financial Officer |
Document and Entity Information - USD ($) |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2015 |
Feb. 05, 2016 |
Jun. 30, 2015 |
|
Document and Entity Information [Abstract] | |||
Entity Registrant Name | AGL RESOURCES INC. | ||
Document Type | 10-K | ||
Current Fiscal Year End Date | --12-31 | ||
Entity Common Stock, Shares Outstanding | 120,384,325 | ||
Entity Public Float | $ 5,591,017,687 | ||
Amendment Flag | false | ||
Entity Central Index Key | 0001004155 | ||
Entity Current Reporting Status | Yes | ||
Entity Voluntary Filers | No | ||
Entity Filer Category | Large Accelerated Filer | ||
Entity Well-known Seasoned Issuer | Yes | ||
Document Period End Date | Dec. 31, 2015 | ||
Document Fiscal Year Focus | 2015 | ||
Document Fiscal Period Focus | FY |
Consolidated Balance Sheets (Parentheticals) - $ / shares |
Dec. 31, 2015 |
Dec. 31, 2014 |
---|---|---|
Statement of Financial Position [Abstract] | ||
Common stock, par value (in dollars per share) | $ 5 | $ 5 |
Common stock, shares authorized | 750,000,000 | 750,000,000 |
Common stock, shares outstanding | 120,376,721 | 119,647,149 |
Treasury shares (in shares) | 216,523 | 216,523 |
Consolidated Statements of Income (Parentheticals) - USD ($) $ in Millions |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2015 |
Dec. 31, 2014 |
Dec. 31, 2013 |
|
Income Statement [Abstract] | |||
Operating revenues, revenue taxes | $ 103 | $ 133 | $ 112 |
Consolidated Statements of Comprehensive Income (Parentheticals) - USD ($) $ in Millions |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2015 |
Dec. 31, 2014 |
Dec. 31, 2013 |
|
Statement of Comprehensive Income [Abstract] | |||
Actuarial loss arising during the period, income tax | $ 0 | $ (48) | $ 46 |
Reclassification of losses to net benefit cost, income tax | 9 | 6 | 10 |
Reclassification of prior service costs to net benefit cost, income tax | 0 | 1 | 2 |
Net derivative instrument gains (losses) arising during the period, income tax | 3 | (2) | 1 |
Reclassification of realized derivative losses to net income, income tax | $ 1 | $ (2) | $ 1 |
Consolidated Statements of Equity (Parentheticals) - $ / shares |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2015 |
Dec. 31, 2014 |
Dec. 31, 2013 |
|
Statement of Stockholders' Equity [Abstract] | |||
Dividends on common stock, per share (in dollars per share) | $ 2.04 | $ 1.96 | $ 1.88 |
Organization and Basis of Presentation |
12 Months Ended |
---|---|
Dec. 31, 2015 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Organization and Basis of Presentation | Organization and Basis of Presentation General AGL Resources Inc. is an energy services holding company that conducts substantially all of its operations through its subsidiaries. Unless the context requires otherwise, references to “we,” “us,” “our,” the “company,” or “AGL Resources” mean consolidated AGL Resources Inc. and its subsidiaries. Basis of Presentation Our consolidated financial statements as of and for the period ended December 31, 2015 are prepared in accordance with GAAP and under the rules of the SEC. Our consolidated financial statements include our accounts, the accounts of our wholly owned subsidiaries and the accounts of our VIE for which we are the primary beneficiary. For unconsolidated entities that we do not control, we use the equity method of accounting and our proportionate share of income or loss is recorded on our Consolidated Statements of Income. See Note 11 for additional information. We have eliminated intercompany profits and transactions in consolidation except for intercompany profits where recovery of such amounts is probable under the affiliates’ rate regulation process. In September 2014, we closed on the sale of Tropical Shipping, which operated within our former cargo shipping segment and whose financial results for the years ended December 31, 2014 and 2013 are reflected as discontinued operations on the Consolidated Statements of Income. Amounts shown in the following notes, unless otherwise indicated, exclude discontinued operations. See Note 15 for additional information on the sale of Tropical Shipping. Certain amounts from prior periods have been reclassified to conform to the current period presentation. The reclassifications had no material impact on our prior period balances. |
Proposed Merger with Southern Company |
12 Months Ended |
---|---|
Dec. 31, 2015 | |
Business Combinations [Abstract] | |
Proposed Merger with Southern Company | Proposed Merger with Southern Company On August 23, 2015, we entered into the Merger Agreement with Southern Company and a new wholly owned subsidiary of Southern Company (Merger Sub), providing for the merger of Merger Sub with and into AGL Resources, with us surviving as a wholly owned subsidiary of Southern Company. At the effective time of the merger, which is expected to occur in the second half of 2016, each share of our common stock, other than certain excluded shares, will convert into the right to receive $66 in cash, without interest, less any applicable withholding taxes. Following the effective time of the merger, we will become a wholly owned, direct subsidiary of Southern Company. Completion of the merger remains subject to various closing conditions, including, among others (i) the receipt of required regulatory approvals from the Federal Communications Commission, California Public Utilities Commission, Georgia Commission, Illinois Commission, Maryland Commission, New Jersey BPU and Virginia Commission, and such approvals having become final orders and (iii) the absence of a judgment, order, decision, injunction, ruling or other finding or agency requirement of a governmental entity prohibiting the closing of the merger. At a special meeting of shareholders held on November 19, 2015, the proposed merger was approved by our shareholders. The waiting period under the Hart-Scott-Rodino Act expired on December 4, 2015. We and Southern Company have made joint filings seeking regulatory approval of the proposed merger with all of the required state regulatory agencies. The Merger Agreement contains certain termination rights for each party. In addition, the Merger Agreement, in certain circumstances, provides for the payment by AGL Resources of a $201 million termination fee to Southern Company and, in certain circumstances, provides for the reimbursement of expenses up to $5 million upon termination of the Merger Agreement (which reimbursement would reduce on a dollar-for-dollar basis any termination fee subsequently paid by us). As of December 31, 2015 we had recorded no liability for termination fees. In connection with this transaction, we recorded merger-related costs in the accompanying Consolidated Statements of Income of $44 million ($26 million, net of tax) for the year ended December 31, 2015. The transaction costs incurred to date are comprised of $24 million of additional stock-based compensation expense associated with the proposed merger as we remeasured our performance share unit awards based upon the increase in trading price of our common stock since the announcement of the Merger Agreement, $16 million of expenses associated with financial advisory, legal and other merger-related costs and $4 million of board of directors stock-based compensation related to the aforementioned increase in the trading price of our common stock. We treated these costs as tax deductible since the requisite closing conditions to the merger have not yet been satisfied. Once the merger is closed, we will evaluate the tax deductibility of these costs and reflect any non-deductible amounts in the effective tax rate. Additionally, subsequent to the announcement of the merger, AGL Resources and each member of the Board were named as defendants in four purported shareholder class action lawsuits relating to the merger, which were dismissed during the first quarter of 2016. |
Significant Accounting Policies and Methods of Application |
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Accounting Policies [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Significant Accounting Policies and Methods of Application | Significant Accounting Policies and Methods of Application Cash and Cash Equivalents Our cash and cash equivalents primarily consist of cash on deposit, money market accounts and certificates of deposit with original maturities of three months or less. Energy Marketing Receivables and Payables Wholesale services provides services to retail marketers, wholesale marketers, utility companies and industrial customers. These customers, also known as counterparties, utilize netting agreements that enable our wholesale services segment to net receivables and payables by counterparty upon settlement. Wholesale services also nets across product lines and against cash collateral, provided the master netting and cash collateral agreements include such provisions. While the amounts due from, or owed to, wholesale services’ counterparties are settled net, they are recorded on a gross basis in our Consolidated Balance Sheets as energy marketing receivables and energy marketing payables. Our wholesale services segment has trade and credit contracts that contain minimum credit rating requirements. These credit rating requirements typically give counterparties the right to suspend or terminate credit if our credit ratings are downgraded to non-investment grade status. Under such circumstances, wholesale services would need to post collateral to continue transacting business with some of its counterparties. To date, our credit ratings have exceeded the minimum requirements. As of December 31, 2015 and 2014, the collateral that wholesale services would have been required to post if our credit ratings had been downgraded to non-investment grade status would not have had a material impact to our consolidated results of operations, cash flows or financial condition. If such collateral were not posted, wholesale services’ ability to continue transacting business with these counterparties would be negatively impacted. Wholesale services has a concentration of credit risk for services it provides to its counterparties. This credit risk is generally concentrated in 20 of its counterparties and is measured by 30-day receivable exposure plus forward exposure. We evaluate the credit risk of our counterparties using an S&P equivalent credit rating, which is determined by a process of converting the lower of the S&P or Moody’s rating to an internal rating ranging from 9 to 1, with 9 being equivalent to AAA/Aaa by S&P and Moody’s and 1 being equivalent to D/Default by S&P and Moody’s. A counterparty that does not have an external rating is assigned an internal rating based on the strength of its financial ratios. As of December 31, 2015, our top 20 counterparties represented 53%, or $196 million, of our total counterparty exposure and had a weighted average S&P equivalent rating of A-. We have established credit policies to determine and monitor the creditworthiness of counterparties, including requirements to post collateral or other credit security, as well as the quality of pledged collateral. Collateral or credit security is most often in the form of cash or letters of credit from an investment-grade financial institution, but may also include cash or U.S. government securities held by a trustee. When wholesale services is engaged in more than one outstanding derivative transaction with the same counterparty and it also has a legally enforceable netting agreement with that counterparty, the “net” mark-to-market exposure represents the netting of the positive and negative exposures with that counterparty combined with a reasonable measure of our credit risk. Wholesale services also uses other netting agreements with certain counterparties with whom it conducts significant transactions. Receivables and Allowance for Uncollectible Accounts Our other trade receivables consist primarily of natural gas sales and transportation services billed to residential, commercial, industrial and other customers. We bill customers monthly, and our accounts receivable are due within 30 days. For the majority of our receivables, we establish an allowance for doubtful accounts based on our collection experience and other factors. For our remaining receivables, if we are aware of a specific customer’s inability to pay, we record an allowance for doubtful accounts against amounts due to reduce the receivable balance to the amount we reasonably expect to collect. If circumstances change, our estimate of the recoverability of accounts receivable could change as well. Circumstances that could affect our estimates include, but are not limited to, customer credit issues, customer deposits and general economic conditions. Customers’ accounts are written off once we deem them to be uncollectible. Nicor Gas Credit risk exposure at Nicor Gas is mitigated by a bad debt rider approved by the Illinois Commission. The bad debt rider provides for the recovery from (or refund to) customers of the difference between Nicor Gas’ actual bad debt experience on an annual basis and the benchmark bad debt expense used to establish its base rates for the respective year. See Note 4 for additional information on the bad debt rider. Atlanta Gas Light Concentration of credit risk occurs at Atlanta Gas Light for amounts billed for services and other costs to its customers, which consist of 14 Marketers in Georgia. The credit risk exposure to Marketers varies seasonally, with the lowest exposure in the non-peak summer months and the highest exposure in the peak winter months. Marketers are responsible for the retail sale of natural gas to end-use customers in Georgia. The functions of the retail sale of gas include the purchase and sale of natural gas, customer service, billings and collections. We obtain credit security support in an amount equal to no less than two times a Marketer’s highest month’s estimated bill from Atlanta Gas Light. Inventories For our regulated utilities, except Nicor Gas, natural gas inventories and the inventories we hold for Marketers in Georgia are carried at cost on a WACOG basis. In Georgia’s competitive environment, Marketers sell natural gas to firm end-use customers at market-based prices. Part of the unbundling process, which resulted from deregulation and provides this competitive environment, is the assignment to Marketers of certain pipeline services that Atlanta Gas Light has under contract. On a monthly basis, Atlanta Gas Light assigns to Marketers the majority of the pipeline storage services that it has under contract, along with a corresponding amount of inventory. Atlanta Gas Light retains and manages a portion of its pipeline storage assets and related natural gas inventories for system balancing and to serve system demand. Nicor Gas’ inventory is carried at cost on a LIFO basis. Inventory decrements occurring during the year that are restored prior to year-end are charged to cost of goods sold at the estimated annual replacement cost. Inventory decrements that are not restored prior to year-end are charged to cost of goods sold at the actual LIFO cost of the layers liquidated. Since the cost of gas, including inventory costs, is charged to customers without markup, subject to Illinois Commission review, LIFO liquidations have no impact on net income. At December 31, 2015, the Nicor Gas LIFO inventory balance was $145 million. Based on the average cost of gas purchased in December 2015, the estimated replacement cost of Nicor Gas’ inventory at December 31, 2015 was $201 million, which exceeded the LIFO cost by $56 million. During 2015, we did not liquidate any of our LIFO-based inventory. Our retail operations, wholesale services and midstream operations segments carry inventory at LOCOM, where cost is determined on a WACOG basis. For these segments, we evaluate the weighted average cost of their natural gas inventories against market prices to determine whether any declines in market prices below the WACOG are other than temporary. As indicated in the following table, for any declines considered to be other than temporary, we recorded LOCOM adjustments to cost of goods sold to reduce the value of our natural gas inventories to market value.
Operational issues at a third-party storage facility during 2015 caused 5 Bcf of our inventory at wholesale services to be inaccessible. These operational issues at this facility have been resolved, and we began withdrawing the inventory in the fourth quarter of 2015. Our capacity contract with the facility expires at the end of the first quarter of 2016. At midstream operations, mechanical integrity tests and engineering studies are periodically performed on the storage facilities in accordance with certain state regulatory requirements. During 2014, an engineering study and mechanical integrity tests were performed at one of our storage facilities and identified a lower amount of working gas capacity due to naturally occurring shrinkage of the storage cavern. Further, based on the lower capacity and an analysis of the volume of natural gas stored in the facility, we recorded $10 million in additional natural gas costs for the year ended December 31, 2014 to true-up the amount of retained fuel at this facility. Other storage facilities at midstream operations were not impacted. Regulated Operations We account for the financial effects of regulation in accordance with authoritative guidance related to regulated entities whose rates are designed to recover the costs of providing service. In accordance with this guidance, incurred costs that would otherwise be charged to expense in the current period are capitalized as regulatory assets when it is probable that such costs will be recovered in rates in the future. Similarly, we recognize regulatory liabilities when it is probable that regulators will require customer refunds through future rates or when revenue is collected from customers for estimated expenditures that have not yet been incurred. Generally, regulatory assets and regulatory liabilities are amortized into our Consolidated Statements of Income over the period authorized by the regulatory agencies. Fair Value Measurements We have financial and nonfinancial assets and liabilities subject to fair value measurement. The financial assets and liabilities measured and carried at fair value include cash and cash equivalents and derivative instruments. The carrying values of receivables, short and long-term investments, accounts payable, short-term debt, other current assets and liabilities, and accrued interest approximate their respective fair value. Our nonfinancial assets and liabilities include pension and welfare benefits. See Note 5 for additional fair value disclosures. As defined in the authoritative guidance related to fair value measurements and disclosures, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). We utilize market data or assumptions that market participants would use in valuing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. We primarily apply the market approach for recurring fair value measurements to utilize the best available information. Accordingly, we use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. We classify fair value balances based on the observance of those inputs. The guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). The three levels of the fair value hierarchy defined by the guidance are as follows: Level 1 Quoted prices in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Our Level 1 items consist of exchange-traded derivatives, money market funds and certain retirement plan assets. Level 2 Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial and commodity instruments that are valued using valuation methodologies. These methodologies are primarily industry-standard methodologies that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. We obtain market price data from multiple sources in order to value some of our Level 2 transactions and this data is representative of transactions that occurred in the marketplace. Instruments in this category include shorter tenor exchange-traded and non-exchange-traded derivatives such as OTC forwards and options and certain retirement plan assets. Level 3 Pricing inputs include significant unobservable inputs that may be used with internally developed methodologies to determine management’s best estimate of fair value from the perspective of market participants. Level 3 instruments include those that may be more structured or otherwise tailored to customers’ needs. Our Level 3 assets, liabilities and any applicable transfers are primarily related to our pension and welfare benefit plan assets as described in Note 5 and Note 7. We determine both transfers into and out of Level 3 using values at the end of the interim period in which the transfer occurred. The authoritative guidance related to fair value measurements and disclosures also includes a two-step process to determine whether the market for a financial asset is inactive or a transaction is distressed. Currently, this authoritative guidance does not affect us, as our derivative instruments are traded in active markets. Derivative Instruments Our policy is to classify derivative cash flows and gains and losses within the same financial statement category as the hedged item, rather than by the nature of the instrument. Fair Value Hierarchy Derivative assets and liabilities are classified in their entirety into the previously described fair value hierarchy levels based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. The measurement of fair value incorporates various factors required under the guidance, which include not only the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits, letters of credit and priority interests), but also the impact of our own nonperformance risk on our liabilities. To mitigate the risk that a counterparty to a derivative instrument defaults on settlement or otherwise fails to perform under contractual terms, we have established procedures to monitor the creditworthiness of counterparties, seek guarantees or collateral backup in the form of cash or letters of credit and, in most instances, enter into netting arrangements. See Note 5 for additional fair value disclosures. Netting of Cash Collateral and Derivative Assets and Liabilities under Master Netting Arrangements We maintain accounts with brokers to facilitate financial derivative transactions in support of our energy marketing and risk management activities. Based on the value of our positions in these accounts and the associated margin requirements, we may be required to deposit cash into these broker accounts. We have elected to net derivative assets and liabilities under master netting arrangements on our Consolidated Balance Sheets. With that election, we are also required to offset cash collateral held in our broker accounts with the associated net fair value of the instruments in the accounts. See Note 5 for additional information about our cash collateral. Natural Gas and Weather Derivative Instruments The fair value of the natural gas derivative instruments that we use to manage exposures arising from changing natural gas prices and warmer-than-normal weather risk reflects the estimated amounts that we would receive or pay to terminate or close the contracts at the reporting date, taking into account the current unrealized gains or losses on open contracts. We use external market quotes and indices to value substantially all of our derivative instruments. See Note 6 for additional derivative disclosures. Distribution Operations Nicor Gas, subject to review by the Illinois Commission, and Elizabethtown Gas, in accordance with a directive from the New Jersey BPU, enter into derivative instruments to hedge the impact of market fluctuations in natural gas prices. In accordance with regulatory requirements, any realized gains or losses related to these derivatives are reflected in natural gas costs and ultimately included in billings to customers. As previously noted, such derivative instruments are reported at fair value each reporting period on our Consolidated Balance Sheets. Hedge accounting is not elected and, in accordance with accounting guidance pertaining to rate-regulated entities, unrealized changes in the fair value of these derivative instruments are deferred or accrued as regulatory assets or liabilities until the related revenue is recognized. For our weather risk associated with Nicor Gas, we have a corporate weather hedging program that utilizes weather derivatives to reduce the risk of lower operating margins potentially resulting from significantly warmer-than-normal weather in Illinois. These weather derivatives are carried at intrinsic value. We will continue to use available methods to mitigate our exposure to weather in Illinois. Retail Operations We have designated a portion of our derivative instruments, consisting of financial swaps to manage the risk associated with forecasted natural gas purchases and sales, as cash flow hedges. We record derivative gains or losses arising from cash flow hedges in OCI and reclassify them into earnings in the same period that the underlying hedged item is recognized in earnings. We currently have minimal hedge ineffectiveness, which occurs when the gains or losses on the hedging instrument more than offset the losses or gains on the hedged item. Any cash flow hedge ineffectiveness is recorded on our Consolidated Statements of Income in the period in which it occurs. We have not designated the remainder of our derivative instruments as hedges for accounting purposes and, accordingly, we record changes in the fair values of such instruments within cost of goods sold on our Consolidated Statements of Income in the period of change. We also enter into weather derivative contracts as economic hedges of operating margins in the event of warmer-than-normal weather in the Heating Season. Exchange-traded options are carried at fair value, with changes reflected in operating revenues. Non exchange-traded options are accounted for using the intrinsic value method. Changes in the intrinsic value for non exchange-traded contracts are also reflected in operating revenues in our Consolidated Statements of Income. Wholesale Services We purchase natural gas for storage when the current market price we pay to buy and transport natural gas plus the cost to store and finance the natural gas is less than the market price we can receive in the future, resulting in a positive net operating margin. We use NYMEX futures and OTC contracts to sell natural gas at that future price to substantially protect the operating margin we will ultimately realize when the stored natural gas is sold. We also enter into transactions to secure transportation capacity between delivery points in order to serve our customers and various markets. We use NYMEX futures and OTC contracts to capture the price differential or spread between the locations served by the capacity in order to substantially protect the operating margin we will ultimately realize when we physically flow natural gas between delivery points. These contracts generally meet the definition of derivatives and are carried at fair value on our Consolidated Balance Sheets, with changes in fair value recorded in operating revenues on our Consolidated Statements of Income in the period of change. These contracts are not designated as hedges for accounting purposes. The purchase, transportation, storage and sale of natural gas are accounted for on a weighted average cost or accrual basis, as appropriate, rather than on the fair value basis we utilize for the derivatives used to mitigate the natural gas price risk associated with our storage and transportation portfolio. We incur monthly demand charges for the contracted storage and transportation capacity and payments associated with asset management agreements, and we recognize these demand charges and payments on our Consolidated Statements of Income in the period they are incurred. This difference in accounting methods can result in volatility in our reported earnings, even though the economic margin is substantially unchanged from the dates the transactions were consummated. Debt We estimate the fair value of debt using a discounted cash flow technique that incorporates a market interest yield curve with adjustments for duration, optionality and risk profile. In determining the market interest yield curve, we consider our currently assigned ratings for unsecured debt and the secured rating for the Nicor Gas first mortgage bonds. See Note 5 for fair value disclosure. Property, Plant and Equipment A summary of our PP&E by classification as of December 31, 2015 and 2014 is provided in the following table.
Distribution Operations Our natural gas utilities’ PP&E consists of property and equipment that is currently in use, being held for future use and currently under construction. We report PP&E at its original cost, which includes:
We do not recognize any gains or losses on depreciable utility property that is retired or otherwise disposed, as required under the composite depreciation method. Such gains or losses are ultimately refunded to, or recovered from, customers through future rate adjustments. Our natural gas utilities also hold property, primarily land, that is not presently used and useful in utility operations and is not included in rate base. Upon sale, any gain or loss is recognized in other income. Retail Operations, Wholesale Services, Midstream Operations and Other PP&E includes property that is in use and under construction, and we report it at cost. We record a gain or loss within operation and maintenance expense for retired or otherwise disposed-of property. Natural gas in salt-dome storage at Jefferson Island and Golden Triangle that is retained as pad gas is classified as non-depreciable PP&E and is carried at cost. Central Valley has two types of pad gas in its depleted reservoir storage facility: the first is non-depreciable PP&E, which is carried at cost, and the second is non-recoverable, which is depreciated over the life of the storage facility. On April 11, 2014, we entered into two arrangements associated with the Dalton Pipeline. The first was a construction and ownership agreement through which we will have a 50% undivided ownership interest in the 106 mile Dalton Pipeline that will be constructed in Georgia and serve as an extension of the Transco natural gas pipeline system into northwest Georgia. We also entered into an agreement to lease our 50% undivided ownership in the Dalton Pipeline once it is placed in service. The lease payments to be received are $26 million annually for an initial term of 25 years. The lessee will be responsible for maintaining the pipeline during the lease term and for providing service to transportation customers under its FERC-regulated tariff. Engineering design work has commenced and construction is expected to begin in the second quarter of 2016. At December 31, 2015, our 50% share of construction costs was $33 million and is reflected in construction work in process on our Consolidated Balance Sheets. Depreciation Expense We compute depreciation expense for distribution operations by applying composite straight-line rates (approved by the state regulatory agencies) to the investment in depreciable property. More information on our rates used and the rate method is provided in the following table.
For our non-regulated segments, we compute depreciation expense on a straight-line basis over the following estimated useful lives of the assets.
AFUDC and Capitalized Interest AFUDC represents the estimated cost of funds, from both debt and equity sources, used to finance the construction of major projects and is capitalized in rate base for ratemaking purposes when the completed projects are placed in service. Atlanta Gas Light, Nicor Gas, Chattanooga Gas and Elizabethtown Gas are authorized by applicable state regulatory agencies or legislatures to capitalize the cost of debt and equity funds as part of the cost of PP&E construction projects on our Consolidated Balance Sheets. The capital expenditures of our other three utilities do not qualify for AFUDC treatment. More information on our authorized or actual AFUDC rates is provided in the following table.
Asset Retirement Obligations We record a liability at fair value for an asset retirement obligation (ARO) when a legal obligation to retire the asset has been incurred, with an offsetting increase to the carrying value of the related asset. Accretion of the ARO due to the passage of time is recorded as an operating expense. We have recorded an ARO of $3 million at December 31, 2015 and 2014 principally for our storage facilities. For our distribution PP&E, we cannot reasonably estimate the fair value of this obligation because we have determined that we have insufficient internal or industry information to reasonably estimate the potential settlement dates or costs. Impairment of Assets Our goodwill is not amortized, but is subject to an annual impairment test. Our other long-lived assets, including our finite-lived intangible assets, require an impairment review when events or circumstances indicate that the carrying amount may not be recoverable. We base our evaluation of the recoverability of other long-lived assets on the presence of impairment indicators such as the future economic benefit of the assets, any historical or future profitability measurements and other external market conditions or factors. Goodwill Our annual impairment test is performed at the reporting unit level during the fourth quarter of each year or more frequently if impairment indicators arise. Our 2014 annual goodwill impairment test indicated that the estimated fair value of our storage and fuels reporting unit, that had $14 million of goodwill, within our midstream operations segment exceeded its carrying value by less than 5% and would be at risk of failing step 1 of the goodwill impairment test if a further decline in the estimated fair value were to occur. While preparing our third quarter 2015 financial statements, and in connection with our 2016 annual budget process, we assessed various market factors and projections prepared by both internal and external sources related to subscription rates for contracting capacity at our storage facilities as well as the profitability of our storage and fuels reporting unit. Based on this assessment, we concluded that a decline in projected storage subscription rates as well as a reduction in the near-term projection of the reporting unit's profitability required us to perform an interim goodwill impairment test as of September 30, 2015. Step 1 of our interim goodwill impairment test compared the fair value of the reporting unit to its carrying value utilizing the income approach, under which the fair value was estimated based on the present value of estimated future cash flows discounted at an appropriate interest rate. The result of our step 1 test revealed that the estimated fair value of our storage and fuels reporting unit was below its carrying value. Step 2 of this interim goodwill impairment test compared the implied fair value of goodwill in our storage and fuels reporting unit, which was calculated as the residual amount from the reporting unit's overall fair value after assigning fair values to its assets and liabilities under a hypothetical purchase price allocation as if the reporting unit had been acquired in a business combination, to its carrying value. Based on the result of our step 2 test, we recorded a non-cash impairment charge of the full $14 million ($9 million, net of tax) of goodwill. For our 2015 annual goodwill impairment test of the remaining goodwill, we performed the qualitative step 0 assessment focusing on the following qualitative factors: macroeconomic conditions, industry and market conditions, cost factors, financial performance, entity specific events and events specific to each reporting unit. Our step 0 analysis concluded that it is more likely than not that the fair value of our reporting units that have goodwill exceeds their carrying amounts and a quantitative assessment was not required. The amounts of goodwill as of December 31, 2015 and 2014 are provided below.
Long-Lived Assets We depreciate or amortize our long-lived assets and other intangible assets, which are all located in the U.S., over their useful lives. We have no significant indefinite-lived intangible assets. These long-lived assets and other intangible assets are reviewed for impairment when events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. When such events or circumstances are present, we assess the recoverability of long-lived assets by determining whether the carrying value will be recovered through expected future cash flows. Impairment is indicated if the carrying amount of the long-lived asset exceeds the sum of the undiscounted future cash flows expected to result from the use and eventual disposition of the asset. If impairment is indicated, we record an impairment loss equal to the difference between the carrying value and the fair value of the long-lived asset. We determined that there were no long-lived asset impairments in 2015 or 2014; however, in 2013, we recorded an $8 million loss related to Sawgrass Storage. Intangible Assets Our intangible assets within our retail operations segment are presented in the following table and represent the estimated fair value at the date of acquisition of the acquired intangible assets in our businesses. As indicated previously, we perform an impairment review when impairment indicators are present. If present, we first determine whether the carrying amount of the asset is recoverable through the undiscounted future cash flows expected from the asset. If the carrying amount is not recoverable, we measure the impairment loss, if any, as the amount by which the carrying amount of the asset exceeds its fair value.
We amortize these intangible assets in a manner in which the economic benefits are consumed utilizing the undiscounted cash flows that were used in the determination of their fair values. Amortization expense was $18 million in 2015, $20 million in 2014 and $18 million in 2013. Amortization expense for the next five years is expected to be as follows:
Accounting for Retirement Benefit Plans We recognize the funded status of our plans as an asset or a liability on our Consolidated Balance Sheets, measuring the plans’ assets and obligations that determine our funded status as of the end of the fiscal year. We generally recognize, as a component of OCI, the changes in funded status that occurred during the year that are not yet recognized as part of net periodic benefit cost. Because substantially all of its retirement costs are recoverable through base rates, Nicor Gas defers the change in funded status that would normally be charged or credited to comprehensive income to a regulatory asset or liability until the period in which the costs are included in base rates, in accordance with the authoritative guidance for rate-regulated entities. The assets of our retirement plans are measured at fair value within the funded status and are classified in the fair value hierarchy in their entirety based on the lowest level of input that is significant to the fair value measurement. In determining net periodic benefit cost, the expected return on plan assets component is determined by applying our expected return on assets to a calculated asset value, rather than to the fair value of the assets as of the end of the previous fiscal year. For more information, see Note 7. In addition, we have elected to amortize gains and losses caused by actual experience that differ from our assumptions into subsequent periods. The amount to be amortized is the amount of the cumulative gain or loss as of the beginning of the year, excluding those gains and losses not yet reflected in the calculated value, that exceeds 10 percent of the greater of the benefit obligation or the calculated asset value. The amortization period is the average remaining service period of active employees. Taxes Income Taxes The reporting of our assets and liabilities for financial accounting purposes differs from the reporting for income tax purposes. The principal difference between net income and taxable income relates to the timing of deductions, primarily due to the benefits of tax depreciation since we generally depreciate assets for tax purposes over a shorter period of time than for book purposes. The determination of our provision for income taxes requires significant judgment, the use of estimates, and the interpretation and application of complex tax laws. Significant judgment is required in assessing the timing and amounts of deductible and taxable items. We report the tax effects of depreciation and other temporary differences as deferred income tax assets or liabilities on our Consolidated Balance Sheets. We have current and deferred income taxes on our Consolidated Statements of Income. Current income tax expense consists of federal and state income tax less applicable tax credits related to the current year. Deferred income tax expense is generally equal to the changes in the deferred income tax liability and regulatory tax liability during the year. Accumulated Deferred Income Tax Assets and Liabilities As noted above, we report some of our assets and liabilities differently for financial accounting purposes than for income tax purposes. We report the tax effects of the differences in those items as deferred income tax assets or liabilities on our Consolidated Balance Sheets. We measure these deferred income tax assets and liabilities using enacted income tax rates. With the sale of Tropical Shipping in the third quarter of 2014, we determined that the cumulative foreign earnings of that business would no longer be indefinitely reinvested offshore. Accordingly, we recognized income tax expense of $60 million in 2014 related to the cumulative foreign earnings for which no tax liabilities had been previously recorded, resulting in our repatriation of $86 million in cash. Refer to Note 15 for additional information. Income Tax Benefits The authoritative guidance related to income taxes requires us to determine whether tax benefits claimed or expected to be claimed on our tax return should be recorded in our consolidated financial statements. Under this guidance, we may recognize the tax benefit from an uncertainty in income taxes only if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position should be measured based upon the largest benefit that has a greater than 50% likelihood of being realized upon ultimate settlement. Uncertainty in Income Taxes We recognize accrued interest related to uncertainty in income taxes in interest expense and penalties in operating expense on our Consolidated Statements of Income. Tax Collections We do not collect income taxes from our customers on behalf of governmental authorities. However, we do collect and remit various other taxes on behalf of various governmental authorities. We record these amounts on our Consolidated Balance Sheets. In other instances, we are allowed to recover from customers other taxes that are imposed upon us. We record such taxes as operating expenses and record the corresponding customer charges as operating revenues on our Consolidated Statements of Income. Revenues Distribution operations We record revenues when goods or services are provided to customers. Those revenues are based on rates approved by the state regulatory agencies of our utilities. As required by the Georgia Commission, Atlanta Gas Light bills Marketers in equal monthly installments for each residential, commercial and industrial end-use customer’s distribution costs. Additionally, as required by the Georgia Commission, Atlanta Gas Light bills Marketers for capacity costs utilizing a seasonal rate design for the calculation of each residential end-use customer’s annual straight-fixed-variable charge, which reflects the historic volumetric usage pattern for the entire residential class. Generally, this seasonal rate design results in billing the Marketers a higher capacity charge in the winter months and a lower charge in the summer months, which impacts our operating cash flows. However, this seasonal billing requirement does not impact our revenues, which are recognized on a straight-line basis, because the associated rate mechanism ensures that we ultimately collect the full annual amount of the straight-fixed-variable charges. All of our utilities, with the exception of Atlanta Gas Light, have rate structures that include volumetric rate designs that allow the opportunity to recover certain costs based on gas usage. Revenues from sales and transportation services are recognized in the same period in which the related volumes are delivered to customers. Revenues from residential and certain commercial and industrial customers are recognized on the basis of scheduled meter readings. Additionally, unbilled revenues are recognized for estimated deliveries of gas not yet billed to these customers, from the last bill date to the end of the accounting period. For other commercial and industrial customers and for all wholesale customers, revenues are based on actual deliveries to the end of the period. The tariffs for Virginia Natural Gas, Elizabethtown Gas and Chattanooga Gas contain WNAs that partially mitigate the impact of unusually cold or warm weather on customer billings and operating margin. The WNAs have the effect of reducing customer bills when winter weather is colder-than-normal and increasing customer bills when weather is warmer-than-normal. In addition, the tariffs for Virginia Natural Gas, Chattanooga Gas and Elkton Gas contain revenue normalization mechanisms that mitigate the impact of conservation and declining customer usage. Revenue Taxes We charge customers for gas revenue and gas use taxes imposed on us and remit amounts owed to various governmental authorities. Our policy for gas revenue taxes is to record the amounts charged by us to customers, which for some taxes includes a small administrative fee, as operating revenues, and to record the related taxes imposed on us as operating expenses on our Consolidated Statements of Income. Our policy for gas use taxes is to exclude these taxes from revenue and expense, aside from a small administrative fee that is included in operating revenues as the tax is imposed on the customer. As a result, the amount recorded in operating revenues will exceed the amount recorded in operating expenses by the amount of administrative fees that are retained by the company. Revenue taxes included in operating expenses were $101 million in 2015, $130 million in 2014 and $110 million in 2013. Retail operations Revenues from natural gas sales and transportation services are recognized in the same period in which the related volumes are delivered to customers. Sales revenues from residential and certain commercial and industrial customers are recognized on the basis of scheduled meter readings. In addition, unbilled revenues are recognized for estimated deliveries of gas not yet billed to these customers, from the most recent meter reading date to the end of the accounting period. For other commercial and industrial customers and for all wholesale customers, revenues are based on actual deliveries during the period. We recognize revenues on 12-month utility-bill management contracts as the lesser of cumulative earned or cumulative billed amounts. We recognize revenues for warranty and repair contracts on a straight-line basis over the contract term. Revenues for maintenance services are recognized at the time such services are performed. Wholesale services Revenues from energy and risk management activities are required under authoritative guidance to be netted with the associated costs. Profits from sales between segments are eliminated and are recognized as goods or services sold to end-use customers. Transactions that qualify as derivatives under authoritative guidance related to derivatives and hedging are recorded at fair value with changes in fair value recognized in earnings in the period of change and characterized as unrealized gains or losses. Gains and losses on derivatives held for energy trading purposes are required to be presented net in revenue. Midstream operations We record operating revenues for storage and transportation services in the period in which volumes are transported and storage services are provided. The majority of our storage services are covered under medium to long-term contracts at fixed market-based rates. We recognize our park and loan revenues ratably over the life of the contract. Cost of Goods Sold Distribution operations Excluding Atlanta Gas Light, which does not sell natural gas to end-use customers, we charge our utility customers for natural gas consumed using natural gas cost recovery mechanisms set by the state regulatory agencies. Under these mechanisms, all prudently incurred natural gas costs are passed through to customers without markup, subject to regulatory review. In accordance with the authoritative guidance for rate-regulated entities, we defer or accrue (that is, include as an asset or liability on the Consolidated Balance Sheets and exclude from, or include on, the Consolidated Statements of Income, respectively) the difference between the actual cost of goods sold and the amount of commodity revenue earned in a given period, such that no operating margin is recognized related to these costs. The deferred or accrued amount is either billed or refunded to our customers prospectively through adjustments to the commodity rate. Deferred natural gas costs are reflected as regulatory assets and accrued natural gas costs are reflected as regulatory liabilities. For more information, see Note 4. Retail operations Our retail operations customers are charged for actual or estimated natural gas consumed. Within our cost of goods sold, we also include costs of fuel and lost and unaccounted for gas, adjustments to reduce the value of our inventories to market value and gains and losses associated with certain derivatives. Costs to service our warranty and repair contract claims are recorded to cost of goods sold. Operating Leases We have certain operating leases with provisions for step rent or escalation payments and certain lease concessions. We account for these leases by recognizing the future minimum lease payments on a straight-line basis over the respective minimum lease terms, in accordance with authoritative guidance related to leases. This accounting treatment does not affect the future annual operating lease cash obligations. For more information, see Note 12. Other Income Our other income is detailed in the following table. For more information on our equity investment income, see Note 11.
Non-Wholly Owned Entities We hold ownership interests in a number of business ventures with varying ownership structures. We evaluate all of our partnership interests and other variable interests to determine if each entity is a VIE, as defined in the authoritative accounting guidance. If a venture is a VIE for which we are the primary beneficiary, we consolidate the assets, liabilities and results of operations of the entity. We reassess our conclusion as to whether an entity is a VIE upon certain occurrences, which are deemed reconsideration events under the guidance. We have concluded that the only venture that we are required to consolidate as a VIE, as we are the primary beneficiary, is SouthStar. On our Consolidated Balance Sheets, we recognize Piedmont’s share of SouthStar as a separate component of equity entitled “noncontrolling interest.” Piedmont’s share of current operations is reflected in “net income attributable to the noncontrolling interest” on our Consolidated Statements of Income. The consolidation of SouthStar has no effect on our calculation of basic or diluted earnings per common share amounts, which are based upon net income attributable to AGL Resources. For entities that are not determined to be VIEs, we evaluate whether we have control or significant influence over the investee to determine the appropriate consolidation and presentation. Generally, entities under our control are consolidated, and entities over which we can exert significant influence, but do not control, are accounted for under the equity method of accounting. However, we also invest in partnerships and limited liability companies that maintain separate ownership accounts. All such investments are required to be accounted for under the equity method unless our interest is so minor that there is virtually no influence over operating and financial policies, as are all investments in joint ventures. Investments accounted for under the equity method are included in long-term investments on our Consolidated Balance Sheets, and the equity income is recorded within other income on our Consolidated Statements of Income and was immaterial for all periods presented. For additional information, see Note 11. Earnings Per Common Share We compute basic earnings per common share attributable to AGL Resources by dividing our net income attributable to AGL Resources by the daily weighted average number of common shares outstanding. Diluted earnings per common share attributable to AGL Resources reflect the potential reduction in earnings per common share attributable to AGL Resources that occurs when potentially dilutive common shares are added to common shares outstanding. We derive our potentially dilutive common shares by calculating the number of shares issuable under restricted stock, restricted stock units and stock options award programs. The vesting of certain shares of the restricted stock and restricted stock units depends on the satisfaction of defined performance criteria and/or time-based criteria. The future issuance of shares underlying the outstanding stock options depends on whether the market price of the common shares underlying the options exceeds the respective exercise prices of the stock options. The following table shows the calculation of our diluted shares attributable to AGL Resources for the periods presented as if performance units currently earned under the plan ultimately vest and as if stock options currently exercisable at prices below the average market prices are exercised.
(1) Daily weighted average shares outstanding.
Sale of Compass Energy On May 1, 2013, we sold Compass Energy, a non-regulated retail natural gas business supplying commercial and industrial customers, within our wholesale services segment. We received an initial cash payment of $12 million, which resulted in an $11 million pre-tax gain ($5 million, net of tax). Under the terms of the purchase and sale agreement, we were 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 was to be received from the buyer annually over a five-year earn-out period based upon the financial performance of Compass Energy. In the third quarter of 2014, we negotiated with the buyer to settle the future earn-out payments and we received $4 million, resulting in the recognition of a $3 million gain. We have a five-year agreement through April 2018 to supply natural gas to our former customers and as a result of our continued involvement, the sale of Compass Energy did not meet the criteria for treatment as a discontinued operation in 2014. Use of Accounting Estimates The preparation of our financial statements in conformity with GAAP requires us to use judgment and make estimates that affect the reported amounts of assets, liabilities, revenues and expenses and the related disclosures. Our estimates are based on historical experience and various other assumptions that we believe to be reasonable under the circumstances. Our estimates may involve complex situations requiring a high degree of judgment either in the application and interpretation of existing literature or in the development of estimates that impact our financial statements. The most significant estimates relate to the accounting for our rate-regulated subsidiaries, uncollectible accounts and other allowances for contingent losses, goodwill and other intangible assets, retirement plan benefit obligations, derivative and hedging activities and provisions for income taxes. We evaluate our estimates on an ongoing basis and our actual results could differ from our estimates. Accounting Developments Accounting standards adopted in 2015 In April 2015, the FASB issued updated authoritative guidance related to debt issuance costs. The amendment modifies the presentation of unamortized debt issuance costs on our Consolidated Balance Sheets. Under the new guidance, we present such amounts as a direct deduction from the face amount of the debt, similar to unamortized debt discounts and premiums, rather than as an asset. Amortization of the debt issuance costs continues to be reported as interest expense on the Consolidated Statements of Income. While the guidance would have been effective for us beginning January 1, 2016, we elected to adopt its provisions effective April 1, 2015, and have applied its provisions to each prior period presented for comparative purposes. This new guidance resulted in an adjustment to the presentation of debt issuance costs primarily from other long-term assets to offset the related debt balances in long-term debt totaling $20 million and $21 million as of December 31, 2015 and 2014, respectively. The April 2015 guidance did not address the classification of debt issuance costs related to line-of-credit arrangements and, consequently, we continued to report such costs as assets subject to amortization over the term of the arrangement. In August 2015, the FASB issued clarifying guidance supporting the deferral and presentation of line-of-credit related debt issuance costs as an asset and subsequently amortizing these costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the arrangement. Other newly issued accounting standards and updated authoritative guidance In May 2014, the FASB issued updated authoritative guidance related to revenue from contracts with customers. The update replaces most of the existing guidance with a single set of principles for recognizing revenue from contracts with customers. In July 2015, the FASB delayed the effective date by one year and the guidance will now be effective for us beginning January 1, 2018. Early adoption of the standard is permitted, but not before the original effective date of December 15, 2016. The new guidance must be applied retrospectively to each prior period presented or via a cumulative effect upon the date of initial application. We have not yet determined the impact of this new guidance, nor have we selected a transition method. In June 2014, the FASB issued an update to authoritative guidance related to accounting for a stock-based compensation performance target that could be achieved after the requisite service period. The guidance was issued to resolve diversity in practice. The new guidance was applied prospectively and became effective for us beginning January 1, 2016. We have determined that this new guidance will not have a material impact on our consolidated financial statements. In February 2015, the FASB issued updated authoritative guidance related to the consolidation of other legal entities into our financial statements. The amendments modify aspects of the consolidation determination that could potentially impact us, including the analysis of limited partnerships and similar legal entities, fee arrangements, and related party relationships. The guidance became effective for us on January 1, 2016. We have determined that this new guidance will not have a material impact on our consolidated financial statements. In April 2015, the FASB issued authoritative guidance related to the accounting for fees paid in connection with arrangements with cloud-based software providers. Under the new guidance, unless a software arrangement includes specific elements enabling customers to possess and operate software on platforms other than that offered by the cloud-based provider, the cost of such arrangements is to be accounted for as an operating expense of the period incurred. The new guidance was applied prospectively and became effective for us on January 1, 2016. We have determined that this new guidance will not have a material impact on our consolidated financial statements. In May 2015, the FASB issued updated authoritative guidance to reduce the diversity in fair value measurements hierarchy disclosures. This amendment removes the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share. This guidance became effective for us on January 1, 2016. We have determined that this new guidance will not have a material impact on our consolidated financial statements. In July 2015, the FASB issued updated authoritative guidance to simplify the measurement of certain inventories. Under the new guidance, inventories are required to be measured at the lower of cost and net realizable value, the latter representing the estimated selling price in the ordinary course of business, reduced by costs of completion, disposal, and transportation. Under current guidance, inventories are required to be measured at the lower of cost or market, but depending upon specific circumstances, market could refer to replacement cost, net realizable value, or net realizable value reduced by a normal profit margin. The amendments do not apply to inventories carried on a LIFO basis, which for us applies only to our Nicor Gas inventories. The guidance is to be applied prospectively, is effective for us beginning January 1, 2017, and early adoption is permitted. We are currently evaluating the potential impact of this new guidance. In November 2015, the FASB issued updated authoritative guidance to the Balance Sheet Classification of Deferred Taxes, which requires companies to present deferred income tax assets and deferred income tax liabilities as noncurrent in a classified balance sheet instead of the current requirement to separate deferred income tax liabilities and assets into current and noncurrent amounts. The guidance is effective for us beginning January 1, 2017. Early application is permitted either prospectively or retrospectively. We have determined that this new guidance will not have a material impact on our consolidated financial statements. In January 2016, the FASB issued updated authoritative guidance related to classification and measurement of Financial Instruments. The amendments modify the accounting and presentation for certain financial liabilities and equity investments not consolidated or reported using the equity method. The guidance is effective for us beginning January 1, 2019; limited early adoption is permitted. We are currently evaluating the potential impact of this new guidance. |
Regulated Operations |
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Regulated Operations [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulated Operations | Regulated Operations Our regulatory assets and liabilities reflected within our Consolidated Balance Sheets as of December 31 are summarized in the following table.
Base rates are designed to provide the opportunity to recover cost and earn a return on investment during the period rates are in effect. As such, all of our regulatory assets recoverable through base rates are subject to review by the respective state regulatory agency during future rate proceedings. We are not aware of evidence that these costs will not be recoverable through either rate riders or base rates, and we believe that we will be able to recover such costs consistent with our historical recoveries. In the event that the provisions of authoritative guidance related to regulated operations were no longer applicable, we would recognize a write-off of regulatory assets that would result in a charge to net income. Additionally, while some regulatory liabilities would be written off, others would continue to be recorded as liabilities, but not as regulatory liabilities. Although the natural gas distribution industry is competing with alternative fuels, primarily electricity, our utility operations continue to recover their costs through cost-based rates established by the state regulatory agencies. As a result, we believe that the accounting prescribed under the guidance remains appropriate. It is also our opinion that all regulatory assets are recoverable in future rate proceedings, and therefore, we have not recorded any regulatory assets that are recoverable but are not yet included in base rates or contemplated in a rate rider or proceeding. The regulatory liabilities that do not represent revenue collected from customers for expenditures that have not yet been incurred are refunded to ratepayers through a rate rider or base rates. If the regulatory liability is included in base rates, the amount is reflected as a reduction to the rate base used to periodically set base rates. The majority of our regulatory assets and liabilities listed in the preceding table are included in base rates except for the regulatory infrastructure program costs, ERC, bad debt over collection, natural gas costs and energy efficiency costs, which are recovered through specific rate riders on a dollar-for-dollar basis. The rate riders that authorize the recovery of regulatory infrastructure program costs and natural gas costs include both a recovery of cost and a return on investment during the recovery period. Nicor Gas’ rate riders for environmental costs and energy efficiency costs provide a return of investment and expense including short-term interest on reconciliation balances. However, there is no interest associated with the under or over collections of bad debt expense. Nicor Gas’ pension and retiree welfare benefit costs have historically been considered in rate proceedings in the same period they are accrued under GAAP. As a regulated utility, Nicor Gas expects to continue rate recovery of the eligible costs of these defined benefit retirement plans and, accordingly, associated changes in the funded status of Nicor Gas’ plans have been deferred as a regulatory asset or liability until recognized in net income, instead of being recognized in OCI. The Illinois Commission presently does not allow Nicor Gas the opportunity to earn a return on its recoverable retirement benefit costs. Such costs are expected to be recovered over a period of approximately 10 years. The regulatory assets related to debt are also not included in rate base, but the costs are recovered over the term of the debt through the authorized rate of return component of base rates. Unrecognized Ratemaking Amounts The following table illustrates our authorized ratemaking amounts that are not recognized on our Consolidated Balance Sheets. These amounts are primarily composed of an allowed equity rate of return on assets associated with certain of our regulatory infrastructure programs. These amounts will be recognized as revenues in our financial statements in the periods they are billable to our customers.
Natural Gas Costs We charge our utility customers for natural gas consumed using natural gas cost recovery mechanisms established by the state regulatory agencies. Under these mechanisms, all prudently incurred natural gas costs are passed through to customers without markup, subject to regulatory review. We defer or accrue the difference between the actual cost of gas and the amount of commodity revenue earned in a given period, such that no operating margin is recognized related to these costs. The deferred or accrued amount is either billed or refunded to our customers prospectively through adjustments to the commodity rate. Environmental Remediation Costs We are subject to federal, state and local laws and regulations governing environmental quality and pollution control that 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, substantially all of which is related to former MGP sites. The ERC assets and liabilities are associated with our distribution operations segment and remediation costs are generally recoverable from customers through rate mechanisms approved by regulators. Accordingly, both costs incurred to remediate the former MGP sites, plus the future estimated cost recorded as liabilities, net of amounts previously collected, are recognized as a regulatory asset until recovered from customers. Our accrued environmental remediation liabilities are estimates of future remediation costs for investigation and cleanup of our current and former operating sites that are contaminated. These estimates are determined using engineering-based estimates and probabilistic models of potential costs when such estimates cannot be made, on an undiscounted basis. These estimates contain various assumptions, which we refine and update on an ongoing basis. These liabilities do not include other potential expenses, such as unasserted property damage claims, personal injury or natural resource damage claims, legal expenses or other costs for which we may be held liable but for which we cannot reasonably estimate an amount. Our accrued environmental remediation liabilities are not regulatory liabilities; however, the associated expenses are deferred as corresponding regulatory assets until the costs are recovered from customers. We primarily recover these deferred costs through three rate riders that authorize dollar-for-dollar recovery. We expect to collect $31 million in revenues over the next 12 months, which is reflected as a current regulatory asset. We recovered $40 million in 2015, $51 million in 2014 and $24 million in 2013 from our ERC rate riders. The following table provides additional information on the estimated costs to remediate our current and former operating sites as of December 31, 2015.
In July 2014, we reached a settlement with an insurance company for environmental claims relating to potential contamination at several MGP sites in New Jersey and North Carolina. The terms of the settlement required the insurance company to pay us a total of $77 million in two installments. We received a $45 million installment in the third quarter of 2014 and the remaining $32 million was paid in the second quarter of 2015. The New Jersey BPU has approved the use of the insurance proceeds to reduce the ERC expenditures that otherwise would have been recovered from our customers in future periods. This reduces our recoverable ERC regulatory assets and has a favorable impact on the rates for our Elizabethtown Gas customers. Bad Debt Rider Nicor Gas’ bad debt rider provides for the recovery from, or refund to, customers of the difference between Nicor Gas’ actual bad debt experience on an annual basis and a benchmark, as determined by the Illinois Commission in February 2010. The over recovery is recorded as an increase to operating expenses on our Consolidated Statements of Income and a regulatory liability on our Consolidated Balance Sheets until refunded to customers. In the period refunded, operating expenses are reduced and the regulatory liability is reversed. The actual bad debt experience and resulting refunds are shown in the following table.
Accumulated Removal Costs In accordance with regulatory treatment, our depreciation rates are comprised of two cost components - historical cost and the estimated cost of removal, net of estimated salvage, of certain regulated properties. We collect these costs in base rates through straight-line depreciation expense, with a corresponding credit to accumulated depreciation. Because the accumulated estimated removal costs are not a generally accepted component of depreciation, but meet the requirements of authoritative guidance related to regulated operations, we have reclassified them from accumulated depreciation to the accumulated removal cost regulatory liability on our Consolidated Balance Sheets. In the rate setting process, the liability for these accumulated removal costs is treated as a reduction to the net rate base upon which our regulated utilities have the opportunity to earn their allowed rate of return. Regulatory Infrastructure Programs We have infrastructure improvement programs at several of our utilities. Descriptions of these are as follows. Nicor Gas In 2013, Illinois enacted legislation that allows Nicor Gas to provide more widespread safety and reliability enhancements to its distribution system. The legislation stipulates that rate increases to customer bills as a result of any infrastructure investments shall not exceed an annual average of 4.0% of base rate revenues. In July 2014, the Illinois Commission approved our new regulatory infrastructure program, Investing in Illinois, for which we implemented rates under the program that became effective in March 2015. We filed the first annual update under the program with the Illinois Commission on April 1, 2015. Atlanta Gas Light Our four-year STRIDE program was approved in December 2013 and is comprised of the Integrated System Reinforcement Program (i-SRP), the Integrated Customer Growth Program (i-CGP), and the Integrated Vintage Plastic Replacement Program (i-VPR). The i-SRP is permitted to spend $445 million 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. 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. Our i-CGP authorizes Atlanta Gas Light to spend $91 million to extend its pipeline facilities to serve customers in areas without pipeline access and create new economic development opportunities in Georgia. The purpose of the i-VPR program is to replace aging plastic pipe that was installed primarily in the 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 2013, the Georgia Commission approved the replacement of 756 miles of vintage plastic pipe over four years at an estimated cost of $275 million. Additional reporting requirements and monitoring by the staff of the Georgia Commission were included in the approval of our STRIDE programs, which authorized a phased-in approach to funding the programs through monthly rider surcharges that began in 2015 and will remain through 2025. The orders for the STRIDE programs provide for recovery of all prudent costs incurred in the performance of the program. Atlanta Gas Light will recover from end-use customers, through billings to Marketers, the costs related to the programs net of any cost savings from the programs. All such amounts will be recovered through a combination of straight-fixed-variable rates and a STRIDE revenue rider surcharge. The regulatory asset represents recoverable incurred costs related to the programs that will be collected in future rates charged to customers through the rate riders. The future expected costs to be recovered through rates related to allowed, but not incurred costs, are recognized in an unrecognized ratemaking amount that is not reflected on our Consolidated Balance Sheets. This allowed cost is primarily the equity return on the capital investment under the program. Atlanta Gas Light capitalizes and depreciates the capital expenditure costs incurred from the STRIDE programs over the life of the assets. Operation and maintenance costs are expensed as incurred. Recoveries, which are recorded as revenue, are based on a formula that allows Atlanta Gas Light to recover operation and maintenance costs in excess of those included in its current base rates, depreciation expense and an allowed rate of return on capital expenditures. However, Atlanta Gas Light is allowed the recovery of carrying costs on the under-recovered balance resulting from the timing difference. Elizabethtown Gas In September 2015, Elizabethtown Gas filed the Safety, Modernization and Reliability Tariff (SMART) plan with the New Jersey BPU seeking approval to invest more than $1.1 billion to replace 630 miles of vintage cast iron, steel and copper pipeline, as well as 240 regulator stations. If approved, the program is expected to be completed by 2027. As currently proposed, costs incurred under the program would be recovered primarily through a rider surcharge over a period of 10 years. In 2009, the New Jersey BPU approved the enhanced infrastructure program for Elizabethtown Gas, which was created in response to the New Jersey Governor’s request for utilities to assist in the economic recovery by increasing infrastructure investments. In May 2011, the New Jersey BPU approved Elizabethtown Gas’ request to spend an additional $40 million under this program, the precursor to the accelerated infrastructure replacement program, before the end of 2012. Costs associated with the investment in this program are recovered through periodic adjustments to base rates that are approved by the New Jersey BPU. In August 2013, the New Jersey BPU approved the recovery of investments under this program through a permanent adjustment to base rates. Additionally, in August 2013, we received approval from the New Jersey BPU for an extension of the accelerated infrastructure replacement program, which allows for infrastructure investment of $115 million over four years, effective as of September 1, 2013. Carrying charges on the additional capital expenditures will be deferred at a WACC of 6.65%, of which 4.27% will be within unrecognized ratemaking amounts and will be recognized in future periods when recovered through rates. 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. In September 2013, Elizabethtown Gas filed for ENDURE, a program designed to improve our distribution system’s resiliency against coastal storms and floods. Under the proposed plan, Elizabethtown Gas invested $15 million in infrastructure and related facilities and communication planning over a one year period that began in January 2014. In July 2014, the New Jersey BPU approved a modified ENDURE plan that allowed Elizabethtown Gas to increase its base rates effective November 1, 2015 for investments made under the program. The program was completed in October 2015. Virginia Natural Gas In 2012, the Virginia Commission approved SAVE, an accelerated infrastructure replacement program, which is expected to be completed over a five-year period. The program permits a maximum 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 program costs through a rate rider that was effective August 1, 2012. The second year performance rate update was approved by the Virginia Commission in July 2014 and became effective as of August 2014. In November 2015, Virginia Natural Gas filed with the Virginia Commission for approval of an extension to the SAVE program through 2021, requesting approval of $30 million in 2016 and $35 million in each of 2017 through 2021. Florida City Gas The Florida Commission approved Florida City Gas' Safety, Access and Facility Enhancement program in September 2015. Under the program, Florida City Gas will spend approximately $10 million annually over a 10-year period on infrastructure relocation and enhancement projects. Costs incurred under the program will be recovered through a rate rider with annual rate adjustments and true-ups. In October 2015, Florida City Gas began spending under the program and plant in service associated with work in the fourth quarter of 2015 will be included in the calculation of rates beginning January 1, 2016. energySMART In May 2014, the Illinois Commission approved Nicor Gas’ energySMART, which outlines energy efficiency program offerings and therm reduction goals with spending of $93 million over a three-year period that began in June 2014. Nicor Gas’ first energy efficiency program ended in May 2014. Investment Tax Credits Deferred investment tax credits associated with distribution operations are included as a regulatory liability on our Consolidated Balance Sheets. These investment tax credits are being amortized over the estimated lives of the related properties as credits to income tax expense. Regulatory Income Tax Liability For our regulated utilities, we measure deferred income tax assets and liabilities using enacted income tax rates. Thus, when the statutory income tax rate declines before a temporary difference has fully reversed, the deferred income tax liability must be reduced to reflect the newly enacted income tax rates. However, the amount of the reduction is transferred to our regulatory income tax liability, which we are amortizing over the lives of the related properties as the temporary differences reverse over approximately 30 years. Other Regulatory Assets and Liabilities Our recoverable pension and retiree welfare benefit plan costs for our utilities other than Nicor Gas are expected to be recovered through base rates over the next 8 to 17 years, based on the remaining recovery periods as designated by the applicable state regulatory agencies. This category also includes recoverable seasonal rates, which reflect the difference between the recognition of a portion of Atlanta Gas Light’s residential base rates revenues on a straight-line basis as compared to the collection of the revenues over a seasonal pattern. These amounts are fully recoverable through base rates within one year. |
Fair Value Measurements |
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Fair Value Disclosures [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Fair Value Measurements | Fair Value Measurements Retirement benefit plans assets The assets of the AGL Resources Inc. Retirement Plan (AGL Plan) and the Health and Welfare Plan for Retirees and Inactive Employees of AGL Resources Inc. (AGL Welfare Plan) were allocated 72% equity and 28% fixed income at December 31, 2015, and 70% equity, 29% fixed income and 1% cash at December 31, 2014 compared to our targets of 70% to 95% equity, 5% to 20% fixed income, and up to 10% cash for both periods. The plans’ investment policies provide for some variation in these targets. The actual asset allocations of our retirement plans are presented in the following table by level within the fair value hierarchy.
The following is a reconciliation of our retirement plan assets in Level 3 of the fair value hierarchy.
Derivative Instruments The following table summarizes, by level within the fair value hierarchy, our derivative assets and liabilities that were carried at fair value, net of counterparty offset and collateral, on a recurring basis on our Consolidated Balance Sheets as of December 31. See Note 6 for additional information on our derivative instruments.
Debt Our long-term debt is recorded at amortized cost, with the exception of Nicor Gas’ first mortgage bonds, which are recorded at their acquisition-date fair value. We amortize the fair value adjustment of Nicor Gas’ first mortgage bonds over the lives of the bonds. The following table presents the carrying amount and fair value of our long-term debt as of December 31.
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Derivative Instruments |
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Derivative Instruments and Hedging Activities Disclosure [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Derivative Instruments | Derivative Instruments Our risk management activities are monitored by our Risk Management Committee, which consists of members of senior management and is charged with reviewing our risk management activities and enforcing policies. Our use of derivative instruments, including physical transactions, is limited to predefined risk tolerances associated with pre-existing or anticipated physical natural gas sales and purchases and system use and storage. We use the following types of derivative instruments and energy-related contracts to manage natural gas price, interest rate, weather, automobile fuel price and foreign currency risks when deemed appropriate:
Certain of our derivative instruments contain credit-risk-related or other contingent features that could require us to post collateral in the normal course of business when our financial instruments are in net liability positions. As of December 31, 2015 and 2014, for agreements with such features, derivative instruments with liability fair values totaled $46 million and $93 million, respectively, for which we had posted no collateral to our counterparties as we exceed the minimum credit rating requirements. As of December 31, 2015, the maximum collateral that could have been required with these features was $2 million. For additional information on our credit-risk-related contingent features, see “Energy Marketing Receivables and Payables” in Note 3 herein. Our derivative instrument activities are included within operating cash flows as an increase (decrease) to net income of $22 million, $(155) million and $66 million for the periods ended December 31, 2015, 2014 and 2013, respectively. The following table summarizes the various ways in which we account for our derivative instruments and the impact on our consolidated financial statements.
Our derivative instruments are comprised of both long and short natural gas positions. A long position is a contract to purchase natural gas, and a short position is a contract to sell natural gas. As of December 31, we had natural gas contracts outstanding in the following quantities:
Derivative Instruments on our Consolidated Balance Sheets In accordance with regulatory requirements, gains and losses on derivative instruments used in hedging activities of natural gas purchases for customer use at distribution operations are reflected in accrued natural gas costs within our Consolidated Balance Sheets until billed to customers. The following amounts deferred as a regulatory asset or liability on our Consolidated Balance Sheets represent the net realized gains (losses) related to these natural gas cost hedging activities as of December 31.
The following table presents the fair values and Consolidated Balance Sheets classifications of our derivative instruments as of December 31.
Derivative Instruments on our Consolidated Statements of Income The following table presents the impacts of our derivative instruments on our Consolidated Statements of Income for the years ended December 31.
Any amounts recognized in operating income related to ineffectiveness or due to a forecasted transaction that is no longer expected to occur were immaterial for the years ended December 31, 2015, 2014 and 2013. Our expected gains and losses to be reclassified from OCI into cost of goods sold, operation and maintenance expense, interest expense and operating revenues and recognized on our Consolidated Statements of Income over the next 12 months are $2 million. These deferred gains are related to natural gas derivative contracts associated with retail operations’ and Nicor Gas’ system use. The expected gains are based upon the fair values of these financial instruments at December 31, 2015. The effective portions of gains and losses on derivative instruments qualifying as cash flow hedges that were recognized in OCI during the periods are presented on our Consolidated Statements of Income. See Note 10 for these amounts. |
Employee Benefit Plans |
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Compensation and Retirement Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Employee Benefit Plans | Employee Benefit Plans Investment Policies, Strategies and Oversight of Plans The Retirement Plan Investment Committee (the Committee) appointed by our Board of Directors is responsible for overseeing the investments of our defined benefit retirement plan and welfare plan. Further, we have an Investment Policy (the Policy) for our pension and welfare benefit plans whose goal is to preserve these plans’ capital and maximize investment earnings in excess of inflation within acceptable levels of capital market volatility. To accomplish this goal, the plans’ assets are managed to optimize long-term return while maintaining a high standard of portfolio quality and diversification. In developing our allocation policy for the pension and welfare plan assets, we examined projections of asset returns and volatility over a long-term horizon. In connection with this analysis, we evaluated the risk and return trade-offs of alternative asset classes and asset mixes given long-term historical relationships as well as prospective capital market returns. We also conducted an asset-liability study to match projected asset growth with projected liability growth to determine whether there is sufficient liquidity for projected benefit payments. We developed our asset mix guidelines by incorporating the results of these analyses with an assessment of our risk posture, and taking into account industry practices. We periodically evaluate our investment strategy to ensure that plan assets are sufficient to meet the benefit obligations of the plans. As part of the ongoing evaluation, we may make changes to our targeted asset allocations and investment strategy. Our investment strategy is designed to meet the following objectives:
To achieve these investment objectives, our investment strategy is divided into two primary portfolios of return seeking and liability hedging assets. Return seeking assets are intended to provide investment returns in excess of liability growth and reduce deficits in the funded status of the plans, while liability hedging assets are intended to reflect the sensitivity of the liabilities to changes in discount rates. See Note 5 for a detailed listing of the investment types, amounts and percentages allocated to the plans. We will continue to diversify retirement plan investments to minimize the risk of large losses in a single asset class. We do not have a concentration of assets in a single entity, industry, country, commodity or class of investment fund. The Policy’s permissible investments include domestic and international equities (including convertible securities and mutual funds), domestic and international fixed income securities (corporate and government obligations), cash and cash equivalents and other suitable investments. Equity market performance and corporate bond rates have a significant effect on our reported funded status. Changes in the projected benefit obligation (PBO) and accumulated postretirement benefit obligation (APBO) are mainly driven by the assumed discount rate. Additionally, equity market performance has a significant effect on our market-related value of plan assets (MRVPA), which is used by the AGL Plan to determine the expected return on the plan assets component of net annual pension cost. The MRVPA is a calculated value. Gains and losses on plan assets are spread through the MRVPA based on the five-year smoothing weighted average methodology. Pension Benefits We sponsor the AGL Plan, which is a tax-qualified defined benefit retirement plan for the following classes of eligible employees: i) AGL Resources’ non-union employees who were employed before January 1, 2012, ii) AGL Resources’ union employees who were employed before January 1, 2013, iii) former Nicor employees who were employed before January 1, 1998, iv) former NUI employees who were employed on or before December 31, 2005, and v) Florida City Gas union employees as of February 1, 2008, who previously participated in a union-sponsored multiemployer plan. A defined benefit plan specifies the amount of benefits an eligible participant will eventually receive using information about the participant, including information related to the participant’s earnings history, years of service and age. Our employees who are not eligible for the AGL Plan are entitled to employer provided benefits under their defined contribution plan that exceeds the defined contribution benefits for those employees who participate in the defined benefit plan. The benefit formula for the former AGL Plan is currently a career average earnings formula. Participants who were employees as of July 1, 2000 and who were at least 50 years of age as of that date earned benefits until December 31, 2010 under a final average pay formula. Participants who were employed as of July 1, 2000, but did not satisfy the age requirement to continue under the final average earnings formula transitioned to the career average earnings formula on July 1, 2000. Prior to 2013, we also sponsored two other tax-qualified defined benefit retirement plans for our eligible employees, the Nicor plan and NUI plan, which were merged into the AGL Plan on December 31, 2012. The participants of these former plans are now being offered their benefits, as described below, through the AGL Plan. Participants in the former Nicor plan, employees hired before January 1, 1998, receive noncontributory defined pension benefits. Pension benefits are based on years of service and the highest average annual salary for management employees and job level for collectively bargained employees (referred to as pension bands). The benefit obligation related to collectively bargained benefits reflects the most recent collective bargained agreement terms with regards to the benefit increases. The former NUI plan included substantially all of NUI Corporation’s employees and provided pension benefits based on years of credited service and final average compensation as of the plan freeze date on December 31, 2005. Welfare Benefits We sponsor the AGL Welfare Plan, which is a defined benefit retiree health care plan for our eligible employees who reach the plan's retirement age while working for us or are receiving benefits under the AGL Resources sponsored long-term disability plan for the legacy AGL employees. This plan includes medical coverage and life insurance benefits for eligible employees: i) AGL Resources' employees who were employed as of June 30, 2002, and ii) former Nicor employees who were employed before March 18, 2014. Eligibility for these benefits is based on age and years of service. Prior to 2013, we also sponsored the Nicor Welfare Benefit Plan, which was terminated as of January 1, 2013. Participants under that plan became eligible to participate in the AGL Welfare Plan. This change in plan participation eligibility did not affect the benefit terms. The state regulatory agencies have approved phase-in plans that defer a portion of the related benefits expense for future recovery. Additionally, the plan terms include limits on the employer share of costs based on the coverage tier, hire date, plan elected and salary level of the employee at retirement. The former AGL Welfare Plan requires contributions by the retirees. Our medical costs are limited to a pre-determined cap amount and eligible retirees pay 100% of the dental and vision premiums. Medicare eligible retirees covered by the former AGL Welfare Plan, including all of those at least age 65, receive benefits through our contribution to a retiree health reimbursement arrangement account. Additionally, on the pre-65 medical coverage of the former AGL Welfare Plan, our expected cost is determined by a retiree premium schedule based on salary level and years of service. Due to the cost limits, there is no impact on our periodic benefit cost or on our accumulated projected benefit obligation for a change in the assumed healthcare cost trend rate for this portion of the plan. The former Nicor Welfare Plan requires contributions for certain categories of retirees. For employees hired on or after January 1, 1983, our medical costs are limited to a pre-determined cap amount based on their years of service at retirement. The Medicare Prescription Drug, Improvement and Modernization Act of 2003 provides for a prescription drug benefit under Medicare Part D, as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to Medicare Part D. Prescription drug coverage for the Nicor Gas Medicare-eligible population changed effective January 1, 2013 from an employer-sponsored prescription drug plan with the Retiree Drug Subsidy to an Employer Group Waiver Plan (EGWP). The EGWP replaces the employer-sponsored prescription drug plan. We also have a separate unfunded supplemental retirement health care plan that provides health care and life insurance benefits to employees of discontinued businesses. This plan is noncontributory with defined benefits. The APBO associated with this plan was $2 million at December 31, 2015 and $3 million at December 31, 2014. Assumptions We considered a variety of factors in determining and selecting our assumptions for the discount rates at December 31. In the fourth quarter of 2015, we changed the method we use to estimate the service and interest cost components of net periodic benefit cost for our defined benefit pension and other postretirement benefit plans. Historically, we estimated the service and interest cost components using a single weighted-average discount rate derived from the yield curve used to measure the benefit obligation at the beginning of the period. We have elected to use a full yield curve approach in the estimation of these components of benefit cost by applying the specific spot rates along the yield curve used in the determination of the benefit obligation to the relevant projected cash flows. The following table presents the components of our pension and welfare costs for the years ended December 31.
The following tables present details about our pension and welfare plans.
A portion of the net benefit cost or credit related to these plans has been capitalized as a cost of constructing gas distribution facilities and the remainder is included in operation and maintenance expense. Assumptions used to determine the health care benefit cost for the AGL Welfare Plan are set forth in the following table.
Assumed health care cost trend rates can have a significant effect on the amounts reported for the health care plans. A one percentage point change in the assumed health care cost trend rates for the AGL Welfare Plan would have the following effects on our benefit obligation, and there was no effect on our service and interest cost.
As a result of a cap on expected cost for the AGL Welfare Plan, a one percentage point increase or decrease in the assumed health care trend does not materially affect the Plan’s periodic benefit cost or accumulated benefit obligation. The effects presented above are related to the former Nicor Welfare Plan. The following table presents the amounts not yet reflected in net periodic benefit cost and included in net regulatory assets and accumulated OCI as of December 31, 2015 and 2014.
The 2016 estimated amortizations out of regulatory assets or accumulated OCI for these plans are set forth in the following table.
We recorded regulatory assets for anticipated future cost recoveries of $125 million and $122 million as of December 31, 2015 and 2014, respectively. The following table presents the gross benefit payments expected for the years ended December 31, 2016 through 2025 for our pension and welfare plans. There will be benefit payments under these plans beyond 2025.
Contributions Our employees generally do not contribute to our pension and welfare plans; however, most Nicor Gas and pre-65 AGL retirees make contributions to their health care plan. We fund the qualified pension plans by contributing at least the minimum amount required by applicable regulations and as recommended by our actuary. However, we may also contribute in excess of the minimum required amount. As required by The Pension Protection Act of 2006 (the Act), we calculate the minimum amount of funding using the traditional unit credit cost method. The Act contained new funding requirements for single-employer defined benefit pension plans and established a 100% funding target (over a 7-year amortization period) for plan years beginning after December 31, 2007. In 2015 and 2014, we had no required contributions to the merged AGL Plan. Employee Savings Plan Benefits We sponsor defined contribution retirement benefit plans that allow eligible participants to make contributions to their accounts up to specified limits. Under these plans, our matching contributions to participant accounts were $17 million in 2015, $17 million in 2014 and $14 million in 2013. |
Stock-based Compensation |
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Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Stock-based Compensation | Stock-Based Compensation General The AGL Resources Inc. Omnibus Performance Incentive Plan, as amended and restated, and the Long-Term Incentive Plan (1999) provide for the grant of incentive and nonqualified stock options, stock appreciation rights, shares of restricted stock, restricted stock units, performance cash awards and other stock-based awards to officers and key employees. Under the Omnibus Performance Incentive Plan, as of December 31, 2015, the number of shares issuable upon exercise of outstanding stock options, warrants and rights is 359,586 shares. Under the Long-Term Incentive Plan (1999), as of December 31, 2015, the number of shares issuable upon exercise of outstanding stock options, warrants and rights is 80,600 shares. The maximum number of shares available for future issuance under the Omnibus Performance Incentive Plan is 3,513,992 shares, which includes 1,514,116 shares previously available under the Nicor Inc. 2006 Long-Term Incentive Plan, as amended, pursuant to NYSE rules. No further grants will be made from the Long-Term Incentive Plan (1999) except for reload options that may be granted pursuant to the terms of certain outstanding options. Accounting Treatment and Compensation Expense We measure and recognize stock-based compensation expense for our stock-based awards over the requisite service period in our financial statements based on the estimated fair value at the date of grant for our stock-based awards using the modified prospective method. These stock awards include:
Performance-based stock awards and performance units contain market and performance conditions. Stock options, restricted stock awards and performance units also contain a service condition. We estimate forfeitures over the requisite service period when recognizing compensation expense. These estimates are adjusted to the extent that actual forfeitures differ, or are expected to materially differ, from such estimates. The authoritative guidance requires excess tax benefits to be reported as a financing cash inflow. The difference between the proceeds from the exercise of our stock-based awards and the par value of the stock is recorded within additional paid-in capital. We have granted stock awards with a grant price equal to the fair market value on the date of the grant. Fair market value is defined under the terms of the applicable plans as the closing price per share of AGL Resources common stock on the grant date. The following table provides additional information related to our cash and stock-based compensation awards.
Incentive and Nonqualified Stock Options The stock options we granted generally have a three-year vesting period and expire 10 years after the date of grant. Participants realize value from option grants only to the extent that the fair market value of our common stock on the date of exercise of the option exceeds the fair market value of the common stock on the date of the grant. As of December 31, 2015 and 2014, we had no unrecognized compensation costs related to stock options. Cash received from stock option exercises for 2015 and 2014 were $5 million and $9 million, respectively, and the income tax benefit from stock option exercises was immaterial for both years. The following tables summarize activity related to stock options for key employees and non-employee directors. As used in the table, intrinsic value for options means the difference between the current market value and the grant price.
We measure compensation cost related to stock options based on the fair value of these awards at their date of grant using the Black-Scholes option-pricing model. There were no options granted in 2015, 2014 and 2013. We use shares purchased under our 2006 share repurchase program to satisfy exercises to the extent that repurchased shares are available. Otherwise, we issue new shares from our authorized common stock. Performance Units In general, a performance unit is an award of the right to receive (i) an equal number of shares of our common stock, which we refer to as a restricted stock unit or (ii) cash, subject to the achievement of certain pre-established performance criteria, which we refer to as a performance cash unit. Performance units are subject to certain transfer restrictions and forfeiture upon termination of employment. The compensation cost of restricted stock unit awards is equal to the grant date fair value of the awards, recognized over the requisite service period, determined according to the authoritative guidance related to stock compensation. The compensation cost of performance cash unit awards is equal to the grant date fair value of the awards measured against progress towards the performance measure, recognized over the requisite service period. No other assumptions are used to value these awards. Restricted Stock Units In general, a restricted stock unit is an award that represents the opportunity to receive a specified number of shares of our common stock, subject to the achievement of certain pre-established performance criteria. In 2015 and 2014, we granted 47,546 and 44,272, respectively, of restricted stock units (including dividends) to certain employees, of which 65,042 were outstanding as of December 31, 2015. The 2015 grants had a performance measurement period that ended December 31, 2015. The performance measure, which related to earnings before interest, income tax, depreciation and amortization, was met. As such, the related restricted stock awards will be granted in 2016 and are subject to a four-year vesting schedule. Performance Share Unit Awards A performance share unit award represents the opportunity to receive cash and shares subject to the achievement of certain pre-established performance criteria. In 2015, 2014 and 2013, we granted performance share unit awards to certain officers. The 2015 performance share units have two performance measures. One measure, which accounts for 75%, relates to the company’s total shareholder return relative to a group of peer companies. The second measure, which accounts for 25%, relates to the company's earnings per share, excluding wholesale services, over the three-year performance period. The 2014 and 2013 performance share units were measured entirely based on the company’s total shareholder return relative to a group of peer companies. The recorded liability and maximum potential liability related to the 2015, 2014 and 2013 grants are as follows:
Stock and Restricted Stock Awards The compensation cost of both stock awards and restricted stock awards is equal to the grant date fair value of the awards, recognized over the requisite service period. No other assumptions are used to value the awards. We refer to restricted stock as an award of our common stock that is subject to time-based vesting or achievement of performance measures. Prior to vesting, restricted stock awards are subject to certain transfer restrictions and forfeiture upon termination of employment. Stock Awards - Non-Employee Directors Non-employee director compensation may be paid in shares of our common stock in connection with initial election, the annual retainer, and chair retainers, as applicable. Stock awards for non-employee directors are 100% vested and non-forfeitable as of the date of grant. During 2015, we issued 26,527 shares with a weighted average fair value of $50.71 to our non-employee directors. Restricted Stock Awards - Employees The following table summarizes the restricted stock awards activity for our employees during the last three years.
Employee Stock Purchase Plan (ESPP) We have a nonqualified, broad-based ESPP for all eligible employees. As of December 31, 2015, there were 315,570 shares available for future issuance under this plan. Employees may purchase shares of our common stock in quarterly intervals at 85% of fair market value, and we record an expense for the 15% purchase price discount. Employee ESPP contributions may not exceed $25,000 per employee during any calendar year. The following table provides additional information about our ESPP as of December 31.
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Debt and Credit Facilities |
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Debt Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Debt and Credit Facilities | Debt and Credit Facilities Our financing activities, including long-term and short-term debt, are subject to customary approval or review by state and federal regulatory bodies. Our wholly owned subsidiary, AGL Capital, was established to provide for our ongoing financing needs through a commercial paper program, the issuance of various debt and hybrid securities and other financing arrangements. We fully and unconditionally guarantee all debt issued by AGL Capital. Nicor Gas is not permitted by regulation to make loans to affiliates or utilize AGL Capital for its financing needs. The following table provides maturity dates or ranges, year-to-date weighted average interest rates and amounts outstanding for our various debt securities and facilities that are included on our Consolidated Balance Sheets.
Short-term Debt Our short-term debt at December 31, 2015 and 2014 was composed of borrowings under our commercial paper programs. Commercial Paper Programs We maintain commercial paper programs at AGL Capital and at Nicor Gas that consist of short-term, unsecured promissory notes used in conjunction with cash from operations to fund our seasonal working capital requirements. Working capital needs fluctuate during the year and are highest during the injection period in advance of the Heating Season. Nicor Gas' commercial paper program supports working capital needs at Nicor Gas, while all of our other subsidiaries and SouthStar participate in AGL Capital's commercial paper program. During 2015, our commercial paper maturities ranged from 1 to 63 days and at December 31, 2015, remaining terms to maturity ranged from 4 to 43 days. During 2015, total borrowings and repayments netted to a payment of $165 million. During 2015 there were no commercial paper issuances with original maturities over three months. Credit Facilities On October 30, 2015, we entered into agreements to amend and extend the AGL Credit Facility and Nicor Gas Credit Facility. Under the terms of these agreements, we extended the maturity dates of the AGL Credit Facility and the Nicor Gas Credit Facility to November 9, 2018 and December 14, 2018, respectively. One of the banks elected not to participate in this extension and its total commitment of $75 million will continue through the fourth quarter of 2017. We also modified the credit facilities to provide for the limited consent by the lenders to the proposed merger with Southern Company. Additionally, we made similar changes to our Bank Rate Mode Covenants Agreement. At December 31, 2015 and 2014, there were no outstanding borrowings under either the AGL Capital or Nicor Gas credit facility. Current Portion of Long-term Debt The current portion of our long-term debt at December 31, 2015 is composed of the portion of our long-term debt due within the next 12 months. Long-term Debt Our long-term debt at December 31, 2015 and 2014 consisted of medium-term notes: Series A, Series B, and Series C; senior notes; first mortgage bonds; and gas facility revenue bonds. We fully and unconditionally guarantee all of our senior notes and gas facility revenue bonds. Additionally, substantially all of Nicor Gas’ properties are subject to the lien of the indenture securing its first mortgage bonds. The majority of our long-term debt matures after fiscal year 2020. The annual maturities of our long-term debt for the next five years and thereafter are as follows:
Senior Notes On November 18, 2015 AGL Capital issued $250 million in 10-year senior notes at a fixed interest rate of 3.875%. The net proceeds from the senior notes, which are guaranteed by AGL Capital, were used to repay a portion of AGL Capital’s commercial paper, including $200 million we borrowed to repay our senior notes that matured on January 15, 2015. The balance of the net proceeds will be used for general corporate purposes, including capital expenditures associated with increased utility investment and construction of our new pipeline projects. On January 23, 2015, we executed $800 million in notional value of 10 year and 30 year fixed-rate forward-starting interest rate swaps to hedge potential interest rate volatility prior to our senior note issuance in the fourth quarter of 2015 and our anticipated issuances in 2016. We have designated the forward-starting interest rate swaps, which are settled on the respective debt issuance dates, as cash flow hedges. We settled $200 million of these interest rate swaps on November 18, 2015, in conjunction with the aforementioned senior note issuance, at which time we received $248 million in net proceeds that are classified as a financing activity on the Consolidated Statements of Cash Flow. The $2 million of debt issuance costs will be amortized to reduce interest expense over the remaining term of the senior notes. We performed a qualitative assessment of effectiveness as of December 31, 2015 and concluded that the remaining hedges are highly effective. First Mortgage Bonds We assumed the first mortgage bonds of Nicor Gas as a result of the 2011 merger with Nicor. Gas Facility Revenue Bonds We are party to a series of loan agreements with the New Jersey Economic Development Authority and Brevard County, Florida under which five series of gas facility revenue bonds have been issued. These revenue bonds are issued by state agencies or counties to investors, and proceeds from the issuance then are loaned to us. Financial and Non-Financial Covenants The AGL Credit Facility and the Nicor Gas Credit Facility each include a financial covenant that requires us to maintain a ratio of total debt to total capitalization of no more than 70% at the end of any month. The following table contains our debt-to-capitalization ratios as of December 31, which are below the maximum allowed.
The credit facilities contain certain non-financial covenants that, among other things, restrict liens and encumbrances, loans and investments, acquisitions, dividends and other restricted payments, asset dispositions, mergers and consolidations, and other matters customarily restricted in such agreements. Default Provisions Our credit facilities and other financial obligations include provisions that, if not complied with, could require early payment or similar actions. The most important default events include the following:
We have no triggering events in our debt instruments that are tied to changes in our specified credit ratings or our stock price and have not entered into any transaction that requires us to issue equity based on credit ratings or other triggering events. We were in compliance with all existing debt provisions and covenants, both financial and non-financial, as of December 31, 2015 and 2014. |
Equity |
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Stockholders' Equity Note [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Equity | Equity Preferred Securities At December 31, 2015 and 2014, we had 10 million shares of authorized, unissued Class A junior participating preferred stock, no par value, and 10 million shares of authorized, unissued preferred stock, no par value. Dividends Our common shareholders may receive dividends when declared at the discretion of our Board of Directors. Dividends may be paid in cash, stock or other form of payment, and payment of future dividends will depend on our future earnings, cash flow, financial requirements and other factors. Additionally, we derive a substantial portion of our consolidated assets, earnings and cash flow from the operation of regulated utility subsidiaries, whose legal authority to pay dividends or make other distributions to us is subject to regulation. As with most other companies, the payment of dividends is restricted by laws in the states where we conduct business. In certain cases, our ability to pay dividends to our common shareholders is limited by (i) our ability to pay our debts as they become due in the usual course of business and satisfy our obligations under certain financing agreements, including our debt-to-capitalization covenant, (ii) our ability to maintain total assets below total liabilities, and (iii) our ability to satisfy our obligations to any preferred shareholders. Accumulated Other Comprehensive Loss Our share of comprehensive income includes net income plus OCI (loss), which includes changes in fair value of certain derivatives designated as cash flow hedges, certain changes in pension and welfare benefit plans and reclassifications for amounts included in net income less net income, and OCI attributable to the noncontrolling interest. For more information on our derivative instruments, see Note 6. For more information on our pensions and retirement benefit obligations, see Note 7. Our OCI (loss) amounts are aggregated within accumulated other comprehensive loss on our Consolidated Balance Sheets. The following table provides changes in the components of our accumulated other comprehensive loss balances, net of the related income tax effects.
The following table provides details of the reclassifications out of accumulated other comprehensive loss and the favorable (unfavorable) impact on net income for the years ended December 31.
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Non-wholly Owned Entities |
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Equity Method Investments and Joint Ventures [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Non-Wholly Owned Entities | Non-Wholly Owned Entities Variable Interest Entities On a quarterly basis, we evaluate our variable interests in other entities, primarily ownership interests, to determine if they represent a variable interest entity (VIE) as defined by the authoritative accounting guidance on consolidation, and if so, which party is the primary beneficiary. We have determined that SouthStar, a joint venture owned by us and Piedmont, is our only VIE for which we are the primary beneficiary. This requires us to consolidate its assets, liabilities and Statements of Income. Our conclusion that SouthStar is a VIE resulted from our equal voting rights with Piedmont not being proportional to our economic obligation to absorb 85% of losses or residual returns from the joint venture. We account for our ownership of SouthStar in accordance with authoritative accounting guidance, which is described within Note 3. On December 9, 2015, we notified Piedmont of our election, in accordance with the change in control provisions in the Second Amended and Restated Limited Liability Company Agreement of SouthStar, to purchase its entire 15% interest in SouthStar at fair market value. The parties currently are negotiating final terms. SouthStar markets natural gas and related services under the trade name Georgia Natural Gas to customers in Georgia, and under various other trade names to customers in Illinois, Ohio, Florida, Maryland, Michigan and New York. Following are additional factors we considered in determining that we have the power to direct SouthStar’s activities that most significantly impact its performance. Operations Our wholly owned subsidiaries Nicor Gas and Atlanta Gas Light provide the following services, which affect SouthStar’s operations:
Liquidity and capital resources
Back office functions
SouthStar’s earnings are allocated entirely in accordance with the ownership interests and are seasonal in nature, with the majority occurring during the first and fourth quarters of each year. SouthStar’s current assets consist primarily of natural gas inventory, derivative instruments and receivables from its customers. SouthStar also has receivables from us due to its participation in AGL Capital’s commercial paper program. SouthStar’s current liabilities consist primarily of accrued natural gas costs, other accrued expenses, customer deposits, derivative instruments and payables to us from its participation in AGL Capital’s commercial paper program. SouthStar’s contractual commitments and obligations, including operating leases and agreements with third-party providers, do not contain terms that would trigger material financial obligations in the event that such contracts were terminated. As a result, our maximum exposure to a loss at SouthStar is considered to be immaterial. SouthStar’s creditors have no recourse to our general credit beyond our corporate guarantees that we have provided to SouthStar’s counterparties and natural gas suppliers. We have provided no financial or other support that was not previously contractually required. With the exception of our corporate guarantees and the aforementioned limited protections related to goodwill and intangible assets, we have not entered into any arrangements that could require us to provide financial support to SouthStar. Price and volume fluctuations of SouthStar’s natural gas inventories can cause significant variations in our working capital and cash flow from operations. Changes in our operating cash flows are also attributable to SouthStar’s working capital changes resulting from the impact of weather, the timing of customer collections, payments for natural gas purchases and cash collateral amounts that SouthStar maintains to facilitate its derivative instruments. Cash flows used in our investing activities include capital expenditures for SouthStar of $3 million, $7 million and $3 million for the years ended December 31, 2015, 2014 and 2013, respectively. Cash flows used in our financing activities include SouthStar’s distribution to Piedmont for its portion of SouthStar’s annual earnings from the previous year, which generally occurs in the first quarter of each fiscal year. For the years ended December 31, 2015, 2014 and 2013, SouthStar distributed $18 million, $17 million and $17 million, respectively, to Piedmont. On September 1, 2013, we contributed to SouthStar our Illinois retail energy businesses with approximately 108,000 customers. Additionally, Piedmont contributed to SouthStar $22.5 million in cash to maintain its 15% ownership in the joint venture. 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. Piedmont’s contribution is reflected as an increase to the noncontrolling interest on our Consolidated Balance Sheets and a financing activity on our Consolidated Statements of Cash Flows. These funds were used to reduce our commercial paper borrowings. The following table provides additional information on SouthStar’s assets and liabilities as of December 31, which are consolidated within our Consolidated Balance Sheets. The SouthStar amounts exclude intercompany eliminations and the balances of our wholly owned subsidiary with an 85% ownership interest in SouthStar.
The following table provides information on SouthStar’s operating revenues and operating expenses for the years ended December 31, which are consolidated within our Consolidated Statements of Income.
Equity Method Investments Triton We have an investment in Triton, a cargo container leasing company, which is included within our “other” non-reportable segment. Container equipment that is acquired by Triton is accounted for in tranches as defined in Triton’s operating agreement, and investors make capital contributions to Triton to invest in each of the tranches. As of December 31, 2015, we had invested in seven tranches established by Triton. Horizon Pipeline We own a 50% interest in a joint venture with Natural Gas Pipeline Company of America that is regulated by the FERC and is included within our midstream operations segment. Horizon Pipeline operates a 70-mile natural gas pipeline from Joliet, Illinois to near the Wisconsin/Illinois border. Nicor Gas typically contracts for 70% to 80% of the total capacity. Pipeline Development Investments In the third quarter of 2014, we entered into partnerships to form two new interstate pipeline companies within our midstream operations segment, as described below. The capacity from these pipelines will further enhance system reliability as well as provide access to a more diverse supply of natural gas. We have concluded that, at present, both companies are VIEs. We are not considered the primary beneficiary and, therefore, we have not consolidated the financial statements for these companies on our consolidated financial statements because we share in the ability to direct the activities that most significantly impact their economic performance with their other member companies. We have accounted for our investments in these companies using the equity method of accounting, and have classified the investments within other noncurrent assets on our Consolidated Balance Sheets. The contractual commitments and obligations, including agreements with third-party providers, of these VIEs for which we are not the primary beneficiary do not contain terms that would trigger material financial obligations in the event that such contracts were terminated. As a result, our maximum exposure to a loss is considered to be immaterial. PennEast Pipeline In August 2014, we entered into a partnership in which we hold a 20% ownership interest in an interstate pipeline company formed to develop and operate a 118-mile natural gas pipeline between New Jersey and Pennsylvania. The initial transportation capacity of 1.0 Bcf per day, which may be expanded to 1.2 Bcf per day, is under long-term contracts, mainly by public utilities and other market-serving entities, such as electric generation companies, in New Jersey, Pennsylvania and New York. Atlantic Coast Pipeline In September 2014, we entered into a project in which we hold a 5% ownership interest to develop and operate a 564-mile natural gas pipeline in North Carolina, Virginia and West Virginia with initial transportation capacity of 1.5 Bcf per day, which may be expanded to 2.0 Bcf per day. Sawgrass Storage We previously owned a 50% interest in Sawgrass Storage, a joint venture between us and a privately held energy exploration and production company for the development of an underground natural gas storage facility in Louisiana with 30 Bcf of working gas capacity that is included within our midstream operations segment. In December 2013, the joint venture decided to terminate the 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. This joint venture was dissolved in May 2015. The carrying amounts on our Consolidated Balance Sheets of our investments that are accounted for under the equity method at December 31 were as follows:
Income from our equity method investments is classified as other income on our Consolidated Statements of Income. The following table provides the income from our equity method investments for the years ended December 31. For more information on our other income, see Note 3.
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Commitments, Guarantees and Contingencies |
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Commitments and Contingencies Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Commitments, Guarantees and Contingencies | Commitments, Guarantees and Contingencies We incur various contractual obligations and financial commitments in the normal course of business that are reasonably likely to have a material effect on liquidity or the availability of capital resources. Contractual obligations include future cash payments required under existing contractual arrangements, such as debt and lease agreements. These obligations may result from both general financing activities and commercial arrangements that are directly supported by related revenue-producing activities. In April 2015, Nicor Gas entered into a series of natural gas purchase obligations in the ordinary course of business, which are reflected in the table below. The following table illustrates our expected future contractual payments under our obligations and other commitments as of December 31, 2015.
We are also involved in legal or administrative proceedings before various courts and agencies with respect to general claims, environmental remediation and other matters. Although we are unable to determine the ultimate outcomes of these contingencies, we believe that our financial statements appropriately reflect these amounts, including the recording of liabilities when a loss is probable and reasonably estimable. Contingencies and Guarantees Contingent financial commitments, such as financial guarantees, represent obligations that become payable only if certain predefined events occur. We have certain subsidiaries that enter into various financial and performance guarantees and indemnities providing assurance to third parties. We believe the likelihood of payment under our guarantees is remote. No liabilities have been recorded for such guarantees and indemnifications, as the fair values were inconsequential at inception. Financial guarantees AGL Equipment Leasing Inc. (AEL), a wholly owned subsidiary, holds our interest in Triton and has an obligation to restore to zero any deficit in its equity account for income tax purposes in the unlikely event that Triton is liquidated and a deficit balance remains. This obligation was not impacted by the 2014 sale of Tropical Shipping and continues for the life of the Triton partnerships. Any payment is effectively limited to the net assets of AEL, which were less than $1 million at December 31, 2015. We believe the likelihood of any such payment by AEL is remote and, as such, no liability has been recorded for this obligation. Indemnities In certain instances, we have undertaken to indemnify current property owners and others against costs associated with the effects and/or remediation of contaminated sites for which we may be responsible under applicable federal or state environmental laws, generally with no limitation as to the amount. These indemnifications relate primarily to ongoing coal tar cleanup, as discussed in the "Environmental Matters" section below. We believe that the likelihood of payment under our other environmental indemnifications is remote. No liability has been recorded for such indemnifications as the fair value was inconsequential at inception. Regulatory Matters In February 2015, Atlanta Gas Light made a filing with the Georgia Commission for a rate true-up of allowed unrecovered revenue of $178 million through December 2014 related to its PRP. In October 2015, Atlanta Gas Light received a final order from the Georgia Commission, which represented a resolution of all matters previously outstanding before the Georgia Commission, including a final determination of the true-up recovery related to the PRP. This order allows Atlanta Gas Light to recover $144 million of the $178 million unrecovered program revenue that was requested in its February 2015 filing. The remaining unrecovered amount relates primarily to recoveries of previously allowed rate of return amounts, which are included in our unrecognized ratemaking amount and does not have a material impact on our consolidated financial statements as of December 31, 2015. Provisions in the order resulted in the recognition of $1 million of interest expense related to the PRP true-up for the year ended December 31, 2015 on our Consolidated Statements of Income. We began recovering the $144 million in October 2015 through the monthly PRP surcharge, which increased by $0.82 on October 1, 2015 and will further increase by $0.81 on each of October 1, 2016 and October 1, 2017. The cumulative total monthly increase to the PRP surcharge will remain at $2.44 and be effective until the earlier of the full recovery of the under-recovered amount or December 31, 2025. During 2015 we recognized $2 million of revenue for this program. Additionally, one of the capital projects under the PRP experienced construction issues on certain segments in late 2013, and prior to these segments being placed into service it was necessary to complete mitigation work. The order from the Georgia Commission allows for the recovery of these mitigation costs in future base rates, but delayed such recovery until at least March 31, 2017. Provisions in the order resulted in the recognition of $5 million in operation and maintenance expense for the year ended December 31, 2015 on our Consolidated Statements of Income. Atlanta Gas Light continues to pursue contractual and legal claims against certain third-party contractors in connection with the mitigation costs incurred for construction issues experienced in finalizing the PRP. Any amounts recovered through the legal process will be retained by Atlanta Gas Light. At March 31, 2017, the total capitalized mitigation cost for which Atlanta Gas Light will seek recovery in future rates is approximately $28 million. In August 2014, staff of the Illinois Commission and the CUB filed testimony in the Nicor Gas 2003 gas cost prudence review disputing certain gas loan transactions offered by Nicor Gas under its Chicago Hub services and requesting refunds of $18 million and $22 million, respectively. We filed surrebuttal testimony in December 2014 disputing that any refund is due, as Nicor Gas was authorized to enter into these transactions and revenues associated with such transactions reduced ratepayers’ costs as either credits to the PGA or reductions to base rates consistent with then-current Illinois Commission orders governing these activities. In July 2015, the Administrative Law Judge issued a proposed order concluding that Nicor Gas’ supply costs and purchases in 2003 were prudent, its reconciliation of the related costs was proper, and the propositions by the staff of the Illinois Commission and the CUB were based on hindsight speculation, which is expressly prohibited in a prudence review examination. In September 2015, the Illinois Commission issued a final order approving the proposal of the Administrative Law Judge. In November 2015, the Illinois Commission granted the CUB's petition for a rehearing on this matter. In February 2016, the Administrative Law Judge issued a proposed order on rehearing affirming the original order by the Illinois Commission, which now requires approval by the Illinois Commission. In December 2012, we filed a petition with the Georgia Commission for approval to resolve a volumetric imbalance 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. In September 2014, we filed a stipulation that was entered between us, staff of the Georgia Commission and several Marketers that included a resolution of the 4.6 Bcf imbalance over a five-year period from January 1, 2015 through December 31, 2019, which was approved by the Georgia Commission in December 2014. During the first half of 2015, discretionary funds available to the Universal Service Fund, which is controlled by the Georgia Commission, were used to resolve their obligation of 25% of the imbalance, or approximately 1.15 Bcf of natural gas. Atlanta Gas Light was also obligated to resolve 25% of the 4.6 Bcf imbalance, or approximately 1.15 Bcf of natural gas, through system injections, which were fully replaced by September 30, 2015. Environmental Matters We are subject to federal, state and local laws and regulations governing environmental quality and pollution control that 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. See Note 4 for additional information on our environmental remediation costs. In September 2015, the EPA filed an administrative complaint and notice of opportunity for hearing against Nicor Gas. The complaint alleges violation of the regulatory requirements applicable to polychlorinated biphenyls in the Nicor Gas distribution system and the EPA seeks a total civil penalty of approximately $0.3 million. While we are unable to predict the ultimate outcome of this matter, the final disposition of this matter is not expected to have a material adverse impact on our liquidity or financial condition. Litigation We are involved in litigation arising in the normal course of business. Although in some cases we are unable to estimate the amount of loss reasonably possible in addition to any amounts already recognized, it is possible that the resolution of these contingencies, either individually or in aggregate, will require us to take charges against, or will result in reductions in, future earnings. Management believes that while the resolutions of these contingencies, whether individually or in aggregate, could be material to earnings in a particular period, they will not have a material adverse effect on our consolidated financial position or cash flows for the year. The company and each member of the Board were named as defendants in four purported shareholder class action lawsuits filed in the United States District Court for the Northern District of Georgia, Atlanta Division, which we refer to as the "Court": Patrick Baker v. AGL Resources Inc., et al., which we refer to as the "Baker Action", Jeff Morton v. AGL Resources Inc., et al., which we refer to as the "Morton Action", Sarah Halberstam and Baruch Z. Halberstam (as custodian for Benjamin Halberstam) v. AGL Resources Inc., et al., which we refer to as the "Halberstam Action", and Manuel Abt v. AGL Resources, Inc., et al., which we refer to as the "Abt Action", filed on September 16, 2015, September 22, 2015, September 28, 2015 and October 9, 2015, respectively. Southern Company and Merger Sub were also named as defendants in the Baker Action and the Morton Action. We refer to the Baker Action, the Morton Action, the Halberstam Action and the Abt Action, collectively, as the "Actions". The Actions alleged that our preliminary proxy statement contained false and misleading statements and omitted material information in violation of certain provisions under the Exchange Act. The Actions also alleged that the members of the Board were liable for those alleged misstatements and omissions. The Morton Action further alleged that the members of the Board breached their fiduciary duties owed to the shareholders of the company in connection with the merger and that Southern Company and Merger Sub aided and abetted such breaches. The Actions sought, among other things, preliminary and permanent injunctive relief enjoining the merger, rescission or rescissory damages in the event the merger is implemented and an award of attorneys' and experts' fees and costs. On October 23, 2015, the Court consolidated the four actions, and on January 5, 2016, the Court dismissed the consolidated action without prejudice. PBR Proceeding Nicor Gas’ PBR plan was a regulatory plan that provided economic incentives based on natural gas cost performance. The PBR plan went into effect in 2000 and was terminated effective January 1, 2003, following allegations that Nicor Gas acted improperly in connection with the plan. Under this plan, Nicor Gas’ total gas supply costs were compared to a market-sensitive benchmark. Savings and losses relative to the benchmark were determined annually and shared equally with sales customers. Since 2002, the amount of the savings and losses required to be shared has been disputed by the CUB and others, with the Illinois Attorney General (IAG) intervening, and subject to extensive contested discovery and other regulatory proceedings before administrative law judges and the Illinois Commission. In 2009, the staff of the Illinois Commission, IAG and CUB requested refunds of $85 million, $255 million and $305 million, respectively. In February 2012, we committed to a stipulation with the staff of the Illinois Commission for a resolution of the dispute through credits to Nicor Gas customers of $64 million. On November 5, 2012, the Administrative Law Judges issued a proposed order for a refund of $72 million to ratepayers. In the fourth quarter of 2012, we increased our accrual for this dispute by $8 million for a total of $72 million as a result of these developments and their effect on the estimated liability. In June 2013, the Illinois Commission issued an order requiring us to refund $72 million to current Nicor Gas customers through our PGA mechanism based upon natural gas throughput. All refunds were completed in the first half of 2014. The CUB's February 28, 2014 appeal of the Illinois Commission’s order requesting refunds consistent with its 2009 request was rejected by the appellate court in Illinois on March 18, 2015. |
Income Taxes |
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Income Taxes | Income Taxes Income Tax Expense The relative split between current and deferred taxes is due to a variety of factors, including true-ups of prior year tax returns, and most importantly, the timing of our property-related deductions. Components of income tax expense on the Consolidated Statements of Income are shown in the following table.
The reconciliations between the statutory federal income tax rate of 35%, the effective rate and the related amount of income tax expense for the years ended December 31, on our Consolidated Statements of Income are presented in the following table.
Accumulated Deferred Income Tax Assets and Liabilities We report some of our assets and liabilities differently for financial accounting purposes than we do for income tax purposes. We report the tax effects of the differences in those items as deferred income tax assets or liabilities on our Consolidated Balance Sheets. We measure the assets and liabilities using income tax rates that are currently in effect. The current portion of our deferred income taxes is recognized within current assets on our Consolidated Balance Sheets. We have provided a valuation allowance for some of these items that reduce our net deferred tax assets to amounts we believe are more likely than not to be realized in future periods. With respect to our continuing operations, we have net operating losses in various jurisdictions. Components that give rise to the net current and long-term accumulated deferred income tax liability are as follows.
Tax Benefits As of December 31, 2015 and December 31, 2014, we did not have a liability for unrecognized tax benefits. Based on current information, we do not anticipate that this will change materially in 2016. As of December 31, 2015, we did not have a liability recorded for payment of interest or penalties associated with uncertainty in income taxes, nor did we have any such interest or penalties during 2015 or 2014. We file a U.S. federal consolidated income tax return and various state income tax returns. We are no longer subject to income tax examinations by the Internal Revenue Service or in any state for years before 2012. |
Segment Information |
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Segment Reporting [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Segment Information | Segment Information Our reportable segments comprise revenue-generating components of the company for which we produce separate financial information internally that we regularly use to make operating decisions and assess performance. Our determination of reportable segments considers the strategic operating units under which we manage sales of various products and services to customers in differing regulatory environments. We manage our businesses through four reportable segments - distribution operations, retail operations, wholesale services and midstream operations. Our non-reportable segments are combined and presented as “other.” In September 2014, we sold Tropical Shipping, which historically operated within our cargo shipping segment. The financial results of these businesses for the years ended December 31, 2014 and 2013 are reflected as discontinued operations on the Consolidated Statements of Income. Amounts shown in this note for total assets as of December 31, 2013 exclude assets held for sale and other amounts shown, unless otherwise indicated, exclude discontinued operations. Cargo shipping also included our investment in Triton, which was not part of the sale and has been reclassified to a non-reportable segment. See Note 15 for additional information. Our distribution operations segment is the largest component of our business and includes natural gas local distribution utilities that construct, manage and maintain intrastate natural gas pipelines and distribution facilities in seven states. Although the operations of this segment are geographically dispersed, the operating subsidiaries within the segment are regulated utilities with rates determined by individual state regulatory agencies. These natural gas distribution utilities have similar economic and risk characteristics. We are also involved in several related and complementary businesses. Our retail operations segment includes retail natural gas marketing to end-use customers primarily in Georgia and Illinois. Additionally, retail operations provides home equipment protection products and services. Our wholesale services segment engages in natural gas storage and gas pipeline arbitrage and related activities. Additionally, this segment provides natural gas asset management and/or related logistics services for each of our utilities except Nicor Gas, as well as for non-affiliated companies. Our midstream operations segment includes our non-utility storage and pipeline operations, including the operation of high-deliverability natural gas storage assets. Our other segment includes subsidiaries that are not significant on a stand-alone basis and that do not align with one of our reportable segments. The chief operating decision maker of the company is the President and Chief Executive Officer, who utilizes EBIT as the primary measure of profit and loss in assessing the results of each segment’s operations. EBIT includes operating income and other income and expenses and excludes income taxes and interest expense, which we evaluate on a consolidated basis. Summarized statements of income, balance sheets and capital expenditure information by segment as of and for the years ended December 31 are shown in the following tables.
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Discontinued Operations |
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Discontinued Operations | Discontinued Operations In September 2014, we sold Tropical Shipping to an unrelated third party. The after-tax cash proceeds and distributions from the transaction were approximately $225 million. We determined that the cumulative foreign earnings of Tropical Shipping would no longer be indefinitely reinvested offshore. Accordingly, we recognized income tax expense of $60 million, of which $31 million was recorded in the first quarter of 2014, and the remaining $29 million was recorded in the third quarter of 2014 related to the cumulative foreign earnings for which no tax liabilities had been previously recorded, resulting in our repatriation of $86 million in cash. During the first quarter of 2014, based upon the negotiated sales price, we recorded a non-cash goodwill impairment charge of $19 million, for which there was no income tax benefit. Additionally, we recognized a total charge of $7 million in the second and third quarters of 2014 related to the suspension of depreciation and amortization on assets for which we were not compensated by the buyer. The financial results of these businesses are reflected as discontinued operations, and the prior periods presented have been recast to reflect the discontinued operations. The components of discontinued operations recorded on the Consolidated Statements of Income as of December 31, are as follows:
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Selected Quarterly Financial Data (Unaudited) |
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Quarterly Financial Information Disclosure [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Selected Quarterly Financial Data (Unaudited) | Selected Quarterly Financial Data (Unaudited) The variance in our quarterly earnings is primarily the result of the seasonal nature of the distribution of natural gas to customers, the volatility within our wholesale services segment and the sale of our cargo shipping segment in 2014. During the Heating Season, natural gas usage and operating revenues are generally higher at our distribution operations and retail operations segments as more customers are connected to our distribution systems and natural gas usage is higher in periods of colder weather. However, our base operating expenses, excluding cost of goods sold, interest expense and certain incentive compensation costs, are incurred relatively uniformly over any given year. Thus, our operating results can vary significantly from quarter to quarter as a result of seasonality. Our 2015 operating revenues and operating income were lower than 2014, primarily as a result of significantly colder-than-normal weather in 2014, lower volatility in the natural gas market and transportation constraints in the Northeast and Midwest. Our quarterly financial data for 2015 and 2014 are summarized below.
Our basic and diluted earnings per common share are calculated based on the weighted daily average number of common shares and common share equivalents outstanding during the quarter. Those totals differ from the basic and diluted earnings per common share attributable to AGL Resources common shareholders shown in the Consolidated Statements of Income, which are based on the weighted average number of common shares and common share equivalents outstanding during the entire year. |
Schedule II - Valuation and Qualifying Accounts |
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Valuation and Qualifying Accounts [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule II - Valuation and Qualifying Accounts | Schedule II AGL Resources Inc. and Subsidiaries VALUATION AND QUALIFYING ACCOUNTS - FOR EACH OF THE THREE YEARS IN THE PERIOD ENDED December 31, 2015.
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Significant Accounting Policies and Methods of Application (Policies) |
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Accounting Policies [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Cash and Cash Equivalents | Cash and Cash Equivalents Our cash and cash equivalents primarily consist of cash on deposit, money market accounts and certificates of deposit with original maturities of three months or less. |
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Energy Marketing Receivables And Payables | Energy Marketing Receivables and Payables Wholesale services provides services to retail marketers, wholesale marketers, utility companies and industrial customers. These customers, also known as counterparties, utilize netting agreements that enable our wholesale services segment to net receivables and payables by counterparty upon settlement. Wholesale services also nets across product lines and against cash collateral, provided the master netting and cash collateral agreements include such provisions. While the amounts due from, or owed to, wholesale services’ counterparties are settled net, they are recorded on a gross basis in our Consolidated Balance Sheets as energy marketing receivables and energy marketing payables. Our wholesale services segment has trade and credit contracts that contain minimum credit rating requirements. These credit rating requirements typically give counterparties the right to suspend or terminate credit if our credit ratings are downgraded to non-investment grade status. Under such circumstances, wholesale services would need to post collateral to continue transacting business with some of its counterparties. To date, our credit ratings have exceeded the minimum requirements. As of December 31, 2015 and 2014, the collateral that wholesale services would have been required to post if our credit ratings had been downgraded to non-investment grade status would not have had a material impact to our consolidated results of operations, cash flows or financial condition. If such collateral were not posted, wholesale services’ ability to continue transacting business with these counterparties would be negatively impacted. Wholesale services has a concentration of credit risk for services it provides to its counterparties. This credit risk is generally concentrated in 20 of its counterparties and is measured by 30-day receivable exposure plus forward exposure. We evaluate the credit risk of our counterparties using an S&P equivalent credit rating, which is determined by a process of converting the lower of the S&P or Moody’s rating to an internal rating ranging from 9 to 1, with 9 being equivalent to AAA/Aaa by S&P and Moody’s and 1 being equivalent to D/Default by S&P and Moody’s. A counterparty that does not have an external rating is assigned an internal rating based on the strength of its financial ratios. As of December 31, 2015, our top 20 counterparties represented 53%, or $196 million, of our total counterparty exposure and had a weighted average S&P equivalent rating of A-. We have established credit policies to determine and monitor the creditworthiness of counterparties, including requirements to post collateral or other credit security, as well as the quality of pledged collateral. Collateral or credit security is most often in the form of cash or letters of credit from an investment-grade financial institution, but may also include cash or U.S. government securities held by a trustee. When wholesale services is engaged in more than one outstanding derivative transaction with the same counterparty and it also has a legally enforceable netting agreement with that counterparty, the “net” mark-to-market exposure represents the netting of the positive and negative exposures with that counterparty combined with a reasonable measure of our credit risk. Wholesale services also uses other netting agreements with certain counterparties with whom it conducts significant transactions. |
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Receivables and Allowance for Uncollectible Accounts | Receivables and Allowance for Uncollectible Accounts Our other trade receivables consist primarily of natural gas sales and transportation services billed to residential, commercial, industrial and other customers. We bill customers monthly, and our accounts receivable are due within 30 days. For the majority of our receivables, we establish an allowance for doubtful accounts based on our collection experience and other factors. For our remaining receivables, if we are aware of a specific customer’s inability to pay, we record an allowance for doubtful accounts against amounts due to reduce the receivable balance to the amount we reasonably expect to collect. If circumstances change, our estimate of the recoverability of accounts receivable could change as well. Circumstances that could affect our estimates include, but are not limited to, customer credit issues, customer deposits and general economic conditions. Customers’ accounts are written off once we deem them to be uncollectible. Nicor Gas Credit risk exposure at Nicor Gas is mitigated by a bad debt rider approved by the Illinois Commission. The bad debt rider provides for the recovery from (or refund to) customers of the difference between Nicor Gas’ actual bad debt experience on an annual basis and the benchmark bad debt expense used to establish its base rates for the respective year. See Note 4 for additional information on the bad debt rider. Atlanta Gas Light Concentration of credit risk occurs at Atlanta Gas Light for amounts billed for services and other costs to its customers, which consist of 14 Marketers in Georgia. The credit risk exposure to Marketers varies seasonally, with the lowest exposure in the non-peak summer months and the highest exposure in the peak winter months. Marketers are responsible for the retail sale of natural gas to end-use customers in Georgia. The functions of the retail sale of gas include the purchase and sale of natural gas, customer service, billings and collections. We obtain credit security support in an amount equal to no less than two times a Marketer’s highest month’s estimated bill from Atlanta Gas Light. |
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Inventories | Inventories For our regulated utilities, except Nicor Gas, natural gas inventories and the inventories we hold for Marketers in Georgia are carried at cost on a WACOG basis. In Georgia’s competitive environment, Marketers sell natural gas to firm end-use customers at market-based prices. Part of the unbundling process, which resulted from deregulation and provides this competitive environment, is the assignment to Marketers of certain pipeline services that Atlanta Gas Light has under contract. On a monthly basis, Atlanta Gas Light assigns to Marketers the majority of the pipeline storage services that it has under contract, along with a corresponding amount of inventory. Atlanta Gas Light retains and manages a portion of its pipeline storage assets and related natural gas inventories for system balancing and to serve system demand. Nicor Gas’ inventory is carried at cost on a LIFO basis. Inventory decrements occurring during the year that are restored prior to year-end are charged to cost of goods sold at the estimated annual replacement cost. Inventory decrements that are not restored prior to year-end are charged to cost of goods sold at the actual LIFO cost of the layers liquidated. Since the cost of gas, including inventory costs, is charged to customers without markup, subject to Illinois Commission review, LIFO liquidations have no impact on net income. At December 31, 2015, the Nicor Gas LIFO inventory balance was $145 million. Based on the average cost of gas purchased in December 2015, the estimated replacement cost of Nicor Gas’ inventory at December 31, 2015 was $201 million, which exceeded the LIFO cost by $56 million. During 2015, we did not liquidate any of our LIFO-based inventory. Our retail operations, wholesale services and midstream operations segments carry inventory at LOCOM, where cost is determined on a WACOG basis. For these segments, we evaluate the weighted average cost of their natural gas inventories against market prices to determine whether any declines in market prices below the WACOG are other than temporary. As indicated in the following table, for any declines considered to be other than temporary, we recorded LOCOM adjustments to cost of goods sold to reduce the value of our natural gas inventories to market value.
Operational issues at a third-party storage facility during 2015 caused 5 Bcf of our inventory at wholesale services to be inaccessible. These operational issues at this facility have been resolved, and we began withdrawing the inventory in the fourth quarter of 2015. Our capacity contract with the facility expires at the end of the first quarter of 2016. At midstream operations, mechanical integrity tests and engineering studies are periodically performed on the storage facilities in accordance with certain state regulatory requirements. During 2014, an engineering study and mechanical integrity tests were performed at one of our storage facilities and identified a lower amount of working gas capacity due to naturally occurring shrinkage of the storage cavern. Further, based on the lower capacity and an analysis of the volume of natural gas stored in the facility, we recorded $10 million in additional natural gas costs for the year ended December 31, 2014 to true-up the amount of retained fuel at this facility. Other storage facilities at midstream operations were not impacted. |
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Regulated Operations | Regulated Operations We account for the financial effects of regulation in accordance with authoritative guidance related to regulated entities whose rates are designed to recover the costs of providing service. In accordance with this guidance, incurred costs that would otherwise be charged to expense in the current period are capitalized as regulatory assets when it is probable that such costs will be recovered in rates in the future. Similarly, we recognize regulatory liabilities when it is probable that regulators will require customer refunds through future rates or when revenue is collected from customers for estimated expenditures that have not yet been incurred. Generally, regulatory assets and regulatory liabilities are amortized into our Consolidated Statements of Income over the period authorized by the regulatory agencies. |
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Fair Value Measurements | Fair Value Measurements We have financial and nonfinancial assets and liabilities subject to fair value measurement. The financial assets and liabilities measured and carried at fair value include cash and cash equivalents and derivative instruments. The carrying values of receivables, short and long-term investments, accounts payable, short-term debt, other current assets and liabilities, and accrued interest approximate their respective fair value. Our nonfinancial assets and liabilities include pension and welfare benefits. See Note 5 for additional fair value disclosures. As defined in the authoritative guidance related to fair value measurements and disclosures, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). We utilize market data or assumptions that market participants would use in valuing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. We primarily apply the market approach for recurring fair value measurements to utilize the best available information. Accordingly, we use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. We classify fair value balances based on the observance of those inputs. The guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). The three levels of the fair value hierarchy defined by the guidance are as follows: Level 1 Quoted prices in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Our Level 1 items consist of exchange-traded derivatives, money market funds and certain retirement plan assets. Level 2 Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial and commodity instruments that are valued using valuation methodologies. These methodologies are primarily industry-standard methodologies that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. We obtain market price data from multiple sources in order to value some of our Level 2 transactions and this data is representative of transactions that occurred in the marketplace. Instruments in this category include shorter tenor exchange-traded and non-exchange-traded derivatives such as OTC forwards and options and certain retirement plan assets. Level 3 Pricing inputs include significant unobservable inputs that may be used with internally developed methodologies to determine management’s best estimate of fair value from the perspective of market participants. Level 3 instruments include those that may be more structured or otherwise tailored to customers’ needs. Our Level 3 assets, liabilities and any applicable transfers are primarily related to our pension and welfare benefit plan assets as described in Note 5 and Note 7. We determine both transfers into and out of Level 3 using values at the end of the interim period in which the transfer occurred. The authoritative guidance related to fair value measurements and disclosures also includes a two-step process to determine whether the market for a financial asset is inactive or a transaction is distressed. Currently, this authoritative guidance does not affect us, as our derivative instruments are traded in active markets. |
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Derivative Instruments | Derivative Instruments Our policy is to classify derivative cash flows and gains and losses within the same financial statement category as the hedged item, rather than by the nature of the instrument. Fair Value Hierarchy Derivative assets and liabilities are classified in their entirety into the previously described fair value hierarchy levels based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. The measurement of fair value incorporates various factors required under the guidance, which include not only the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits, letters of credit and priority interests), but also the impact of our own nonperformance risk on our liabilities. To mitigate the risk that a counterparty to a derivative instrument defaults on settlement or otherwise fails to perform under contractual terms, we have established procedures to monitor the creditworthiness of counterparties, seek guarantees or collateral backup in the form of cash or letters of credit and, in most instances, enter into netting arrangements. See Note 5 for additional fair value disclosures. Netting of Cash Collateral and Derivative Assets and Liabilities under Master Netting Arrangements We maintain accounts with brokers to facilitate financial derivative transactions in support of our energy marketing and risk management activities. Based on the value of our positions in these accounts and the associated margin requirements, we may be required to deposit cash into these broker accounts. We have elected to net derivative assets and liabilities under master netting arrangements on our Consolidated Balance Sheets. With that election, we are also required to offset cash collateral held in our broker accounts with the associated net fair value of the instruments in the accounts. See Note 5 for additional information about our cash collateral. Natural Gas and Weather Derivative Instruments The fair value of the natural gas derivative instruments that we use to manage exposures arising from changing natural gas prices and warmer-than-normal weather risk reflects the estimated amounts that we would receive or pay to terminate or close the contracts at the reporting date, taking into account the current unrealized gains or losses on open contracts. We use external market quotes and indices to value substantially all of our derivative instruments. See Note 6 for additional derivative disclosures. Distribution Operations Nicor Gas, subject to review by the Illinois Commission, and Elizabethtown Gas, in accordance with a directive from the New Jersey BPU, enter into derivative instruments to hedge the impact of market fluctuations in natural gas prices. In accordance with regulatory requirements, any realized gains or losses related to these derivatives are reflected in natural gas costs and ultimately included in billings to customers. As previously noted, such derivative instruments are reported at fair value each reporting period on our Consolidated Balance Sheets. Hedge accounting is not elected and, in accordance with accounting guidance pertaining to rate-regulated entities, unrealized changes in the fair value of these derivative instruments are deferred or accrued as regulatory assets or liabilities until the related revenue is recognized. For our weather risk associated with Nicor Gas, we have a corporate weather hedging program that utilizes weather derivatives to reduce the risk of lower operating margins potentially resulting from significantly warmer-than-normal weather in Illinois. These weather derivatives are carried at intrinsic value. We will continue to use available methods to mitigate our exposure to weather in Illinois. Retail Operations We have designated a portion of our derivative instruments, consisting of financial swaps to manage the risk associated with forecasted natural gas purchases and sales, as cash flow hedges. We record derivative gains or losses arising from cash flow hedges in OCI and reclassify them into earnings in the same period that the underlying hedged item is recognized in earnings. We currently have minimal hedge ineffectiveness, which occurs when the gains or losses on the hedging instrument more than offset the losses or gains on the hedged item. Any cash flow hedge ineffectiveness is recorded on our Consolidated Statements of Income in the period in which it occurs. We have not designated the remainder of our derivative instruments as hedges for accounting purposes and, accordingly, we record changes in the fair values of such instruments within cost of goods sold on our Consolidated Statements of Income in the period of change. We also enter into weather derivative contracts as economic hedges of operating margins in the event of warmer-than-normal weather in the Heating Season. Exchange-traded options are carried at fair value, with changes reflected in operating revenues. Non exchange-traded options are accounted for using the intrinsic value method. Changes in the intrinsic value for non exchange-traded contracts are also reflected in operating revenues in our Consolidated Statements of Income. Wholesale Services We purchase natural gas for storage when the current market price we pay to buy and transport natural gas plus the cost to store and finance the natural gas is less than the market price we can receive in the future, resulting in a positive net operating margin. We use NYMEX futures and OTC contracts to sell natural gas at that future price to substantially protect the operating margin we will ultimately realize when the stored natural gas is sold. We also enter into transactions to secure transportation capacity between delivery points in order to serve our customers and various markets. We use NYMEX futures and OTC contracts to capture the price differential or spread between the locations served by the capacity in order to substantially protect the operating margin we will ultimately realize when we physically flow natural gas between delivery points. These contracts generally meet the definition of derivatives and are carried at fair value on our Consolidated Balance Sheets, with changes in fair value recorded in operating revenues on our Consolidated Statements of Income in the period of change. These contracts are not designated as hedges for accounting purposes. The purchase, transportation, storage and sale of natural gas are accounted for on a weighted average cost or accrual basis, as appropriate, rather than on the fair value basis we utilize for the derivatives used to mitigate the natural gas price risk associated with our storage and transportation portfolio. We incur monthly demand charges for the contracted storage and transportation capacity and payments associated with asset management agreements, and we recognize these demand charges and payments on our Consolidated Statements of Income in the period they are incurred. This difference in accounting methods can result in volatility in our reported earnings, even though the economic margin is substantially unchanged from the dates the transactions were consummated. Debt We estimate the fair value of debt using a discounted cash flow technique that incorporates a market interest yield curve with adjustments for duration, optionality and risk profile. In determining the market interest yield curve, we consider our currently assigned ratings for unsecured debt and the secured rating for the Nicor Gas first mortgage bonds. See Note 5 for fair value disclosure. |
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Property, Plant and Equipment | Property, Plant and Equipment A summary of our PP&E by classification as of December 31, 2015 and 2014 is provided in the following table.
Distribution Operations Our natural gas utilities’ PP&E consists of property and equipment that is currently in use, being held for future use and currently under construction. We report PP&E at its original cost, which includes:
We do not recognize any gains or losses on depreciable utility property that is retired or otherwise disposed, as required under the composite depreciation method. Such gains or losses are ultimately refunded to, or recovered from, customers through future rate adjustments. Our natural gas utilities also hold property, primarily land, that is not presently used and useful in utility operations and is not included in rate base. Upon sale, any gain or loss is recognized in other income. Retail Operations, Wholesale Services, Midstream Operations and Other PP&E includes property that is in use and under construction, and we report it at cost. We record a gain or loss within operation and maintenance expense for retired or otherwise disposed-of property. Natural gas in salt-dome storage at Jefferson Island and Golden Triangle that is retained as pad gas is classified as non-depreciable PP&E and is carried at cost. Central Valley has two types of pad gas in its depleted reservoir storage facility: the first is non-depreciable PP&E, which is carried at cost, and the second is non-recoverable, which is depreciated over the life of the storage facility. On April 11, 2014, we entered into two arrangements associated with the Dalton Pipeline. The first was a construction and ownership agreement through which we will have a 50% undivided ownership interest in the 106 mile Dalton Pipeline that will be constructed in Georgia and serve as an extension of the Transco natural gas pipeline system into northwest Georgia. We also entered into an agreement to lease our 50% undivided ownership in the Dalton Pipeline once it is placed in service. The lease payments to be received are $26 million annually for an initial term of 25 years. The lessee will be responsible for maintaining the pipeline during the lease term and for providing service to transportation customers under its FERC-regulated tariff. Engineering design work has commenced and construction is expected to begin in the second quarter of 2016. At December 31, 2015, our 50% share of construction costs was $33 million and is reflected in construction work in process on our Consolidated Balance Sheets. Depreciation Expense We compute depreciation expense for distribution operations by applying composite straight-line rates (approved by the state regulatory agencies) to the investment in depreciable property. More information on our rates used and the rate method is provided in the following table.
For our non-regulated segments, we compute depreciation expense on a straight-line basis over the following estimated useful lives of the assets.
AFUDC and Capitalized Interest AFUDC represents the estimated cost of funds, from both debt and equity sources, used to finance the construction of major projects and is capitalized in rate base for ratemaking purposes when the completed projects are placed in service. Atlanta Gas Light, Nicor Gas, Chattanooga Gas and Elizabethtown Gas are authorized by applicable state regulatory agencies or legislatures to capitalize the cost of debt and equity funds as part of the cost of PP&E construction projects on our Consolidated Balance Sheets. The capital expenditures of our other three utilities do not qualify for AFUDC treatment. More information on our authorized or actual AFUDC rates is provided in the following table.
Asset Retirement Obligations We record a liability at fair value for an asset retirement obligation (ARO) when a legal obligation to retire the asset has been incurred, with an offsetting increase to the carrying value of the related asset. Accretion of the ARO due to the passage of time is recorded as an operating expense. We have recorded an ARO of $3 million at December 31, 2015 and 2014 principally for our storage facilities. For our distribution PP&E, we cannot reasonably estimate the fair value of this obligation because we have determined that we have insufficient internal or industry information to reasonably estimate the potential settlement dates or costs. |
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Impairment of Assets | Impairment of Assets Our goodwill is not amortized, but is subject to an annual impairment test. Our other long-lived assets, including our finite-lived intangible assets, require an impairment review when events or circumstances indicate that the carrying amount may not be recoverable. We base our evaluation of the recoverability of other long-lived assets on the presence of impairment indicators such as the future economic benefit of the assets, any historical or future profitability measurements and other external market conditions or factors. Goodwill Our annual impairment test is performed at the reporting unit level during the fourth quarter of each year or more frequently if impairment indicators arise. Our 2014 annual goodwill impairment test indicated that the estimated fair value of our storage and fuels reporting unit, that had $14 million of goodwill, within our midstream operations segment exceeded its carrying value by less than 5% and would be at risk of failing step 1 of the goodwill impairment test if a further decline in the estimated fair value were to occur. While preparing our third quarter 2015 financial statements, and in connection with our 2016 annual budget process, we assessed various market factors and projections prepared by both internal and external sources related to subscription rates for contracting capacity at our storage facilities as well as the profitability of our storage and fuels reporting unit. Based on this assessment, we concluded that a decline in projected storage subscription rates as well as a reduction in the near-term projection of the reporting unit's profitability required us to perform an interim goodwill impairment test as of September 30, 2015. Step 1 of our interim goodwill impairment test compared the fair value of the reporting unit to its carrying value utilizing the income approach, under which the fair value was estimated based on the present value of estimated future cash flows discounted at an appropriate interest rate. The result of our step 1 test revealed that the estimated fair value of our storage and fuels reporting unit was below its carrying value. Step 2 of this interim goodwill impairment test compared the implied fair value of goodwill in our storage and fuels reporting unit, which was calculated as the residual amount from the reporting unit's overall fair value after assigning fair values to its assets and liabilities under a hypothetical purchase price allocation as if the reporting unit had been acquired in a business combination, to its carrying value. Based on the result of our step 2 test, we recorded a non-cash impairment charge of the full $14 million ($9 million, net of tax) of goodwill. For our 2015 annual goodwill impairment test of the remaining goodwill, we performed the qualitative step 0 assessment focusing on the following qualitative factors: macroeconomic conditions, industry and market conditions, cost factors, financial performance, entity specific events and events specific to each reporting unit. Our step 0 analysis concluded that it is more likely than not that the fair value of our reporting units that have goodwill exceeds their carrying amounts and a quantitative assessment was not required. The amounts of goodwill as of December 31, 2015 and 2014 are provided below.
Long-Lived Assets We depreciate or amortize our long-lived assets and other intangible assets, which are all located in the U.S., over their useful lives. We have no significant indefinite-lived intangible assets. These long-lived assets and other intangible assets are reviewed for impairment when events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. When such events or circumstances are present, we assess the recoverability of long-lived assets by determining whether the carrying value will be recovered through expected future cash flows. Impairment is indicated if the carrying amount of the long-lived asset exceeds the sum of the undiscounted future cash flows expected to result from the use and eventual disposition of the asset. If impairment is indicated, we record an impairment loss equal to the difference between the carrying value and the fair value of the long-lived asset. We determined that there were no long-lived asset impairments in 2015 or 2014; however, in 2013, we recorded an $8 million loss related to Sawgrass Storage. Intangible Assets Our intangible assets within our retail operations segment are presented in the following table and represent the estimated fair value at the date of acquisition of the acquired intangible assets in our businesses. As indicated previously, we perform an impairment review when impairment indicators are present. If present, we first determine whether the carrying amount of the asset is recoverable through the undiscounted future cash flows expected from the asset. If the carrying amount is not recoverable, we measure the impairment loss, if any, as the amount by which the carrying amount of the asset exceeds its fair value.
We amortize these intangible assets in a manner in which the economic benefits are consumed utilizing the undiscounted cash flows that were used in the determination of their fair values. Amortization expense was $18 million in 2015, $20 million in 2014 and $18 million in 2013. Amortization expense for the next five years is expected to be as follows:
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Accounting for Retirement Benefit Plans | Accounting for Retirement Benefit Plans We recognize the funded status of our plans as an asset or a liability on our Consolidated Balance Sheets, measuring the plans’ assets and obligations that determine our funded status as of the end of the fiscal year. We generally recognize, as a component of OCI, the changes in funded status that occurred during the year that are not yet recognized as part of net periodic benefit cost. Because substantially all of its retirement costs are recoverable through base rates, Nicor Gas defers the change in funded status that would normally be charged or credited to comprehensive income to a regulatory asset or liability until the period in which the costs are included in base rates, in accordance with the authoritative guidance for rate-regulated entities. The assets of our retirement plans are measured at fair value within the funded status and are classified in the fair value hierarchy in their entirety based on the lowest level of input that is significant to the fair value measurement. In determining net periodic benefit cost, the expected return on plan assets component is determined by applying our expected return on assets to a calculated asset value, rather than to the fair value of the assets as of the end of the previous fiscal year. For more information, see Note 7. In addition, we have elected to amortize gains and losses caused by actual experience that differ from our assumptions into subsequent periods. The amount to be amortized is the amount of the cumulative gain or loss as of the beginning of the year, excluding those gains and losses not yet reflected in the calculated value, that exceeds 10 percent of the greater of the benefit obligation or the calculated asset value. The amortization period is the average remaining service period of active employees. |
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Taxes | Taxes Income Taxes The reporting of our assets and liabilities for financial accounting purposes differs from the reporting for income tax purposes. The principal difference between net income and taxable income relates to the timing of deductions, primarily due to the benefits of tax depreciation since we generally depreciate assets for tax purposes over a shorter period of time than for book purposes. The determination of our provision for income taxes requires significant judgment, the use of estimates, and the interpretation and application of complex tax laws. Significant judgment is required in assessing the timing and amounts of deductible and taxable items. We report the tax effects of depreciation and other temporary differences as deferred income tax assets or liabilities on our Consolidated Balance Sheets. We have current and deferred income taxes on our Consolidated Statements of Income. Current income tax expense consists of federal and state income tax less applicable tax credits related to the current year. Deferred income tax expense is generally equal to the changes in the deferred income tax liability and regulatory tax liability during the year. Accumulated Deferred Income Tax Assets and Liabilities As noted above, we report some of our assets and liabilities differently for financial accounting purposes than for income tax purposes. We report the tax effects of the differences in those items as deferred income tax assets or liabilities on our Consolidated Balance Sheets. We measure these deferred income tax assets and liabilities using enacted income tax rates. With the sale of Tropical Shipping in the third quarter of 2014, we determined that the cumulative foreign earnings of that business would no longer be indefinitely reinvested offshore. Accordingly, we recognized income tax expense of $60 million in 2014 related to the cumulative foreign earnings for which no tax liabilities had been previously recorded, resulting in our repatriation of $86 million in cash. Refer to Note 15 for additional information. Income Tax Benefits The authoritative guidance related to income taxes requires us to determine whether tax benefits claimed or expected to be claimed on our tax return should be recorded in our consolidated financial statements. Under this guidance, we may recognize the tax benefit from an uncertainty in income taxes only if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position should be measured based upon the largest benefit that has a greater than 50% likelihood of being realized upon ultimate settlement. Uncertainty in Income Taxes We recognize accrued interest related to uncertainty in income taxes in interest expense and penalties in operating expense on our Consolidated Statements of Income. Tax Collections We do not collect income taxes from our customers on behalf of governmental authorities. However, we do collect and remit various other taxes on behalf of various governmental authorities. We record these amounts on our Consolidated Balance Sheets. In other instances, we are allowed to recover from customers other taxes that are imposed upon us. We record such taxes as operating expenses and record the corresponding customer charges as operating revenues on our Consolidated Statements of Income. |
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Revenues | Revenues Distribution operations We record revenues when goods or services are provided to customers. Those revenues are based on rates approved by the state regulatory agencies of our utilities. As required by the Georgia Commission, Atlanta Gas Light bills Marketers in equal monthly installments for each residential, commercial and industrial end-use customer’s distribution costs. Additionally, as required by the Georgia Commission, Atlanta Gas Light bills Marketers for capacity costs utilizing a seasonal rate design for the calculation of each residential end-use customer’s annual straight-fixed-variable charge, which reflects the historic volumetric usage pattern for the entire residential class. Generally, this seasonal rate design results in billing the Marketers a higher capacity charge in the winter months and a lower charge in the summer months, which impacts our operating cash flows. However, this seasonal billing requirement does not impact our revenues, which are recognized on a straight-line basis, because the associated rate mechanism ensures that we ultimately collect the full annual amount of the straight-fixed-variable charges. All of our utilities, with the exception of Atlanta Gas Light, have rate structures that include volumetric rate designs that allow the opportunity to recover certain costs based on gas usage. Revenues from sales and transportation services are recognized in the same period in which the related volumes are delivered to customers. Revenues from residential and certain commercial and industrial customers are recognized on the basis of scheduled meter readings. Additionally, unbilled revenues are recognized for estimated deliveries of gas not yet billed to these customers, from the last bill date to the end of the accounting period. For other commercial and industrial customers and for all wholesale customers, revenues are based on actual deliveries to the end of the period. The tariffs for Virginia Natural Gas, Elizabethtown Gas and Chattanooga Gas contain WNAs that partially mitigate the impact of unusually cold or warm weather on customer billings and operating margin. The WNAs have the effect of reducing customer bills when winter weather is colder-than-normal and increasing customer bills when weather is warmer-than-normal. In addition, the tariffs for Virginia Natural Gas, Chattanooga Gas and Elkton Gas contain revenue normalization mechanisms that mitigate the impact of conservation and declining customer usage. Revenue Taxes We charge customers for gas revenue and gas use taxes imposed on us and remit amounts owed to various governmental authorities. Our policy for gas revenue taxes is to record the amounts charged by us to customers, which for some taxes includes a small administrative fee, as operating revenues, and to record the related taxes imposed on us as operating expenses on our Consolidated Statements of Income. Our policy for gas use taxes is to exclude these taxes from revenue and expense, aside from a small administrative fee that is included in operating revenues as the tax is imposed on the customer. As a result, the amount recorded in operating revenues will exceed the amount recorded in operating expenses by the amount of administrative fees that are retained by the company. Revenue taxes included in operating expenses were $101 million in 2015, $130 million in 2014 and $110 million in 2013. Retail operations Revenues from natural gas sales and transportation services are recognized in the same period in which the related volumes are delivered to customers. Sales revenues from residential and certain commercial and industrial customers are recognized on the basis of scheduled meter readings. In addition, unbilled revenues are recognized for estimated deliveries of gas not yet billed to these customers, from the most recent meter reading date to the end of the accounting period. For other commercial and industrial customers and for all wholesale customers, revenues are based on actual deliveries during the period. We recognize revenues on 12-month utility-bill management contracts as the lesser of cumulative earned or cumulative billed amounts. We recognize revenues for warranty and repair contracts on a straight-line basis over the contract term. Revenues for maintenance services are recognized at the time such services are performed. Wholesale services Revenues from energy and risk management activities are required under authoritative guidance to be netted with the associated costs. Profits from sales between segments are eliminated and are recognized as goods or services sold to end-use customers. Transactions that qualify as derivatives under authoritative guidance related to derivatives and hedging are recorded at fair value with changes in fair value recognized in earnings in the period of change and characterized as unrealized gains or losses. Gains and losses on derivatives held for energy trading purposes are required to be presented net in revenue. Midstream operations We record operating revenues for storage and transportation services in the period in which volumes are transported and storage services are provided. The majority of our storage services are covered under medium to long-term contracts at fixed market-based rates. We recognize our park and loan revenues ratably over the life of the contract. |
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Cost of Goods Sold | Cost of Goods Sold Distribution operations Excluding Atlanta Gas Light, which does not sell natural gas to end-use customers, we charge our utility customers for natural gas consumed using natural gas cost recovery mechanisms set by the state regulatory agencies. Under these mechanisms, all prudently incurred natural gas costs are passed through to customers without markup, subject to regulatory review. In accordance with the authoritative guidance for rate-regulated entities, we defer or accrue (that is, include as an asset or liability on the Consolidated Balance Sheets and exclude from, or include on, the Consolidated Statements of Income, respectively) the difference between the actual cost of goods sold and the amount of commodity revenue earned in a given period, such that no operating margin is recognized related to these costs. The deferred or accrued amount is either billed or refunded to our customers prospectively through adjustments to the commodity rate. Deferred natural gas costs are reflected as regulatory assets and accrued natural gas costs are reflected as regulatory liabilities. For more information, see Note 4. Retail operations Our retail operations customers are charged for actual or estimated natural gas consumed. Within our cost of goods sold, we also include costs of fuel and lost and unaccounted for gas, adjustments to reduce the value of our inventories to market value and gains and losses associated with certain derivatives. Costs to service our warranty and repair contract claims are recorded to cost of goods sold. |
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Operating Leases | Operating Leases We have certain operating leases with provisions for step rent or escalation payments and certain lease concessions. We account for these leases by recognizing the future minimum lease payments on a straight-line basis over the respective minimum lease terms, in accordance with authoritative guidance related to leases. This accounting treatment does not affect the future annual operating lease cash obligations. For more information, see Note 12. |
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Earnings Per Common Share | Earnings Per Common Share We compute basic earnings per common share attributable to AGL Resources by dividing our net income attributable to AGL Resources by the daily weighted average number of common shares outstanding. Diluted earnings per common share attributable to AGL Resources reflect the potential reduction in earnings per common share attributable to AGL Resources that occurs when potentially dilutive common shares are added to common shares outstanding. We derive our potentially dilutive common shares by calculating the number of shares issuable under restricted stock, restricted stock units and stock options award programs. The vesting of certain shares of the restricted stock and restricted stock units depends on the satisfaction of defined performance criteria and/or time-based criteria. The future issuance of shares underlying the outstanding stock options depends on whether the market price of the common shares underlying the options exceeds the respective exercise prices of the stock options. |
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Sale of Compass Energy | Sale of Compass Energy On May 1, 2013, we sold Compass Energy, a non-regulated retail natural gas business supplying commercial and industrial customers, within our wholesale services segment. We received an initial cash payment of $12 million, which resulted in an $11 million pre-tax gain ($5 million, net of tax). Under the terms of the purchase and sale agreement, we were 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 was to be received from the buyer annually over a five-year earn-out period based upon the financial performance of Compass Energy. In the third quarter of 2014, we negotiated with the buyer to settle the future earn-out payments and we received $4 million, resulting in the recognition of a $3 million gain. We have a five-year agreement through April 2018 to supply natural gas to our former customers and as a result of our continued involvement, the sale of Compass Energy did not meet the criteria for treatment as a discontinued operation in 2014. |
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Non-Wholly Owned Entities | Non-Wholly Owned Entities We hold ownership interests in a number of business ventures with varying ownership structures. We evaluate all of our partnership interests and other variable interests to determine if each entity is a VIE, as defined in the authoritative accounting guidance. If a venture is a VIE for which we are the primary beneficiary, we consolidate the assets, liabilities and results of operations of the entity. We reassess our conclusion as to whether an entity is a VIE upon certain occurrences, which are deemed reconsideration events under the guidance. We have concluded that the only venture that we are required to consolidate as a VIE, as we are the primary beneficiary, is SouthStar. On our Consolidated Balance Sheets, we recognize Piedmont’s share of SouthStar as a separate component of equity entitled “noncontrolling interest.” Piedmont’s share of current operations is reflected in “net income attributable to the noncontrolling interest” on our Consolidated Statements of Income. The consolidation of SouthStar has no effect on our calculation of basic or diluted earnings per common share amounts, which are based upon net income attributable to AGL Resources. For entities that are not determined to be VIEs, we evaluate whether we have control or significant influence over the investee to determine the appropriate consolidation and presentation. Generally, entities under our control are consolidated, and entities over which we can exert significant influence, but do not control, are accounted for under the equity method of accounting. However, we also invest in partnerships and limited liability companies that maintain separate ownership accounts. All such investments are required to be accounted for under the equity method unless our interest is so minor that there is virtually no influence over operating and financial policies, as are all investments in joint ventures. Investments accounted for under the equity method are included in long-term investments on our Consolidated Balance Sheets, and the equity income is recorded within other income on our Consolidated Statements of Income and was immaterial for all periods presented. For additional information, see Note 11. |
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Use of Accounting Estimates | Use of Accounting Estimates The preparation of our financial statements in conformity with GAAP requires us to use judgment and make estimates that affect the reported amounts of assets, liabilities, revenues and expenses and the related disclosures. Our estimates are based on historical experience and various other assumptions that we believe to be reasonable under the circumstances. Our estimates may involve complex situations requiring a high degree of judgment either in the application and interpretation of existing literature or in the development of estimates that impact our financial statements. The most significant estimates relate to the accounting for our rate-regulated subsidiaries, uncollectible accounts and other allowances for contingent losses, goodwill and other intangible assets, retirement plan benefit obligations, derivative and hedging activities and provisions for income taxes. We evaluate our estimates on an ongoing basis and our actual results could differ from our estimates. |
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Accounting Developments | Accounting Developments Accounting standards adopted in 2015 In April 2015, the FASB issued updated authoritative guidance related to debt issuance costs. The amendment modifies the presentation of unamortized debt issuance costs on our Consolidated Balance Sheets. Under the new guidance, we present such amounts as a direct deduction from the face amount of the debt, similar to unamortized debt discounts and premiums, rather than as an asset. Amortization of the debt issuance costs continues to be reported as interest expense on the Consolidated Statements of Income. While the guidance would have been effective for us beginning January 1, 2016, we elected to adopt its provisions effective April 1, 2015, and have applied its provisions to each prior period presented for comparative purposes. This new guidance resulted in an adjustment to the presentation of debt issuance costs primarily from other long-term assets to offset the related debt balances in long-term debt totaling $20 million and $21 million as of December 31, 2015 and 2014, respectively. The April 2015 guidance did not address the classification of debt issuance costs related to line-of-credit arrangements and, consequently, we continued to report such costs as assets subject to amortization over the term of the arrangement. In August 2015, the FASB issued clarifying guidance supporting the deferral and presentation of line-of-credit related debt issuance costs as an asset and subsequently amortizing these costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the arrangement. Other newly issued accounting standards and updated authoritative guidance In May 2014, the FASB issued updated authoritative guidance related to revenue from contracts with customers. The update replaces most of the existing guidance with a single set of principles for recognizing revenue from contracts with customers. In July 2015, the FASB delayed the effective date by one year and the guidance will now be effective for us beginning January 1, 2018. Early adoption of the standard is permitted, but not before the original effective date of December 15, 2016. The new guidance must be applied retrospectively to each prior period presented or via a cumulative effect upon the date of initial application. We have not yet determined the impact of this new guidance, nor have we selected a transition method. In June 2014, the FASB issued an update to authoritative guidance related to accounting for a stock-based compensation performance target that could be achieved after the requisite service period. The guidance was issued to resolve diversity in practice. The new guidance was applied prospectively and became effective for us beginning January 1, 2016. We have determined that this new guidance will not have a material impact on our consolidated financial statements. In February 2015, the FASB issued updated authoritative guidance related to the consolidation of other legal entities into our financial statements. The amendments modify aspects of the consolidation determination that could potentially impact us, including the analysis of limited partnerships and similar legal entities, fee arrangements, and related party relationships. The guidance became effective for us on January 1, 2016. We have determined that this new guidance will not have a material impact on our consolidated financial statements. In April 2015, the FASB issued authoritative guidance related to the accounting for fees paid in connection with arrangements with cloud-based software providers. Under the new guidance, unless a software arrangement includes specific elements enabling customers to possess and operate software on platforms other than that offered by the cloud-based provider, the cost of such arrangements is to be accounted for as an operating expense of the period incurred. The new guidance was applied prospectively and became effective for us on January 1, 2016. We have determined that this new guidance will not have a material impact on our consolidated financial statements. In May 2015, the FASB issued updated authoritative guidance to reduce the diversity in fair value measurements hierarchy disclosures. This amendment removes the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share. This guidance became effective for us on January 1, 2016. We have determined that this new guidance will not have a material impact on our consolidated financial statements. In July 2015, the FASB issued updated authoritative guidance to simplify the measurement of certain inventories. Under the new guidance, inventories are required to be measured at the lower of cost and net realizable value, the latter representing the estimated selling price in the ordinary course of business, reduced by costs of completion, disposal, and transportation. Under current guidance, inventories are required to be measured at the lower of cost or market, but depending upon specific circumstances, market could refer to replacement cost, net realizable value, or net realizable value reduced by a normal profit margin. The amendments do not apply to inventories carried on a LIFO basis, which for us applies only to our Nicor Gas inventories. The guidance is to be applied prospectively, is effective for us beginning January 1, 2017, and early adoption is permitted. We are currently evaluating the potential impact of this new guidance. In November 2015, the FASB issued updated authoritative guidance to the Balance Sheet Classification of Deferred Taxes, which requires companies to present deferred income tax assets and deferred income tax liabilities as noncurrent in a classified balance sheet instead of the current requirement to separate deferred income tax liabilities and assets into current and noncurrent amounts. The guidance is effective for us beginning January 1, 2017. Early application is permitted either prospectively or retrospectively. We have determined that this new guidance will not have a material impact on our consolidated financial statements. In January 2016, the FASB issued updated authoritative guidance related to classification and measurement of Financial Instruments. The amendments modify the accounting and presentation for certain financial liabilities and equity investments not consolidated or reported using the equity method. The guidance is effective for us beginning January 1, 2019; limited early adoption is permitted. We are currently evaluating the potential impact of this new guidance. |
Significant Accounting Policies and Methods of Application (Tables) |
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Accounting Policies [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Inventory Lower of Cost or Market Adjustment | As indicated in the following table, for any declines considered to be other than temporary, we recorded LOCOM adjustments to cost of goods sold to reduce the value of our natural gas inventories to market value.
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Property, Plant and Equipment [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Property, Plant and Equipment | A summary of our PP&E by classification as of December 31, 2015 and 2014 is provided in the following table.
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Schedule of Goodwill | The amounts of goodwill as of December 31, 2015 and 2014 are provided below.
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Schedule of Finite-Lived Intangible Assets | Our intangible assets within our retail operations segment are presented in the following table and represent the estimated fair value at the date of acquisition of the acquired intangible assets in our businesses. As indicated previously, we perform an impairment review when impairment indicators are present. If present, we first determine whether the carrying amount of the asset is recoverable through the undiscounted future cash flows expected from the asset. If the carrying amount is not recoverable, we measure the impairment loss, if any, as the amount by which the carrying amount of the asset exceeds its fair value.
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Schedule of Finite-Lived Intangible Assets, Future Amortization Expense | Amortization expense for the next five years is expected to be as follows:
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Schedule of Other Nonoperating Income (Expense) | Our other income is detailed in the following table. For more information on our equity investment income, see Note 11.
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Schedule of Weighted Average Number of Shares | The following table shows the calculation of our diluted shares attributable to AGL Resources for the periods presented as if performance units currently earned under the plan ultimately vest and as if stock options currently exercisable at prices below the average market prices are exercised.
(1) Daily weighted average shares outstanding.
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Depreciation [Member] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Property, Plant and Equipment | More information on our rates used and the rate method is provided in the following table.
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Estimated Useful Lives [Member] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Property, Plant and Equipment | For our non-regulated segments, we compute depreciation expense on a straight-line basis over the following estimated useful lives of the assets.
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Authorized AFUDC Rates [Member] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Property, Plant and Equipment | More information on our authorized or actual AFUDC rates is provided in the following table.
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Regulated Operations (Tables) |
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Schedule of Regulatory Assets | Our regulatory assets and liabilities reflected within our Consolidated Balance Sheets as of December 31 are summarized in the following table.
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Environmental Exit Costs by Cost | The following table provides additional information on the estimated costs to remediate our current and former operating sites as of December 31, 2015.
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Schedule of Valuation Allowance for Impairment of Recognized Servicing Assets | The actual bad debt experience and resulting refunds are shown in the following table.
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Schedule of Regulatory Assets | The following table illustrates our authorized ratemaking amounts that are not recognized on our Consolidated Balance Sheets. These amounts are primarily composed of an allowed equity rate of return on assets associated with certain of our regulatory infrastructure programs. These amounts will be recognized as revenues in our financial statements in the periods they are billable to our customers.
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Fair Value Measurements (Tables) |
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Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis | The following table presents the carrying amount and fair value of our long-term debt as of December 31.
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Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation | The following is a reconciliation of our retirement plan assets in Level 3 of the fair value hierarchy.
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Pension and Other Postretirement Plans Costs [Member] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis | The actual asset allocations of our retirement plans are presented in the following table by level within the fair value hierarchy.
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Natural Gas Derivatives [Member] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis | The following table summarizes, by level within the fair value hierarchy, our derivative assets and liabilities that were carried at fair value, net of counterparty offset and collateral, on a recurring basis on our Consolidated Balance Sheets as of December 31. See Note 6 for additional information on our derivative instruments.
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Derivative Instruments (Tables) |
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2015 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Notional Amounts of Outstanding Derivative Positions | As of December 31, we had natural gas contracts outstanding in the following quantities:
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Loss Recognized In Income | The following amounts deferred as a regulatory asset or liability on our Consolidated Balance Sheets represent the net realized gains (losses) related to these natural gas cost hedging activities as of December 31.
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Schedule of Derivative Instruments in Statement of Financial Position, Fair Value | The following table presents the fair values and Consolidated Balance Sheets classifications of our derivative instruments as of December 31.
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Schedule of Derivative Instruments | The following table presents the impacts of our derivative instruments on our Consolidated Statements of Income for the years ended December 31.
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Employee Benefit Plans (Tables) |
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2015 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Compensation and Retirement Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Net Benefit Costs | The following table presents the components of our pension and welfare costs for the years ended December 31.
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Schedule of Defined Benefit Plans Disclosures | The following tables present details about our pension and welfare plans.
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Schedule of Health Care Cost Trend Rates | Assumptions used to determine the health care benefit cost for the AGL Welfare Plan are set forth in the following table.
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Schedule of Effect of One-Percentage-Point Change in Assumed Health Care Cost Trend Rates | A one percentage point change in the assumed health care cost trend rates for the AGL Welfare Plan would have the following effects on our benefit obligation, and there was no effect on our service and interest cost.
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Schedule of Net Periodic Benefit Cost Not yet Recognized | The following table presents the amounts not yet reflected in net periodic benefit cost and included in net regulatory assets and accumulated OCI as of December 31, 2015 and 2014.
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Schedule of Amounts in Accumulated Other Comprehensive Income (Loss) to be Recognized over Next Fiscal Year | The 2016 estimated amortizations out of regulatory assets or accumulated OCI for these plans are set forth in the following table.
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Schedule of Expected Benefit Payments | The following table presents the gross benefit payments expected for the years ended December 31, 2016 through 2025 for our pension and welfare plans. There will be benefit payments under these plans beyond 2025.
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Stock-based Compensation (Tables) |
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2015 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Compensation Cost for Share-based Payment Arrangements, Allocation of Share-based Compensation Costs by Plan | The following table provides additional information related to our cash and stock-based compensation awards.
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Schedule of Share-based Compensation, Stock Options, Activity | As used in the table, intrinsic value for options means the difference between the current market value and the grant price.
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Schedule of Nonvested Performance-based Units Activity | The recorded liability and maximum potential liability related to the 2015, 2014 and 2013 grants are as follows:
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Schedule of Share-based Compensation, Restricted Stock and Restricted Stock Units Activity | The following table summarizes the restricted stock awards activity for our employees during the last three years.
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Schedule of Share-based Compensation, Employee Stock Purchase Plan, Activity | The following table provides additional information about our ESPP as of December 31.
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Debt and Credit Facilities (Tables) |
12 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2015 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Debt Disclosure [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Debt | The following table provides maturity dates or ranges, year-to-date weighted average interest rates and amounts outstanding for our various debt securities and facilities that are included on our Consolidated Balance Sheets.
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Schedule of Maturities of Long-term Debt | The majority of our long-term debt matures after fiscal year 2020. The annual maturities of our long-term debt for the next five years and thereafter are as follows:
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Schedule of Capitalization | The following table contains our debt-to-capitalization ratios as of December 31, which are below the maximum allowed.
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Equity (Tables) |
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2015 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Stockholders' Equity Note [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Accumulated Other Comprehensive Income (Loss) | The following table provides changes in the components of our accumulated other comprehensive loss balances, net of the related income tax effects.
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Reclassification out of Accumulated Other Comprehensive Income | The following table provides details of the reclassifications out of accumulated other comprehensive loss and the favorable (unfavorable) impact on net income for the years ended December 31.
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Non-wholly Owned Entities (Tables) |
12 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2015 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Equity Method Investments and Joint Ventures [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net | The following table provides additional information on SouthStar’s assets and liabilities as of December 31, which are consolidated within our Consolidated Balance Sheets. The SouthStar amounts exclude intercompany eliminations and the balances of our wholly owned subsidiary with an 85% ownership interest in SouthStar.
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Schedule of Variable Interest Entities | The following table provides information on SouthStar’s operating revenues and operating expenses for the years ended December 31, which are consolidated within our Consolidated Statements of Income.
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Equity Method Investments | The carrying amounts on our Consolidated Balance Sheets of our investments that are accounted for under the equity method at December 31 were as follows:
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Schedule of Other Nonoperating Income, by Component | The following table provides the income from our equity method investments for the years ended December 31. For more information on our other income, see Note 3.
|
Commitments, Guarantees and Contingencies (Tables) |
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2015 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Commitments and Contingencies Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Contractual Obligation, Fiscal Year Maturity Schedule | The following table illustrates our expected future contractual payments under our obligations and other commitments as of December 31, 2015.
|
Income Taxes (Tables) |
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2015 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Income Tax Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Components of Income Tax Expense (Benefit) | Components of income tax expense on the Consolidated Statements of Income are shown in the following table.
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Schedule of Effective Income Tax Rate Reconciliation | The reconciliations between the statutory federal income tax rate of 35%, the effective rate and the related amount of income tax expense for the years ended December 31, on our Consolidated Statements of Income are presented in the following table.
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Schedule of Deferred Tax Assets and Liabilities | Components that give rise to the net current and long-term accumulated deferred income tax liability are as follows.
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Segment Information (Tables) |
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2015 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Segment Reporting [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Segment Reporting Information, by Segment | Summarized statements of income, balance sheets and capital expenditure information by segment as of and for the years ended December 31 are shown in the following tables.
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Reconciliation of Revenue from Segments to Consolidated | A reconciliation of our operating revenues and our intercompany revenues for the years ended December 31, are shown in the following table. Wholesale services 2014 operating revenues are related to colder-than-normal weather and extreme volatility and are not indicative of future performance.
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Discontinued Operations (Tables) |
12 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2015 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Discontinued Operations and Disposal Groups [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Disposal Groups, Including Discontinued Operations, Income Statement, Balance Sheet and Additional Disclosures | The components of discontinued operations recorded on the Consolidated Statements of Income as of December 31, are as follows:
|
Selected Quarterly Financial Data (Unaudited) (Tables) |
12 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2015 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Quarterly Financial Information Disclosure [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Quarterly Financial Information | Our quarterly financial data for 2015 and 2014 are summarized below.
|
Proposed Merger with Southern Company (Details) - USD ($) |
12 Months Ended | |||
---|---|---|---|---|
Aug. 23, 2015 |
Dec. 31, 2015 |
Dec. 31, 2014 |
Dec. 31, 2013 |
|
Business Acquisition [Line Items] | ||||
Merger-related expenses | $ 44,000,000 | $ 0 | $ 0 | |
Share-based compensation expense | 40,000,000 | $ 24,000,000 | $ 22,000,000 | |
Southern Company [Member] | ||||
Business Acquisition [Line Items] | ||||
Common stock right to convert to cash, price per share (in dollars per share) | $ 66 | |||
Merger termination fee | $ 201,000,000 | |||
Reimbursement of expenses upon termination, up to | $ 5,000,000 | |||
Merger termination fee liability | 0 | |||
Share-based compensation expense | 24,000,000 | |||
Financial advisory, legal and other merger expense | 16,000,000 | |||
Southern Company [Member] | Operation and Maintenance Expense [Member] | ||||
Business Acquisition [Line Items] | ||||
Merger-related expenses | 44,000,000 | |||
Merger related expenses, net of tax | 26,000,000 | |||
Director [Member] | Southern Company [Member] | ||||
Business Acquisition [Line Items] | ||||
Board of directors stock-based compensation | $ 4,000,000 |
Significant Accounting Policies and Methods of Application - Cost of Goods Sold Adjustments (Details) - USD ($) $ in Millions |
Dec. 31, 2015 |
Dec. 31, 2014 |
Dec. 31, 2013 |
---|---|---|---|
Inventory [Line Items] | |||
LOCOM adjustments | $ 23 | $ 77 | $ 9 |
Retail Operations [Member] | |||
Inventory [Line Items] | |||
LOCOM adjustments | 3 | 4 | 1 |
Wholesale Services [Member] | |||
Inventory [Line Items] | |||
LOCOM adjustments | 19 | 73 | 8 |
Other [Member] | |||
Inventory [Line Items] | |||
LOCOM adjustments | $ 1 | $ 0 | $ 0 |
Significant Accounting Policies and Methods of Application - Property, Plant and Equipment (Details) - USD ($) $ in Millions |
Dec. 31, 2015 |
Dec. 31, 2014 |
---|---|---|
Property, Plant and Equipment [Line Items] | ||
PP&E, gross | $ 12,566 | $ 11,552 |
Less accumulated depreciation | 2,775 | 2,462 |
Property, plant and equipment, net | 9,791 | 9,090 |
Transportation and distribution [Member] | ||
Property, Plant and Equipment [Line Items] | ||
PP&E, gross | 9,912 | 9,105 |
Storage Facilities [Member] | ||
Property, Plant and Equipment [Line Items] | ||
PP&E, gross | 1,255 | 1,202 |
Other [Member] | ||
Property, Plant and Equipment [Line Items] | ||
PP&E, gross | 985 | 919 |
Construction Work in Progress [Member] | ||
Property, Plant and Equipment [Line Items] | ||
PP&E, gross | $ 414 | $ 326 |
Significant Accounting Policies and Methods of Application - Estimated Useful Lives of Assets (Details) |
12 Months Ended |
---|---|
Dec. 31, 2015 | |
Transportation equipment [Member] | Minimum [Member] | |
Property, Plant and Equipment [Line Items] | |
Estimated useful life | 5 years |
Transportation equipment [Member] | Maximum [Member] | |
Property, Plant and Equipment [Line Items] | |
Estimated useful life | 10 years |
Storage Caverns [Member] | Minimum [Member] | |
Property, Plant and Equipment [Line Items] | |
Estimated useful life | 40 years |
Storage Caverns [Member] | Maximum [Member] | |
Property, Plant and Equipment [Line Items] | |
Estimated useful life | 60 years |
Other [Member] | Maximum [Member] | |
Property, Plant and Equipment [Line Items] | |
Estimated useful life | 40 years |
Significant Accounting Policies and Methods of Application - Authorized AFUDC Rates (Details) - USD ($) $ in Millions |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2015 |
Dec. 31, 2014 |
Dec. 31, 2013 |
|
Property, Plant and Equipment [Line Items] | |||
AFUDC (in dollars) | $ 6 | $ 7 | $ 18 |
Atlanta Gas Light [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Authorized AFUDC rates (as a percent) | 8.10% | 8.10% | 8.10% |
Nicor Gas [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Authorized AFUDC rates (as a percent) | 0.82% | 0.24% | 0.31% |
Chattanooga Gas [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Authorized AFUDC rates (as a percent) | 7.41% | 7.41% | 7.41% |
Elizabethtown Gas [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Authorized AFUDC rates (as a percent) | 1.69% | 0.44% | 0.41% |
Significant Accounting Policies and Methods of Application - Changes in Amount of Goodwill (Details) - USD ($) $ in Millions |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2015 |
Dec. 31, 2014 |
Dec. 31, 2013 |
|
Goodwill [Roll Forward] | |||
Goodwill - December 31, 2014 | $ 1,827 | ||
Impairment | (14) | $ 0 | $ 0 |
Goodwill - December 31, 2015 | 1,813 | 1,827 | |
Distribution Operations [Member] | |||
Goodwill [Roll Forward] | |||
Goodwill - December 31, 2014 | 1,640 | ||
Impairment | 0 | ||
Goodwill - December 31, 2015 | 1,640 | 1,640 | |
Retail Operations [Member] | |||
Goodwill [Roll Forward] | |||
Goodwill - December 31, 2014 | 173 | ||
Impairment | 0 | ||
Goodwill - December 31, 2015 | 173 | 173 | |
Midstream Operations [Member] | |||
Goodwill [Roll Forward] | |||
Goodwill - December 31, 2014 | 14 | ||
Impairment | (14) | ||
Goodwill - December 31, 2015 | $ 0 | $ 14 |
Significant Accounting Policies and Methods of Application - Intangible Assets (Details) - USD ($) $ in Millions |
12 Months Ended | |
---|---|---|
Dec. 31, 2015 |
Dec. 31, 2014 |
|
Finite-Lived Intangible Assets [Line Items] | ||
Gross | $ 177 | $ 175 |
Accumulated amortization | (68) | (50) |
Net | $ 109 | 125 |
Customer Relationships [Member] | ||
Finite-Lived Intangible Assets [Line Items] | ||
Weighted average amortization period (in years) | 13 years | |
Gross | $ 132 | 130 |
Accumulated amortization | (57) | (42) |
Net | $ 75 | 88 |
Trade Names [Member] | ||
Finite-Lived Intangible Assets [Line Items] | ||
Weighted average amortization period (in years) | 13 years | |
Gross | $ 45 | 45 |
Accumulated amortization | (11) | (8) |
Net | $ 34 | $ 37 |
Significant Accounting Policies and Methods of Application - Expected Amortization Expense (Details) $ in Millions |
Dec. 31, 2015
USD ($)
|
---|---|
Accounting Policies [Abstract] | |
2016 | $ 17 |
2017 | 15 |
2018 | 14 |
2019 | 12 |
2020 | $ 11 |
Significant Accounting Policies and Methods of Application - Other Income (Details) - USD ($) $ in Millions |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2015 |
Dec. 31, 2014 |
Dec. 31, 2013 |
|
Accounting Policies [Abstract] | |||
Equity investment income | $ 6 | $ 8 | $ 3 |
AFUDC - equity | 4 | 5 | 12 |
Other, net | 3 | 1 | 1 |
Total other income | $ 13 | $ 14 | $ 16 |
Regulated Operations - Estimated Recognition of Rate Making Assets (Details) - USD ($) $ in Millions |
Dec. 31, 2015 |
Dec. 31, 2014 |
---|---|---|
Regulatory Assets [Line Items] | ||
Regulatory assets | $ 738 | $ 714 |
Regulatory Asset Off Balance Sheet [Member] | ||
Regulatory Assets [Line Items] | ||
Regulatory assets | 122 | 127 |
Regulatory Asset Off Balance Sheet [Member] | Atlanta Gas Light [Member] | ||
Regulatory Assets [Line Items] | ||
Regulatory assets | 103 | 113 |
Regulatory Asset Off Balance Sheet [Member] | Virginia Natural Gas [Member] | ||
Regulatory Assets [Line Items] | ||
Regulatory assets | 12 | 12 |
Regulatory Asset Off Balance Sheet [Member] | Elizabethtown Gas [Member] | ||
Regulatory Assets [Line Items] | ||
Regulatory assets | 4 | 2 |
Regulatory Asset Off Balance Sheet [Member] | Nicor Gas [Member] | ||
Regulatory Assets [Line Items] | ||
Regulatory assets | $ 3 | $ 0 |
Regulated Operations - Bad Debt Rider (Details) - USD ($) $ in Millions |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2015 |
Dec. 31, 2014 |
Dec. 31, 2013 |
|
Valuation Allowance for Impairment of Recognized Servicing Assets [Line Items] | |||
Benchmark | $ 63 | $ 63 | $ 63 |
Actual bad debt | 12 | 35 | 21 |
Total refund | 51 | 28 | 42 |
Amount to be refunded in 2015 | 30 | 12 | 0 |
Amount to be refunded in 2016 | 21 | 0 | 0 |
Refunded in 2014 [Member] | |||
Valuation Allowance for Impairment of Recognized Servicing Assets [Line Items] | |||
Amount refunded | 0 | 0 | 25 |
Refunded In 2015 [Member] | |||
Valuation Allowance for Impairment of Recognized Servicing Assets [Line Items] | |||
Amount refunded | $ 0 | $ 16 | $ 17 |
Fair Value Measurements - Derivative Assets and Liabilities (Details) - Natural Gas Derivatives [Member] - USD ($) $ in Millions |
Dec. 31, 2015 |
Dec. 31, 2014 |
---|---|---|
Natural gas derivatives | ||
Assets | $ 208 | $ 284 |
Liabilities | (46) | (93) |
Assets, Netting of cash collateral | 33 | 52 |
Liabilities Netting of cash collateral | 63 | 81 |
Level 1 [Member] | ||
Natural gas derivatives | ||
Assets | 53 | 58 |
Liabilities | (63) | (80) |
Level 2 [Member] | ||
Natural gas derivatives | ||
Assets | 122 | 174 |
Liabilities | $ (46) | $ (94) |
Fair Value Measurements - Amortized Cost and Fair Value of Long-Term Debt (Details) - USD ($) $ in Millions |
Dec. 31, 2015 |
Dec. 31, 2014 |
---|---|---|
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Long-term debt carrying amount | $ 3,820 | $ 3,781 |
Level 2 [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Long-term debt fair value | $ 4,066 | $ 4,231 |
Derivative Instruments - Net Long Natural Gas Contracts (Details) - Bcf |
12 Months Ended | |
---|---|---|
Dec. 31, 2015 |
Dec. 31, 2014 |
|
Derivative [Line Items] | ||
Total volumes | (9) | 84 |
Cash Flow Hedges [Member] | ||
Derivative [Line Items] | ||
Total volumes | 5 | 9 |
Cash Flow Hedges [Member] | Short [Member] | ||
Derivative [Line Items] | ||
Total volumes | 6 | 4 |
Cash Flow Hedges [Member] | Long [Member] | ||
Derivative [Line Items] | ||
Total volumes | 11 | 13 |
Not Designated as Hedges [Member] | ||
Derivative [Line Items] | ||
Total volumes | (14) | 75 |
Not Designated as Hedges [Member] | Short [Member] | ||
Derivative [Line Items] | ||
Total volumes | 3,089 | 2,828 |
Not Designated as Hedges [Member] | Long [Member] | ||
Derivative [Line Items] | ||
Total volumes | 3,075 | 2,903 |
Derivative Instruments - Gains and Losses on Derivative Instruments (Details) - USD ($) $ in Millions |
12 Months Ended | |
---|---|---|
Dec. 31, 2015 |
Dec. 31, 2014 |
|
Nicor Gas [Member] | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Realized gains (losses) related to hedging natural gas costs | $ (47) | $ 10 |
Elizabethtown Gas [Member] | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Realized gains (losses) related to hedging natural gas costs | $ (20) | $ 2 |
Employee Benefit Plans - Health Care Benefit Cost Assumptions (Details) |
12 Months Ended | |
---|---|---|
Dec. 31, 2015 |
Dec. 31, 2014 |
|
Compensation and Retirement Disclosure [Abstract] | ||
Health care cost trend rate assumed for next year | 7.90% | 8.10% |
Ultimate rate to which the cost trend rate is assumed to decline | 4.50% | 4.50% |
Year that reaches ultimate trend rate | 2030 | 2030 |
Employee Benefit Plans - One-Percentage-Point Change in Assumed Health Care Cost (Details) $ in Millions |
12 Months Ended |
---|---|
Dec. 31, 2015
USD ($)
| |
Compensation and Retirement Disclosure [Abstract] | |
1% Health care cost trend rate increase | $ 13 |
1% Health care cost trend rate decrease | $ (11) |
Employee Benefit Plans - Expected Benefit Payments (Details) $ in Millions |
Dec. 31, 2015
USD ($)
|
---|---|
Pension Plans [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
2016 | $ 79 |
2017 | 68 |
2018 | 70 |
2019 | 73 |
2020 | 75 |
2021-2025 | 374 |
Welfare Plans [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
2016 | 20 |
2017 | 20 |
2018 | 21 |
2019 | 22 |
2020 | 23 |
2021-2025 | $ 116 |
Stock-based Compensation - Compensation Costs, Tax Benefits and Excess Tax Benefits (Details) - USD ($) $ in Millions |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2015 |
Dec. 31, 2014 |
Dec. 31, 2013 |
|
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |||
Compensation costs | $ 40 | $ 24 | $ 22 |
Income tax benefits | 1 | 1 | 1 |
Excess tax benefits | $ 0 | $ 0 | $ 0 |
Stock-based Compensation - Nonvested Performance Share Units (Details) - Performance Share Unit Awards [Member] $ in Millions |
12 Months Ended |
---|---|
Dec. 31, 2015
USD ($)
| |
Granted in 2013 [Member] | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Fair value accrued | $ 18 |
Maximum aggregate payout | 24 |
Granted in 2014 [Member] | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Fair value accrued | 13 |
Maximum aggregate payout | 28 |
Granted In 2015 [Member] | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Fair value accrued | 7 |
Maximum aggregate payout | $ 29 |
Stock-based Compensation - Employee Stock Purchase Plan (Details) - USD ($) |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2015 |
Dec. 31, 2014 |
Dec. 31, 2013 |
|
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |||
Shares purchased on the open market | 106,994 | 100,199 | 97,734 |
Average per-share purchase price (in dollars per share) | $ 55.47 | $ 51.60 | $ 42.96 |
Total purchase price discount (in dollars) | $ 793,931 | $ 739,598 | $ 628,358 |
Debt and Credit Facilities - Maturities of Long-Term Debt (Details) $ in Millions |
Dec. 31, 2015
USD ($)
|
---|---|
Debt Disclosure [Abstract] | |
2016 | $ 545 |
2017 | 22 |
2018 | 155 |
2019 | 350 |
2020 | 0 |
Thereafter | 2,684 |
Total | $ 3,756 |
Debt and Credit Facilities - Debt-to-Capitalization Ratios (Details) |
Dec. 31, 2015 |
Dec. 31, 2014 |
---|---|---|
Schedule of Capitalization [Line Items] | ||
Debt-to-capitalization ratio (as a percent) | 0.7 | |
AGL Resources Inc [Member] | ||
Schedule of Capitalization [Line Items] | ||
Debt-to-capitalization ratio (as a percent) | 0.54 | 0.55 |
Nicor Gas [Member] | ||
Schedule of Capitalization [Line Items] | ||
Debt-to-capitalization ratio (as a percent) | 0.56 | 0.62 |
Equity - Narrative (Details) - $ / shares |
Dec. 31, 2015 |
Dec. 31, 2014 |
---|---|---|
Class of Stock [Line Items] | ||
Preferred stock, shares authorized (in shares) | 10,000,000 | |
Preferred stock, par or stated value per share (in dollars per share) | $ 0 | |
Preferred Class A [Member] | ||
Class of Stock [Line Items] | ||
Preferred stock, shares authorized (in shares) | 10,000,000 | 10,000,000 |
Preferred stock, par or stated value per share (in dollars per share) | $ 0 | $ 0 |
Preferred Stock [Member] | ||
Class of Stock [Line Items] | ||
Preferred stock, shares authorized (in shares) | 10,000,000 | |
Preferred stock, par or stated value per share (in dollars per share) | $ 0 |
Equity - Other Comprehensive Income (Loss) (Details) - USD ($) $ in Millions |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2015 |
Dec. 31, 2014 |
Dec. 31, 2013 |
|
Accumulated Other Comprehensive Income (Loss) [Roll Forward] | |||
Balance | $ 3,828 | $ 3,613 | $ 3,391 |
Balance | 3,975 | 3,828 | 3,613 |
Cash Flow Hedges [Member] | |||
Accumulated Other Comprehensive Income (Loss) [Roll Forward] | |||
Balance | (6) | 1 | (3) |
OCI, before reclassifications | 0 | (6) | 1 |
Amounts reclassified from accumulated OCI | 8 | (1) | 3 |
Balance | 2 | (6) | 1 |
Retirement Benefit Plans [Member] | |||
Accumulated Other Comprehensive Income (Loss) [Roll Forward] | |||
Balance | (200) | (137) | (215) |
OCI, before reclassifications | 0 | (71) | 66 |
Amounts reclassified from accumulated OCI | 12 | 8 | 12 |
Balance | (188) | (200) | (137) |
Total [Member] | |||
Accumulated Other Comprehensive Income (Loss) [Roll Forward] | |||
Balance | (206) | (136) | (218) |
OCI, before reclassifications | 0 | (77) | 67 |
Amounts reclassified from accumulated OCI | 20 | 7 | 15 |
Balance | $ (186) | $ (206) | $ (136) |
Non-wholly Owned Entities - SouthStars Revenues and Expenses (Details) - USD ($) $ in Millions |
3 Months Ended | 12 Months Ended | |||||||||
---|---|---|---|---|---|---|---|---|---|---|---|
Dec. 31, 2015 |
Sep. 30, 2015 |
Jun. 30, 2015 |
Mar. 31, 2015 |
Dec. 31, 2014 |
Sep. 30, 2014 |
Jun. 30, 2014 |
Mar. 31, 2014 |
Dec. 31, 2015 |
Dec. 31, 2014 |
Dec. 31, 2013 |
|
Variable Interest Entity [Line Items] | |||||||||||
Operating revenues | $ 962 | $ 584 | $ 674 | $ 1,721 | $ 1,445 | $ 589 | $ 889 | $ 2,462 | $ 3,941 | $ 5,385 | $ 4,209 |
Operating expenses | |||||||||||
Cost of goods sold | 1,645 | 2,765 | 2,110 | ||||||||
Operation and maintenance | 914 | 939 | 887 | ||||||||
Depreciation and amortization | 397 | 380 | 397 | ||||||||
Taxes other than income taxes | 181 | 208 | 187 | ||||||||
Total operating expenses | 3,195 | 4,292 | 3,581 | ||||||||
Operating income | $ 216 | $ 59 | $ 107 | $ 364 | $ 286 | $ 78 | $ 139 | $ 592 | 746 | 1,095 | $ 639 |
South Star [Member] | |||||||||||
Variable Interest Entity [Line Items] | |||||||||||
Operating revenues | 711 | 866 | |||||||||
Operating expenses | |||||||||||
Cost of goods sold | 490 | 645 | |||||||||
Operation and maintenance | 81 | 87 | |||||||||
Depreciation and amortization | 10 | 11 | |||||||||
Taxes other than income taxes | 1 | 1 | |||||||||
Total operating expenses | 582 | 744 | |||||||||
Operating income | $ 129 | $ 122 |
Non-wholly Owned Entities - Equity Method Investments (Details) - USD ($) $ in Millions |
Dec. 31, 2015 |
Dec. 31, 2014 |
---|---|---|
Schedule of Equity Method Investments [Line Items] | ||
Equity method investments | $ 80 | $ 80 |
Triton [Member] | ||
Schedule of Equity Method Investments [Line Items] | ||
Equity method investments | 49 | 62 |
Horizon Pipeline [Member] | ||
Schedule of Equity Method Investments [Line Items] | ||
Equity method investments | 14 | 14 |
PennEast Pipeline [Member] | ||
Schedule of Equity Method Investments [Line Items] | ||
Equity method investments | 9 | 1 |
Atlantic Coast Pipeline [Member] | ||
Schedule of Equity Method Investments [Line Items] | ||
Equity method investments | 7 | 2 |
Other [Member] | ||
Schedule of Equity Method Investments [Line Items] | ||
Equity method investments | $ 1 | $ 1 |
Non-wholly Owned Entities - Income from Equity Method Investments (Details) - USD ($) $ in Millions |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2015 |
Dec. 31, 2014 |
Dec. 31, 2013 |
|
Schedule of Equity Method Investments [Line Items] | |||
Income (loss) from equity method investments | $ 6 | $ 8 | $ 3 |
Triton [Member] | |||
Schedule of Equity Method Investments [Line Items] | |||
Income (loss) from equity method investments | 4 | 6 | 9 |
Horizon Pipeline [Member] | |||
Schedule of Equity Method Investments [Line Items] | |||
Income (loss) from equity method investments | 2 | 2 | 2 |
Other [Member] | |||
Schedule of Equity Method Investments [Line Items] | |||
Income (loss) from equity method investments | $ 0 | $ 0 | $ (8) |
Income Taxes - Narrative (Details) - USD ($) |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2015 |
Dec. 31, 2014 |
Dec. 31, 2013 |
|
Valuation Allowance [Line Items] | |||
Statutory federal income tax rate (as a percent) | 35.00% | 35.00% | 35.00% |
Deferred tax asset, valuation allowance | $ 19,000,000 | $ 20,000,000 | |
Unrecognized tax benefits | 0 | 0 | |
Interest and penalties accrued | 0 | ||
Interests and penalties incurred | 0 | 0 | |
Related to Net Operating Losses [Member] | |||
Valuation Allowance [Line Items] | |||
Deferred tax asset, valuation allowance | 1,000,000 | ||
Related to Investment in Triton [Member] | |||
Valuation Allowance [Line Items] | |||
Deferred tax asset, valuation allowance | $ 19,000,000 | ||
Domestic Tax Authority [Member] | |||
Valuation Allowance [Line Items] | |||
Net operating loss carryforwards | $ 11,000,000 |
Income Taxes - Income Tax Expense (Details) - USD ($) $ in Millions |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2015 |
Dec. 31, 2014 |
Dec. 31, 2013 |
|
Current income taxes | |||
Federal | $ (11) | $ 113 | $ 164 |
State | 10 | 38 | 35 |
Deferred income taxes | |||
Federal | 198 | 184 | (8) |
State | 18 | 17 | (11) |
Amortization of investment tax credits | (2) | (2) | (3) |
Total income tax expense | $ 213 | $ 350 | $ 177 |
Income Taxes - Income Tax Reconciliation (Details) - USD ($) $ in Millions |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2015 |
Dec. 31, 2014 |
Dec. 31, 2013 |
|
Income Tax Disclosure [Abstract] | |||
Computed tax expense at statutory rate | $ 205 | $ 325 | $ 165 |
State income tax, net of federal income tax benefit | 21 | 36 | 20 |
Tax effect of net income attributable to the noncontrolling interest | (8) | (7) | (7) |
Amortization of investment tax credits | (2) | (2) | (3) |
Affordable housing credits | (1) | (2) | (2) |
Flexible dividend deduction | (2) | (2) | (2) |
Sale of Compass Energy | 0 | 0 | 6 |
Other | 0 | 2 | 0 |
Total income tax expense | $ 213 | $ 350 | $ 177 |
Segment Information - Narrative (Details) |
12 Months Ended |
---|---|
Dec. 31, 2015
state
segment
| |
Segment Reporting Information [Line Items] | |
Number of reportable segments | segment | 4 |
Distribution Operations [Member] | |
Segment Reporting Information [Line Items] | |
Number of states in which entity operates | state | 7 |
Discontinued Operations - Discontinued Operations from Statement of Income (Details) - USD ($) $ in Millions |
3 Months Ended | 12 Months Ended | |||||
---|---|---|---|---|---|---|---|
Dec. 31, 2014 |
Sep. 30, 2014 |
Jun. 30, 2014 |
Mar. 31, 2014 |
Dec. 31, 2015 |
Dec. 31, 2014 |
Dec. 31, 2013 |
|
Operating expenses | |||||||
(Loss) income from discontinued operations, net of tax | $ 0 | $ (31) | $ 1 | $ (50) | $ 0 | $ (80) | $ 5 |
Tropical Shipping [Member] | |||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||||||
Operating revenues | 243 | 365 | |||||
Operating expenses | |||||||
Cost of goods sold | 149 | 222 | |||||
Operation and maintenance | 75 | 110 | |||||
Depreciation and amortization | 5 | 19 | |||||
Taxes other than income taxes | 5 | 6 | |||||
Loss on sale and goodwill impairment | 28 | 0 | |||||
Total operating expenses | 262 | 357 | |||||
Operating (loss) income | (19) | 8 | |||||
(Loss) income before income taxes | (19) | 8 | |||||
Income tax expense | $ (29) | $ (31) | (61) | (3) | |||
(Loss) income from discontinued operations, net of tax | $ (80) | $ 5 |
Selected Quarterly Financial Data (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Millions |
3 Months Ended | 12 Months Ended | |||||||||
---|---|---|---|---|---|---|---|---|---|---|---|
Dec. 31, 2015 |
Sep. 30, 2015 |
Jun. 30, 2015 |
Mar. 31, 2015 |
Dec. 31, 2014 |
Sep. 30, 2014 |
Jun. 30, 2014 |
Mar. 31, 2014 |
Dec. 31, 2015 |
Dec. 31, 2014 |
Dec. 31, 2013 |
|
Quarterly Financial Information Disclosure [Abstract] | |||||||||||
Operating revenues | $ 962 | $ 584 | $ 674 | $ 1,721 | $ 1,445 | $ 589 | $ 889 | $ 2,462 | $ 3,941 | $ 5,385 | $ 4,209 |
Operating income | 216 | 59 | 107 | 364 | 286 | 78 | 139 | 592 | 746 | 1,095 | 639 |
EBIT | 220 | 61 | 111 | 367 | 292 | 81 | 141 | 595 | 759 | 1,109 | 655 |
Income from continuing operations | 112 | 12 | 44 | 205 | 152 | 23 | 59 | 346 | 373 | 580 | 308 |
Income from continuing operations attributable to AGL Resources | $ 107 | $ 11 | $ 42 | $ 193 | 148 | 23 | 57 | 334 | 353 | 562 | 290 |
(Loss) income from discontinued operations, net of tax | 0 | (31) | 1 | (50) | 0 | (80) | 5 | ||||
Net income (loss) attributable to AGL Resources | $ 148 | $ (8) | $ 58 | $ 284 | $ 353 | $ 482 | $ 295 | ||||
Basic earnings (loss) per common share (in dollars per share) | $ 0.89 | $ 0.09 | $ 0.35 | $ 1.62 | $ 2.95 | $ 4.06 | $ 2.50 | ||||
Diluted earnings (loss) per common share (in dollars per share) | $ 0.89 | $ 0.09 | $ 0.35 | $ 1.62 | 2.94 | 4.04 | 2.49 | ||||
Basic earnings (loss) per common share: | |||||||||||
Continuing operations (in dollars per share) | $ 1.24 | $ 0.19 | $ 0.48 | $ 2.82 | 2.95 | 4.73 | 2.46 | ||||
Discontinued operations (in dollars per share) | 0.00 | (0.25) | 0.01 | (0.43) | 0.00 | (0.67) | 0.04 | ||||
Diluted earnings (loss) per common share: | |||||||||||
Continuing operations (in dollars per share) | 1.24 | 0.19 | 0.48 | 2.81 | 2.94 | 4.71 | 2.45 | ||||
Discontinued operations (in dollars per share) | $ 0.00 | $ (0.25) | $ 0.01 | $ (0.43) | $ 0.00 | $ (0.67) | $ 0.04 |
Schedule II - Valuation and Qualifying Accounts (Details) - USD ($) $ in Millions |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2015 |
Dec. 31, 2014 |
Dec. 31, 2013 |
|
Allowance for Uncollectible Accounts [Member] | |||
Movement in Valuation Allowances and Reserves [Roll Forward] | |||
Balance at beginning of period | $ 35 | $ 29 | $ 28 |
Additions charged to costs and expenses | 27 | 54 | 37 |
Additions charged to other accounts | 3 | 2 | 0 |
Deductions | (36) | (50) | (36) |
Balance at end of period | 29 | 35 | 29 |
Income Tax Valuation [Member] | |||
Movement in Valuation Allowances and Reserves [Roll Forward] | |||
Balance at beginning of period | 20 | 22 | 22 |
Additions charged to costs and expenses | 0 | 0 | 0 |
Additions charged to other accounts | 0 | 0 | 0 |
Deductions | (1) | (2) | 0 |
Balance at end of period | $ 19 | $ 20 | $ 22 |
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