Notes to Condens
ed Consolidated Financial Statements (unaudited)
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1.
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Basis of Accounting Presentation
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The accompanying unaudited condensed consolidated financial statements for NiSource reflect all normal recurring adjustments that are
necessary, in the opinion of management, to present fairly the results of operations in accordance with GAAP in the United States of America.
The accompanying financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in
NiSource’s Annual Report on Form 10-K for the fiscal year ended December 31, 2010. Income for interim periods may not be indicative of results for the calendar year due to weather variations and other factors.
The unaudited condensed consolidated financial statements have been prepared pursuant to the rules and regulations of the SEC. Certain information and
note disclosures normally included in annual financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to those rules and regulations, although NiSource believes that the disclosures made are adequate to make the
information not misleading.
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2.
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Recent Accounting Pronouncements
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Recently Adopted Accounting Pronouncements
Fair Value Measurements and Disclosures.
In January 2010, the FASB issued authoritative guidance that amends the disclosures about transfers into and out of Levels 1 and 2 and
requires separate disclosures about purchases, sales, issuances, and settlements relating to Level 3 measurements. This guidance also clarifies existing fair value disclosures about the level of disaggregation and about inputs and valuation
techniques used to measure fair value. This guidance is effective for the first reporting period, including interim periods, beginning after December 15, 2009, except for the requirement to provide Level 3 activity of purchases, sales,
issuances, and settlements on a gross basis, which is effective for fiscal years beginning after December 15, 2010. Early adoption is permitted. NiSource adopted the guidance on January 1, 2010 with the exception of the requirement to
provide Level 3 activity of purchases, sales, issuances, and settlements on a gross basis. The guidance pertaining to the gross presentation of Level 3 activity was adopted on January 1, 2011. Refer to Note 9, “Fair Value
Disclosures,” for additional information.
Recently Issued Accounting Pronouncements
Goodwill Impairment
. In September 2011, the FASB issued Accounting Standards Update 2011-08, which gives entities testing goodwill for
impairment the option of performing a qualitative assessment before calculating the fair value of a reporting unit for the goodwill impairment test. The amendment is effective for fiscal years, and interim periods within those years, beginning after
December 15, 2011. NiSource is currently reviewing the provisions of this new standard to determine the impact on its Condensed Consolidated Financial Statements (unaudited) and Notes to Condensed Consolidated Financial Statements (unaudited).
Comprehensive Income
. In June 2011, the FASB issued Accounting Standards Update 2011-05, which revises the manner in which
entities present comprehensive income in their financial statements. The new guidance removes the presentation options in ASC 220 and requires entities to report components of comprehensive income in either (1) a continuous statement of
comprehensive income or (2) two separate but consecutive statements. The update does not change the items that must be reported in other comprehensive income. For public entities, the amendments are effective for fiscal years, and interim
periods within those years, beginning after December 15, 2011. NiSource is currently reviewing the provisions of this new standard to determine the impact on its Condensed Consolidated Financial Statements (unaudited) and Notes to Condensed
Consolidated Financial Statements (unaudited).
Basic EPS is computed by dividing income available to common stockholders by the weighted-average number of shares of common stock
outstanding for the period. The weighted average shares outstanding for diluted EPS includes the incremental effects of the various long-term incentive compensation plans and the Forward Agreements (refer to Note 4 “Forward Equity
Agreement” for additional information). The calculation of diluted earnings per
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ITEM 1.
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FINANCIAL STATEMENTS (continued)
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N
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NC
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Notes to Condensed Consolidated Financial Statements (unaudited) (continued)
share for September 30, 2011 and 2010 excludes out-of-the-money stock options that had an anti-dilutive effect. The numerator in calculating both basic and diluted EPS for each period is
reported net income. The computation of diluted average common shares follows:
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Three Months Ended
September 30,
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Nine Months Ended
September 30,
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(in thousands)
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2011
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2010
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2011
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2010
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Denominator
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Basic average common shares outstanding
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280,765
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278,088
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280,112
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277,538
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Dilutive potential common shares
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Stock options
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19
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—
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—
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—
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Shares contingently issuable under employee stock plans
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1,119
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957
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1,087
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903
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Shares restricted under employee stock plans
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376
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410
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342
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368
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Forward Agreements
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6,731
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415
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5,814
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138
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Diluted Average Common Shares
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289,010
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279,870
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287,355
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278,947
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4.
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Forward Equity Agreement
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On September 14, 2010, NiSource and Credit Suisse Securities (USA) LLC, as forward seller, closed an underwritten registered
public offering of 24,265,000 shares of NiSource’s common stock. All of the shares sold were borrowed and delivered to the underwriters by the forward seller. NiSource did not receive any of the proceeds from the sale of the borrowed shares,
but NiSource will receive proceeds upon settlement of the Forward Agreements referred to below.
In connection with the public offering,
NiSource entered into forward sale agreements (“Forward Agreements”) with an affiliate of the forward seller covering an aggregate of 24,265,000 shares of NiSource’s common stock. Settlement of the Forward Agreements is expected to
occur no later than September 10, 2012. Subject to certain exceptions, NiSource may elect cash or net share settlement for all or a portion of its obligations under the Forward Agreements. Upon any physical settlement of the Forward Agreements,
NiSource will deliver shares of its common stock in exchange for cash proceeds at the forward sale price, which initially is $15.9638 and is subject to adjustment as provided in the Forward Agreements. If the equity forward had been settled by
delivery of shares at September 30, 2011, NiSource would have received approximately $363.3 million based on a forward price of $14.972 for the 24,265,000 shares. NiSource currently anticipates settling the equity forward by delivering shares.
In accordance with ASC 815-40, NiSource has classified the Forward Agreement as an equity transaction. As a result of this classification, no
amounts have been recorded in the Condensed Consolidated Financial Statements (unaudited) as of and for the nine months ended September 30, 2011 and the year ended December 31, 2010 in connection with the Forward Agreements. The only
impact to the Condensed Consolidated Financial Statements (unaudited) is the inclusion of incremental shares within the calculation of fully diluted EPS under the treasury stock method. Refer to Note 3, “Earnings Per Share,” for additional
information.
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5.
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Discontinued Operations and Assets and Liabilities Held for Sale
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The assets of discontinued operations and held for sale on the Condensed Consolidated Balance Sheets (unaudited) at September 30,
2011 were:
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(in millions)
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Property, plant and
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Assets of discontinued operations and held for sale:
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equipment, net
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Columbia Transmission
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$
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2.3
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Total
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$
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2.3
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There were no liabilities of discontinued operations held for sale at September 30, 2011.
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ITEM 1.
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FINANCIAL STATEMENTS (continued)
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Notes to Condensed Consolidated Financial Statements (unaudited) (continued)
The assets of discontinued operations and held for sale on the Condensed Consolidated Balance Sheets
(unaudited) at December 31, 2010 were:
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(in millions)
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Assets of discontinued operations and held for sale:
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Property, plant and
equipment, net
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NiSource Corporate Services
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$
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5.6
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Columbia Transmission
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2.3
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Total
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$
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7.9
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Assets classified as discontinued operations or held for sale are no longer depreciated. There were no liabilities of
discontinued operations held for sale at December 31, 2010.
On February 22, 2011, NiSource Corporate Services sold the Marble Cliff
facility for $6.0 million. The sale resulted in a net gain of $0.2 million after deducting the fees associated with the transaction.
On
June 18, 2009, Columbia Transmission received approval from the FERC to abandon certain natural gas pipeline facilities by sale of its Line R System in West Virginia. Assets held for sale related to the Line R System have a net book value of
$2.1 million, the sale of which continues to be negotiated with a third party.
Lake Erie Land, which is a wholly-owned subsidiary of NiSource
Development Company, was in the process of selling real estate over a 10-year period as a part of an agreement reached in June 2006 with a private real estate development group. In the second quarter of 2009, the developer was unable to meet certain
contractual obligations under the sale agreement and consequently NiSource sought remedial actions. In April 2011, NiSource settled a mortgage foreclosure action against the developer, reacquired the Sand Creek Country Club, and purchased additional
properties owned by the developer to be marketed along with the existing Lake Erie Land properties to prospective purchasers. This transaction qualified as a business combination in accordance with GAAP. The properties were acquired at fair value
and included the Sand Creek Country Club and additional commercial properties for a total of $15.8 million and $3.5 million of land and are included in Other Investments and Other Property in the Condensed Consolidated Balance Sheet (unaudited) at
September 30, 2011. NiSource’s total investment in Lake Erie Land after these acquisitions is $51.3 million as of September 30, 2011. NiSource is seeking to market the Lake Erie Land properties, but has determined they do not meet the
criteria to be classified as assets held for sale in accordance with GAAP as of September 30, 2011. The revenue and earnings of Sand Creek Country Club are not material.
Results from discontinued operations, which primarily arise from changes in estimate for certain liabilities for NiSource’s former exploration and production subsidiary, CER, are provided in the
following table:
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Three Months Ended
September 30,
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Nine Months Ended
September 30,
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(in millions)
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2011
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2010
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2011
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2010
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Revenues from Discontinued Operations
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$
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—
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$
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—
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$
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—
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$
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0.7
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Loss from discontinued operations
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(2.7
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)
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(0.4
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)
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(2.8
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)
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(0.5
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Income tax benefit
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(1.1
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)
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(0.2
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(1.0
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(0.2
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Loss from Discontinued Operations—net of taxes
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$
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(1.6
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$
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(0.2
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$
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(1.8
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)
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$
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(0.3
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Gain on Disposition of Discontinued Operations—net of taxes
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$
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—
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$
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—
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$
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—
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$
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0.1
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12
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ITEM 1.
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FINANCIAL STATEMENTS (continued)
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N
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Notes to Condensed Consolidated Financial Statements (unaudited) (continued)
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6.
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Asset Retirement Obligations
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Certain costs of removal that have been, and continue to be, included in depreciation rates and collected in the service rates of the
rate-regulated subsidiaries are classified as “Regulatory liabilities and other removal costs” on the Condensed Consolidated Balance Sheets (unaudited).
Changes in NiSource’s liability for asset retirement obligations for the nine months ended September 30, 2011 and 2010 are presented in the table below:
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(in millions)
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2011
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2010
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Balance as of January 1,
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$
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138.8
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$
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138.2
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Accretion expense
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0.5
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0.6
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Accretion recorded as a regulatory asset/liability
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5.8
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5.6
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Settlements
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(1.7
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(5.6
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Change in estimated cash flows
(a)
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(2.9
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(4.5
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Balance as of September 30,
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$
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140.5
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$
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134.3
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(a)
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The change in estimated cash flows for 2010 is attributed to changes in the estimated useful lives and costs for electric generating stations.
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Gas Distribution Operations Regulatory Matters
Significant Rate Developments
. On June 1, 2011, Columbia of Virginia filed an application for approval of an infrastructure tracking mechanism pursuant to the Steps to Advance
Virginia’s Energy (“SAVE”) Plan Act. Columbia of Virginia’s SAVE Plan provides for recovery of costs associated with the accelerated replacement of certain facilities designed to improve system safety or reliability through a
rate rider that would commence on December 30, 2011. The proposed replacement program would result in investments of $20 million per year from 2012 through 2016, as well as covering $2.9 million in investment occurring in 2011. The Staff of the
VSCC filed responsive testimony on August 22, 2011 and a public hearing was held on September 7, 2011. The Hearing Examiner issued a Report on October 6, 2011 recommending approval of the substantive provisions of the SAVE Plan. A
VSCC Order is due to be issued by November 28, 2011.
On March 8, 2011, Columbia of Kentucky made its annual filing with the
Kentucky PSC related to the AMRP Rider and requested an increase of $0.5 million in the rates related to the Rider. This filing was approved by the Kentucky PSC on April 29, 2011.
On January 14, 2011, Columbia of Pennsylvania filed a base rate case with the Pennsylvania PUC, seeking a revenue increase of approximately $37.8 million annually, and seeking to implement a
levelized distribution charge for its residential class that would feature the recovery of all fixed costs through a flat monthly charge. The parties jointly filed a petition for approval of a partial settlement on July 1, 2011. The partial
settlement resolved all issues except Columbia of Pennsylvania’s proposed residential rate design and a challenge to the structure of one of Columbia of Pennsylvania’s customer programs. The settlement provides for an annual revenue
increase of $17 million. The Pennsylvania PUC issued an order on October 14, 2011 approving the annual revenue increase of $17 million. New rates went into effect on October 18, 2011. The Pennsylvania PUC’s ruling increased the
minimum residential customer charge from $12.25 to $18.73, which includes charges for a 20 Ccf monthly usage allowance for residential customers before a volumetric distribution charge is applied.
On November 30, 2010, Columbia of Ohio filed a notice of intent to file an application to adjust rates associated with Rider IRP and Rider DSM. On
February 28, 2011, Columbia of Ohio filed its application to adjust rates associated with IRP and DSM Riders. The DSM Rider tracks and recovers costs associated with Columbia of Ohio’s energy efficiency and conservation programs. The
application sought to increase the annual revenue from the riders by approximately $24 million. On April 7, 2011, the parties filed a stipulation that settled this case, which was approved as filed by the PUCO on April 27, 2011. The Order
allowed Columbia of Ohio to increase its annual revenues by approximately $24 million effective May 1, 2011.
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ITEM 1.
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FINANCIAL STATEMENTS (continued)
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Notes to Condensed Consolidated Financial Statements (unaudited) (continued)
On November 12, 2010, Columbia of Pennsylvania filed a petition for an order authorizing the
company to revise its accounting methodology for the gas it holds in storage. Columbia of Pennsylvania had historically used Last-In First-Out (LIFO) accounting but sought permission to move to a Weighted Average Cost of Gas (WACOG) accounting
methodology as a means of simplifying regulatory accounting and to realize the value of low-cost gas injected into storage decades ago. On February 4, 2011, Columbia of Pennsylvania filed a settlement agreement with the Pennsylvania PUC in
which regulatory stakeholders agreed that Columbia of Pennsylvania should adopt the WACOG accounting methodology and provide the benefit of the low-cost gas supplies to its customers. On March 31, 2011, the Pennsylvania PUC approved the
settlement and Columbia of Pennsylvania began to provide the benefit of $35.7 million as a credit to its customers as a reduction of the GCR rate.
On September 29, 2010, Columbia of Pennsylvania filed tariff modifications with the Pennsylvania PUC, seeking permission to apply a BTU content billing adjustment to customers’ metered
volumetric consumption. The filing sought to account for high BTU content gas that is produced from Marcellus Shale, which burns hotter than gas from other sources, resulting in lower volumes than assumed in the design of the Columbia of
Pennsylvania’s rates. The proposed billing adjustment was designed to produce revenues reflective of the BTU content underlying the demand forecast in the design of Columbia of Pennsylvania’s most recently approved base rates. If the
billing adjustment had been in place for the twelve months ended June 30, 2010, it would have produced additional revenues of approximately $3.7 million. By an Order entered on January 26, 2011, the Pennsylvania PUC consolidated this
matter with Columbia of Pennsylvania’s base rate case filed on January 14, 2011. As described above, on October 14, 2011, the Pennsylvania PUC approved a partial settlement of the base rate case. The partial settlement resolves the
issue of BTU content whereby Columbia of Pennsylvania will convert from volumetric billing to heat content billing by no later than the June 2012 billing cycle. Columbia of Pennsylvania projects that heat content billing will commence by the
February 2012 billing cycle.
On September 1, 2010 Northern Indiana, Northern Indiana Fuel and Light and Kokomo Gas filed a petition for
merger into one company (Northern Indiana). Northern Indiana Fuel and Light and Kokomo Gas also filed rate proceedings on September 1, 2010. On February 23, 2011, a stipulation and settlement agreement was filed with the IURC that provides
for the merger and settlement of the rate proceedings. The settlement stipulated that all of Northern Indiana’s existing services, rates and charges would be applicable in the former Northern Indiana Fuel and Light and Kokomo Gas territories,
including one unified Gas Cost Adjustment mechanism. The application of Northern Indiana’s rates in the former Northern Indiana Fuel and Light and Kokomo Gas territories will result in a decrease in revenue of approximately $0.8 million, when
compared to a normalized test year ended March 31, 2010. This is primarily offset by reductions in depreciation expense. An uncontested settlement hearing was held on March 23, 2011. The IURC issued its Final Order on May 31, 2011,
approving without change the earlier stipulation and settlement agreement agreed to by the parties. Rates and services provided by the merger agreement became effective July 1, 2011.
On May 3, 2010, Northern Indiana filed a natural gas rate case with the IURC. Northern Indiana entered into a comprehensive settlement with all parties on August 24, 2010. The Settlement
Agreement was approved in entirety by Order issued on November 4, 2010 and new rates were placed into effect November 5, 2010. The Order resulted in a decrease in revenue of approximately $14.9 million when compared to a normalized test
year ended December 31, 2009. The IURC authorized Northern Indiana to increase the monthly fixed charge for residential customers from $6.36 to $11.00. The IURC also approved revised depreciation accrual rates for gas plant and authorized
Northern Indiana to reduce current period gas plant depreciation expense by up to $25.7 million annually for the next four years or until further order of the IURC, whichever occurs first.
On May 3, 2010, Columbia of Virginia filed a base rate case with the VSCC seeking an annual revenue increase of $13.0 million to recover an updated level of costs upon the expiration of its
Performance Based Regulation Plan on December 31, 2010. Columbia of Virginia also sought a Weather Normalization Adjustment (“WNA”), cost recovery of certain gas-related items through its Purchased Gas Adjustment (“PGA”)
mechanism rather than base rates, and forward looking adjustments predicted to occur during the rate year ending December 31, 2011. On November 16, 2010, Columbia of Virginia, the VSCC Staff and the other parties filed a Proposed
Stipulation and Recommendation (“Stipulation”) that would result in an annual revenue increase of $4.9 million, including
14
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ITEM 1.
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FINANCIAL STATEMENTS (continued)
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N
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Notes to Condensed Consolidated Financial Statements (unaudited) (continued)
authorization of the WNA and recovery of certain gas-related items through the PGA mechanism. The Chief Hearing Examiner issued a Report on December 2, 2010 recommending approval of the
Stipulation. The VSCC issued a Final Order on December 17, 2010 adopting the Stipulation. New rates became effective January 1, 2011.
On June 27, 2011, Northern Indiana filed a settlement agreement with the IURC in which regulatory stakeholders agreed that Northern Indiana should
adopt the WACOG accounting methodology and provide the benefit of the low-cost gas supplies to its customers. Northern Indiana had historically used LIFO accounting methodology. On August 31, 2011, the IURC approved the settlement and Northern
Indiana will transition to WACOG accounting methodology beginning January 2012.
Northern Indiana’s current ARP will expire on
March 31, 2012 unless extended by the IURC pursuant to the filing. On September 30, 2011 Northern Indiana filed a Petition with the IURC to extend the products and services contained in its current gas ARP, including Supplier Choice
effective April 1, 2012. Northern Indiana has been in settlement discussions with the parties and anticipates a final settlement in the fourth quarter of 2011.
On October 21, 2009, the IURC issued an Order in the proceeding concerning Northern Indiana’s annual gas recovery, rejecting the use of a four-year average to compute unaccounted for gas. This
Order required Northern Indiana to refund an estimated $5.8 million to customers based on a calculation utilizing a one-year average of unaccounted for gas for the twelve month periods ended July 31, 2008 and July 31, 2009. A reserve was
provided for the full amount of the refund, which Northern Indiana began returning to customers in March 2010, and was completed in May 2011.
Columbia of Massachusetts filed an application to implement its Targeted Infrastructure Reinvestment Factor (“TIRF”) on April 30, 2010. On
October 29, 2010, the Massachusetts DPU approved Columbia of Massachusetts’ proposed adjustment factor, to take effect November 1, 2010, subject to further investigation and reconciliation. On April 29, 2011, Columbia of
Massachusetts filed its second annual application of its TIRF tracker for DPU approval for new rates to go into effect November 1, 2011, and is currently awaiting review and approval by the DPU. On September 16, 2010, Columbia of
Massachusetts filed a petition for approval to implement its first semi-annual revenue decoupling adjustment factor (“RDAF”) for the Peak Period. That adjustment, which took effect on November 1, 2010, subject to further review and
reconciliation, was approved by the DPU on March 23, 2011. Columbia of Massachusetts filed its application for approval of its Off-peak Period RDAF on March 15, 2011. The rate took effect on May 1, 2011, subject to further review and
reconciliation by the DPU. On September 15, 2011, Columbia of Massachusetts filed a petition for approval of its second Peak Period RDAF, with a proposed effective date of November 1, 2011, and is awaiting DPU action with respect to that
filing.
In March 2009, Indiana Governor Daniels signed Senate Bill 423 into law giving the Indiana Finance Authority the ability to contract,
on behalf of gas customers in the state of Indiana, with developers capable of building facilities that manufacture Substitute Natural Gas from coal. The Indiana Finance Authority (“IFA”) received one bid, from Indiana Gasification, by the
April 9, 2009 deadline to initiate a Substitute Natural Gas plant in Southern Indiana under a 30 year contract. In March 2010, Governor Daniels signed into law House Enrolled Act 1086, which allows the IFA to enter into contracts for the sale
of Substitute Natural Gas with third parties, with proceeds from and costs of those sales being reflected on customers’ bills. The IURC must approve the final purchase contract between the IFA and Indiana Gasification as well as the management
agreement between IFA and the utilities for collection of funds or pass through of credits to customers related to the purchase contracts. On December 16, 2010, the IFA filed a Petition seeking approval of the purchase contract and the
management agreement. The IURC held a Prehearing Conference on January 27, 2011, in which a procedural schedule was established. All hearings in this proceeding occurred during two weeks in May 2011 and based upon the schedule it is anticipated
that an order will be issued in 2011.
On January 30, 2009, Columbia of Ohio filed an application with the PUCO to implement a gas supply
auction. The auction replaced Columbia of Ohio’s current GCR mechanism for providing commodity gas supplies to its sales customers. By Order dated December 2, 2009, the PUCO approved a stipulation that resolved all issues in the case.
Pursuant to the stipulation, Columbia of Ohio conducted two consecutive one-year long standard service offer auction periods starting April 1, 2010 and April 1, 2011. On February 23, 2010, Columbia of Ohio held the first standard
service offer auction which resulted in a final retail price adjustment of $1.93 per Mcf. On February 24, 2010 the PUCO issued an entry that approved the results of the auction and directed Columbia of Ohio to proceed
15
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ITEM 1.
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FINANCIAL STATEMENTS (continued)
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N
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OURCE
I
NC
.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)
with the implementation of the standard service offer process. On February 8, 2011, Columbia of Ohio held its second standard service offer auction which resulted in a retail price
adjustment of $1.88 per Mcf. On February 9, 2011, the PUCO issued an entry that approved the results of the auction with the new retail price adjustment to become effective April 1, 2011. Columbia of Ohio is scheduled to conduct its first
standard choice offer auction in February 2012. Several parties have challenged the transition from a standard service offer auction to a standard choice offer auction and on September 7, 2011, the PUCO issued an Order authorizing Columbia of
Ohio to implement a standard choice offer auction in February 2012. On October 7, 2011, the OCC filed an application for rehearing of the PUCO’s Order. Columbia of Ohio filed a memorandum contra on October 17, 2011. NiSource is
currently reviewing the impact on its Condensed Consolidated Financial Statements (unaudited) and Notes to Condensed Consolidated Financial Statements (unaudited) related to this Order.
On October 3, 2011, Columbia of Ohio filed an application with PUCO, requesting authority to defer incurred charges to a regulatory asset for debt-based post-in-service carrying charges, depreciation
and property taxes associated with Columbia of Ohio’s capital program.
On September 9, 2011, Columbia of Ohio filed an application
with PUCO to continue and expand its DSM program. In its application, Columbia of Ohio proposes to spend $20 million annually (adjusted for inflation) on weatherization programs for residential and commercial customers for calendar years 2012
through 2016. Columbia of Ohio will continue to recover program expenses through Rider DSM and has proposed a shared savings incentive not to exceed $3.9 million over the five-year program.
Cost Recovery and Trackers
. A significant portion of the distribution companies’ revenue is related to the recovery of gas costs, the review and recovery of which occurs via standard
regulatory proceedings. All states require periodic review of actual gas procurement activity to determine prudence and to permit the recovery of prudently incurred costs related to the supply of gas for customers. NiSource distribution companies
have historically been found prudent in the procurement of gas supplies to serve customers.
Certain operating costs of the NiSource
distribution companies are significant, recurring in nature, and generally outside the control of the distribution companies. Some states allow the recovery of such costs via cost tracking mechanisms. Such tracking mechanisms allow for abbreviated
regulatory proceedings in order for the distribution companies to implement charges and recover appropriate costs. Tracking mechanisms allow for more timely recovery of such costs as compared with more traditional cost recovery mechanisms. Examples
of such mechanisms include GCR adjustment mechanisms, tax riders, and bad debt recovery mechanisms.
Comparability of Gas Distribution
Operations line item operating results is impacted by regulatory trackers that allow for the recovery in rates of certain costs such as bad debt expenses. Increases in the expenses that are the subject of trackers, result in a corresponding increase
in net revenues and therefore have essentially no impact on total operating income results.
Certain of the NiSource distribution companies
have completed rate proceedings involving infrastructure replacement or are embarking upon regulatory initiatives to replace significant portions of their operating systems that are nearing the end of their useful lives. Each LDC’s approach to
cost recovery may be unique, given the different laws, regulations and precedent that exist in each jurisdiction.
Gas Transmission and
Storage Operations Regulatory Matters
Columbia Gulf Rate Case.
On October 28, 2010, Columbia Gulf filed a rate case with the
FERC, proposing a rate increase and tariff changes. Among other things, the filing proposed a revenue increase of approximately $50 million to cover increases in the cost of services, which includes adjustments for operation and maintenance
expenses, capital investments, adjustments to depreciation rates and expense, rate of return, and increased federal, state and local taxes. On November 30, 2010, the FERC issued an Order allowing new rates to become effective by May 2011,
subject to refund. Columbia Gulf placed new rates into effect, subject to refund, on May 1, 2011.
16
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ITEM 1.
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FINANCIAL STATEMENTS (continued)
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Notes to Condensed Consolidated Financial Statements (unaudited) (continued)
Columbia Gulf and the active parties to the case negotiated a settlement which was filed with the FERC on September 9, 2011. On September 30, 2011, the Chief Judge severed the issues
relating to a contesting party for separate hearing and decision. On October 4, 2011, the Presiding Judge certified the settlement to the FERC as uncontested, and the settlement is now pending a ruling from the FERC.
Electric Operations Regulatory Matters
Significant Rate Developments
. On June 27, 2008, Northern Indiana filed a petition with the IURC for new electric base rates and
charges. The filing requested an increase in base rates calculated to produce additional gross margin of $85.7 million when compared to a normalized test year ended December 31, 2007. On August 25, 2010, the IURC issued an Order
authorizing electric rates to reflect investments in reliability, environmental technology and other infrastructure improvements.
Upon review
of the Order, NiSource concluded that the overall impact is in line with the company’s expected outcome for the case and its financial outlook. The IURC approved a rate base of $2,639.0 million and an overall rate of return of 7.29%, which
results in an allowed net operating income of $192.4 million. In conjunction with approved expenses, the Order approves rates designed to produce a margin of $899.0 million based on 2007 test year volumes. The approved rate base includes the Sugar
Creek Generating Station. Among other findings, the IURC also approved revised depreciation accrual rates for electric and common plant, amortization of deferrals, and two new tracking mechanisms, a Resource Adequacy Tracker and RTO Tracker. The
IURC also found that Northern Indiana, before declaring or paying any dividends to NiSource must provide the IURC notice at least 20 business days prior. Northern Indiana provided such notice prior to making any dividend declaration subsequent to
the receipt of the August 25, 2010 Order.
Consistent with Northern Indiana’s proposal, the IURC also approved a rate base that
excludes Dean H. Mitchell Generating Station and Michigan City Generating Station Units 2 and 3. In accordance with ASC 980, Northern Indiana retired the Dean H. Mitchell Generating Station and Michigan City Generating Station Units 2 and 3 during
the third quarter of 2010 as the stations are no longer used and useful. As a result of the Order, construction work in progress, materials and supplies and base coal of $0.6 million, $2.9 million and $0.8 million, respectively were expensed during
the third quarter of 2010 as there were no remaining future economic benefits associated with these assets.
Some parties sought
reconsideration or rehearing of specific aspects of the case. On April 25, 2011, the IURC issued a docket entry to extend the deemed denied date for reconsideration or rehearing to be 30 days following the IURC’s Order on Northern
Indiana’s November 19, 2010 petition for new electric base rates and charges. Several parties have also filed an appeal of the IURC Order to the Indiana Court of Appeals. The appeals are still pending.
As part of the Order, the IURC required Northern Indiana to file a compliance filing with updated tariffs and Northern Indiana made such filing on
September 14, 2010. New rates cannot be implemented until the IURC approves the filed tariff. As part of the April 25, 2011 docket entry, the IURC also suspended the compliance filing schedule. Based on this docket entry, Northern Indiana
does not believe that rates from the August 25, 2010 IURC Order will be implemented.
Northern Indiana filed a petition for
reconsideration with the IURC on September 14, 2010 to clarify that the effective date of certain aspects of the 2008 case including the new depreciation rates, commencement of amortization of deferred balances and discontinuance of further
regulatory deferrals and the annual bill credit in effect since 2002 should coincide with the IURC’s approval of new customer rates. On October 22, 2010, the IURC issued a docket entry clarifying that this interpretation is correct.
On November 19, 2010, Northern Indiana filed a petition with the IURC for new electric base rates and charges. The filing requests an
increase in base rates calculated to produce additional gross revenue of $75.7 million when compared to a normalized test year ended June 30, 2010. This is calculated to provide the opportunity to earn a return of 7.70% on net original cost
rate base of $2,706 million. If approved, the rates from this new petition would replace any other existing rates, including those that may be approved by effect of the August 25, 2010 Order. The proposed rates would ease bill impacts on
residential customers, while still allowing Northern Indiana to continue investing in service, reliability and infrastructure improvements. Northern Indiana filed the proceeding under the
17
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ITEM 1.
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FINANCIAL STATEMENTS (continued)
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Notes to Condensed Consolidated Financial Statements (unaudited) (continued)
IURC’s minimum standard filing requirements prescribing timeframes for issuance of an order if required information is supplied as part of the rate case filing. The IURC held its prehearing
conference on December 17, 2010 and issued a prehearing conference order on January 5, 2011. The parties agreed to and the IURC ordered a procedural schedule that includes a bifurcated hearing. The evidentiary hearing on the revenue
requirement portion of Northern Indiana’s case-in-chief was held on February 28 – March 4, 2011, and the evidentiary hearing on the cost allocation portion of the case was held the week of May 16, 2011.
On July 18, 2011, Northern Indiana filed with the IURC a collaborative settlement in its 2010 Electric Rate Case with the OUCC, Northern Indiana
Industrial Group, NLMK Indiana and Indiana Municipal Utilities Group. The provisions of the stipulation and settlement agreement are subject to the review and approval of the IURC. The provisions of the settlement include a revenue requirement of
$1,401 million, including other revenue of $46 million for a net revenue requirement of $1,355 million from base rates. The margin, embedded in the $1,401 million, is $926.5 million, as compared to test year actual of $817 million. If the settlement
is approved, it would terminate the current customer credit ($59 million reduction in margins during the test year), include two new tracking mechanisms, a Resource Adequacy Tracker and RTO Tracker and lead to the expiration of certain industrial
special contracts ($32.8 million reduction in margins during the test year). The settlement agreement will limit the proposed base rate impact to the residential customer class to a 4.5% increase. The parties have also agreed to a rate of return of
6.98% based upon a 10.2% return on equity. The settlement, if approved, would also resolve all pending issues related to compliance with the August 25, 2010 Order in the 2008 Electric Rate Case. On August 19, 2011, the City of Hammond
filed testimony in opposition to the settlement. A final hearing was held on September 12, 2011 and September 13, 2011. The settling parties filed their proposed order on September 20, 2011 and the City of Hammond was the only party
to file a response which seeks a rejection of the settlement agreement. The settling parties filed a joint reply to the City of Hammond’s response on October 14, 2011. The settlement includes a request by the parties for the IURC to issue
an order approving the settlement by December 31, 2011. Northern Indiana is awaiting the Commission order.
Northern Indiana received a
favorable regulatory order on February 18, 2009 related to its actions to increase its electric generating capacity and advance its electric rate case. Acting on a settlement reached among Northern Indiana and its regulatory stakeholders, the
IURC ruled that Northern Indiana’s Sugar Creek electric generating plant was in service for ratemaking purposes as of December 1, 2008. The IURC also approved the deferral of depreciation expenses and debt-based carrying costs associated
with the $330.0 million Sugar Creek investment. Northern Indiana purchased Sugar Creek on May 30, 2008 and effective December 1, 2008, Sugar Creek was accepted as an internal designated network resource within the MISO. The Sugar Creek
investment was included in the rate base as part of the IURC’s August 25, 2010 Order. Northern Indiana will continue to defer depreciation expenses and debt-based carrying costs associated with the $330.0 million Sugar Creek investment
until the IURC’s approval and implementation of new customer rates. The annual deferral for Sugar Creek is reduced by the annual depreciation on the Mitchell plant of $4.5 million, pursuant to the FAC-71 settlement. The IURC also approved a
five year amortization of balances that were deferred as of December 31, 2009 and such amortization will commence with the IURC’s approval and implementation of new customer rates. The same treatment was requested in the 2010 Electric rate
case filing.
During 2002, Northern Indiana settled certain regulatory matters related to an electric rate review. On September 23, 2002,
the IURC issued an Order adopting most aspects of the settlement. The Order approving the settlement provides that certain electric customers of Northern Indiana will receive bill credits of approximately $55.1 million each year. The credits will
continue at approximately the same annual level and per the same methodology, until the IURC approval and implementation of new customer rates. Credits amounting to $38.6 million and $46.0 million were recognized for electric customers for the nine
months ended September 30, 2011 and 2010, respectively.
On December 9, 2009, the IURC issued an Order in its generic DSM
investigation proceeding establishing an overall annual energy savings goal of 2% to be achieved by Indiana jurisdictional electric utilities in 10 years, with interim savings goals established in years one through nine. Under the Order, Northern
Indiana and other jurisdictional electric utilities must file DSM plans on July 1, 2010, 2013, 2016, and 2019, with annual updates in the interim periods. The IURC requires that certain core programs be established and administered by an
independent third party. The IURC did not make any specific findings with respect to cost recovery issues. In compliance with the December 9, 2009 Order, on March 16, 2010 Northern Indiana filed a proposal for a mechanism to recover the
costs associated with these energy efficiency programs, including lost revenue. On June
18
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ITEM 1.
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FINANCIAL STATEMENTS (continued)
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N
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Notes to Condensed Consolidated Financial Statements (unaudited) (continued)
17, 2010, Northern Indiana filed for approval of its energy efficiency programs, recovery of program costs and lost revenue, and its proposed performance incentive level and methodology. On
May 25, 2011, the IURC issued an Order approving the mechanism to recover the costs associated with these energy efficiency programs. On July 27, 2011, the IURC issued an Order approving the energy efficiency programs. However, the IURC
denied lost revenue recovery at this time and Northern Indiana may consider filing with the IURC a request for the recovery of lost revenue once rates and charges become effective in the 2010 Electric Rate Case. The IURC also approved Northern
Indiana’s proposal to seek performance incentives after program results can be evaluated based upon evaluation, measurement and verification data. In August 2011, Northern Indiana made its initial filing for recovery of costs incurred and
estimated through June 2012. On October 25, 2011 the IURC issued an Order approving the recovery of actual and estimated expenses in the amount of approximately $20 million.
On July 13, 2011, Northern Indiana received approval from the IURC to significantly improve its ability to purchase customer-generated electricity from renewable energy projects. The program,
supported by consumer and environmental groups, also allows customers to generate more of their own electricity using renewable energy to reduce their utility costs.
MISO
. As part of Northern Indiana’s participation in the MISO transmission service, wholesale energy and ancillary service markets, certain administrative fees and non-fuel costs have
been incurred. IURC orders have been issued authorizing the deferral for consideration in a future rate case proceeding of certain non-fuel related costs incurred after Northern Indiana’s rate moratorium, which expired on July 31, 2006.
Northern Indiana proposed recovery of the cumulative amount of net non-fuel charges that were deferred as of December 31, 2008, and to recover, through a tracker, charges deferred between December 31, 2008 and the IURC’s approval of
new customer rates. During the nine months ended September 30, 2011 and 2010, net MISO costs of $6.6 million and $5.8 million were deferred, respectively. As of September 30, 2011, Northern Indiana had deferred a total of $40.0 million of
net MISO costs. In the Order issued on August 25, 2010, the IURC approved an RTO tracker for recovery of MISO non-fuel costs and revenues and off-system sales sharing and ordered that purchased power costs and fuel-related MISO charge types be
recovered in the FAC. The IURC also approved a purchase capacity tracker referred to as the Resource Adequacy Tracker. Similar treatment was requested in the 2010 Electric Rate Case filing. The implementation of such trackers coincides with the
IURC’s approval and implementation of new customer rates.
MISO and PJM Interconnection undertook a joint effort in April and May 2009 to
identify a source of unaccounted flows on several coordinated flowgates. The analysis found that certain PJM Interconnection generating units that were once associated with unit-specific capacity sales were erroneously excluded from PJM
Interconnection’s market flows, which significantly affected the congestion price on reciprocally coordinated flowgates on Northern Indiana systems. Higher PJM Interconnection market flows on congested flowgates would have resulted in higher
payments to MISO by PJM Interconnection during market-to-market coordination since April 1, 2005. The model was fixed on June 18, 2009. On January 4, 2011, the MISO and PJM Interconnection jointly filed a settlement agreement, which
FERC approved on June 16, 2011, to resolve the disputed market-to-market transactions that occurred prior to June, 2009. The settlement agreement provides for a review of existing procedures for implementing the joint operating agreement, a
process for reviewing future changes to implementation procedures, and enhanced access to each party’s data. In addition, there was a release and discharge of all claims by any market participant related to the joint operating agreement for all
events that occurred prior to the filing of the January 4, 2011 settlement agreement.
Cost Recovery and Trackers
. A
significant portion of Northern Indiana’s revenue is related to the recovery of fuel costs to generate power and the fuel costs related to purchased power. These costs are recovered through a FAC, a standard, quarterly, “summary”
regulatory proceeding in Indiana. Various interveners, including the OUCC, had taken issue with the allocation of costs included in Northern Indiana’s FAC-80, FAC-81 and FAC-82, which cover the reconciliation of April through December 2008. The
IURC granted a sub-docket to consider such issues in those filings. The intervening parties and Northern Indiana discussed procedures to eliminate these concerns and to resolve them for the historical periods. On November 4, 2009, the IURC
approved a settlement agreement which called for a credit of $8.2 million to be provided to FAC customers beginning in November 2009, less any amount for attorney’s fees and expenses. This credit was completed in January 2011.
As part of the August 25, 2010 Order, a new “purchase power benchmark” became effective. This purchase power benchmark superseded the one
made effective by a settlement in October 2007. The benchmark is based upon the
19
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ITEM 1.
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FINANCIAL STATEMENTS (continued)
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N
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Notes to Condensed Consolidated Financial Statements (unaudited) (continued)
costs of power generated by a hypothetical natural gas fired unit using gas purchased and delivered to Northern Indiana. During the nine months ended September 30, 2011 and 2010, the amount
of purchased power costs exceeding the benchmark amounted to zero and $0.4 million, respectively, which was recognized as a net reduction of revenues.
Northern Indiana has approval from the IURC to recover certain environmental related costs through an ECT. Under the ECT, Northern Indiana is permitted to recover (1) AFUDC and a return on the
capital investment expended by Northern Indiana to implement IDEM’s NOx SIP and CAIR and CAMR compliance plan projects through an ECRM and (2) related operation and maintenance and depreciation expenses once the environmental facilities
become operational through an EERM. The IURC approved the continued use of the ECRM and the EERM trackers in the August 25, 2010 Order and Northern Indiana has requested similar treatment in the November 19, 2010 filing. Upon IURC approval
of new customer rates, the cost relating to environmental projects that were in service as of June 30, 2010 will be recovered through base rates and will no longer be tracked through the ECRM and EERM.
The IURC has authorized Northern Indiana to recover costs relating to qualified pollution control projects estimated to cost $514 million, which includes
new projects at the R.M. Schahfer Generating Station approved by the IURC’s December 29, 2010 Order. On August 5, 2011 Northern Indiana filed ECR-18, which included $278 million (capital expenditure net of accumulated depreciation) of
such capital costs for the period ended June 30, 2011. On March 22, 2011, Northern Indiana filed a petition with the IURC for a certificate of public convenience and necessity and associated relief for the construction of additional
environmental projects required to comply with the NOV consent decree lodged in the United States District Court for the Northern District of Indiana on January 13, 2011. Refer to Note 18-C, “Environmental Matters,” for additional
information. The evidentiary hearing was held at the IURC on August 31, 2011 addressing the relief regarding (i) the construction of a FGD unit at R.M. Schahfer Generating Station Unit 15 and (ii) a cost estimate increase for the
projects approved by the December 29, 2010 Order, which included estimates for a FGD unit at R.M. Schahfer Generating Station Unit 14 and associated common facilities for Units 14 and 15. The evidentiary hearing is scheduled at the IURC for
December 14 and 15, 2011, for the balance of the projects associated with the relief requested on March 22, 2011. This includes potential consideration of relief associated with the construction of a FGD unit on Michigan City Generating
Station Unit 12. On October 20, 2011 and October 21, 2011, the OUCC and the Industrial Group, respectively, filed testimony in opposition of the proposed construction of a FGD unit on Michigan City Generating Station Unit 12.
|
8.
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Risk Management Activities
|
NiSource is exposed to certain risks relating to its ongoing business operations. The primary risks managed by using derivative
instruments are commodity price risk and interest rate risk. Derivative natural gas contracts are entered into to manage the price risk associated with natural gas price volatility and to secure forward natural gas prices. Interest rate swaps
are entered into to manage interest rate risk associated with NiSource’s fixed-rate borrowings. NiSource designates some of its commodity forward contracts as cash flow hedges of forecasted purchases of commodities and designates its interest
rate swaps as fair value hedges of fixed-rate borrowings. Additionally, certain NiSource subsidiaries enter into forward physical contracts with various third parties to procure or sell natural gas or power. Certain forward physical contracts are
derivatives which qualify for the normal purchase and normal sales exception which do not require mark-to-market accounting.
Accounting
Policy for Derivative Instruments.
The ASC topic on accounting for derivatives and hedging requires an entity to recognize all derivatives as either assets or liabilities on the Condensed Consolidated Balance Sheets (unaudited) at fair value,
unless such contracts are exempted such as a normal purchase and normal sale contract under the provisions of the ASC topic. The accounting for changes in the fair value of a derivative depends on the intended use of the derivative and resulting
designation.
NiSource uses a variety of derivative instruments (exchange traded futures and options, physical forwards and options, basis
contracts, financial commodity swaps, and interest rate swaps) to effectively manage its commodity price risk and interest rate risk exposure. If certain conditions are met, a derivative may be specifically designated as (a) a hedge of the
exposure to changes in the fair value of a recognized asset or liability or an unrecognized firm commitment, or (b) a hedge of the exposure to variable cash flows of a forecasted transaction. In order for a derivative contract to be designated
as a hedge, the relationship between the hedging instrument and the hedged item
20
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ITEM 1.
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FINANCIAL STATEMENTS (continued)
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Notes to Condensed Consolidated Financial Statements (unaudited) (continued)
or transaction must be highly effective. The effectiveness test is performed at the inception of the hedge and each reporting period thereafter, throughout the period that the hedge is
designated. Any amounts determined to be ineffective are recognized currently in earnings. For derivative contracts that qualify for the normal purchase and normal sales exception, a contract’s fair value is not recognized in the Consolidated
Financial Statements until the contract is settled.
Unrealized and realized gains and losses are recognized each period as components of
AOCI, regulatory assets and liabilities or earnings depending on the designation of the derivative instrument. For subsidiaries that utilize derivatives for cash flow hedges, the effective portions of the gains and losses are recorded to AOCI and
are recognized in earnings concurrent with the disposition of the hedged risks. If a forecasted transaction corresponding to a cash flow hedge is no longer probable to occur, the accumulated gains or losses on the derivative are recognized currently
in earnings. For fair value hedges, the gains and losses are recorded in earnings each period together with the change in the fair value of the hedged item.
As a result of the rate-making process, the rate-regulated subsidiaries generally record gains and losses as regulatory liabilities or assets and recognize such gains or losses in earnings when both the
contracts settle and the physical commodity flows. These gains and losses recognized in earnings are then subsequently recovered or passed back to customers in revenues through rates. When gains and losses are recognized in earnings, they are
recognized in cost of sales for derivatives that correspond to commodity risk activities and are recognized in interest expense for derivatives that correspond to interest-rate risk activities.
NiSource has elected not to net fair value amounts for its derivative instruments or the fair value amounts recognized for its right to receive cash
collateral or obligation to pay cash collateral arising from those derivative instruments recognized at fair value, which are executed with the same counterparty under a master netting arrangement. NiSource discloses amounts recognized for the right
to reclaim cash collateral within “Restricted cash” and amounts recognized for the right to return cash collateral within current liabilities on the Consolidated Balance Sheets.
Commodity Price Risk Programs
NiSource and NiSource’s utility customers are exposed to variability in cash flows associated with natural gas purchases and volatility in natural gas prices.
NiSource purchases natural gas for sale and delivery to its retail, commercial and industrial customers, and for most customers the variability in the market price of gas is passed through in their rates. Some of NiSource’s utility subsidiaries
offer programs where variability in the market price of gas is assumed by the respective utility. The objective of NiSource’s commodity price risk programs is to mitigate this gas cost variability, for NiSource or on behalf of its customers,
associated with natural gas purchases or sales by economically hedging the various gas cost components by using a combination of futures, options, forward physical contracts, basis swap contracts or other derivative contracts. Northern Indiana also
uses derivative contracts to minimize risk associated with power price volatility. These commodity price risk programs and their respective accounting treatment are described below.
Northern Indiana, Columbia of Pennsylvania, Columbia of Kentucky, Columbia of Maryland and Columbia of Virginia use NYMEX derivative contracts to minimize risk associated with gas price volatility. These
derivative programs must be marked to fair value, but because these derivatives are used within the framework of the companies’ GCR or FAC mechanism, regulatory assets or liabilities are recorded to offset the change in the fair value of these
derivatives.
Northern Indiana and Columbia of Virginia offer a fixed price program as an alternative to the standard GCR mechanism. These
services provide customers with the opportunity to either lock in their gas cost or place a cap on the gas costs that would be charged in future months. In order to hedge the anticipated physical purchases associated with these obligations, forward
physical contracts, NYMEX futures and NYMEX options are used to secure forward gas prices. The accounting treatment elected for these contracts is varied whereby certain of these contracts are accounted for as cash flow hedges while some contracts
are not. The normal purchase and normal sales exception is elected for forward physical contracts associated with these programs where delivery of the commodity is probable to occur.
Northern Indiana also offers a DependaBill program to its customers as an alternative to the standard tariff rate that is charged to residential customers. The program allows Northern Indiana customers to
fix their total monthly bill in
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ITEM 1.
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FINANCIAL STATEMENTS (continued)
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Notes to Condensed Consolidated Financial Statements (unaudited) (continued)
future months at a flat rate regardless of gas usage or commodity cost. In order to hedge the anticipated physical purchases associated with these obligations, forward physical contracts, NYMEX
futures and NYMEX options have been used to secure forward gas prices. The accounting treatment elected for these contracts is varied whereby certain of these contracts are accounted for as cash flow hedges while some contracts are not. The normal
purchase and normal sales exception is elected for forward physical contracts associated with these programs whereby delivery of the commodity is probable to occur.
Northern Indiana enters into gas purchase contracts at first of the month prices that give counterparties the daily option to either sell an additional package of gas at first of the month prices or
recall the original volume to be delivered. Northern Indiana charges a fee for this option. The changes in the fair value of these options are primarily due to the changing expectations of the future intra-month volatility of gas prices. These
written options are derivative instruments, must be marked to fair value and do not meet the requirement for hedge accounting treatment. However, Northern Indiana records the related gains and losses associated with these transactions as a
regulatory asset or liability.
Columbia of Kentucky, Columbia of Ohio, and Columbia of Pennsylvania enter into contracts that allow
counterparties the option to sell gas to them at first of the month prices for a particular month of delivery. These Columbia LDCs charge the counterparties a fee for this option. The changes in the fair value of the options are primarily due to the
changing expectations of the future intra-month volatility of gas prices. These Columbia LDCs defer a portion of the change in the fair value of the options as either a regulatory asset or liability based on the regulatory customer sharing
mechanisms in place, with the remaining changes in fair value recognized currently in earnings.
As part of the MISO Day 2 initiative,
Northern Indiana was allocated or has purchased FTRs. These FTRs help Northern Indiana offset congestion costs due to the MISO Day 2 activity. The FTRs are marked to fair value and are not accounted for as a hedge, but since congestion costs are
recoverable through the fuel cost recovery mechanism, the related gains and losses associated with marking these derivatives to market are recorded as a regulatory asset or liability. In the second quarter of 2008, MISO changed its allocation
procedures from an allocation of FTRs to an allocation of ARRs, whereby Northern Indiana was allocated ARRs based on its historical use of the MISO administered transmission system. ARRs entitle the holder to a stream of revenues or charges based on
the price of the associated FTR in the FTR auction, so ARRs can be used to purchase FTRs in the FTR auction. ARRs are not derivatives.
NiSource is in the process of winding down its unregulated natural gas marketing business, where gas financial contracts are utilized to economically
hedge expected future gas purchases associated with forward gas agreements. These financial contracts, as well as the associated forward physical sales contracts, are derivatives and are marked-to-market with all associated gains and losses
recognized to income. NiSource established reserves of $3.3 million at September 30, 2011 and $6.4 million at December 31, 2010, against certain of these physical sale contract derivatives. These amounts represent reserves related to the
creditworthiness of certain customers, the fair value of future cash flows, and the cost of maintaining significant amounts of restricted cash. The physical sales contracts marked-to-market had a fair value gain of approximately $128.9 million at
September 30, 2011 and $154.4 million at December 31, 2010, while the financial derivative contracts marked-to-market had a fair value loss of $124.1 million at September 30, 2011 and $137.5 million at December 31, 2010. The
$137.5 million loss at December 31, 2010 did not include approximately $10.3 million of January 2011 financial positions as these positions were settled in December 2010.
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ITEM 1.
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FINANCIAL STATEMENTS (continued)
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Notes to Condensed Consolidated Financial Statements (unaudited) (continued)
Commodity price risk program derivative contracted gross volumes are as follows:
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September 30, 2011
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December 31, 2010
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Commodity Price Risk Program:
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Gas price volatility program derivatives (MMDth)
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35.7
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28.4
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Price Protection Service program derivatives (MMDth)
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1.5
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1.6
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DependaBill program derivatives (MMDth)
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0.4
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0.4
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Regulatory incentive program derivatives (MMDth)
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4.6
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2.0
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Gas marketing program derivatives (MMDth)
(a)
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32.9
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48.2
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Gas marketing forward physical derivatives (MMDth)
(b)
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32.4
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48.0
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Electric energy program FTR derivatives (mw)
(c)
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11,846.7
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8,279.1
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(a)
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Basis contract volumes not included in the above table were 26.5 MMDth and 42.0 MMDth as of September 30, 2011 and December 31, 2010, respectively.
|
|
(b)
|
Basis contract volumes not included in the above table were 34.4 MMDth and 52.1 MMDth as of September 30, 2011 and December 31, 2010, respectively.
|
|
(c)
|
Megawatt hours reported in thousands
|
Interest Rate Risk Activities
. NiSource recognizes that the prudent and selective use of derivatives may help it to lower its cost of debt capital
and manage its interest rate exposure. NiSource Finance has entered into various “receive fixed” and “pay floating” interest rate swap agreements which modify the interest rate characteristics of its outstanding long-term debt
from fixed to variable rate. These interest rate swaps also serve to hedge the fair market value of NiSource Finance’s outstanding debt portfolio. As of September 30, 2011, NiSource had $6.3 billion of outstanding fixed rate debt, of which
$500.0 million is subject to fluctuations in interest rates as a result of the fixed-to-variable interest rate swap transactions. These interest rate swaps are designated as fair value hedges. NiSource had no net gain or loss recognized in earnings
due to hedging ineffectiveness for the nine months ended September 30, 2011 and 2010.
On July 22, 2003, NiSource Finance entered
into fixed-to-variable interest rate swap agreements in a notional amount of $500 million with four counterparties with an 11-year term. NiSource Finance receives payments based upon a fixed 5.40% interest rate and pays a floating interest amount
based on U.S. 6-month BBA LIBOR plus an average of 0.78% per annum. There was no exchange of premium at the initial date of the swaps. In addition, each party has the right to cancel the swaps on July 15, 2013.
Contemporaneously with the issuance on September 16, 2005 of $1 billion of its 5.25% and 5.45% notes, maturing September 15, 2017 and 2020,
respectively, NiSource Finance settled $900 million of forward starting interest rate swap agreements with six counterparties. NiSource paid an aggregate settlement payment of $35.5 million which is being amortized from AOCI to interest expense over
the term of the underlying debt, resulting in an effective interest rate of 5.67% and 5.88%, respectively. As of September 30, 2011, AOCI includes $11.7 million related to forward starting interest rate swap settlement. These derivative
contracts are accounted for as a cash flow hedge.
As of September 30, 2011, NiSource holds a 47.5% interest in Millennium. During 2008,
Millennium entered into various interest rate swap agreements in order to protect against the risk of increasing interest rates. During August 2010, Millennium completed the refinancing of its long-term debt, securing permanent fixed-rate
financing through the private placement issuance of two tranches of notes totaling $725.0 million: $375.0 million at 5.33% due June 30, 2027, and $350.0 million at 6.00% due June 30, 2032. Upon the issuance of these notes,
Millennium repaid all outstanding borrowings under the credit agreement, terminated the sponsor guarantee and cash settled the interest rate hedges. These interest rate hedges were accounted for as cash flow hedges by Millennium. As it reports
Millennium as an equity method investment, NiSource is required to recognize a proportional share of Millennium’s OCI. NiSource’s proportionate share of the remaining unrealized loss is $20.4 million, net of tax. Millennium is
amortizing the unrealized loss related to these terminated interest rate swaps into earnings using the effective interest method through interest expense as interest payments are made. NiSource records its proportionate share of the amortization as
Equity Earnings in Unconsolidated Affiliates at the Condensed Statements of Consolidated Income (unaudited).
23
|
ITEM 1.
|
FINANCIAL STATEMENTS (continued)
|
N
I
S
OURCE
I
NC
.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)
NiSource’s location and fair value of derivative instruments on the Condensed Consolidated Balance
Sheets (unaudited) were:
|
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
|
|
|
September
30,
2011
|
|
|
December 31,
2010
|
|
|
|
|
|
|
|
|
Fair Value
|
|
|
Fair Value
|
|
|
Asset Derivatives
|
|
|
|
|
|
|
|
|
|
Balance Sheet Location
|
|
|
|
|
|
|
|
|
|
Derivatives designated as hedging instruments
|
|
|
|
|
|
|
|
|
|
Interest rate risk activities
|
|
|
|
|
|
|
|
|
|
Price risk management assets (current)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
Price risk management assets (noncurrent)
|
|
|
57.7
|
|
|
|
61.1
|
|
|
|
|
|
|
|
|
|
|
|
|
Total derivatives designated as hedging instruments
|
|
$
|
57.7
|
|
|
$
|
61.1
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives not designated as hedging instruments
|
|
|
|
|
|
|
|
|
|
Commodity price risk programs
|
|
|
|
|
|
|
|
|
|
Price risk management assets (current)
|
|
$
|
136.7
|
|
|
$
|
159.5
|
|
|
Price risk management assets (noncurrent)
|
|
|
133.7
|
|
|
|
179.2
|
|
|
|
|
|
|
|
|
|
|
|
|
Total derivatives not designated as hedging instruments
|
|
$
|
270.4
|
|
|
$
|
338.7
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Asset Derivatives
|
|
$
|
328.1
|
|
|
$
|
399.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September
30,
2011
|
|
|
December 31,
2010
|
|
|
|
|
|
(in millions)
|
|
Fair Value
|
|
|
Fair Value
|
|
|
Liability Derivatives
|
|
|
|
|
|
|
|
|
|
Balance Sheet Location
|
|
|
|
|
|
|
|
|
|
Derivatives designated as hedging instruments
|
|
|
|
|
|
|
|
|
|
Commodity price risk programs
|
|
|
|
|
|
|
|
|
|
Price risk management liabilities (current)
|
|
$
|
0.9
|
|
|
$
|
1.0
|
|
|
Price risk management liabilities (noncurrent)
|
|
|
0.1
|
|
|
|
0.2
|
|
|
|
|
|
|
|
|
|
|
|
|
Total derivatives designated as hedging instruments
|
|
$
|
1.0
|
|
|
$
|
1.2
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives not designated as hedging instruments
|
|
|
|
|
|
|
|
|
|
Commodity price risk programs
|
|
|
|
|
|
|
|
|
|
Price risk management liabilities (current)
|
|
$
|
170.7
|
|
|
$
|
172.9
|
|
|
Price risk management liabilities (noncurrent)
|
|
|
136.5
|
|
|
|
181.4
|
|
|
|
|
|
|
|
|
|
|
|
|
Total derivatives not designated as hedging instruments
|
|
$
|
307.2
|
|
|
$
|
354.3
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Liability Derivatives
|
|
$
|
308.2
|
|
|
$
|
355.5
|
|
|
|
|
|
|
|
|
|
|
|
The effect of derivative instruments on the Condensed Statements of Consolidated Income (unaudited) was:
Derivatives in Cash Flow Hedging Relationships
Three Months Ended,
(in millions)
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amount of Gain
(Loss)
Recognized in OCI on
Derivative
(Effective
Portion)
|
|
|
|
|
Amount of Gain
(Loss)
Reclassified from AOCI
into Income
(Effective
Portion)
|
|
|
|
|
|
|
|
|
|
|
|
Location of Gain (Loss)
Reclassified from AOCI
into Income (Effective
Portion)
|
|
|
|
|
|
|
|
Derivatives in Cash Flow
Hedging Relationships
|
|
Sept. 30,
|
|
|
Sept. 30,
|
|
|
|
Sept. 30,
|
|
|
Sept. 30,
|
|
|
|
2011
|
|
|
2010
|
|
|
|
2011
|
|
|
2010
|
|
|
Commodity price risk programs
|
|
$
|
(0.2
|
)
|
|
$
|
(0.5
|
)
|
|
Cost of Sales
|
|
$
|
0.1
|
|
|
$
|
0.1
|
|
|
Interest rate risk activities
|
|
|
0.4
|
|
|
|
0.4
|
|
|
Interest expense, net
|
|
|
(0.7
|
)
|
|
|
(0.7
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
0.2
|
|
|
$
|
(0.1
|
)
|
|
|
|
$
|
(0.6
|
)
|
|
$
|
(0.6
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
24
|
ITEM 1.
|
FINANCIAL STATEMENTS (continued)
|
N
I
S
OURCE
I
NC
.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)
Nine Months Ended
(in millions)
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives in Cash Flow
Hedging Relationships
|
|
Amount of Gain
(Loss)
Recognized in OCI on
Derivative
(Effective
Portion)
|
|
|
Location of Gain (Loss)
Reclassified from AOCI
into Income (Effective
Portion)
|
|
Amount of Gain
(Loss)
Reclassified from AOCI
into Income (Effective
Portion)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sept. 30,
|
|
|
Sept. 30,
|
|
|
|
Sept. 30,
|
|
|
Sept. 30,
|
|
|
|
2011
|
|
|
2010
|
|
|
|
2011
|
|
|
2010
|
|
|
Commodity price risk programs
|
|
$
|
0.3
|
|
|
$
|
(0.3
|
)
|
|
Cost of Sales
|
|
$
|
0.9
|
|
|
$
|
0.9
|
|
|
Interest rate risk activities
|
|
|
1.2
|
|
|
|
1.2
|
|
|
Interest expense, net
|
|
|
(2.0
|
)
|
|
|
(2.0
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
1.5
|
|
|
$
|
0.9
|
|
|
|
|
$
|
(1.1
|
)
|
|
$
|
(1.1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended,
(in millions)
:
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives in Cash Flow Hedging
Relationships
|
|
Location of Gain (Loss)
Recognized in Income on
Derivative (Ineffective Portion
and Amount Excluded from
|
|
Amount of Gain (Loss) Recognized
in Income on Derivative
(Ineffective Portion and Amount
Excluded from
Effectiveness
Testing)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effectiveness Testing)
|
|
Sept. 30, 2011
|
|
|
Sept. 30, 2010
|
|
|
Commodity price risk programs
|
|
Cost of Sales
|
|
$
|
—
|
|
|
$
|
—
|
|
|
Interest rate risk activities
|
|
Interest expense, net
|
|
|
—
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended,
(in millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives in Cash Flow Hedging
Relationships
|
|
Location of Gain (Loss)
Recognized in Income on
Derivative (Ineffective Portion
and Amount Excluded from
Effectiveness Testing)
|
|
Amount of Gain (Loss)
Recognized
in Income on Derivative
(Ineffective Portion and
Amount
Excluded from Effectiveness
Testing)
|
|
|
|
|
Sept. 30, 2011
|
|
|
Sept. 30, 2010
|
|
|
Commodity price risk programs
|
|
Cost of Sales
|
|
$
|
—
|
|
|
$
|
—
|
|
|
Interest rate risk activities
|
|
Interest expense, net
|
|
|
—
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
It is anticipated that during the next twelve months the expiration and settlement of cash flow hedge contracts will
result in income statement recognition of amounts currently classified in AOCI of approximately $0.5 million of loss, net of taxes.
Derivatives in Fair Value Hedging Relationships
Three Months Ended,
(in millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives in Fair Value Hedging
Relationships
|
|
Location of Gain (Loss)
Recognized
in
Income on Derivatives
|
|
Amount of Gain (Loss) Recognized
in Income on Derivatives
|
|
|
|
|
|
|
|
Sept. 30, 2011
|
|
|
Sept. 30, 2010
|
|
|
Interest rate risk activities
|
|
Interest expense, net
|
|
$
|
(3.0
|
)
|
|
$
|
2.9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
$
|
(3.0
|
)
|
|
$
|
2.9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
25
|
ITEM 1.
|
FINANCIAL STATEMENTS (continued)
|
N
I
S
OURCE
I
NC
.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)
Nine Months Ended,
(in millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives in Fair Value Hedging
Relationships
|
|
Location of (Loss) Gain Recognized in
Income on Derivatives
|
|
Amount of (Loss) Gain Recognized
in Income on Derivatives
|
|
|
|
|
|
|
|
Sept. 30, 2011
|
|
|
Sept. 30, 2010
|
|
|
Interest rate risk activities
|
|
Interest expense, net
|
|
$
|
(3.5
|
)
|
|
$
|
9.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
$
|
(3.5
|
)
|
|
$
|
9.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended,
(in millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
Hedged Item in Fair Value Hedge
Relationships
|
|
Location of Gain (Loss) Recognized in
Income on Related Hedged Item
|
|
Amount of Gain (Loss)
Recognized
in Income on Related Hedged Items
|
|
|
|
|
|
|
|
Sept. 30, 2011
|
|
|
Sept. 30, 2010
|
|
|
Fixed-rate debt
|
|
Interest expense, net
|
|
$
|
3.0
|
|
|
$
|
(2.9
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
$
|
3.0
|
|
|
$
|
(2.9
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended,
(in millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
Hedged Item in Fair Value Hedge
Relationships
|
|
Location of Gain (Loss) Recognized in
Income on Related Hedged Item
|
|
Amount of Gain (Loss) Recognized
in Income on Related Hedged Items
|
|
|
|
|
|
|
|
Sept. 30, 2011
|
|
|
Sept. 30, 2010
|
|
|
Fixed-rate debt
|
|
Interest expense, net
|
|
$
|
3.5
|
|
|
$
|
(9.0
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
$
|
3.5
|
|
|
$
|
(9.0
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives not designated as hedging instruments
Three Months Ended,
(in millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives Not Designated as Hedging
Instruments
|
|
Location of Gain (Loss)
Recognized in
Income on Derivatives
|
|
Amount of Realized/Unrealized Gain
(Loss) Recognized in Income on
Derivatives *
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sept. 30, 2011
|
|
|
Sept. 30, 2010
|
|
|
Commodity price risk programs
|
|
Gas Distribution revenues
|
|
$
|
(0.1
|
)
|
|
$
|
(0.1
|
)
|
|
Commodity price risk programs
|
|
Other revenues
|
|
|
16.6
|
|
|
|
43.4
|
|
|
Commodity price risk programs
|
|
Cost of Sales
|
|
|
(7.4
|
)
|
|
|
(38.8
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
$
|
9.1
|
|
|
$
|
4.5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
*
|
For the amounts of realized/unrealized gain (loss) recognized in income on derivatives disclosed in the table above, gains of $9.4 million and $7.4 million for the
third quarter of 2011 and 2010, respectively, were deferred as allowed by regulatory orders. These amounts will be amortized to income over future periods of up to twelve months as specified in a regulatory order.
|
26
|
ITEM 1.
|
FINANCIAL STATEMENTS (continued)
|
N
I
S
OURCE
I
NC
.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)
Nine Months Ended,
(in millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives Not Designated as Hedging
Instruments
|
|
Location of Gain (Loss)
Recognized in
Income on
Derivatives
|
|
Amount of Realized/Unrealized Gain
(Loss) Recognized in Income on
Derivatives *
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sept. 30, 2011
|
|
|
Sept. 30, 2010
|
|
|
Commodity price risk programs
|
|
Gas Distribution revenues
|
|
$
|
(21.8
|
)
|
|
$
|
(21.6
|
)
|
|
Commodity price risk programs
|
|
Other revenues
|
|
|
35.0
|
|
|
|
116.1
|
|
|
Commodity price risk programs
|
|
Cost of Sales
|
|
|
(15.3
|
)
|
|
|
(106.4
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
$
|
(2.1
|
)
|
|
$
|
(11.9
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
* For the amounts of realized/unrealized gain (loss) recognized in income on derivatives disclosed in the table above,
losses of $9.8 million and $8.8 million for the third quarter of 2011 and 2010, respectively, were deferred as allowed per regulatory orders. These amounts will be amortized to income over future periods of up to twelve months as specified in a
regulatory order.
NiSource has not reclassified earnings from AOCI to Cost of Sales due to the probability that certain forecasted
transactions would not occur for the nine months ended September 30, 2011 and 2010.
NiSource’s derivative instruments measured at
fair value as of September 30, 2011 and December 31, 2010 do not contain any credit-risk-related contingent features.
Certain
NiSource affiliates have physical commodity purchase agreements that contain “ratings triggers” that require increases in collateral if the credit rating of NiSource or certain of its affiliates are rated below BBB- by Standard &
Poor’s or below Baa3 by Moody’s. These agreements are primarily for the physical purchase or sale of natural gas and electricity. The collateral requirement from a downgrade below the ratings trigger levels would amount to approximately
$1.8 million. In addition to agreements with ratings triggers, there are some agreements that contain “adequate assurance” or “material adverse change” provisions that could result in additional credit support such as letters of
credit and cash collateral to transact business.
NiSource had $176.6 million and $198.3 million of cash on deposit with brokers for margin
requirements associated with open derivative positions reflected within “Restricted cash” on the Condensed Consolidated Balance Sheets (unaudited) as of September 30, 2011 and December 31, 2010, respectively.
27
|
ITEM 1.
|
FINANCIAL STATEMENTS (continued)
|
N
I
S
OURCE
I
NC
.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)
|
9.
|
Fair Value Disclosures
|
|
A.
|
Fair Value Measurements.
|
Recurring Fair Value Measurements.
The following tables present financial assets and liabilities measured and
recorded at fair value on NiSource’s Condensed Consolidated Balance Sheets (unaudited) on a recurring basis and their level within the fair value hierarchy as of September 30, 2011 and December 31, 2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Recurring Fair Value Measurements
September 30, 2011 (in millions)
|
|
Quoted Prices in
Active
Markets
for Identical
Assets
(Level 1)
|
|
|
Significant
Other
Observable
Inputs
(Level 2)
|
|
|
Significant
Unobservable
Inputs
(Level 3)
|
|
|
Balance as of
Sept.
30, 2011
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity Price risk management assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Physical price risk programs
|
|
$
|
—
|
|
|
$
|
133.1
|
|
|
$
|
—
|
|
|
$
|
133.1
|
|
|
Financial price risk programs
|
|
|
134.0
|
|
|
|
3.3
|
|
|
|
—
|
|
|
|
137.3
|
|
|
Interest rate risk activities
|
|
|
—
|
|
|
|
57.7
|
|
|
|
—
|
|
|
|
57.7
|
|
|
Available-for-sale securities
|
|
|
36.3
|
|
|
|
60.9
|
|
|
|
—
|
|
|
|
97.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
170.3
|
|
|
$
|
255.0
|
|
|
$
|
—
|
|
|
$
|
425.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity Price risk management liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Physical price risk programs
|
|
$
|
—
|
|
|
$
|
3.4
|
|
|
$
|
—
|
|
|
$
|
2.4
|
|
|
Financial price risk programs
|
|
|
302.0
|
|
|
|
2.4
|
|
|
|
0.4
|
|
|
|
305.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
302.0
|
|
|
$
|
5.8
|
|
|
$
|
0.4
|
|
|
$
|
308.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Recurring Fair Value Measurements
December 31, 2010 (in millions)
|
|
Quoted Prices in
Active
Markets
for Identical
Assets
(Level 1)
|
|
|
Significant
Other
Observable
Inputs
(Level 2)
|
|
|
Significant
Unobservable
Inputs
(Level 3)
|
|
|
Balance as
of
December 31, 2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity Price risk management assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Physical price risk programs
|
|
$
|
—
|
|
|
$
|
161.4
|
|
|
$
|
—
|
|
|
$
|
161.4
|
|
|
Financial price risk programs
|
|
|
173.8
|
|
|
|
3.2
|
|
|
|
0.3
|
|
|
|
177.3
|
|
|
Interest rate risk activities
|
|
|
—
|
|
|
|
61.1
|
|
|
|
—
|
|
|
|
61.1
|
|
|
Available-for-sale securities
|
|
|
43.5
|
|
|
|
37.9
|
|
|
|
—
|
|
|
|
81.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
217.3
|
|
|
$
|
263.6
|
|
|
$
|
0.3
|
|
|
$
|
481.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity Price risk management liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Physical price risk programs
|
|
$
|
—
|
|
|
$
|
3.6
|
|
|
$
|
—
|
|
|
$
|
3.6
|
|
|
Financial price risk programs
|
|
|
348.5
|
|
|
|
3.3
|
|
|
|
0.1
|
|
|
|
351.9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
348.5
|
|
|
$
|
6.9
|
|
|
$
|
0.1
|
|
|
$
|
355.5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price risk management assets and liabilities include commodity exchange-traded and non-exchange-based derivative
contracts. Exchange-traded derivative contracts are generally based on unadjusted quoted prices in active markets and are classified within Level 1. These financial assets and liabilities are secured with cash on deposit with the exchange; therefore
nonperformance risk has not been incorporated into these valuations. Certain non-exchange-
28
|
ITEM 1.
|
FINANCIAL STATEMENTS (continued)
|
N
I
S
OURCE
I
NC
.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)
traded derivatives are valued using broker or over-the-counter, on-line exchanges. In such cases, these non-exchange-traded derivatives are classified within Level 2. Non-exchange-based
derivative instruments include swaps, forwards, and options. In certain instances, these instruments may utilize models to measure fair value. NiSource uses a similar model to value similar instruments. Valuation models utilize various inputs that
include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, other observable inputs for the asset or liability, and market-corroborated
inputs, i.e., inputs derived principally from or corroborated by observable market data by correlation or other means. Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in
Level 2. Certain derivatives trade in less active markets with a lower availability of pricing information and models may be utilized in the valuation. When such inputs have a significant impact on the measurement of fair value, the instrument is
categorized in Level 3. Credit risk is considered in the fair value calculation of derivative instruments that are not exchange-traded. Credit exposures are adjusted to reflect collateral agreements which reduce exposures.
To determine the fair value of derivatives associated with NiSource’s unregulated natural gas marketing business, certain reserves were calculated.
These reserves were primarily determined by evaluating the credit worthiness of certain customers, fair value of future cash flows, and the cost of maintaining restricted cash. Refer to Note 8, “Risk Management Activities” for additional
information on price risk assets.
Price risk management assets also include fixed-to-floating interest-rate swaps, which are designated as
fair value hedges, as a means to achieve NiSource’s targeted level of variable-rate debt as a percent of total debt. NiSource uses a calculation of future cash inflows and estimated future outflows related to the swap agreements, which are
discounted and netted to determine the current fair value. Additional inputs to the present value calculation include the contract terms, as well as market parameters such as current and projected interest rates and volatility. As they are based on
observable data and valuations of similar instruments, the interest-rate swaps are categorized in Level 2 in the fair value hierarchy. Credit risk is considered in the fair value calculation of the interest rate swap.
Available-for-sale securities are investments pledged as collateral for trust accounts related to NiSource’s wholly-owned insurance company.
Available-for-sale securities are included within “Other investments” in the Condensed Consolidated Balance Sheets (unaudited). Securities classified within Level 1 include U.S. Treasury debt securities which are highly liquid and are
actively traded in over-the-counter markets. NiSource values corporate and mortgage-backed debt securities using a matrix pricing model that incorporates market-based information. These securities trade less frequently and are classified within
Level 2. Total gains and losses from available-for-sale securities are included in other comprehensive income (loss). The amortized cost, gross unrealized gains and losses, and fair value of available-for-sale debt securities at September 30,
2011 and December 31, 2010 were:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amortized
|
|
|
Total
|
|
|
Total
|
|
|
Fair
|
|
|
(in millions)
|
|
Cost
|
|
|
Gains
|
|
|
Losses
|
|
|
Value
|
|
|
Available-for-sale debt securities, Sept. 30, 2011
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. Treasury
|
|
$
|
40.2
|
|
|
$
|
1.6
|
|
|
$
|
—
|
|
|
$
|
41.8
|
|
|
Corporate/Other
|
|
|
54.2
|
|
|
|
1.5
|
|
|
|
(0.3
|
)
|
|
|
55.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Available-for-sale debt securities
|
|
$
|
94.4
|
|
|
$
|
3.1
|
|
|
$
|
(0.3
|
)
|
|
$
|
97.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amortized
|
|
|
Total
|
|
|
Total
|
|
|
Fair
|
|
|
(in millions)
|
|
Cost
|
|
|
Gains
|
|
|
Losses
|
|
|
Value
|
|
|
Available-for-sale debt securities, Dec. 31, 2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. Treasury
|
|
$
|
43.4
|
|
|
$
|
0.6
|
|
|
$
|
(0.5
|
)
|
|
$
|
43.5
|
|
|
Corporate/Other
|
|
|
36.1
|
|
|
|
2.0
|
|
|
|
(0.2
|
)
|
|
|
37.9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Available-for-sale debt securities
|
|
$
|
79.5
|
|
|
$
|
2.6
|
|
|
$
|
(0.7
|
)
|
|
$
|
81.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the three months ended September 30, 2011 and 2010, the net realized gain on the sale of available-for-sale U.S.
Treasury debt securities was $0.1 million and $0.3 million, respectively. For the three months ended September 30, 2011 and 2010, the realized gain on sale of available-for-sale Corporate/Other bond debt securities was $0.1 million and $0.3
million, respectively.
29
|
ITEM 1.
|
FINANCIAL STATEMENTS (continued)
|
N
I
S
OURCE
I
NC
.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)
For the nine months ended September 30, 2011 and 2010, the net realized gain on the sale of
available-for-sale U.S. Treasury debt securities was $0.4 million. For the nine months ended September 30, 2011 and 2010, the realized gain on sale of available-for-sale Corporate/Other bond debt securities was $1.0 million.
The cost of maturities sold is based upon specific identification. At September 30, 2011, approximately $2.7 million of U.S. Treasury debt
securities have maturities of less than a year while the remaining securities have maturities of greater than one year. At September 30, 2011, approximately $0.6 million of Corporate/Other bonds have maturities of less than a year while the
remaining securities have maturities of greater than one year.
NiSource adopted the requirement to provide Level 3 activity of purchases,
sales, issuances, and settlements on a gross basis, which is effective for fiscal years beginning after December 15, 2010, during the first quarter of 2011. The following tables present the fair value reconciliation of Level 3 assets and
liabilities measured at fair value on a recurring basis for the three and nine months ended September 30, 2011 and 2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial
|
|
|
|
|
|
|
|
|
|
|
Transmission
|
|
|
Other
|
|
|
|
|
|
Three Months Ended September 30, 2011
(in millions)
|
|
Rights
|
|
|
Derivatives
|
|
|
Total
|
|
|
Balance as of July 1, 2011
|
|
$
|
—
|
|
|
$
|
(0.8
|
)
|
|
$
|
(0.8
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total gains or (losses) (unrealized/realized)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Included in regulatory assets/liabilities
|
|
|
—
|
|
|
|
0.4
|
|
|
|
0.4
|
|
|
Purchases
|
|
|
—
|
|
|
|
(0.2
|
)
|
|
|
(0.2
|
)
|
|
Settlements
|
|
|
—
|
|
|
|
0.2
|
|
|
|
0.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance as of September 30, 2011
|
|
$
|
—
|
|
|
$
|
(0.4
|
)
|
|
$
|
(0.4
|
)
|
|
Change in unrealized gains/(losses) relating to instruments still held as of September 30, 2011
|
|
$
|
—
|
|
|
$
|
(1.1
|
)
|
|
$
|
(1.1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial
|
|
|
|
|
|
|
|
|
|
|
Transmission
|
|
|
Other
|
|
|
|
|
|
Three Months Ended September 30, 2010
(in millions)
|
|
Rights
|
|
|
Derivatives
|
|
|
Total
|
|
|
Balance as of July 1, 2010
|
|
$
|
—
|
|
|
$
|
0.2
|
|
|
$
|
0.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total gains or losses (unrealized/realized)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Included in regulatory assets/liabilities
|
|
|
(6.4
|
)
|
|
|
(0.1
|
)
|
|
|
(6.5
|
)
|
|
Settlements
|
|
|
6.4
|
|
|
|
(0.6
|
)
|
|
|
5.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance as of September 30, 2010
|
|
$
|
—
|
|
|
$
|
(0.5
|
)
|
|
$
|
(0.5
|
)
|
|
Change in unrealized gains/(losses) relating to instruments still held as of September 30, 2010
|
|
$
|
—
|
|
|
$
|
(0.1
|
)
|
|
$
|
(0.1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
30
|
ITEM 1.
|
FINANCIAL STATEMENTS (continued)
|
N
I
S
OURCE
I
NC
.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial
|
|
|
|
|
|
|
|
|
|
|
Transmission
|
|
|
Other
|
|
|
|
|
|
Nine Months Ended, September 30, 2011
(in millions)
|
|
Rights
|
|
|
Derivatives
|
|
|
Total
|
|
|
Balance as of January 1, 2011
|
|
$
|
—
|
|
|
$
|
0.2
|
|
|
$
|
0.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total gains or (losses) (unrealized/realized)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Included in regulatory assets/liabilities
|
|
|
—
|
|
|
|
(0.7
|
)
|
|
|
(0.7
|
)
|
|
Purchases
|
|
|
—
|
|
|
|
(1.1
|
)
|
|
|
(1.1
|
)
|
|
Settlements
|
|
|
—
|
|
|
|
1.2
|
|
|
|
1.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance as of September 30, 2011
|
|
$
|
—
|
|
|
$
|
(0.4
|
)
|
|
$
|
(0.4
|
)
|
|
Change in unrealized gains/(losses) relating to instruments still held as of September 30, 2011
|
|
$
|
—
|
|
|
$
|
(1.1
|
)
|
|
$
|
(1.1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial
|
|
|
|
|
|
|
|
|
|
|
Transmission
|
|
|
Other
|
|
|
|
|
|
Nine Months Ended, September 30, 2010
(in millions)
|
|
Rights
|
|
|
Derivatives
|
|
|
Total
|
|
|
Balance as of January 1, 2010
|
|
$
|
1.9
|
|
|
$
|
0.2
|
|
|
$
|
2.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total gains or losses (unrealized/realized)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Included in regulatory assets/liabilities
|
|
|
(10.6
|
)
|
|
|
(0.1
|
)
|
|
|
(10.7
|
)
|
|
Settlements
|
|
|
8.7
|
|
|
|
(0.6
|
)
|
|
|
8.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance as of September 30, 2010
|
|
$
|
—
|
|
|
$
|
(0.5
|
)
|
|
$
|
(0.5
|
)
|
|
Change in unrealized gains/(losses) relating to instruments still held as of September 30, 2010
|
|
$
|
—
|
|
|
$
|
(0.1
|
)
|
|
$
|
(0.1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As discussed in Note 8 “Risk Management Activities,” as part of the MISO Day 2 initiative, Northern Indiana
obtains FTRs, which help to offset congestion costs due to the MISO Day 2 activity. These instruments are considered derivatives and are classified as Level 3 and reflected in the table above. FTRs are valued using a valuation model based on the
value of allocated ARRs and forecasted congestion costs. Since congestion costs are recoverable through the fuel cost recovery mechanism, the related gains and losses associated with marking these derivatives to market are recorded as a regulatory
asset or liability. Northern Indiana also writes options for regulatory incentive purposes which are also considered Level 3 valuations. Realized gains and losses for these Level 3 recurring items are included in income within Cost of Sales on the
Condensed Statements of Consolidated Income (unaudited). Unrealized gains and losses from Level 3 recurring items are included within Regulatory assets or Regulatory liabilities on the Condensed Consolidated Balance Sheets (unaudited).
Non-recurring Fair Value Measurements.
There were no significant non-recurring fair value measurements recorded during the nine months
ended September 30, 2011 and 2010.
B. Other Fair Value Disclosures for Financial Instruments.
NiSource has certain financial
instruments that are not measured at fair value on a recurring basis but nevertheless are recorded at amounts that approximate fair value due to their liquid or short-term nature, including cash and cash equivalents, restricted cash, accounts
receivable, accounts payable, customer deposits and short-term borrowings. NiSource’s long-term borrowings are recorded at historical amounts unless designated as a hedged item in a fair value hedge.
The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate
fair value.
Investments.
NiSource has corporate owned life insurance which is measured and recorded at cash surrender value.
NiSource’s investments in corporate owned life insurance at September 30, 2011 and December 31, 2010 were $24.6 million and $26.0 million, respectively.
Long-term Debt.
The fair values of these securities are estimated based on the quoted market prices for the same or similar issues or on the rates offered for securities of the same
remaining maturities. Certain premium costs associated with the early settlement of long-term debt are not taken into consideration in determining fair value.
31
|
ITEM 1.
|
FINANCIAL STATEMENTS (continued)
|
N
I
S
OURCE
I
NC
.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)
The carrying amount and estimated fair values of financial instruments were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Carrying
|
|
|
Estimated Fair
|
|
|
Carrying
|
|
|
Estimated Fair
|
|
|
|
|
Amount as of
|
|
|
Value as of
|
|
|
Amount as of
|
|
|
Value as of
|
|
|
(in millions)
|
|
Sept. 30, 2011
|
|
|
Sept. 30, 2011
|
|
|
Dec. 31, 2010
|
|
|
Dec. 31, 2010
|
|
|
Long-term investments
|
|
$
|
25.2
|
|
|
$
|
24.0
|
|
|
$
|
26.7
|
|
|
$
|
25.4
|
|
|
Long-term debt (including current portion)
|
|
|
6,345.5
|
|
|
|
7,149.7
|
|
|
|
5,970.3
|
|
|
|
6,482.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.
|
Transfers of Financial Assets
|
Transfers of accounts receivable are accounted for as secured borrowings resulting in the recognition of short-term borrowings on the
Condensed Consolidated Balance Sheets (unaudited). The maximum amount of debt that can be recognized related to NiSource’s accounts receivable programs is $515 million.
All accounts receivables sold to the commercial paper conduits are valued at face value, which approximate fair value due to their short-term nature. The amount of the undivided percentage ownership
interest in the accounts receivables sold is determined in part by required loss reserves under the agreements. Below is information about the accounts receivable securitization agreements entered into by NiSource’s subsidiaries.
On October 23, 2009, Columbia of Ohio entered into an agreement to sell, without recourse, substantially all of its trade receivables, as they
originate, to CGORC, a wholly-owned subsidiary of Columbia of Ohio. CGORC, in turn, is party to an agreement with BTMU and RBS, also dated October 23, 2009, under the terms of which it sells an undivided percentage ownership interest in its
accounts receivable to commercial paper conduits sponsored by BTMU and RBS. On October 21, 2011, the agreement was renewed with an amendment increasing the maximum seasonal program limit from $200 million to $240 million. The amended agreement
expires on October 19, 2012, and can be renewed if mutually agreed to by all parties. As of September 30, 2011, $60.0 million of accounts receivable had been transferred by CGORC. CGORC is a separate corporate entity from NiSource and
Columbia of Ohio, with its own separate obligations, and upon a liquidation of CGORC, CGORC’s obligations must be satisfied out of CGORC’s assets prior to any value becoming available to CGORC’s stockholder. Under the agreement, an
event of termination occurs if NiSource’s debt rating is withdrawn by either Standard & Poor’s or Moody’s, or falls below BB- or Ba3 at either Standard & Poor’s or Moody’s, respectively.
On October 23, 2009, Northern Indiana entered into an agreement to sell, without recourse, substantially all of its trade receivables, as they
originate, to NARC, a wholly-owned subsidiary of Northern Indiana. NARC, in turn, is party to an agreement with RBS, also dated October 23, 2009, under the terms of which it sells an undivided percentage ownership interest in its accounts
receivable to a commercial paper conduit sponsored by RBS. The maximum seasonal program limit under the terms of the agreement is $200 million. On August 31, 2011, the agreement was renewed, having a new scheduled termination date of
August 29, 2012, and can be further renewed if mutually agreed to by both parties. As of September 30, 2011, $125.0 million of accounts receivable had been transferred by NARC. NARC is a separate corporate entity from NiSource and Northern
Indiana, with its own separate obligations, and upon a liquidation of NARC, NARC’s obligations must be satisfied out of NARC’s assets prior to any value becoming available to NARC’s stockholder. Under the agreement, an event of
termination occurs if Northern Indiana’s debt rating is withdrawn by either Standard & Poor’s or Moody’s, or falls below BB or Ba2 at either Standard & Poor’s or Moody’s, respectively.
On March 15, 2010, Columbia of Pennsylvania entered into an agreement to sell, without recourse, substantially all of its trade receivables, as they
originate, to CPRC, a wholly-owned subsidiary of Columbia of Pennsylvania. CPRC, in turn, is party to an agreement with BTMU, also dated March 15, 2010, under the terms of which it sells an undivided percentage ownership interest in its
accounts receivable to a commercial paper conduit sponsored by BTMU. The maximum seasonal program limit under the terms of the agreement is $75 million. On March 14, 2011, the agreement was renewed, having a new scheduled termination date of
March 13, 2012, and can be further renewed if mutually agreed to by both parties. As of September 30, 2011, $8.2 million of accounts receivable had been transferred by CPRC. CPRC is a separate corporate entity from NiSource and Columbia of
Pennsylvania, with its own separate obligations, and upon a liquidation of CPRC, CPRC’s obligations must be satisfied out of CPRC’s assets prior to any value becoming available to CPRC’s stockholder. Under the agreement, an event of
termination occurs if NiSource’s debt rating is withdrawn by either Standard & Poor’s or Moody’s, or falls below BB- or Ba3 at either Standard & Poor’s or Moody’s, respectively.
32
|
ITEM 1.
|
FINANCIAL STATEMENTS (continued)
|
N
I
S
OURCE
I
NC
.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)
The following table reflects the gross and net receivables transferred as well as short-term borrowings
related to the securitization transactions as of September 30, 2011 and December 31, 2010 for Columbia of Ohio, Northern Indiana and Columbia of Pennsylvania:
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
|
September 30, 2011
|
|
|
December 31, 2010
|
|
|
Gross Receivables
|
|
$
|
311.4
|
|
|
$
|
655.6
|
|
|
Less: Receivables not transferred
|
|
|
118.2
|
|
|
|
380.6
|
|
|
|
|
|
|
|
|
|
|
|
|
Net receivables transferred
|
|
$
|
193.2
|
|
|
$
|
275.0
|
|
|
|
|
|
|
|
|
|
|
|
|
Short-term debt due to asset securitization
|
|
$
|
193.2
|
|
|
$
|
275.0
|
|
|
|
|
|
|
|
|
|
|
|
For the three months ended September 30, 2011 and 2010, $0.7 million and $1.5 million of fees associated with the
securitization transactions were recorded as interest expense, respectively. For the nine months ended September 30, 2011 and 2010, $3.0 million and $5.2 million of fees associated with the securitization transactions were recorded as interest
expense, respectively. Columbia of Ohio, Northern Indiana and Columbia of Pennsylvania remain responsible for collecting on the receivables securitized and the receivables cannot be sold to another party.
In accordance with the provisions for goodwill accounting under GAAP, NiSource tests its goodwill for impairment annually as of
June 30 each year unless indicators, events, or circumstances would require an immediate review. Goodwill is tested for impairment at a level of reporting referred to as a reporting unit, which generally is an operating segment or a component
of an operating segment as defined by the FASB.
NiSource’s goodwill assets as of September 30, 2011 were $3.7 billion pertaining
primarily to the acquisition of Columbia on November 1, 2000. Of this amount, approximately $2.0 billion is allocated to Columbia Transmission Operations and $1.7 billion is allocated to Columbia Distribution Operations. In addition, Northern
Indiana Gas Distribution Operations’ goodwill assets at September 30, 2011 related to the purchase of Northern Indiana Fuel and Light in March 1993 and Kokomo Gas in February 1992 were $18.8 million.
The test performed at June 30, 2011 indicated that the fair value of each of the reporting units that carry or are allocated goodwill exceeded their
carrying values, indicating that no impairment exists under Step 1 of the annual impairment test.
NiSource considered whether there were any
events or changes in circumstances subsequent to the annual test that would reduce the fair value of any of the reporting units below their carrying amounts and necessitate another goodwill impairment test. No such indicators were noted that would
require goodwill impairment testing during the third quarter.
NiSource’s interim effective tax rates reflect the estimated annual effective tax rates for 2011 and 2010, adjusted for tax
expense associated with certain discrete items. The effective tax rates for the three months ended September 30, 2011 and 2010 were 32.0% and (20.1)%, respectively. The effective tax rates for the nine months ended September 30, 2011 and
2010 were 35.6% and 31.6%, respectively. These effective tax rates differ from the Federal tax rate of 35% primarily due to the effects of tax credits, state income taxes, utility rate-making, and other permanent book-to-tax differences such as the
electric production tax deduction provided under Internal Revenue Code Section 199.
In the third quarter of 2010, NiSource recorded a
$15.2 million reduction to income tax expense in connection with the Pennsylvania PUC approval of the Columbia of Pennsylvania base rate case settlement on August 18, 2010. The adjustment to income tax expense results from the settlement
agreement to flow through in current rates the tax benefits related to a tax accounting method change for certain capitalized costs approved by the Internal Revenue Services
33
|
ITEM 1.
|
FINANCIAL STATEMENTS (continued)
|
N
I
S
OURCE
I
NC
.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)
On May 12, 2011, the governor of Indiana signed into law House Bill 1004, which among other things,
lowers the corporate income tax rate from 8.5% to 6.5% over four years beginning on July 1, 2012. The reduction in the tax rate will impact deferred income taxes and tax related regulatory assets and liabilities recoverable in the rate making
process. In addition, other deferred tax assets and liabilities, primarily deferred tax assets related to Indiana net operating loss carryforward, will be reduced to reflect the lower rate at which these temporary differences and tax benefits will
be realized. In the second quarter 2011, NiSource recorded tax expense of $6.8 million to reflect the effect of this rate change.
On
August 19, 2011, the IRS issued Revenue Procedure 2011-43, which provided a safe harbor method that taxpayers may use to determine whether certain expenditures related to electric transmission and distribution assets must be capitalized. This
revenue procedure provided procedures for obtaining automatic consent from the IRS to adopt the safe harbor method for the first or second taxable year beginning after December 31, 2011. NiSource changed its method of tax accounting related to
certain expenditures, including those related to electric transmission and distribution assets in 2008. At December 31, 2010, NiSource had $107.4 million of unrecorded tax benefits related to this method change pending resolution on audit or
further guidance from the IRS or United States Treasury Department. As a result of the issuance of the revenue procedure NiSource revised its estimates and recorded tax benefits of $12.9 million in the third quarter of 2011. Excluding minor amounts
of interest, the revision of estimate did not impact total income tax expense.
There were no material changes recorded in the third quarter
of 2011 to NiSource’s uncertain tax positions as of December 31, 2010 except as noted above.
|
13.
|
Pension and Other Postretirement Benefits
|
NiSource provides defined contribution plans and noncontributory defined benefit retirement plans that cover its employees. Benefits
under the defined benefit retirement plans reflect the employees’ compensation, years of service and age at retirement. Additionally, NiSource provides health care and life insurance benefits for certain retired employees. The majority of
employees may become eligible for these benefits if they reach retirement age while working for NiSource. The expected cost of such benefits is accrued during the employees’ years of service. Current rates of rate-regulated companies include
postretirement benefit costs, including amortization of the regulatory assets that arose prior to inclusion of these costs in rates. For most plans, cash contributions are remitted to grantor trusts.
For the nine months ended September 30, 2011, NiSource has contributed $142.7 million to its pension plans and $41.4 million to its other
postretirement benefit plans.
The following table provides the components of the plans’ net periodic benefits cost for the three and
nine months ended September 30, 2011 and 2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Benefits
|
|
|
Other Postretirement
Benefits
|
|
|
Three Months Ended September 30,
(in millions)
|
|
2011
|
|
|
2010
|
|
|
2011
|
|
|
2010
|
|
|
Components of Net Periodic Benefit Cost
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service cost
|
|
$
|
9.4
|
|
|
$
|
9.8
|
|
|
$
|
2.5
|
|
|
$
|
2.5
|
|
|
Interest cost
|
|
|
29.9
|
|
|
|
31.5
|
|
|
|
9.6
|
|
|
|
10.6
|
|
|
Expected return on assets
|
|
|
(41.8
|
)
|
|
|
(36.0
|
)
|
|
|
(6.7
|
)
|
|
|
(6.1
|
)
|
|
Amortization of transition obligation
|
|
|
—
|
|
|
|
—
|
|
|
|
0.3
|
|
|
|
0.3
|
|
|
Amortization of prior service cost
|
|
|
0.1
|
|
|
|
0.5
|
|
|
|
(0.1
|
)
|
|
|
0.5
|
|
|
Recognized actuarial loss
|
|
|
13.9
|
|
|
|
14.4
|
|
|
|
1.7
|
|
|
|
1.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Net Periodic Benefit Costs
|
|
$
|
11.5
|
|
|
$
|
20.2
|
|
|
$
|
7.3
|
|
|
$
|
9.5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
34
|
ITEM 1.
|
FINANCIAL STATEMENTS (continued)
|
N
I
S
OURCE
I
NC
.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Benefits
|
|
|
Other
Postretirement
Benefits
|
|
|
Nine Months Ended September 30,
(in millions)
|
|
2011
|
|
|
2010
|
|
|
2011
|
|
|
2010
|
|
|
Components of Net Periodic Benefit Cost
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service cost
|
|
$
|
28.2
|
|
|
$
|
29.3
|
|
|
$
|
7.5
|
|
|
$
|
7.3
|
|
|
Interest cost
|
|
|
89.7
|
|
|
|
94.3
|
|
|
|
28.8
|
|
|
|
31.8
|
|
|
Expected return on assets
|
|
|
(125.4
|
)
|
|
|
(107.8
|
)
|
|
|
(20.1
|
)
|
|
|
(18.0
|
)
|
|
Amortization of transition obligation
|
|
|
—
|
|
|
|
—
|
|
|
|
0.9
|
|
|
|
0.9
|
|
|
Amortization of prior service cost
|
|
|
0.3
|
|
|
|
1.5
|
|
|
|
(0.3
|
)
|
|
|
1.2
|
|
|
Recognized actuarial loss
|
|
|
41.7
|
|
|
|
43.4
|
|
|
|
5.1
|
|
|
|
4.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Net Periodic Benefit Costs
|
|
$
|
34.5
|
|
|
$
|
60.7
|
|
|
$
|
21.9
|
|
|
$
|
27.9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the quarters ended September 30, 2011 and 2010, pension and other postretirement benefit cost of approximately
$13.1 million and $8.3 million, respectively, was capitalized as a component of plant or recognized as a regulatory asset or liability consistent with regulatory orders for certain of NiSource’s regulated businesses. For the nine months ended
September 30, 2011 and 2010, pension and other postretirement benefit cost of approximately $21.9 million and $15.4 million, respectively, was capitalized as a component of plant or recognized as a regulatory asset or liability consistent with
regulatory orders for certain of NiSource’s regulated business.
On September 1, 2011, NiSource announced that effective
August 31, 2011, Christopher A. Helms retired from his position as Executive Vice President and Group CEO of the NiSource Gas Transmission and Storage Group, as well as any other offices or directorships with NiSource or any affiliate. In
connection with his retirement from NiSource, NiSource and Mr. Helms entered into a letter agreement on August 30, 2011 (the “Agreement”). The Agreement provided, among other things, for a separation payment plus a lump sum
payment for health and welfare benefits, which were accrued at September 30, 2011.
|
14.
|
Variable Interests and Variable Interest Entities
|
In general, a VIE is an entity which (1) has an insufficient amount of at-risk equity to permit the entity to finance its
activities without additional financial subordinated support provided by any parties, (2) whose at-risk equity owners, as a group, do not have power, through voting rights or similar rights, to direct activities of the entity that most
significantly impact the entity’s economic performance or (3) whose at-risk owners do not absorb the entity’s losses or receive the entity’s residual return. A VIE is required to be consolidated by a company if that company is
determined to be the primary beneficiary of the VIE.
NiSource consolidates those VIEs for which it is the primary beneficiary. Prior to the
adoption of the new FASB guidance on consolidation of VIEs, the prevalent method for determining the primary beneficiary was through a quantitative method. With the adoption of the guidance, NiSource also considers qualitative elements in
determining the primary beneficiary. These qualitative measures include the ability to control an entity and the obligation to absorb losses or the right to receive benefits.
NiSource’s analysis under this standard includes an assessment of guarantees, operating leases, purchase agreements, and other contracts, as well as its investments and joint ventures. For items that
have been identified as variable interests, or where there is involvement with an identified VIE, an in-depth review of the relationship between the relevant entities and NiSource is made to evaluate qualitative and quantitative factors to determine
the primary beneficiary, if any, and whether additional disclosures would be required under the current standard.
At September 30, 2011,
consistent with prior periods, NiSource consolidated its low income housing real estate investments from which NiSource derives certain tax benefits. Based on the newly adopted guidance on the consolidation of variable interest entities, these
investments met the definition of a VIE. As of September 30, 2011, NiSource is a 99% limited partner with a net investment of approximately $1.2 million. Consistent with prior periods, NiSource evaluated the nature and intent of the low income
housing investments when determining the
35
|
ITEM 1.
|
FINANCIAL STATEMENTS (continued)
|
N
I
S
OURCE
I
NC
.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)
primary beneficiary. NiSource concluded that it continues to be the primary beneficiary. Subject to certain conditions precedent, NiSource has the contractual right to take control of the low
income housing properties. At September 30, 2011, gross assets of the low income housing real estate investments in continuing operations were $29.0 million. Current and non-current assets were $1.4 million and $27.6 million, respectively. As
of September 30, 2011, NiSource recorded long-term debt of approximately $11.3 million as a result of consolidating these investments. However, this debt is nonrecourse to NiSource and NiSource’s direct and indirect subsidiaries.
Approximately $0.7 million of the assets are restricted to settle the obligations of the entity.
Northern Indiana has a service agreement
with Pure Air, a general partnership between Air Products and Chemicals, Inc. and First Air Partners LP, under which Pure Air provides scrubber services to reduce sulfur dioxide emissions for Units 7 and 8 at the Bailly Generating Station. Services
under this contract commenced on July 1, 1992, and Northern Indiana pays for the services under a combination of fixed and variable charges. The agreement provides that, assuming various performance standards are met by Pure Air, a termination
payment would be due if Northern Indiana terminated the agreement prior to the end of the twenty-year contract period. NiSource has made an exhaustive effort to obtain information needed from Pure Air to determine the status of Pure Air as a VIE.
However, Northern Indiana had not been able to obtain this information and as a result, it is unclear whether Pure Air is a VIE and if Northern Indiana is the primary beneficiary. Northern Indiana will continue to request the information required to
determine whether Pure Air is a VIE. Northern Indiana has no exposure to loss related to the service agreement with Pure Air.
During July 2011, Northern Indiana redeemed $18.7 million of its medium-term notes, with an average interest rate of 7.30%.
On June 10, 2011, NiSource Finance issued $400.0 million of 5.95% senior unsecured notes that mature June 15, 2041.
On December 8, 2010, NiSource Finance issued $250.0 million of 6.25% senior unsecured notes that mature December 15, 2040.
On December 1, 2010, NiSource Finance announced that it was commencing a cash tender offer for up to $250.0 million aggregate principal amount of
its outstanding 10.75% notes due 2016 and 6.80% notes due 2019. A condition of the offering was that all validly tendered 2016 notes would be accepted for purchase before any 2019 notes were accepted. On December 14, 2010, NiSource Finance
announced that approximately $272.9 million of the aggregate principal amount of its outstanding 10.75% notes due 2016 were validly tendered. Based upon the principal amount of the 2016 notes tendered, NiSource Finance increased the maximum
aggregate principal amount of 2016 notes it would purchase from $250.0 million to $325.0 million and terminated the portion of the tender offer related to its 6.80% notes due 2019. On December 30, 2010, NiSource Finance announced that $273.1
million of these notes were successfully tendered. In accordance with the provisions of ASC 470,
Debt
, NiSource determined the new 6.25% notes due 2040 to be substantially different from the old debt instrument, and therefore the transaction
qualified as a debt extinguishment. NiSource recorded a $96.7 million loss on early extinguishment of long-term debt, primarily attributable to early redemption premiums and unamortized discounts and fees.
On November 15, 2010, NiSource Finance redeemed $681.8 million of its 7.875% unsecured notes.
|
16.
|
Short-Term Borrowings
|
During June 2011, NiSource Finance implemented a new commercial paper program with a program limit of up to $500.0 million with a
dealer group comprised of Barclays, Citigroup, Credit Suisse and Wells Fargo. Commercial paper issuances are supported by available capacity under NiSource’s $1.5 billion unsecured revolving credit facility, which expires in March 2015. At
September 30, 2011, NiSource had $425.8 million of commercial paper outstanding.
36
|
ITEM 1.
|
FINANCIAL STATEMENTS (continued)
|
N
I
S
OURCE
I
NC
.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)
On March 3, 2011, NiSource Finance entered into a new $1.5 billion four-year revolving credit
facility with a syndicate of banks led by Barclays Capital. The new facility has a termination date of March 3, 2015 and replaced an existing $1.5 billion five-year credit facility which would have expired during July 2011. The purpose of the
facility is to fund ongoing working capital requirements and for general corporate purposes, including supporting liquidity for NiSource’s commercial paper program, and provides for the issuance of letters of credit. At September 30, 2011,
NiSource had $615.0 million of outstanding borrowings under this facility.
As of September 30, 2011 and December 31, 2010, NiSource
had $37.4 million and $32.5 million, respectively, of stand-by letters of credit outstanding, of which $19.2 million and $14.2 million, respectively, were under the revolving credit facility.
Beginning January 1, 2010, transfers of accounts receivable that previously qualified for sales accounting no longer qualify and are accounted for as secured borrowings resulting in the recognition
of short-term debt on the Condensed Consolidated Balance Sheet in the amount of $193.2 million and $275.0 million as of September 30, 2011 and December 31, 2010, respectively. Refer to Note 10, “Transfers of Financial Assets,”
for additional information.
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30,
|
|
|
December 31,
|
|
|
(in millions)
|
|
2011
|
|
|
2010
|
|
|
Commercial Paper weighted average interest rate of 0.98% at September 30, 2011
|
|
$
|
425.8
|
|
|
$
|
—
|
|
|
Credit facilities borrowings weighted average interest rate of 1.96% and 0.78% at September 30, 2011 and December 31,
2010, respectively
|
|
|
615.0
|
|
|
|
1,107.5
|
|
|
Accounts receivable securitization facility borrowings
|
|
|
193.2
|
|
|
|
275.0
|
|
|
|
|
|
|
|
|
|
|
|
|
Total short-term borrowings
|
|
$
|
1,234.0
|
|
|
$
|
1,382.5
|
|
|
|
|
|
|
|
|
|
|
|
Given their turnover is less than 90 days, cash flows related to the borrowings and repayments of the items listed above
are presented net at the Condensed Statements of Consolidated Cash Flows (unaudited).
|
17.
|
Share-Based Compensation
|
Prior to May 11, 2010, NiSource issued long-term incentive grants to key management employees under a long-term incentive plan
approved by stockholders on April 13, 1994 (“1994 Plan”). The 1994 Plan, as amended and restated, permits the following types of grants, separately or in combination: nonqualified stock options, incentive stock options, restricted
stock awards, stock appreciation rights, restricted stock units, contingent stock units and dividend equivalents payable on grants of options, performance units and contingent stock awards.
The stockholders approved and adopted the NiSource Inc. 2010 Omnibus Incentive Plan (the “Omnibus Plan”), at the Annual Meeting of Stockholders held on May 11, 2010. The Omnibus Plan
provides that the number of shares of common stock of NiSource available for awards is 8,000,000 plus the number of shares subject to outstanding awards granted under either the 1994 Plan or the Director Plan (described below) that expire or
terminate for any reason and no further awards are permitted to be granted under the 1994 Plan or the Director Plan. The types of awards authorized under the Omnibus Plan do not significantly differ from those previously allowed under the 1994 Plan.
At September 30, 2011, there were 7,992,445 shares reserved for future awards under the Omnibus Plan.
NiSource recognized stock-based
employee compensation expense of $4.0 million and $3.0 million for the three months ended September 30, 2011 and 2010, respectively, as well as related tax benefits of $1.3 million and $0.7 million. For the nine months ended September 30,
2011 and 2010, stock-based employee compensation expense of $10.2 million and $9.0 million was recognized, respectively, as well as related tax benefits of $3.6 million and $2.8 million, respectively.
As of September 30, 2011, the total remaining unrecognized compensation cost related to nonvested awards amounted to $17.8 million, which will be
amortized over the weighted-average remaining requisite service period of 1.9 years.
37
|
ITEM 1.
|
FINANCIAL STATEMENTS (continued)
|
N
I
S
OURCE
I
NC
.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)
Stock Options.
As of September 30, 2011, approximately 3.2 million options were
outstanding and exercisable with a weighted average strike price of $22.01.
Restricted Awards.
During the nine months ended
September 30, 2011, NiSource granted 141,544 restricted stock units, subject to service conditions, at a total grant date fair value of $2.4 million, based on the average market price of NiSource’s common stock at the date of each grant
less the present value of dividends not received during the vesting period, which will be expensed, net of forfeitures, over the vesting period of approximately three years. The service conditions for 119,308 units lapse in January 2014 when 100% of
the shares vest. If before January 2014, the employee terminates employment (1) due to retirement, having attained age 55 and completed ten years of service, or (2) due to death or disability, the employment conditions will lapse with
respect to a pro rata portion of the restricted units on the date of termination. Termination due to any other reason will result in all restricted units awarded being forfeited effective the employee’s date of termination. Employees will be
entitled to receive dividends upon vesting. The service conditions lapse for the remaining 22,236 units between March 2012 and July 2014. As of September 30, 2011, 702,298 nonvested restricted stock units were granted and outstanding.
Contingent Stock Units.
During the nine months ended September 30, 2011, NiSource granted 745,042 contingent stock
units subject to performance conditions, at a grant date fair-value of $11.9 million, based on the average market price of NiSource’s common stock at the date of each grant less the present value of dividends not received during the vesting
period which will be expensed, net of forfeitures, over the three year requisite service period. The performance conditions are based on achievement of non-GAAP financial measures. The service conditions lapse on January 31, 2014 when 100% of
the shares vest. If the employee terminates employment before January 31, 2014 (1) due to retirement, having attained age 55 and completed ten years of service, or (2) due to death or disability, the employment conditions will lapse
with respect to a pro rata portion of the contingent units on the date of termination. Termination due to any other reason will result in all contingent units awarded being forfeited effective the employee’s date of termination. Employees will
be entitled to receive dividends upon vesting. As of September 30, 2011, 2,234,744 nonvested contingent stock units were granted and outstanding.
Non-employee Director Awards.
As of May 11, 2010, awards to non-employee directors may be made only under the NiSource Inc. 2010 Omnibus Incentive Plan (the “Omnibus Plan”). The
Omnibus Plan provides for awards to employees and non-employee directors of incentive and nonqualified stock options, stock appreciation rights, restricted stock and restricted stock units, performance shares, performance units, cash-based awards
and other stock-based awards. Currently, restricted stock units are granted annually to non-employee directors, subject to a non-employee director’s election to defer receipt of such restricted stock unit award. The non-employee director’s
restricted stock units vest on the last day of the non-employee director’s annual term corresponding to the year the restricted stock units were awarded subject to special pro-rata vesting rules in the event of Retirement or Disability (as
defined in the award agreement), or death. The vested restricted stock units are payable as soon as practicable following vesting except as otherwise provided pursuant to the non-employee director’s election to defer. As of September 30,
2011, 110,178 restricted stock units had been issued under the Omnibus Plan.
Only restricted stock units remain outstanding under the prior
plan for non-employee directors, the Amended and Restated Non-employee Director Stock Incentive Plan (the “Director Plan”). All such awards are fully vested and shall be distributed to the directors upon their separation from the Board. As
of September 30, 2011, 274,315 restricted stock units remain outstanding under the Director Plan and as noted above no further shares may be issued under the Director Plan.
401(k) Match, Profit Sharing and Non-Discretionary Employer Contribution for Certain Employees.
NiSource has a voluntary 401(k) savings plan covering eligible employees that allows for periodic
discretionary matches as a percentage of each participant’s contributions in newly issued shares of common stock. NiSource also has a retirement savings plan that provides for discretionary profit sharing contributions of shares of common stock
to eligible employees based on earnings results and a non-discretionary employer contribution of 3% for salaried employees hired after January 1, 2010 payable in shares of common stock. For the quarter ended September 30, 2011 and 2010,
NiSource recognized 401(k) match, profit sharing and non-discretionary employer contribution expense of $6.5 million and $4.4 million, respectively. For the nine months ended September 30, 2011 and 2010, NiSource recognized 401(k) match, profit
sharing and non-discretionary employer contribution expense of $17.2 million and $14.2 million, respectively.
38
|
ITEM 1.
|
FINANCIAL STATEMENTS (continued)
|
N
I
S
OURCE
I
NC
.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)
|
18.
|
Other Commitments and Contingencies
|
A. Guarantees and Indemnities.
As a part of normal business, NiSource and certain subsidiaries enter into various agreements
providing financial or performance assurance to third parties on behalf of certain subsidiaries. Such agreements include guarantees and stand-by letters of credit. These agreements are entered into primarily to support or enhance the
creditworthiness otherwise attributed to a subsidiary on a stand-alone basis, thereby facilitating the extension of sufficient credit to accomplish the subsidiaries’ intended commercial purposes. The total commercial commitments in existence at
September 30, 2011 and the years in which they expire were:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
|
Total
|
|
|
2011
|
|
|
2012
|
|
|
2013
|
|
|
2014
|
|
|
2015
|
|
|
After
|
|
|
Guarantees of subsidiaries debt
|
|
$
|
5,870.9
|
|
|
$
|
—
|
|
|
$
|
315.0
|
|
|
$
|
545.0
|
|
|
$
|
500.0
|
|
|
$
|
230.0
|
|
|
$
|
4,280.9
|
|
|
Guarantees supporting commodity transactions of subsidiaries
|
|
|
149.9
|
|
|
|
6.1
|
|
|
|
61.9
|
|
|
|
—
|
|
|
|
—
|
|
|
|
80.0
|
|
|
|
1.9
|
|
|
Accounts receivable securitization
|
|
|
193.2
|
|
|
|
193.2
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
Lines of credit
|
|
|
1,040.8
|
|
|
|
1,040.8
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
Letters of credit
|
|
|
37.4
|
|
|
|
0.4
|
|
|
|
35.8
|
|
|
|
0.2
|
|
|
|
1.0
|
|
|
|
—
|
|
|
|
—
|
|
|
Other guarantees
|
|
|
272.7
|
|
|
|
2.0
|
|
|
|
11.9
|
|
|
|
222.6
|
|
|
|
32.2
|
|
|
|
—
|
|
|
|
4.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total commercial commitments
|
|
$
|
7,564.9
|
|
|
$
|
1,242.5
|
|
|
$
|
424.6
|
|
|
$
|
767.8
|
|
|
$
|
533.2
|
|
|
$
|
310.0
|
|
|
$
|
4,286.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Guarantees of Subsidiaries Debt.
NiSource has guaranteed the payment of $5.9 billion of debt for various wholly-
owned subsidiaries including NiSource Finance and Columbia of Massachusetts, and through a support agreement, Capital Markets, which is reflected on NiSource’s Condensed Consolidated Balance Sheets (unaudited). The subsidiaries are required to
comply with certain covenants under the debt indenture and in the event of default, NiSource would be obligated to pay the debt’s principal and related interest. NiSource does not anticipate its subsidiaries will have any difficulty maintaining
compliance. On October 3, 2011, NiSource executed a Second Supplemental Indenture to the original Columbia of Massachusetts Indenture dated April 1, 1991, for the specific purpose of guarantying Columbia of Massachusetts’ outstanding
medium-term notes.
Guarantees Supporting Commodity Transactions of Subsidiaries.
NiSource has issued guarantees, which support up to
$149.9 million of commodity-related payments for its current subsidiaries involved in energy related activities. These guarantees were provided to counterparties in order to facilitate physical and financial transactions involving natural gas. To
the extent liabilities exist under the commodity-related contracts subject to these guarantees, such liabilities are included in the Condensed Consolidated Balance Sheets (unaudited).
Lines and Letters of Credit and Accounts Receivable Advances.
On March 3, 2011, NiSource Finance entered into a new $1.5 billion four-year revolving credit facility with a syndicate of banks
led by Barclays Capital. The new facility replaced an existing $1.5 billion five-year credit facility which would have expired during July 2011. The new facility has a termination date of March 3, 2015. The purpose of the facility is to fund
ongoing working capital requirements and for general corporate purposes, including supporting liquidity for the Company’s commercial paper program, and provides for the issuance of letters of credit. At September 30, 2011, NiSource had
$615.0 million in borrowings under its four-year revolving credit facility, $425.8 million in commercial paper outstanding and $193.2 million outstanding under its accounts receivable securitization agreements. At September 30, 2011, NiSource
issued stand-by letters of credit of approximately $37.4 million for the benefit of third parties. See Note 16, “Short-Term Borrowings,” for additional information.
Other Guarantees or Obligations.
On June 30, 2008, NiSource sold Whiting Clean Energy to BPAE for $216.7 million which included $16.1 million in working capital. The agreement with BPAE
contains representations, warranties, covenants and closing conditions. NiSource has executed purchase and sales agreement guarantees totaling $220 million which guarantee performance of PEI’s covenants, agreements, obligations, liabilities,
representations and warranties under the agreement with BPAE. No amounts related to the purchase and sales agreement guarantees are reflected in the Condensed Consolidated Balance Sheet (unaudited) as of September 30, 2011. These guarantees are
due to expire in June 2013.
39
|
ITEM 1.
|
FINANCIAL STATEMENTS (continued)
|
N
I
S
OURCE
I
NC
.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)
NiSource has additional purchase and sales agreement guarantees totaling $30.0 million, which guarantee
performance of the seller’s covenants, agreements, obligations, liabilities, representations and warranties under the agreements. No amounts related to the purchase and sales agreement guarantees are reflected in the Condensed Consolidated
Balance Sheets (unaudited). Management believes that the likelihood NiSource would be required to perform or otherwise incur any significant losses associated with any of the aforementioned guarantees is remote.
In connection with Millennium’s refinancing of its long-term debt in August 2010, NiSource provided a letter of credit to Union Bank N.A., as
Collateral Agent for deposit into a debt service reserve account as required under the Deposit and Disbursement Agreement governing the Millennium notes offering. This account is to be drawn upon by the note holders in the event that Millennium is
delinquent on its principal and interest payments. The value of NiSource’s letter of credit represents 47.5% (NiSource’s ownership percentage in Millennium) of the Debt Service Reserve Account requirement, or $16.2 million. The total
exposure for NiSource is $16.2 million. NiSource recorded an accrued liability of $1.5 million related to the inception date fair value of this guarantee as of September 30, 2011.
NiSource has issued other guarantees supporting derivative related payments associated with interest rate swap agreements issued by NiSource Finance, operating leases for many of its subsidiaries and for
other agreements entered into by its current and former subsidiaries.
B.
Other Legal Proceedings.
In the normal course of its
business, NiSource and its subsidiaries have been named as defendants in various legal proceedings. In the opinion of management, the ultimate disposition of these currently asserted claims will not have a material impact on NiSource’s
consolidated financial position.
Tawney, et al. v. Columbia Natural Resources, Inc., Roane County, WV Circuit Court
The Plaintiffs, who are West Virginia landowners, filed a lawsuit in early 2003 in the West Virginia Circuit Court for Roane County, West Virginia (the
“Trial Court”) against CNR alleging that CNR underpaid royalties on gas produced on their land by improperly deducting post-production costs and not paying a fair value for the gas. Plaintiffs also claimed that Defendants fraudulently
concealed the deduction of post-production charges. In December 2004, the Trial Court granted Plaintiffs’ motion to add NiSource and Columbia as Defendants. The Trial Court later certified the case as a class action that includes any person
who, after July 31, 1990, received or is due royalties from CNR (and its predecessors or successors) on lands lying within the boundary of the state of West Virginia. Although NiSource sold CNR in 2003, NiSource remained obligated to manage
this litigation and was responsible for the majority of any damages awarded to Plaintiffs. On January 27, 2007, the jury hearing the case returned a verdict against all Defendants in the amount of $404.3 million inclusive of both compensatory
and punitive damages; Defendants subsequently filed their Petition for Appeal, which was later amended, with the West Virginia Supreme Court of Appeals (the “Appeals Court”), which refused the petition on May 22, 2008. On
August 22, 2008, Defendants filed Petitions to the United States Supreme Court for writ of certiorari. Given the Appeals Court’s earlier refusal of the appeal, NiSource adjusted its reserve in the second quarter of 2008 to reflect the
portion of the Trial Court judgment for which NiSource would be responsible, inclusive of interest. This amount was included in “Legal and environmental reserves,” on the Consolidated Balance Sheet as of December 31, 2008. On
October 24, 2008, the Trial Court preliminarily approved a Settlement Agreement with a total settlement amount of $380 million. The settlement received final approval by the Trial Court on November 22, 2008. NiSource’s share of the
settlement liability is up to $338.8 million. On June 21, 2011, the Court issued the Second Supplemental Order to conclude administration of settlement. The Order sets forth the specific steps to be taken by the Parties to close administration
of the settlement and terminate the settlement fund. As of September 30, 2011, NiSource funded all claims tendered by the Claims Administrator. NiSource does not expect to make additional material payments in this matter.
Environmental Protection Agency Notice of Violation
On September 29, 2004, the EPA issued an NOV to Northern Indiana for alleged violations of the CAA and the Indiana SIP. The NOV alleges that modifications were made to certain boiler units at three
of Northern Indiana’s generating stations between the years 1985 and 1995 without obtaining appropriate air permits for the modifications. Northern Indiana, EPA, Department of Justice, and IDEM have settled the matter.
40
|
ITEM 1.
|
FINANCIAL STATEMENTS (continued)
|
N
I
S
OURCE
I
NC
.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)
The consent decree was entered by the United States District Court for the Northern District of Indiana
on July 22, 2011. The consent decree covers Northern Indiana’s four coal generating stations: Bailly, Michigan City, R.M. Schahfer, and D.H. Mitchell. Northern Indiana must surrender environmental permits for D.H. Mitchell’s
coal-fired boilers, which have not been used to generate power since 2002. At the other generating stations, Northern Indiana must install additional control equipment, including three new SO2 control devices and one new NOx control device. The
consent decree also imposes emissions limits for NOx, SO2, and particulate, and annual tonnage limits for NOx and SO2. In addition, Northern Indiana paid fines of $3.5 million in the third quarter of 2011, must surrender certain NOx and SO2
allowances, and invest $9.5 million in environmental mitigation projects. Northern Indiana estimates the cost of NSR related capital improvements at $570 to $845 million, which will be expended between 2010 and 2018. Northern Indiana believes the
capital costs will likely be recoverable from ratepayers.
C. Environmental Matters.
NiSource operations are subject to environmental statutes and regulations related to air quality, water quality, hazardous waste and solid waste. NiSource
believes that it is in substantial compliance with those environmental regulations currently applicable to its operations and believes that it has all necessary permits to conduct its operations.
It is management’s continued intent to address environmental issues in cooperation with regulatory authorities in such a manner as to achieve
mutually acceptable compliance plans. However, there can be no assurance that fines and penalties will not be incurred. Management expects a significant portion of environmental assessment and remediation costs to be recoverable through rates for
certain NiSource companies.
As of September 30, 2011 and December 31, 2010, NiSource had recorded reserves of approximately
$105.7 million and $79.8 million, respectively, to cover environmental remediation at various sites. NiSource accrues for costs associated with environmental remediation obligations when the incurrence of such costs is probable and the
amounts can be reasonably estimated. The original estimates for cleanup can differ materially from the amount ultimately expended. The actual future expenditures depend on many factors, including currently enacted laws and regulations, the nature
and extent of contamination, and the method of cleanup. These expenditures are not currently estimable at some sites. NiSource periodically adjusts its reserves as information is collected and estimates become more refined.
Air
The actions listed below
could require further reductions in emissions from various emission sources. NiSource will continue to closely monitor developments in these matters.
Climate Change.
Future legislative and regulatory programs could significantly restrict emissions of GHGs or could impose a cost or tax on GHG emissions. Recently, proposals have been developed to
implement Federal, state and regional GHG programs and to create renewable energy standards.
In 2009 and 2010, the United States Congress
considered a number of legislative proposals to regulate GHG emissions. The United States House of Representatives passed a comprehensive climate change bill in June 2009 that would have created a GHG cap-and-trade system and implemented
renewable energy standards. Bills on the same topics were introduced in the Senate in 2009 and 2010, but failed to garner enough support to pass.
If a Federal or state comprehensive climate change bill were to be enacted into law, the impact on NiSource’s financial performance would depend on a number of factors, including the overall level of
required GHG reductions, the renewable energy targets, the degree to which offsets may be used for compliance, the amount of recovery allowed from customers, and the extent to which NiSource would be entitled to receive CO 2 allowances at no cost.
Comprehensive Federal or state GHG regulation could result in additional expense or compliance costs that may not be fully recoverable from customers and could materially impact NiSource’s financial results.
National Ambient Air Quality Standards
. The CAA requires EPA to set national air quality standards for particulate matter and five other
pollutants (the NAAQS) considered harmful to public health and the environment. Periodically EPA imposes new or modifies existing NAAQS. States that contain areas that do not meet the new or revised standards must take steps to maintain or achieve
compliance with the standards. These steps could include additional pollution controls on boilers, engines, turbines, and other facilities owned by electric generation, gas distribution, and gas transmission operations.
41
|
ITEM 1.
|
FINANCIAL STATEMENTS (continued)
|
N
I
S
OURCE
I
NC
.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)
The following NAAQS were recently added or modified:
Particulate Matter:
In 2006, the EPA issued revisions to the NAAQS for particulate matter. The final rule (1) increased the stringency of the
current fine particulate (PM2.5) standard, (2) added a new standard for inhalable coarse particulate (particulate matter between 10 and 2.5 microns in diameter), and (3) revoked the annual standards for coarse particulate (PM10) while
retaining the 24-hour PM10 standards. These actions were challenged in a case before the DC Court of Appeals,
American Farm Bureau Federation et al. v. EPA.
In 2009, the appeals court granted portions of the plaintiffs’ petitions
challenging the fine particulate standards but denied portions of the petitions challenging the standards for coarse particulate. State plans implementing the new standard for inhalable coarse particulate and the modified 24-hour standard for fine
particulate are expected in 2012. The annual and secondary PM2.5 standards have been remanded to the EPA for reconsideration.
Ozone (eight
hour):
On September 2, 2011, the EPA announced it would implement its 2008 eight-hour ozone NAAQS rather than tightening the standard in 2012. The EPA will review, and possibly revise, the standard in 2013 consistent with CAA requirements.
Northern Indiana will continue to monitor this matter and cannot estimate the impact of any new rules at this time.
Nitrogen Dioxide
(NO2):
The EPA revised the NO2 NAAQS by adding a one-hour standard while retaining the annual standard. The new standard could impact some NiSource combustion sources. EPA will designate areas that do not meet the new standard beginning in 2012.
States with areas that do not meet the standard will need to develop rules to bring areas into compliance within five years of designation. Additionally, under certain permitting circumstances emissions from some existing NiSource combustion sources
may need to be assessed and compared to the revised NO2 standards before areas are designated. Petitions challenging the rule have been filed by various parties. NiSource will continue to monitor this matter and cannot estimate the impact of the
rules at this time.
National Emission Standard for Hazardous Air Pollutants.
On August 20, 2010, the EPA revised national
emission standards for hazardous air pollutants for certain stationary reciprocating internal combustion engines. Compliance requirements vary by engine type and will generally be required within three years. NiSource is continuing its evaluation of
the cost impacts of the final rule and estimates the cost of compliance to be $20 to $25 million.
Waste
NiSource subsidiaries are potentially responsible parties at waste disposal sites under the CERCLA (commonly known as Superfund) and similar state laws.
Additionally, a program has been instituted to identify and investigate former MGP sites where Gas Distribution Operations subsidiaries or predecessors may have liability. The program has identified up to 84 such sites and initial investigations
have been conducted at 56 sites. Follow-up investigation activities have been completed or are in progress at 50 sites and remedial measures have been implemented or completed at 37 sites. Remedial actions at many of these sites are being overseen
by state or federal environmental agencies through consent agreements or voluntary remediation agreements. The final costs of cleanup have not yet been determined. In the fourth quarter of 2011, NiSource plans to evaluate of all such sites for which
remediation is not yet complete. As the evaluations, site investigations and cleanups proceed, reserves could increase or otherwise be adjusted to reflect new information.
Additional Issues Related to Individual Business Segments
The sections above
describe various regulatory actions that affect Gas Transmission and Storage Operations, Electric Operations, and certain other discontinued operations for which we have retained a liability. Specific information is provided below.
42
|
ITEM 1.
|
FINANCIAL STATEMENTS (continued)
|
N
I
S
OURCE
I
NC
.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)
Gas Transmission and Storage Operations.
Waste
Columbia Transmission
continues to conduct characterization and remediation activities at specific sites under a 1995 AOC (subsequently modified in 1996 and 2007). The 1995 AOC originally covered 245 major facilities, approximately 13,000 liquid removal points,
approximately 2,200 mercury measurement stations and about 3,700 storage well locations. As a result of the 2007 amendment, approximately 50 facilities remain subject to the terms of the AOC. During the third quarter of 2011, Columbia Transmission
completed a study to estimate its future remediation requirements related to the AOC. Columbia Transmission accordingly increased its liability for estimated remediation costs by $25.6 million. The total liability at Columbia Transmission related to
the facilities subject to remediation was $33.7 million and $9.5 million at September 30, 2011 and December 31, 2010, respectively. The liability represents Columbia Transmission’s best estimate of the cost to remediate the facilities
or manage the sites until retirement. A Response Action Work Plan consistent with this estimate was submitted to the EPA in October 2011. Remediation costs are estimated based on the information available, applicable remediation standards, and
experience with similar facilities. Columbia Transmission expects that the remediation for these facilities will be completed in 2015.
One of
the facilities subject to the 1995 AOC is the Majorsville Operations Center, which was remediated under an EPA approved Remedial Action Work Plan in the summer of 2008. Pursuant to the Remedial Action Work Plan, Columbia Transmission completed a
project that stabilized residual oil contained in soils at the site and in sediments in an adjacent stream. Columbia Transmission continues to monitor the site subject to EPA oversight. On April 23, 2009, PADEP issued an NOV to Columbia
Transmission, alleging that the remediation did not fully address the contamination. The NOV asserts violations of the Pennsylvania Clean Streams Law and the Pennsylvania Solid Waste Management Act and includes a proposed penalty of $1 million.
Columbia Transmission is unable to estimate the likelihood or cost of potential penalties or additional remediation at this time.
Electric Operations.
Air
Northern Indiana expects to become subject to a number of new air-quality mandates in the next several years. These mandates may
require Northern Indiana to make capital improvements to its electric generating stations. The cost of capital improvements is estimated to be $620 to $995 million. This figure includes additional capital improvements associated with the Cross-State
Air Pollution Rule (CSAPR) and the proposed Utility Hazardous Air Pollutants Rule. Northern Indiana believes that the capital costs will likely be recoverable from ratepayers.
Sulfur dioxide:
On December 8, 2009, the EPA revised the SO2 NAAQS by adopting a new 1-hour primary NAAQS for sulfur dioxide (SO2). EPA expects to designate areas that do not meet the new
standard by mid-2012. States with such areas would have until 2014 to develop attainment plans with compliance required by 2017. Northern Indiana will continue to monitor developments in these matters but does not anticipate a material impact.
Clean Air Interstate Rule (CAIR) / Transport Rule/ Cross-State Air Pollution Rule:
On July 6, 2011, the EPA announced its
replacement for the 2005 CAIR to reduce the interstate transport of fine particulate matter and ozone. The CSAPR reduces overall emissions of SO2 and NOx by setting state-wide caps on power plant emissions. The CSAPR limits emissions, including
Northern Indiana’s, with restricted emission allowance trading programs beginning in 2012. Emission allowances issued under the CAIR program will be eliminated as of January 1, 2012. Northern Indiana utilized the inventory model in
accounting for emission allowances issued under the CAIR program whereby these allowances were recognized at zero cost upon receipt from the EPA. Northern Indiana believes its current multi-pollutant compliance plan and NOV capital investments will
allow Northern Indiana to meet the emission requirements of CSAPR in 2012.
Utility Hazardous Air Pollutants:
On
February 8, 2008, the United States Court of Appeals for the District of Columbia Circuit vacated two EPA rules that are the basis for the Indiana Air Pollution Control Board’s Clean Air Mercury Rule (CAMR) that established utility mercury
emission limits in two phases (2010 and 2018) and a cap-and-trade program to meet those limits. In response to the vacatur, the EPA is pursuing a new Section 112 rulemaking to establish MACT standards for electric utilities. EPA announced its
proposal on March 16, 2011 and intends to finalize the rule by November 2011. Northern Indiana will continue its evaluation and monitoring of this matter.
43
|
ITEM 1.
|
FINANCIAL STATEMENTS (continued)
|
N
I
S
OURCE
I
NC
.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)
New Source Review:
On September 29, 2004, the EPA issued an NOV to Northern Indiana for
alleged violations of the CAA and the Indiana SIP. The NOV alleges that modifications were made to certain boiler units at three of Northern Indiana’s generating stations between the years 1985 and 1995 without obtaining appropriate air permits
for the modifications. Northern Indiana, EPA, the Department of Justice, and IDEM have settled the matter.
The consent decree was entered by
the United States District Court for the Northern District of Indiana on July 22, 2011. The consent decree covers Northern Indiana’s four coal generating stations: Bailly, Michigan City, R.M. Schahfer, and D.H. Mitchell. Northern Indiana
must surrender environmental permits for D.H. Mitchell’s coal-fired boilers, which have not been used to generate power since 2002. At the other generating stations, Northern Indiana must install additional control equipment, including three
new scrubbers to control sulfur dioxide (“SO2”) and one new nitrogen oxide (“NOx”) control device. The consent decree also imposes emissions limits for NOx, SO2, and particulate matter, and annual tonnage limits for NOx and SO2.
In addition, Northern Indiana paid fines of $3.5 million in the third quarter of 2011, must surrender certain NOx and SO2 allowances, and invest $9.5 million in environmental mitigation projects. Northern Indiana is estimating the cost of NSR
related capital improvements at $570 to $845 million which will be expended between 2010 and 2018. Northern Indiana believes the capital costs will likely be recoverable from ratepayers.
Water
The Phase II Rule of the Clean Water Act Section 316(b), which requires
all large existing steam electric generating stations to meet certain performance standards to reduce the effects on aquatic organisms at their cooling water intake structures, became effective on September 7, 2004. Under this rule, stations
will either have to demonstrate that the performance of their existing fish protection systems meet the new standards or develop new systems, such as a closed-cycle cooling tower. Various court challenges and EPA responses ensued. The EPA announced
a proposed rule and is obligated to finalize a rule in 2012. Northern Indiana will continue to monitor this matter but cannot estimate the cost of compliance at this time.
Waste
On March 31, 2005, the EPA and Northern Indiana entered into an AOC
under the authority of Section 3008(h) of the RCRA for the Bailly Station. The order requires Northern Indiana to identify the nature and extent of releases of hazardous waste and hazardous constituents from the facility. Northern Indiana must
also remediate any release of hazardous constituents that present an unacceptable risk to human health or the environment. The process to complete investigation and select appropriate remediation activities is ongoing. The final costs of cleanup
could change based on EPA review.
On June 21, 2010, EPA published a proposed rule for coal combustion residuals through the RCRA. The
proposal outlines multiple regulatory approaches that EPA is considering. These proposed regulations could negatively affect Northern Indiana’s ongoing byproduct reuse programs and would impose additional requirements on its management of coal
combustion residuals. Northern Indiana will continue to monitor developments in this matter but cannot estimate the cost of compliance at this time.
Other Operations.
Waste
NiSource affiliates have retained environmental liabilities, including cleanup liabilities associated with some of their former operations. Four sites are
associated with former propane operations and ten sites associated with former petroleum operations. At one of those sites, an AOC has been signed with EPA to address petroleum residue in soil and groundwater.
44
|
ITEM 1.
|
FINANCIAL STATEMENTS (continued)
|
N
I
S
OURCE
I
NC
.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)
|
19.
|
Accumulated Other Comprehensive Loss
|
The following table displays the components of Accumulated Other Comprehensive Loss.
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
|
September 30, 2011
|
|
|
December 31, 2010
|
|
|
Other comprehensive income (loss), before tax:
|
|
|
|
|
|
|
|
|
|
Unrealized gains on securities
|
|
$
|
6.2
|
|
|
$
|
6.1
|
|
|
Tax expense on unrealized gains on securities
|
|
|
(2.4
|
)
|
|
|
(2.4
|
)
|
|
Unrealized losses on cash flow hedges
|
|
|
(52.9
|
)
|
|
|
(56.4
|
)
|
|
Tax benefit on unrealized losses on cash flow hedges
|
|
|
20.2
|
|
|
|
21.6
|
|
|
Unrecognized pension and OPEB costs
|
|
|
(41.1
|
)
|
|
|
(43.3
|
)
|
|
Tax benefit on unrecognized pension and OPEB costs
|
|
|
15.6
|
|
|
|
16.5
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Accumulated Other Comprehensive Loss, net of taxes
|
|
$
|
(54.4
|
)
|
|
$
|
(57.9
|
)
|
|
|
|
|
|
|
|
|
|
|
Equity Investment
During 2008, Millennium, in which Columbia Transmission has an equity investment, entered into three interest rate swap agreements with a notional amount totaling $420.0 million with seven counterparties.
During August 2010, Millennium completed the refinancing of its long-term debt, securing permanent fixed-rate financing through the private placement issuance of two tranches of notes totaling $725.0 million: $375.0 million at 5.33% due
June 30, 2027, and $350.0 million at 6.00% due June 30, 2032. Upon the issuance of these notes, Millennium repaid all outstanding borrowings under the credit agreement, terminated the sponsor guarantee, and cash settled the interest rate
hedges. These interest rate swap derivatives were accounted for as cash flow hedges by Millennium. As Millennium is an equity method investment, NiSource is required to recognize a proportional share of Millennium’s OCI. Millennium is
amortizing the unrealized loss related to these terminated interest rate swaps into earnings using the effective interest method through interest expense as interest payments are made. NiSource records its proportionate share of the amortization as
Equity Earnings in Unconsolidated Affiliates at the Condensed Statements of Consolidated Income (unaudited). NiSource’s proportionate share of the remaining unrealized loss, net of tax, was $20.4 million as of September 30, 2011 and $21.1
million as of December 31, 2010, which are included in unrealized losses on cash flow hedges above.
|
20.
|
Business Segment Information
|
Operating segments are components of an enterprise for which separate financial information is available and evaluated regularly by the
chief operating decision maker in deciding how to allocate resources and assess performance. The NiSource Chief Executive Officer is the chief operating decision maker.
At September 30, 2011, NiSource’s operations are divided into three primary business segments. The Gas Distribution Operations segment provides natural gas service and transportation for
residential, commercial and industrial customers in Ohio, Pennsylvania, Virginia, Kentucky, Maryland, Indiana and Massachusetts. The Gas Transmission and Storage Operations segment offers gas transportation and storage services for LDCs, marketers
and industrial and commercial customers located in northeastern, mid-Atlantic, midwestern and southern states. The Electric Operations segment provides electric service in 20 counties in the northern part of Indiana.
45
|
ITEM 1.
|
FINANCIAL STATEMENTS (continued)
|
N
I
S
OURCE
I
NC
.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)
The following table provides information about business segments. NiSource uses operating income as its
primary measurement for each of the reported segments and makes decisions on finance, dividends and taxes at the corporate level on a consolidated basis. Segment revenues include intersegment sales to affiliated subsidiaries, which are eliminated in
consolidation. Affiliated sales are recognized on the basis of prevailing market, regulated prices or at levels provided for under contractual agreements. Operating income is derived from revenues and expenses directly associated with each segment.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
September 30,
|
|
|
Nine Months Ended
September 30,
|
|
|
(in millions)
|
|
2011
|
|
|
2010
|
|
|
2011
|
|
|
2010
|
|
|
REVENUES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas Distribution Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unaffiliated
|
|
$
|
418.2
|
|
|
$
|
428.8
|
|
|
$
|
2,632.7
|
|
|
$
|
2,526.2
|
|
|
Intersegment
|
|
|
0.2
|
|
|
|
1.3
|
|
|
|
1.1
|
|
|
|
9.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
418.4
|
|
|
|
430.1
|
|
|
|
2,633.8
|
|
|
|
2,536.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas Transmission and Storage Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unaffiliated
|
|
|
202.4
|
|
|
|
185.7
|
|
|
|
616.3
|
|
|
|
565.8
|
|
|
Intersegment
|
|
|
31.1
|
|
|
|
31.8
|
|
|
|
106.1
|
|
|
|
125.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
233.5
|
|
|
|
217.5
|
|
|
|
722.4
|
|
|
|
691.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unaffiliated
|
|
|
406.6
|
|
|
|
399.5
|
|
|
|
1,106.2
|
|
|
|
1,061.6
|
|
|
Intersegment
|
|
|
0.2
|
|
|
|
0.1
|
|
|
|
0.6
|
|
|
|
0.5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
406.8
|
|
|
|
399.6
|
|
|
|
1,106.8
|
|
|
|
1,062.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Corporate and Other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unaffiliated
|
|
|
41.5
|
|
|
|
124.1
|
|
|
|
174.0
|
|
|
|
514.3
|
|
|
Intersegment
|
|
|
113.2
|
|
|
|
109.6
|
|
|
|
345.9
|
|
|
|
319.5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
154.7
|
|
|
|
233.7
|
|
|
|
519.9
|
|
|
|
833.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Eliminations
|
|
|
(144.7
|
)
|
|
|
(142.8
|
)
|
|
|
(453.7
|
)
|
|
|
(455.4
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated Revenues
|
|
$
|
1,068.7
|
|
|
$
|
1,138.1
|
|
|
$
|
4,529.2
|
|
|
$
|
4,667.9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income (Loss)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas Distribution Operations
|
|
$
|
7.9
|
|
|
$
|
(42.5
|
)
|
|
$
|
295.9
|
|
|
$
|
211.1
|
|
|
Gas Transmission and Storage Operations
|
|
|
68.2
|
|
|
|
76.2
|
|
|
|
271.4
|
|
|
|
277.0
|
|
|
Electric Operations
|
|
|
78.8
|
|
|
|
95.9
|
|
|
|
161.8
|
|
|
|
190.6
|
|
|
Corporate and Other
|
|
|
(7.4
|
)
|
|
|
(6.3
|
)
|
|
|
(19.1
|
)
|
|
|
(12.8
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated Operating Income
|
|
$
|
147.5
|
|
|
$
|
123.3
|
|
|
$
|
710.0
|
|
|
$
|
665.9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
46
|
ITEM 1.
|
FINANCIAL STATEMENTS (continued)
|
N
I
S
OURCE
I
NC
.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)
|
21.
|
Supplemental Cash Flow Information
|
The following table provides additional information regarding NiSource’s Condensed Statements of Consolidated Cash Flows
(unaudited) for the nine months ended September 30, 2011 and 2010:
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30,
(in millions)
|
|
2011
|
|
|
2010
|
|
|
Supplemental Disclosures of Cash Flow Information
|
|
|
|
|
|
|
|
|
|
Non-cash transactions:
|
|
|
|
|
|
|
|
|
|
Capital expenditures included in current liabilities
|
|
$
|
92.5
|
|
|
$
|
74.3
|
|
|
Change in equity investments related to unrealized (losses) gains
|
|
|
—
|
|
|
|
24.5
|
|
|
Stock issuance to employee saving plans
|
|
|
17.2
|
|
|
|
14.2
|
|
|
Schedule of interest and income taxes paid:
|
|
|
|
|
|
|
|
|
|
Cash paid for interest, net of interest capitalized amounts
|
|
$
|
319.9
|
|
|
$
|
326.6
|
|
|
Cash paid for income taxes
|
|
|
6.8
|
|
|
|
38.4
|
|
|
|
|
|
|
|
|
|
|
|
47
