Attached files
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EX-32.2 - EXHIBIT 32.2 - SOUTHERN Co GAS | q22016ex322.htm |
EX-32.1 - EXHIBIT 32.1 - SOUTHERN Co GAS | q22016ex321.htm |
EX-31.2 - EXHIBIT 31.2 - SOUTHERN Co GAS | q22016ex312.htm |
EX-31.1 - EXHIBIT 31.1 - SOUTHERN Co GAS | q22016ex311.htm |
EX-12 - EXHIBIT 12 - SOUTHERN Co GAS | q22016ex12.htm |
UNITED STATES | |
SECURITIES AND EXCHANGE COMMISSION | |
Washington, D.C. 20549 | |
FORM 10-Q | |
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF | |
THE SECURITIES EXCHANGE ACT OF 1934 | |
For the Quarterly Period Ended June 30, 2016 | |
Commission File Number 1-14174 | |
SOUTHERN COMPANY GAS | |
Ten Peachtree Place NE, Atlanta, Georgia 30309 | |
404-584-4000 | |
Georgia | 58-2210952 |
(State of incorporation) | (I.R.S. Employer Identification No.) |
Southern Company Gas (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. | |
Southern Company Gas has submitted electronically and posted on its corporate website every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months. |
Southern Company Gas is a large accelerated filer and is not a shell company. |
The number of shares of Southern Company Gas' common stock, Par Value $0.01 Per Share, outstanding as of July 25, 2016, was 100, all of which were held by The Southern Company. |
Southern Company Gas
Quarterly Report on Form 10-Q
For the Quarter Ended June 30, 2016
TABLE OF CONTENTS
Page | ||
Item Number. | ||
1A. | ||
GLOSSARY OF KEY TERMS | |
2015 Form 10-K | Our Annual Report on Form 10-K for the year ended December 31, 2015, filed with the SEC on February 11, 2016 |
Atlanta Gas Light | Atlanta Gas Light Company |
Atlantic Coast Pipeline | Atlantic Coast Pipeline, LLC |
Bcf | Billion cubic feet |
Central Valley | Central Valley Gas Storage, LLC |
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 |
ERC | Environmental remediation costs |
FASB | Financial Accounting Standards Board |
FERC | Federal Energy Regulatory Commission |
Fitch | Fitch Ratings |
GAAP | Accounting principles generally accepted in the United States of America |
Georgia Commission | Georgia Public Service Commission, the state regulatory agency for Atlanta Gas Light |
Golden Triangle | Golden Triangle Storage, Inc. |
Heating 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 |
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 |
LIFO | Last-in, first-out |
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 entered into on August 23, 2015 by Southern Company, AMS Corp., a subsidiary of Southern Company, and Southern Company Gas |
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 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 |
PennEast Pipeline | PennEast Pipeline Company, LLC |
Piedmont | Piedmont Natural Gas Company, Inc. |
Pivotal Utility | Pivotal Utility Holdings, Inc., doing business as Elizabethtown Gas, Elkton Gas and Florida City Gas |
PRP | Pipeline Replacement Program, Atlanta Gas Light's 15-year infrastructure replacement program, which ended in December 2013 |
S&P | S&P Global Ratings |
SEC | Securities and Exchange Commission |
Sequent | Sequent Energy Management, L.P. |
Southern Company | The Southern Company |
Southern Company Gas | Southern Company Gas (formerly known as AGL Resources Inc.) |
Southern Company Gas Capital | Southern Company Gas Capital Corporation (formerly known as AGL Capital Corporation) |
Southern Company Gas Credit Facility | $1.3 billion credit agreement entered into by Southern Company Gas Capital to support its commercial paper program |
SouthStar | SouthStar Energy Services, LLC |
Triton | Triton Container Investments, LLC |
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. |
WACOG | Weighted average cost of gas |
PART I – FINANCIAL INFORMATION
Item 1. Condensed Consolidated Financial Statements (Unaudited)
SOUTHERN COMPANY GAS AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS - ASSETS
(UNAUDITED)
As of | ||||||||||||
In millions | June 30, 2016 | December 31, 2015 | June 30, 2015 | |||||||||
Current assets | ||||||||||||
Cash and cash equivalents | $ | 15 | $ | 19 | $ | 25 | ||||||
Receivables | ||||||||||||
Energy marketing | 429 | 445 | 430 | |||||||||
Natural gas, unbilled revenues and other | 355 | 516 | 445 | |||||||||
Less allowance for uncollectible accounts | 38 | 29 | 46 | |||||||||
Total receivables, net | 746 | 932 | 829 | |||||||||
Inventories | ||||||||||||
Natural gas | 398 | 622 | 395 | |||||||||
Other | 29 | 29 | 26 | |||||||||
Total inventories | 427 | 651 | 421 | |||||||||
Derivative instruments, including cash collateral | 100 | 206 | 158 | |||||||||
Current deferred income taxes | 63 | — | 26 | |||||||||
Prepaid expenses | 60 | 218 | 51 | |||||||||
Regulatory assets | 47 | 68 | 48 | |||||||||
Other | 16 | 21 | 14 | |||||||||
Total current assets | 1,474 | 2,115 | 1,572 | |||||||||
Long-term assets and other deferred debits | ||||||||||||
Property, plant and equipment | 13,039 | 12,566 | 11,903 | |||||||||
Less accumulated depreciation | 2,891 | 2,775 | 2,524 | |||||||||
Property, plant and equipment, net | 10,148 | 9,791 | 9,379 | |||||||||
Goodwill | 1,813 | 1,813 | 1,827 | |||||||||
Regulatory assets | 679 | 670 | 642 | |||||||||
Intangible assets | 101 | 109 | 112 | |||||||||
Other | 273 | 256 | 303 | |||||||||
Total long-term assets and other deferred debits | 13,014 | 12,639 | 12,263 | |||||||||
Total assets | $ | 14,488 | $ | 14,754 | $ | 13,835 |
See Notes to Condensed Consolidated Financial Statements (Unaudited).
SOUTHERN COMPANY GAS AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS - LIABILITIES, CONTINGENTLY REDEEMABLE NONCONTROLLING INTEREST AND EQUITY
(UNAUDITED)
As of | ||||||||||||
In millions, except share and per share amounts | June 30, 2016 | December 31, 2015 | June 30, 2015 | |||||||||
Current liabilities | ||||||||||||
Short-term debt | $ | 114 | $ | 1,010 | $ | 459 | ||||||
Current portion of long-term debt | 575 | 545 | 125 | |||||||||
Energy marketing trade payables | 436 | 418 | 455 | |||||||||
Other accounts payable – trade | 278 | 255 | 272 | |||||||||
Accrued expenses | 221 | 200 | 183 | |||||||||
Regulatory liabilities | 156 | 134 | 154 | |||||||||
Customer deposits and credit balances | 143 | 165 | 115 | |||||||||
Derivative instruments, including cash collateral | 65 | 44 | 43 | |||||||||
Accrued environmental remediation liabilities | 59 | 67 | 83 | |||||||||
Temporary LIFO liquidation | 49 | — | 38 | |||||||||
Current deferred income taxes | — | 31 | — | |||||||||
Other | 109 | 131 | 120 | |||||||||
Total current liabilities | 2,205 | 3,000 | 2,047 | |||||||||
Long-term liabilities and other deferred credits | ||||||||||||
Long-term debt | 3,709 | 3,275 | 3,452 | |||||||||
Accumulated deferred income taxes | 1,992 | 1,912 | 1,780 | |||||||||
Regulatory liabilities | 1,627 | 1,611 | 1,622 | |||||||||
Accrued pension and retiree welfare benefits | 513 | 515 | 526 | |||||||||
Accrued environmental remediation liabilities | 379 | 364 | 346 | |||||||||
Other | 89 | 102 | 73 | |||||||||
Total long-term liabilities and other deferred credits | 8,309 | 7,779 | 7,799 | |||||||||
Total liabilities and other deferred credits | 10,514 | 10,779 | 9,846 | |||||||||
Commitments, guarantees and contingencies (see Note 11) | ||||||||||||
Contingently redeemable noncontrolling interest | 41 | — | — | |||||||||
Equity | ||||||||||||
Common stock, $5 par value; 750,000,000 shares authorized; outstanding: 120,741,810 shares at June 30, 2016, 120,376,721 shares at December 31, 2015, and 120,081,995 shares at June 30, 2015 | 605 | 603 | 601 | |||||||||
Additional paid-in capital | 2,133 | 2,099 | 2,099 | |||||||||
Retained earnings | 1,424 | 1,421 | 1,425 | |||||||||
Accumulated other comprehensive loss | (221 | ) | (186 | ) | (169 | ) | ||||||
Treasury shares, at cost: 216,523 shares at June 30, 2016, December 31, 2015, and June 30, 2015 | (8 | ) | (8 | ) | (8 | ) | ||||||
Total common shareholders’ equity | 3,933 | 3,929 | 3,948 | |||||||||
Noncontrolling interest | — | 46 | 41 | |||||||||
Total equity | 3,933 | 3,975 | 3,989 | |||||||||
Total liabilities, redeemable noncontrolling interest and equity | $ | 14,488 | $ | 14,754 | $ | 13,835 |
See Notes to Condensed Consolidated Financial Statements (Unaudited).
SOUTHERN COMPANY GAS AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
In millions, except per share amounts | 2016 | 2015 | 2016 | 2015 | ||||||||||||
Operating revenues (includes revenue taxes of $17 and $57 for the three and six months ended June 30, 2016, respectively, and $18 and $74 for the three and six months ended June 30, 2015, respectively) | $ | 571 | $ | 674 | $ | 1,905 | $ | 2,395 | ||||||||
Operating expenses | ||||||||||||||||
Cost of goods sold | 191 | 222 | 769 | 1,157 | ||||||||||||
Operation and maintenance | 213 | 209 | 454 | 458 | ||||||||||||
Depreciation and amortization | 104 | 98 | 206 | 195 | ||||||||||||
Taxes other than income taxes | 37 | 38 | 99 | 114 | ||||||||||||
Merger-related expenses | 53 | — | 56 | — | ||||||||||||
Total operating expenses | 598 | 567 | 1,584 | 1,924 | ||||||||||||
Operating (loss) income | (27 | ) | 107 | 321 | 471 | |||||||||||
Other income | 3 | 4 | 6 | 7 | ||||||||||||
Interest expense, net | (48 | ) | (42 | ) | (95 | ) | (86 | ) | ||||||||
(Loss) income before income taxes | (72 | ) | 69 | 232 | 392 | |||||||||||
Income tax (benefit) expense | (24 | ) | 25 | 87 | 143 | |||||||||||
Net (loss) income | (48 | ) | 44 | 145 | 249 | |||||||||||
Less net income attributable to noncontrolling interest | 3 | 2 | 14 | 14 | ||||||||||||
Net (loss) income attributable to Southern Company Gas | $ | (51 | ) | $ | 42 | $ | 131 | $ | 235 | |||||||
Per common share information attributable to Southern Company Gas | ||||||||||||||||
Basic (loss) earnings per common share | $ | (0.43 | ) | $ | 0.35 | $ | 1.09 | $ | 1.97 | |||||||
Diluted (loss) earnings per common share | $ | (0.43 | ) | $ | 0.35 | $ | 1.09 | $ | 1.96 | |||||||
Cash dividends declared per common share | $ | 0.53 | $ | 0.51 | $ | 1.06 | $ | 1.02 | ||||||||
Weighted average number of common shares outstanding | ||||||||||||||||
Basic | 120.3 | 119.5 | 120.2 | 119.4 | ||||||||||||
Diluted | 120.5 | 119.8 | 120.5 | 119.7 |
See Notes to Condensed Consolidated Financial Statements (Unaudited).
SOUTHERN COMPANY GAS AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(UNAUDITED)
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
In millions | 2016 | 2015 | 2016 | 2015 | ||||||||||||
Net (loss) income | $ | (48 | ) | $ | 44 | $ | 145 | $ | 249 | |||||||
Other comprehensive (loss) income, net of tax | ||||||||||||||||
Retirement benefit plans, net of tax | ||||||||||||||||
Reclassification of actuarial losses to net benefit cost (net of income tax of $2 and $4 for the three and six months ended June 30, 2016, respectively, and $2 and $4 for the three and six months ended June 30, 2015, respectively) | 2 | 4 | 5 | 7 | ||||||||||||
Retirement benefit plans, net | 2 | 4 | 5 | 7 | ||||||||||||
Cash flow hedges, net of tax | ||||||||||||||||
Net derivative (loss) gain arising during the period (net of income tax of $7 and $23 for the three and six months ended June 30, 2016, respectively, and $16 and $17 for the three and six months ended June 30, 2015, respectively) | (12 | ) | 25 | (41 | ) | 27 | ||||||||||
Reclassification of realized derivative gain to net income (net of income tax of less than $1 for the three and six months ended June 30, 2016 and 2015) | 2 | 4 | 1 | 4 | ||||||||||||
Cash flow hedges, net | (10 | ) | 29 | (40 | ) | 31 | ||||||||||
Other comprehensive (loss) income, net of tax | (8 | ) | 33 | (35 | ) | 38 | ||||||||||
Comprehensive (loss) income | (56 | ) | 77 | 110 | 287 | |||||||||||
Less comprehensive income attributable to noncontrolling interest | 3 | 3 | 14 | 15 | ||||||||||||
Comprehensive (loss) income attributable to Southern Company Gas | $ | (59 | ) | $ | 74 | $ | 96 | $ | 272 |
See Notes to Condensed Consolidated Financial Statements (Unaudited).
SOUTHERN COMPANY GAS AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF EQUITY
(UNAUDITED)
Southern Company Gas | |||||||||||||||||||||||||||||||
Common stock | Additional paid-in capital | Retained earnings | Accumulated other comprehensive loss | Treasury shares | Noncontrolling interest | Total | |||||||||||||||||||||||||
In millions, except per share amounts | Shares | Amount | |||||||||||||||||||||||||||||
Balance as of December 31, 2014 | 119.6 | $ | 599 | $ | 2,087 | $ | 1,312 | $ | (206 | ) | $ | (8 | ) | $ | 44 | $ | 3,828 | ||||||||||||||
Net income | — | — | — | 235 | — | — | 14 | 249 | |||||||||||||||||||||||
Other comprehensive income | — | — | — | — | 37 | — | 1 | 38 | |||||||||||||||||||||||
Dividends on common stock ($1.02 per share) | — | — | — | (122 | ) | — | — | — | (122 | ) | |||||||||||||||||||||
Distribution to noncontrolling interest | — | — | — | — | — | — | (18 | ) | (18 | ) | |||||||||||||||||||||
Stock granted, share-based compensation, net of forfeitures | — | — | (13 | ) | — | — | — | — | (13 | ) | |||||||||||||||||||||
Stock issued, dividend reinvestment plan | 0.1 | 1 | 5 | — | — | — | — | 6 | |||||||||||||||||||||||
Stock issued, share-based compensation, net of forfeitures | 0.4 | 1 | 14 | — | — | — | — | 15 | |||||||||||||||||||||||
Share-based compensation expense, net of tax | — | — | 6 | — | — | — | — | 6 | |||||||||||||||||||||||
Balance as of June 30, 2015 | 120.1 | $ | 601 | $ | 2,099 | $ | 1,425 | $ | (169 | ) | $ | (8 | ) | $ | 41 | $ | 3,989 |
Southern Company Gas | |||||||||||||||||||||||||||||||
Common stock | Additional paid-in capital | Retained earnings | Accumulated other comprehensive loss | Treasury shares | Noncontrolling interest | Total | |||||||||||||||||||||||||
In millions, except per share amounts | Shares | Amount | |||||||||||||||||||||||||||||
Balance as of December 31, 2015 | 120.4 | $ | 603 | $ | 2,099 | $ | 1,421 | $ | (186 | ) | $ | (8 | ) | $ | 46 | $ | 3,975 | ||||||||||||||
Net income attributable to Southern Company Gas | — | — | — | 131 | — | — | — | 131 | |||||||||||||||||||||||
Other comprehensive loss | — | — | — | — | (35 | ) | — | — | (35 | ) | |||||||||||||||||||||
Dividends on common stock ($1.06 per share) | — | — | — | (128 | ) | — | — | — | (128 | ) | |||||||||||||||||||||
Stock granted, share-based compensation, net of forfeitures | — | — | (9 | ) | — | — | — | — | (9 | ) | |||||||||||||||||||||
Stock issued, dividend reinvestment plan | — | — | 6 | — | — | — | — | 6 | |||||||||||||||||||||||
Stock issued, share-based compensation, net of forfeitures | 0.3 | 2 | 15 | — | — | — | — | 17 | |||||||||||||||||||||||
Share-based compensation expense, net of tax | — | — | 22 | — | — | — | — | 22 | |||||||||||||||||||||||
Reclassification of noncontrolling interest | — | — | — | — | — | — | (46 | ) | (46 | ) | |||||||||||||||||||||
Balance as of June 30, 2016 | 120.7 | $ | 605 | $ | 2,133 | $ | 1,424 | $ | (221 | ) | $ | (8 | ) | $ | — | $ | 3,933 |
See Notes to Condensed Consolidated Financial Statements (Unaudited).
SOUTHERN COMPANY GAS AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
Six Months Ended June 30, | ||||||||
In millions | 2016 | 2015 | ||||||
Cash flows from operating activities: | ||||||||
Net income | $ | 145 | $ | 249 | ||||
Adjustments to reconcile net income to net cash flow provided by operating activities | ||||||||
Depreciation and amortization | 206 | 195 | ||||||
Change in derivative instrument assets and liabilities | 136 | 42 | ||||||
Deferred income taxes | 8 | 27 | ||||||
Changes in certain assets and liabilities | ||||||||
Inventories, net of temporary LIFO liquidation | 273 | 333 | ||||||
Prepaid and miscellaneous taxes | 187 | 150 | ||||||
Receivables, other than energy marketing | 174 | 363 | ||||||
Energy marketing receivables and trade payables, net | 34 | 27 | ||||||
Trade payables, other than energy marketing | 26 | (41 | ) | |||||
Accrued natural gas costs, net | 11 | 43 | ||||||
Accrued expenses | (20 | ) | (28 | ) | ||||
Other, net | (67 | ) | 125 | |||||
Net cash flow provided by operating activities | 1,113 | 1,485 | ||||||
Cash flows from investing activities: | ||||||||
Expenditures for property, plant and equipment | (548 | ) | (452 | ) | ||||
Other, net | (11 | ) | 5 | |||||
Net cash flow used in investing activities | (559 | ) | (447 | ) | ||||
Cash flows from financing activities: | ||||||||
Issuance of long-term debt | 596 | — | ||||||
Distribution to noncontrolling interest | (19 | ) | (18 | ) | ||||
Payment of long-term debt | (125 | ) | (200 | ) | ||||
Dividends paid on common shares | (128 | ) | (122 | ) | ||||
Net repayments of commercial paper | (896 | ) | (716 | ) | ||||
Other, net | 14 | 12 | ||||||
Net cash flow used in financing activities | (558 | ) | (1,044 | ) | ||||
Net decrease in cash and cash equivalents | (4 | ) | (6 | ) | ||||
Cash and cash equivalents at beginning of period | 19 | 31 | ||||||
Cash and cash equivalents at end of period | $ | 15 | $ | 25 | ||||
Cash paid (received) during the period for | ||||||||
Interest | $ | 119 | $ | 93 | ||||
Income taxes | (100 | ) | (57 | ) |
See Notes to Condensed Consolidated Financial Statements (Unaudited).
SOUTHERN COMPANY GAS AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
Note 1 - Organization and Basis of Presentation
General
Southern Company Gas (formerly known as AGL Resources Inc.) is an energy services holding company that conducts substantially all of its operations through its subsidiaries. As more fully described in Note 2 herein, on July 1, 2016, we became a wholly owned subsidiary of Southern Company. On July 11, 2016, we changed our name to Southern Company Gas. Unless the context requires otherwise, references to “we,” “us,” “our,” the “company” or “Southern Company Gas” mean consolidated Southern Company Gas and its subsidiaries.
Our Condensed Consolidated Balance Sheet as of December 31, 2015 was derived from our audited consolidated financial statements. We have prepared the accompanying unaudited condensed consolidated financial statements under the rules and regulations of the SEC. In accordance with such rules and regulations, we have condensed or omitted certain information and notes that would typically be included in our annual audited financial statements. Our unaudited condensed consolidated financial statements reflect all adjustments of a normal recurring nature that are, in the opinion of management, necessary for a fair statement of our financial results for the interim periods and should be read in conjunction with our consolidated financial statements and related notes included in Item 8 of our 2015 Form 10-K.
Due to the seasonal nature of our business and other factors, our results of operations and our financial condition for the periods presented are not necessarily indicative of the results of operations or financial condition to be expected for, or as of, any other period.
Basis of Presentation
Our unaudited condensed 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 unaudited Condensed Consolidated Statements of Income. See Note 10 for additional information on our non-wholly owned entities. 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.
Note 2 - Merger with Southern Company
On July 1, 2016, we completed the previously announced merger with Southern Company. In accordance with the Merger Agreement, a wholly owned subsidiary of Southern Company merged with and into the company, with us surviving as a wholly owned subsidiary of Southern Company.
At the effective time of the merger, each share of our common stock, other than certain excluded shares, was converted into the right to receive $66 in cash, without interest. Also at the effective time of the merger:
• | our outstanding restricted stock units, restricted stock awards and non-employee director stock awards were deemed fully vested and were canceled and converted into the right to receive an amount in cash equal to the product of (i) the total number of shares of our common stock subject to such award and (ii) the merger consideration of $66 per share; |
• | our outstanding stock options, all of which were fully vested, were canceled and converted into the right to receive an amount in cash equal to the product of (i) the total number of shares of our common stock subject to such options and (ii) the excess of the merger consideration of $66 per share over the applicable exercise price per share of such options; and |
• | each outstanding award of performance share units was converted into an award of Southern Company's restricted stock units. The conversion ratio was the product of (i) the greater of (a) 125% of the number of units underlying such award based on target level achievement of all relevant performance goals and (b) the number of units underlying such award based on the actual level of achievement of all relevant performance goals against target and (ii) an exchange ratio based on the merger consideration of $66 per share as compared to the volume-weighted average price per share of Southern Company common stock, on the same terms and conditions relating to vesting schedule and payment terms, and otherwise on similar terms and conditions, as were applicable to such performance share unit awards, subject to certain exceptions. |
During the three and six months ended June 30, 2016, we recorded merger-related expenses on the accompanying unaudited Condensed Consolidated Statements of Income of $53 million ($39 million, net of tax) and $56 million ($41 million, net of tax), respectively. The transaction costs incurred for the three and six months ended June 30, 2016 were comprised of $29 million and $31 million, respectively, of financial advisory fees, legal expenses and other merger-related costs, including certain amounts payable upon successful completion of the merger, which was deemed probable on June 29, 2016, and $24 million and $25 million, respectively, of additional compensation related expenses, including accelerated vesting of share-based compensation expenses and certain merger-related compensation charges. We previously treated these costs as tax deductible since the requisite closing conditions to the merger had not yet been satisfied. During the second quarter of 2016, when the merger became probable, we re-evaluated the tax deductibility of these costs and reflected any non-deductible amounts in the effective tax rate.
The receipt of required regulatory approvals was conditioned upon certain terms and commitments. In connection with these regulatory approvals, certain regulatory agencies have prohibited us from recovering goodwill and merger-related expenses, required us to maintain a minimum number of employees for a set period of time to ensure that certain pipeline safety standards and the competence level of the employee workforce is not degraded, and/or required us to maintain our pre-merger level of support for various social and charitable programs. The most notable terms and commitments with potential financial impacts include:
• | rate credits of $18 million to be paid to customers in New Jersey and Maryland; |
• | sharing of merger savings with customers in Georgia starting in 2020; |
• | phasing-out the use of the Nicor name or logo by our retail energy subsidiaries in conducting non-utility business in Illinois; |
• | reaffirming that Elizabethtown Gas will file a base rate case no later than September 1, 2016, with another base rate case no later than three years after the 2016 rate case; |
• | requiring Elkton Gas to file a base rate case within 2 years of closing the merger; and |
• | there is no restriction on our other utilities ability to file future rate cases. |
As these terms and commitments are related to post-merger operations, our financial position and results of operations as of and for the three and six months ended June 30, 2016 did not reflect the financial impacts of these items.
Upon completion of the merger, we amended and restated our Bylaws and Articles of Incorporation, under which we now have the authority to issue no more than 110 million shares of stock consisting of (i) 100 million shares of common stock and (ii) 10 million shares of preferred stock, both categories of which have a par value of $0.01 per share. The amended and restated Articles of Incorporation do not allow any treasury shares to be held. Additionally, upon completion of the merger, we provided notice of our change in control to holders of certain senior notes and made an offer to prepay up to $275 million of such debt instruments. These senior notes are included in current portion of long-term debt on the accompanying unaudited Condensed Consolidated Balance Sheet as of June 30, 2016.
Note 3 - Significant Accounting Policies and Methods of Application
Our significant accounting policies are described in Note 3 to our consolidated financial statements and related notes included in Item 8 of our 2015 Form 10-K. There have been no significant changes to our accounting policies during the year.
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 accounting 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, goodwill and other intangible assets, derivatives and hedging activities, uncollectible accounts and other allowances for contingent losses, retirement plan benefit obligations and provisions for income taxes. We evaluate our estimates on an ongoing basis, and our actual results could differ from our estimates.
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.
Nicor Gas’ inventory is carried at cost on a LIFO basis. Under the LIFO method, inventory decrements occurring during the year that are expected to be restored prior to year-end are charged to cost of goods sold at the estimated annual replacement cost, and the difference between this cost and the actual liquidated LIFO layer cost is recorded as a temporary LIFO liquidation on our unaudited Condensed Consolidated Balance Sheets. Interim inventory decrements that are not expected to be restored prior to year-end are charged to cost of goods sold at the actual LIFO cost of the layers liquidated. The inventory decrement as of June 30, 2016 is expected to be restored prior to year-end and the inventory decrement as of June 30, 2015 was restored prior to December 31, 2015.
Our retail operations, wholesale services and midstream operations segments carry inventory at LOCOM, where cost is determined on a WACOG basis. For the periods presented, we recorded LOCOM adjustments to cost of goods sold in the following amounts to reduce the value of our natural gas inventories to market value.
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
In millions | 2016 | 2015 | 2016 | 2015 | ||||||||||||
LOCOM adjustments | $ | — | $ | — | $ | 3 | $ | 10 |
Goodwill
We perform an annual impairment test on our reporting units that contain goodwill during the fourth fiscal quarter of each year or more frequently if impairment indicators arise. The amounts of goodwill as of June 30, 2016 and 2015, and December 31, 2015 are provided in the following table.
In millions | Distribution operations | Retail operations | Midstream operations | Consolidated | ||||||||||||
Goodwill - June 30, 2015 | $ | 1,640 | $ | 173 | $ | 14 | $ | 1,827 | ||||||||
Impairment (1) | — | — | (14 | ) | (14 | ) | ||||||||||
Goodwill - December 31, 2015 | 1,640 | 173 | — | 1,813 | ||||||||||||
Goodwill - June 30, 2016 | $ | 1,640 | $ | 173 | $ | — | $ | 1,813 |
(1) Based on the result of an interim impairment test performed as of September 30, 2015, we recorded a non-cash impairment charge of the full $14 million ($9 million, net of tax) of goodwill at midstream operations.
(Loss) Earnings per Common Share
The following table shows the calculation of our diluted shares attributable to Southern Company Gas 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.
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
In millions, except per share amounts | 2016 | 2015 | 2016 | 2015 | ||||||||||||
Net (loss) income attributable to Southern Company Gas | $ | (51 | ) | $ | 42 | $ | 131 | $ | 235 | |||||||
Denominator | ||||||||||||||||
Basic weighted average number of shares outstanding (1) | 120.3 | 119.5 | 120.2 | 119.4 | ||||||||||||
Effect of dilutive securities | 0.2 | 0.3 | 0.3 | 0.3 | ||||||||||||
Diluted weighted average number of shares outstanding (2) | 120.5 | 119.8 | 120.5 | 119.7 | ||||||||||||
(Loss) earnings per common share attributable to Southern Company Gas | ||||||||||||||||
Basic (loss) earnings per common share | $ | (0.43 | ) | $ | 0.35 | $ | 1.09 | $ | 1.97 | |||||||
Diluted (loss) earnings per common share | $ | (0.43 | ) | $ | 0.35 | $ | 1.09 | $ | 1.96 |
(1) | Daily weighted average shares outstanding. |
(2) | Excludes all outstanding stock options whose effect would have been anti-dilutive. |
Upon completing the merger with Southern Company on July 1, 2016, all of our common shares are held, beneficially and of record, by Southern Company. As a result, earnings per common share disclosures will no longer be included in our quarterly and annual reports.
Accounting Developments
Accounting standards adopted in 2016
Effective January 1, 2016, we adopted the accounting guidance described below, none of which had a material impact on our unaudited condensed consolidated financial statements. For additional information on these accounting standards, see "Accounting Developments" in Note 3 to our consolidated financial statements and related notes included in Item 8 of our 2015 Form 10-K.
• | accounting for a share-based compensation performance target that could be achieved after the requisite service period; |
• | consolidation of other legal entities into our financial statements; |
• | accounting for fees paid in connection with arrangements with cloud-based software providers; and |
• | reducing the diversity in fair value measurements hierarchy disclosures. |
Other newly issued accounting standards and updated authoritative guidance
In March 2016, the FASB issued updated authoritative guidance related to accounting for certain aspects of share-based payment transactions. The new guidance changes the income tax accounting related to the tax "windfall" or "shortfall" on share-based compensation, increases the tax withholding level allowed before triggering liability classification of the award and allows for a policy election to account for forfeitures as they occur. This guidance 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 February 2016, the FASB issued updated authoritative guidance related to accounting for lease transactions. The new guidance will require all organizations that use leased assets, referred to as "lessees," to recognize all leases with terms of more than 12 months on the balance sheet as right of use assets and corresponding liabilities. Lessees will continue to recognize lease expense based on classification of the lease, using a straight-line expense pattern for operating leases and a front-loaded expense pattern for financing leases. The accounting for lessors is substantially equivalent to the existing guidance. It also requires additional disclosures, both qualitative and quantitative, including amount, timing, and uncertainty of cash flows arising from leases. The new guidance is effective for us beginning January 1, 2019 and must be applied using the modified retrospective approach to each prior period presented. Early adoption of this new guidance is permitted. We are currently evaluating the potential impact of this new guidance.
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, 2018, and limited early adoption is permitted. We are currently evaluating the potential impact of this new guidance, but do not anticipate that it will have a material impact on our consolidated financial statements.
In November 2015, the FASB issued updated authoritative guidance related to the balance sheet classification of deferred taxes, which requires companies to present deferred income tax assets and deferred income tax liabilities as noncurrent on 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, and early application is permitted either prospectively or retrospectively. We expect to adopt this new guidance in the third quarter of 2016 and have determined that this new guidance will not have a material impact on our consolidated financial statements.
In July 2015, the FASB issued an update to 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 effective for us beginning January 1, 2017 with prospective application, and early adoption is permitted. We are currently evaluating the potential impact of this new guidance.
In May 2014, the FASB issued an update to 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 determined the impact of this new guidance, nor have we selected a transition method.
Note 4 - Regulated Operations
The accounting policies for our regulated operations are described within "Regulated Operations" in Note 3 to our consolidated financial statements and related notes included in Item 8 of our 2015 Form 10-K. Our regulatory assets and liabilities recorded on our unaudited Condensed Consolidated Balance Sheets as of the dates presented are summarized in the following table.
In millions | June 30, 2016 | December 31, 2015 | June 30, 2015 | |||||||||
Regulatory assets | ||||||||||||
Recoverable ERC | $ | 18 | $ | 31 | $ | 27 | ||||||
Recoverable pension and retiree welfare benefit costs | 12 | 12 | 11 | |||||||||
Unrecovered weather normalization | 9 | — | 1 | |||||||||
Deferred natural gas costs | — | 6 | — | |||||||||
Recoverable seasonal rates | — | 10 | — | |||||||||
Other | 8 | 9 | 9 | |||||||||
Regulatory assets – current | 47 | 68 | 48 | |||||||||
Recoverable ERC | 386 | 370 | 350 | |||||||||
Recoverable pension and retiree welfare benefit costs | 109 | 113 | 105 | |||||||||
Recoverable regulatory infrastructure program costs | 84 | 83 | 77 | |||||||||
Long-term debt fair value adjustment | 63 | 66 | 70 | |||||||||
Other | 37 | 38 | 40 | |||||||||
Regulatory assets – long-term | 679 | 670 | 642 | |||||||||
Total regulatory assets | $ | 726 | $ | 738 | $ | 690 | ||||||
Regulatory liabilities | ||||||||||||
Accumulated removal costs | $ | 52 | $ | 53 | $ | 25 | ||||||
Bad debt over collection | 49 | 42 | 27 | |||||||||
Accrued natural gas costs | 29 | 24 | 67 | |||||||||
Deferred seasonal rates | 8 | — | 8 | |||||||||
Other | 18 | 15 | 27 | |||||||||
Regulatory liabilities – current | 156 | 134 | 154 | |||||||||
Accumulated removal costs | 1,552 | 1,538 | 1,544 | |||||||||
Regulatory income tax liability | 24 | 27 | 27 | |||||||||
Bad debt over collection | 23 | 21 | 18 | |||||||||
Unamortized investment tax credit | 19 | 20 | 21 | |||||||||
Other | 9 | 5 | 12 | |||||||||
Regulatory liabilities – long-term | 1,627 | 1,611 | 1,622 | |||||||||
Total regulatory liabilities | $ | 1,783 | $ | 1,745 | $ | 1,776 |
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.
Unrecognized Ratemaking Amounts The following table illustrates our authorized ratemaking amounts that are not recognized on our unaudited Condensed 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.
In millions | June 30, 2016 | December 31, 2015 | June 30, 2015 | |||||||||
Atlanta Gas Light (1) | $ | 106 | $ | 103 | $ | 126 | ||||||
Virginia Natural Gas | 12 | 12 | 11 | |||||||||
Elizabethtown Gas | 5 | 4 | 3 | |||||||||
Nicor Gas | 3 | 3 | 1 | |||||||||
Total | $ | 126 | $ | 122 | $ | 141 |
(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 that allows Atlanta Gas Light to recover $144 million of the $178 million of incurred and allowed costs that were deferred for future recovery. |
Deferred/Accrued 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 regulatory agencies. 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 conventional engineering-based cost estimates and probabilistic models of estimated costs when such conventional 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 rate riders that authorize dollar-for-dollar recovery. We expect to collect $18 million in revenues over the next 12 months, which is reflected as a current regulatory asset. The following table provides additional information on the estimated costs to remediate our current and former operating sites as of June 30, 2016.
Dollars in millions | # of sites | Probabilistic model cost estimates | Engineering-based cost estimates | Amount recorded | Expected costs over next 12 months | Cost recovery period | |||||||||||||
Illinois (1) | 26 | $206 - $470 | $ | 46 | $ | 252 | $ | 27 | As incurred | ||||||||||
New Jersey | 6 | 111 - 190 | 8 | 119 | 14 | 7 years | |||||||||||||
Georgia and Florida | 13 | 38 - 64 | 24 | 62 | 18 | 5 years | |||||||||||||
North Carolina (2) | 1 | n/a | 5 | 5 | — | No recovery | |||||||||||||
Total | 46 | $355 - $724 | $ | 83 | $ | 438 | $ | 59 |
(1) | 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%. |
(2) | 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. |
Regulatory Infrastructure Programs An update to our infrastructure improvement programs at our utilities is as follows:
Virginia Natural Gas In March 2016, the Virginia Commission approved an extension to our original Steps to Advance Virginia's Energy (SAVE) program to replace more than 200 miles of aging pipeline infrastructure. Under this program, Virginia Natural Gas is allowed to invest up to $30 million in 2016 and $35 million annually in years 2017 through 2021 on qualifying infrastructure projects.
Note 5 - Fair Value Measurements
The methods used to determine the fair values of our assets and liabilities are described within "Fair Value Measurements" in Note 3 to our consolidated financial statements and related notes included in Item 8 of our 2015 Form 10-K.
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 unaudited Condensed Consolidated Balance Sheets as of the dates presented. See Note 6 herein for additional information on our derivative instruments.
June 30, 2016 | December 31, 2015 | June 30, 2015 | ||||||||||||||||||||||
In millions | Assets (1) | Liabilities | Assets (1) | Liabilities | Assets (1) | Liabilities | ||||||||||||||||||
Quoted prices in active markets (Level 1) | $ | 17 | $ | (80 | ) | $ | 53 | $ | (63 | ) | $ | 3 | $ | (53 | ) | |||||||||
Significant other observable inputs (Level 2) | 50 | (76 | ) | 122 | (46 | ) | 128 | (45 | ) | |||||||||||||||
Netting of counterparty offset and cash collateral | 43 | 77 | 33 | 63 | 64 | 53 | ||||||||||||||||||
Total carrying value (2) | $ | 110 | $ | (79 | ) | $ | 208 | $ | (46 | ) | $ | 195 | $ | (45 | ) |
(1) | Balances of $5 million at June 30, 2016, $10 million at December 31, 2015 and $2 million at June 30, 2015, 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. |
Long-Term 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 lists the carrying amount and fair value of our long-term debt as of the dates presented.
In millions | June 30, 2016 | December 31, 2015 | June 30, 2015 | |||||||||
Long-term debt carrying amount | $ | 4,284 | $ | 3,820 | $ | 3,577 | ||||||
Long-term debt fair value (1) | 4,836 | 4,066 | 3,857 |
(1) | Fair value determined using Level 2 inputs. |
Note 6 - Derivative Instruments
Our objectives and strategies for using derivative instruments, and the related accounting policies and methods used to determine their fair values are described within "Fair Value Measurements" in Note 3 to our consolidated financial statements and related notes included in Item 8 of our 2015 Form 10-K. See Note 5 herein for additional information on the fair value of our derivative instruments. 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 June 30, 2016, December 31, 2015 and June 30, 2015, for agreements with such features, derivative instruments with liability fair values totaled $79 million, $46 million and $45 million, respectively, for which we had posted no collateral to our counterparties as we exceed the minimum credit rating requirements. As of June 30, 2016, 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 to our consolidated financial statements and related notes included in Item 8 of our 2015 Form 10-K. Our derivative instrument activities are included within operating cash flows as increases to net income of $136 million and $42 million for the six months ended June 30, 2016 and 2015, respectively.
Quantitative Disclosures Related to Derivative Instruments
Our derivative instruments include 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 the dates presented, we had natural gas contracts outstanding in the following quantities:
In Bcf (1) | June 30, 2016 (2) | December 31, 2015 | June 30, 2015 | ||||||
Cash flow hedges | 4 | 5 | 6 | ||||||
Not designated as hedges | 38 | (14 | ) | 24 | |||||
Total volumes | 42 | (9 | ) | 30 | |||||
Short position – cash flow hedges | (5 | ) | (6 | ) | (8 | ) | |||
Short position – not designated as hedges | (3,092 | ) | (3,089 | ) | (2,930 | ) | |||
Long position – cash flow hedges | 9 | 11 | 14 | ||||||
Long position – not designated as hedges | 3,130 | 3,075 | 2,954 | ||||||
Net long (short) position | 42 | (9 | ) | 30 |
(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) | 97% of these contracts have durations of two years or less and 3% expire between two and five years. |
In addition to natural gas derivative contracts, we entered into interest rate swaps, which we account for as cash flow hedges. See Note 8 herein for additional information on our interest rate swaps.
Derivative Instruments on our Unaudited Condensed 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 unaudited Condensed Consolidated Balance Sheets until they are billed to customers. The following amounts deferred as a regulatory asset or liability on our unaudited Condensed Consolidated Balance Sheets are included in the net realized gains (losses) related to these natural gas cost hedging activities as of the periods presented.
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
In millions | 2016 | 2015 | 2016 | 2015 | ||||||||||||
Nicor Gas | $ | (10 | ) | $ | (18 | ) | $ | (12 | ) | $ | (21 | ) | ||||
Elizabethtown Gas | (4 | ) | (4 | ) | (10 | ) | (8 | ) |
The following table presents the fair values and unaudited Condensed Consolidated Balance Sheets classifications of our derivative instruments as of the dates presented.
June 30, 2016 | December 31, 2015 | June 30, 2015 | ||||||||||||||||||||||||
In millions | Classification | Assets | Liabilities | Assets | Liabilities | Assets | Liabilities | |||||||||||||||||||
Designated as cash flow hedges | ||||||||||||||||||||||||||
Natural gas contracts | Current | $ | 4 | $ | (4 | ) | $ | 3 | $ | (5 | ) | $ | — | $ | (4 | ) | ||||||||||
Natural gas contracts | Long-term | — | (1 | ) | — | (2 | ) | — | (1 | ) | ||||||||||||||||
Interest rate swap agreements | Current | — | (30 | ) | 9 | — | 24 | — | ||||||||||||||||||
Interest rate swap agreements | Long-term | — | — | — | — | 23 | — | |||||||||||||||||||
Total designated as cash flow hedges | $ | 4 | $ | (35 | ) | $ | 12 | $ | (7 | ) | $ | 47 | $ | (5 | ) | |||||||||||
Not designated as hedges | ||||||||||||||||||||||||||
Natural gas contracts | Current | $ | 520 | $ | (557 | ) | $ | 751 | $ | (672 | ) | $ | 473 | $ | (481 | ) | ||||||||||
Natural gas contracts | Long-term | 83 | (99 | ) | 179 | (187 | ) | 92 | (91 | ) | ||||||||||||||||
Total not designated as hedges | $ | 603 | $ | (656 | ) | $ | 930 | $ | (859 | ) | $ | 565 | $ | (572 | ) | |||||||||||
Gross amounts of recognized assets and liabilities (1) (2) | $ | 607 | $ | (691 | ) | $ | 942 | $ | (866 | ) | $ | 612 | $ | (577 | ) | |||||||||||
Gross amounts offset on our unaudited Condensed Consolidated Balance Sheets (2) | (492 | ) | 612 | (724 | ) | 820 | (415 | ) | 532 | |||||||||||||||||
Net amounts of assets and liabilities presented on our unaudited Condensed Consolidated Balance Sheets (3) | $ | 115 | $ | (79 | ) | $ | 218 | $ | (46 | ) | $ | 197 | $ | (45 | ) |
(1) | The gross amounts of recognized assets and liabilities are netted within our unaudited Condensed 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 $120 million as of June 30, 2016, $96 million as of December 31, 2015, and $117 million as of June 30, 2015. Cash collateral is included in the “Gross amounts offset on our unaudited Condensed Consolidated Balance Sheets” line of this table. |
(3) | As of June 30, 2016, December 31, 2015, and June 30, 2015, we held letters of credit from counterparties that under master netting arrangements would offset an insignificant portion of these assets. |
Derivative Instruments on our Unaudited Condensed Consolidated Statements of Income
The following table presents the impacts of our derivative instruments on our unaudited Condensed Consolidated Statements of Income for the periods presented.
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
In millions | 2016 | 2015 | 2016 | 2015 | ||||||||||||
Designated as cash flow hedges (1) | ||||||||||||||||
Natural gas contracts - net loss reclassified from OCI into cost of goods sold | $ | (1 | ) | $ | (3 | ) | $ | (1 | ) | $ | (4 | ) | ||||
Natural gas contracts - net loss reclassified from OCI into operation and maintenance expense | — | (1 | ) | — | (1 | ) | ||||||||||
Interest rate swaps - net (loss) gain reclassified from OCI into interest expense | (1 | ) | — | — | 1 | |||||||||||
Total designated as cash flow hedges, net of tax | (2 | ) | (4 | ) | (1 | ) | (4 | ) | ||||||||
Not designated as hedges (1) | ||||||||||||||||
Natural gas contracts - net fair value adjustments recorded in operating revenues | (93 | ) | 3 | (73 | ) | (21 | ) | |||||||||
Natural gas contracts - net fair value adjustments recorded in cost of goods sold (2) | 5 | 1 | 4 | (1 | ) | |||||||||||
Income tax | 33 | (1 | ) | 26 | 9 | |||||||||||
Total not designated as hedges, net of tax | (55 | ) | 3 | (43 | ) | (13 | ) | |||||||||
Total losses on derivative instruments, net of tax | $ | (57 | ) | $ | (1 | ) | $ | (44 | ) | $ | (17 | ) |
(1) | Associated with the fair value of derivative instruments held at June 30, 2016 and 2015. |
(2) | Excludes gains (losses) recorded in cost of goods sold associated with weather derivatives of less than $1 million and $3 million for the three and six months ended June 30, 2016, respectively, and $1 million and $(1) million for the three and six months ended June 30, 2015, respectively, as they are accounted for based on intrinsic value rather than fair value. |
Amounts recognized in income related to ineffectiveness or due to a forecasted transaction that is no longer expected to occur were immaterial for all periods presented. Upon settlement of our interest rate swaps on May 13, 2016, we realized a $26 million loss that was recognized in accumulated other comprehensive loss on our unaudited Condensed Consolidated Balance Sheet as of June 30, 2016. Our expected net losses to be reclassified from OCI into cost of goods sold, operation and maintenance expense, interest expense and operating revenues to be recognized on our unaudited Condensed Consolidated Statements of Income over the next 12 months are $3 million. These deferred losses are related to natural gas derivative contracts associated with retail operations’ and Nicor Gas’ system use and our interest rate swaps. The expected losses are based upon the fair values of these financial instruments at June 30, 2016. 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 unaudited Condensed Consolidated Statements of Income. See Note 9 herein for these amounts.
There have been no other significant changes to our derivative instruments, as described in Note 3, Note 5, Note 6 and Note 10 to our consolidated financial statements and related notes included in Item 8 of our 2015 Form 10-K.
Note 7 - Employee Benefit Plans
Effective July 1, 2016, in connection with the approval of the merger, Southern Company Services, Inc. became the sponsor of the two benefit plans discussed below.
Pension Benefits
The benefits of our Southern Company Gas Retirement Plan, a tax-qualified defined benefit retirement plan for our eligible employees, are described in Note 7 to our consolidated financial statements and related notes included in Item 8 of our 2015 Form 10-K. Following are the components of our pension costs for the periods indicated.
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
In millions | 2016 | 2015 | 2016 | 2015 | ||||||||||||
Service cost (1) | $ | 7 | $ | 7 | $ | 13 | $ | 14 | ||||||||
Interest cost (1) | 11 | 12 | 21 | 23 | ||||||||||||
Expected return on plan assets | (17 | ) | (17 | ) | (33 | ) | (33 | ) | ||||||||