Regulatory Matters

Gas Distribution Operations Regulatory Matters

Significant Rate Developments. 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 instead of LIFO, Northern Indiana’s historical method. On August 31, 2011, the IURC approved the settlement and Northern Indiana transitioned to WACOG accounting methodology beginning January 1, 2012.

On December 28, 2011, the IURC issued an order approving Northern Indiana's portfolio of gas energy efficiency programs and authorizing the recovery of program costs associated with those programs through semi-annual tracker filings.

On March 15, 2012, the IURC approved a settlement agreement with Northern Indiana and all participating parties to extend its product and services contained in its current gas ARP indefinitely.

On May 19, 2008, Columbia of Ohio filed an application with the PUCO to defer environmental remediation expenses. On September 24, 2008, the PUCO approved the application. Each year Columbia of Ohio must report on the amounts deferred during the previous year. On December 6, 2011, Columbia of Ohio filed its annual deferral report for the twelve months ended November 30, 2011. PUCO Staff filed its Comments on January 5, 2012, and objected to deferral of costs for a Toledo remediation project. Columbia of Ohio capitalized $2.4 million in costs associated with the Toledo project which will be proposed for recovery as a component of future rate base.

On September 14, 2012, Columbia of Massachusetts filed its Peak Period Gas Adjustment Factor, Pension Expense Factor, Residential Assistance Adjustment Factor and Peak Period Revenue Decoupling Factor, each with a proposed effective date of November 1, 2012.

On April 13, 2012, Columbia of Massachusetts submitted a filing with the Massachusetts DPU requesting an annual revenue requirement increase of $29.2 million. Columbia of Massachusetts filed using a historic test year ended December 31, 2011. Additionally, Columbia of Massachusetts proposed rate-year, rate base treatment, as well as modification to the TIRF. The rate-year, rate base treatment has been proposed to reduce the impact of regulatory lag. The Massachusetts DPU issued an order on November 1, 2012 approving an annual revenue increase of $7.8 million, effective November 1, 2012. Columbia of Massachusetts is continuing to evaluate the order.

On February 14, 2012, Columbia of Ohio held its first standard choice offer auction which resulted in a retail price adjustment of $1.53 per Mcf. On February 14, 2012, the PUCO issued an entry that approved the results of the auction with the new retail price adjustment effective April 1, 2012. As a result of the implementation of the standard choice offer, Columbia of Ohio reports lower gross revenues and lower cost of sales. There is no impact on net revenues.

On October 3, 2011, Columbia of Ohio filed an application with the 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. Interested parties filed comments on Columbia of Ohio’s application by February 17, 2012. Columbia of Ohio filed Reply Comments on February 27, 2012. Columbia of Ohio filed supplemental reply comments on July 26, 2012 and Staff filed sur-reply comments on August 15, 2012. On August 29, 2012, the Commission issued a Finding and Order in which it approved Columbia of Ohio's application subject to certain modifications contained therein and granted the appropriate accounting as modified by the Finding and Order. On September 28, 2012, the Office of the Ohio Consumers' Counsel filed an application for rehearing in which it contested the cap mechanism set forth in the PUCO Order. Columbia of Ohio filed a memorandum contra the application for rehearing on October 8, 2012. The PUCO denied the Ohio Consumer's Counsel's application for rehearing on October 24, 2012.

On November 30, 2011, 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, 2012, 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 $27.9 million. On April 10, 2012, Columbia of Ohio reached a settlement with parties allowing for an increase in annual revenue from the Riders of approximately $27 million. On April 25, 2012, the PUCO issued an Entry that provided for approval of the settlement with new rates effective April 29, 2012.

On December 9, 2011, Columbia of Ohio filed a Notice of Intent to file an application to extend its Infrastructure Replacement Program. Columbia of Ohio filed an amended Notice of Intent and an amended Motion for Waiver on March 5, 2012. On May 8, 2012, Columbia of Ohio filed its application and supporting exhibits and testimony. On September 26, 2012 the parties filed a Joint Stipulation and Recommendation that provided for the extension of Columbia of Ohio's IRP process for an additional five years and settlement of all issues.

On March 30, 2012, Columbia of Ohio filed an application with the PUCO that requests authority to establish a regulatory asset for corporate OPEB expenses allocated to Columbia of Ohio. The amount that Columbia of Ohio sought authority to defer is $2.1 million. By Entry dated July 18, 2012, the PUCO approved the application.

On April 19, 2012, Columbia of Ohio filed an application that requests authority to increase its uncollectible expense rider rate in order to generate an additional $14.6 million in annual revenue in order to offset anticipated increases in uncollectible expenses. On May 30, 2012, the PUCO issued an Entry that provided for approval of Columbia of Ohio’s April 19, 2012 application for adjustment of its uncollectible expense rider with the new rate effective May 30, 2012.

On April 30, 2012, Columbia of Ohio filed an application to adjust its Interim, Emergency and Temporary Percentage of Income Payment Plan Rider (“PIPP”) from $0.1274 per Mcf to $0.0294 per Mcf to provide for the passback of an overrecovery of approximately $10.9 million and the recovery of its annual change in PIPP arrears. The PUCO approved the application and the revised PIPP Rider went into effect for the first billing unit of July 2012.

In 2009, the PUCO granted Columbia of Ohio an exemption from the regulation of natural gas commodity prices. The 2009 Order also shielded Columbia of Ohio's capacity contract levels from prudency audits for three years, and approved a mechanism for sharing off-system sales and capacity release revenues for three years. On October 4, 2012, Columbia of Ohio and other parties filed a non-unanimous stipulation that would extend key provisions of the 2009 agreement for an additional five years.

On April 12, 2012, Columbia of Virginia filed an application with the VSCC for approval to amend and extend its CARE Plan for an additional three year period beginning January 1, 2013. The Amended CARE Plan includes incentives for residential and small general service customers to actively pursue conservation and energy efficiency measures, a surcharge designed to recover the costs of such measures on a real-time basis, and a performance-based incentive for the delivery of conservation and energy efficiency benefits. The Amended CARE Plan also includes a rate decoupling mechanism designed to mitigate the impact of declining customer usage. On April 27, 2012, the VSCC issued a procedural order inviting comments from the VSCC Staff and interested persons. The VSCC Staff and Columbia of Virginia reached a comprehensive settlement of the issues in the case and filed a Joint Motion requesting VSCC approval of the settlement terms on July 13, 2012. On August 6, 2012, the VSCC issued a Final Order approving the settlement and extending the CARE Plan through 2015.

On September 28, 2012, Columbia of Pennsylvania filed a base rate case with the Pennsylvania PUC, seeking a revenue increase of approximately $77.3 million annually, and seeking to implement a Revenue Normalization Adjustment for its residential class that would mitigate revenue volatility associated with usage based rates. Columbia of Pennsylvania is the first utility in Pennsylvania to seek Pennsylvania PUC approval to design rates to recover costs that are projected to be incurred after the implementation of those new rates, as recently authorized by the Pennsylvania General Assembly with the passage of Act 11 of 2012. Accordingly, Columbia of Pennsylvania is seeking to implement rates in July 2013 under which Columbia of Pennsylvania would immediately begin to recover costs that are projected for the twelve-month period ending June 30, 2014. Columbia of Pennsylvania expects that the Pennsylvania PUC will issue an order in the second quarter of 2013, with rates going into effect in the third quarter of 2013.

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 Transmission Customer Settlement. Columbia Transmission reached an agreement with a majority of its customers and filed a customer settlement in support of its comprehensive interstate natural gas pipeline modernization program with the FERC on September 4, 2012. Only one party, the Public Service Commission of Maryland, filed a (limited) protest to the Settlement. On October 4, 2012, Columbia Transmission filed its reply addressing the issues raised by the Public Service Commission of Maryland. The parties have asked the FERC to approve the settlement before the end of 2012. Columbia Transmission expects to invest approximately $1.5 billion over a five-year period to modernize its system to improve system integrity and enhance service reliability and flexibility. The settlement with firm customers includes an initial five-year term with provisions for potential extensions thereafter. The settlement proposes initial refunds totaling $50.0 million, adjustments to base rates and depreciation, and a Capital Cost Recovery Mechanism (CCRM), a tracker mechanism that provides recovery and return on the $300.0 million annual investment. Additional details of the settlement are as follows:

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An immediate $50.0 million refund to max rate contract customers to be paid in two installments of $25.0 million. The first payment is expected to be paid in the next monthly billing cycle that is at least 15 days after Columbia Transmission receives a final FERC order approving the settlement. The second installment is expected to be paid the later of January 31, 2013, or in the next monthly billing cycle that is at least 15 days after a final FERC order.


•	Base rate reductions, the first retroactive to January 1, 2012, which equates to approximately $35 million in revenues annually and the second beginning January 1, 2014, which equates to approximately $25.0 million in revenues annually thereafter;

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The CCRM will allow Columbia Transmission to recover, through an additive capital demand rate, its revenue requirement for capital investments made under Columbia Transmission's long-term plan to modernize its interstate transmission system. The mechanism provides for a 14% revenue requirement with a portion designated as a recovery of increased taxes other than income taxes. The additive demand rate is earned on costs associated with projects placed into service by October 31 each year. The CCRM will give Columbia Transmission the opportunity to recover its revenue requirement associated with $300.0 million annual investment in the modernization program, while maintaining competitive rates for its shippers. The CCRM recovers the revenue requirement associated with qualifying modernization costs that Columbia Transmission incurs after satisfying the requirement associated with $100.0 million in annual capital maintenance expenditure. The CCRM applies to Columbia Transmission's transportation shippers. The CCRM will not exceed $300.0 million per year, subject to a 15% annual tolerance and a total cap of $1.5 billion for the entire five-year Initial Term.


•	Depreciation rate reduction to 1.5% and elimination of negative salvage rate, retroactive to January 1, 2012, which equates to approximately $35 million in reduced annual expenses that is linked to the base rate reduction above;


•	A revenue sharing mechanism pursuant to which Columbia Transmission will share 75% of specified revenues earned in excess of an annual threshold;


•	A moratorium through January 31, 2018 on changes to Columbia Transmission's reduced transportation base rates; and


•	A commitment from Columbia Transmission that it will file a general NGA Section 4(e) rate application to be effective no later than February 1, 2019

Columbia Transmission petitioned for FERC approval of the settlement as filed preferably no later than December 1, 2012, to allow the parties to the agreement to begin receiving the benefits of the settlement without delay. On September 30, 2012, Columbia Transmission recorded the $50.0 million refund obligation and a pro rata share of the retroactive base rate reduction, which amounted to $22.9 million, and the pro rata reduction in depreciation expense that amounted to $24.9 million.

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. 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 Administrative Law Judge certified the settlement agreement as uncontested to the FERC with severance of the contesting party from the settlement. On November 1, 2011, Columbia Gulf began billing interim rates to customers. On December 1, 2011, the FERC issued an order approving the settlement without change. The key elements of the settlement, which was a “black box agreement”, include: (1) increased base rate to $0.1520 per Dth and (2) establishing a postage stamp rate design. No protests to the order were filed and therefore, pursuant to the Settlement, the order became final on January 1, 2012 which made the settlement effective on February 1, 2012. On February 2, 2012, the Presiding Administrative Law Judge issued an initial decision granting a joint motion terminating the remaining litigation with the contesting party and allowing it to become a settling party. The FERC issued an order on March 15, 2012, affirming the initial decision, which terminated the remaining litigation with the contesting party. Refunds of approximately $16 million, accrued as of December 31, 2011, were disbursed to settling parties in March 2012.

Electric Operations Regulatory Matters

Significant Rate Developments. On July 18, 2011, Northern Indiana filed with the IURC a settlement in its 2010 Electric Rate Case with the OUCC, Northern Indiana Industrial Group, NLMK Indiana and Indiana Municipal Utilities Group. The settlement agreement limited 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 also resolves all pending issues related to compliance with the August 25, 2010 Order in the 2008 Electric Rate Case. On December 21, 2011, the IURC issued an Order approving the Settlement Agreement as filed, and new electric base rates became effective on December 27, 2011. On January 20, 2012, the City of Hammond filed an appeal of the IURC’s December 21, 2011 Order and subsequently, on June 4, 2012, filed a motion to dismiss the appeal. The motion was granted on June 27, 2012.

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 provided that certain electric customers of Northern Indiana would receive bill credits of approximately $55.1 million each year. The credits continued at approximately the same annual level and per the same methodology, until the IURC approval and implementation of new customer rates, which occurred on December 27, 2011. The recovery of the final reconciliation of the credits will be completed in the fourth quarter of 2012. Credits amounting to $(4.7) million and $38.6 million were recognized for electric customers for the first nine months of 2012 and 2011, 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.

On July 27, 2011, the IURC issued an order approving Northern Indiana's portfolio of electric energy efficiency programs authorizing the recovery of program costs and on August 8, 2012, approved recovery of lost margins associated with those programs through semi-annual tracker filings.

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.

As part of a multi-state effort to strengthen the electric transmission system serving the Midwest, Northern Indiana anticipates making investments in two projects, a 100-mile, 345 kV transmission project and a 66-mile, 765 kV transmission project in Indiana. These projects are reviewed and authorized by the MISO and are scheduled to be in service during the latter part of the decade. On July 19, 2012, the FERC issued an order approving construction work in progress in rate base and abandoned plant cost recovery requested by Northern Indiana, for the 100-mile, 345 kV transmission project. On September 12, 2012, Northern Indiana filed with the FERC for construction work in progress in rate base and abandoned plant cost recovery for the 66-mile, 765 kV project. On October 16, 2012, Northern Indiana filed for FERC approval of forward looking rates, which would allow for the more timely recovery of Northern Indiana's investment in transmission assets. On February 8, 2012, Pioneer Transmission, LLC filed a complaint with the FERC, seeking to obtain 100 percent of the investment rights in this second project. In response on July 19, 2012, the FERC issued an order which denied the complaint filed by Pioneer Transmission, LLC and affirmed that Northern Indiana and Duke Energy are the appropriate parties to share equally in the development of the 66-mile 765 kV transmission project extending between Reynolds, Indiana and Greentown, Indiana. On August 20, 2012, Pioneer Transmission, LLC, Northern Indiana, and MISO filed a settlement agreement resolving the Pioneer complaint case establishing Northern Indiana's right to develop 50 percent of the project. The Settlement is currently pending at the FERC.

In the Order issued on August 25, 2010, the IURC approved a semi-annual 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 semi-annual purchase capacity tracker referred to as the RA Tracker. Similar treatment was requested in the 2010 Electric Rate Case filing and approved in the December 21, 2011 Order approving the Settlement Agreement. The implementation of such trackers coincides with the implementation of new customer rates. On August 22, 2012, the IURC issued an order authorizing Northern Indiana to retain certain revenues under MISO Schedule 26-A to support investments in Northern Indiana's Multi-Value Projects under MISO's 2011 transmission expansion plan.

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 costs of power generated by a hypothetical natural gas fired unit using gas purchased and delivered to Northern Indiana. During the first nine months of 2012 and 2011, there were no non-recoverable purchased power costs.

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 and EPA Regulations. Refer to Note 18-C, “Environmental Matters,” for additional information. This petition has since been trifurcated into three separate phases. On December 28, 2011, February 15, 2012, and September 5, 2012, the IURC issued orders approving estimated project costs of approximately $800 million and granting the requested ratemaking and accounting relief associated with these projects through annual and semi-annual tracker filings.