2.2.0.7 false Regulatory Matters 0208 - Disclosure - Regulatory Matters true false false false 1 USD false false USD Standard http://www.xbrl.org/2003/iso4217 USD iso4217 0 USDEPS Divide http://www.xbrl.org/2003/iso4217 USD iso4217 http://www.xbrl.org/2003/instance shares xbrli 0 Shares Standard http://www.xbrl.org/2003/instance shares xbrli 0 $ 2 Regulatory Matters [Abstract] 0 us-gaap_RegulatoryAssetsAndLiabilitiesDisclosureAbstract us-gaap true na duration No definition available. false false false false false true false false false false false false 1 false false false false 0 0 false false false xbrli:stringItemType string No definition available. false 3 Regulatory Matters 1 us-gaap_PublicUtilitiesDisclosureTextBlock us-gaap true na duration No definition available. false false false false false false false false false false false verboselabel false 1 false false false false 0 0   <div style="font-family: 'Times New Roman',Times,serif"> <div align="justify" style="font-size: 10pt; margin-top: 12pt"><b>8.</b>            <b>Regulatory Matters</b> </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt"><u>Gas Distribution Operations Regulatory Matters</u> </div> <div align="justify" style="font-size: 10pt; margin-top: 12pt"><b><i>Significant Rate Developments.</i></b> </div> <div align="justify" style="font-size: 10pt; margin-top: 0pt">On May 3, 2010, Northern Indiana filed a natural gas rate case with the IURC, the first since 1987, proposing enhanced low income assistance and extending energy-efficiency programs for customers, as well as a change in rate design. Among other things, the filing also proposes a mechanism for the deferral of certain pension and other postretirement costs and for adjustments to depreciation rates and expense. In a Prehearing Conference Order issued June 16, 2010, the IURC established the procedural schedule. Evidentiary hearings are scheduled to begin on November 1, 2010. New rates are targeted to be effective by early 2011 or sooner. </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt">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 seeks a Weather Normalization Adjustment, cost recovery of certain gas related items through its Purchased Gas Adjustment mechanism rather than base rates, and forward looking accounting adjustments predicted to occur during the rate year ending December 31, 2011. New rates are scheduled to become effective January 1, 2011. </div>   </div>  <div style="font-family: 'Times New Roman',Times,serif"> <div align="justify" style="font-size: 10pt; margin-top: 0pt"> <u> </u> <u> </u> </div> <div align="justify" style="font-size: 10pt; margin-top: 0pt"> <font style="font-variant: small-caps"> <b> </b> </font> <b> </b> </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt">On February 26, 2010, Columbia of Ohio filed an application to adjust rates associated with Riders IRP and DSM. Rider DSM tracks and recovers costs associated with Columbia of Ohio’s energy efficiency and conservation programs. On April 14, 2010, Columbia of Ohio filed a Joint Stipulation and Recommendation that settled all issues. On April 28, 2010, the PUCO issued an Order approving the Stipulation. Rates associated with Riders IRP and DSM were increased by approximately $17.8 million annually, beginning April 29, 2010. </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt">On January 28, 2010, Columbia of Pennsylvania filed a base rate case with the Pennsylvania PUC, seeking a revenue increase of approximately $32.0 million annually. On June 25, 2010, Columbia of Pennsylvania filed a Joint Petition for Settlement that, if approved, would result in an annual revenue increase of $12 million. Columbia of Pennsylvania anticipates that the Pennsylvania PUC will issue a final order approving the Settlement and that new rates will go into effect on October 1, 2010. </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt">On January 28, 2010, Columbia of Maryland filed a base rate case with the Maryland PSC, seeking a revenue increase of $2.2 million annually in order for Columbia of Maryland to earn the rate of return authorized by the PSC in its 2008 rate case. On May 10, 2010, the parties filed a Joint Motion for Approval of Stipulation and Settlement Agreement that would result in an annual revenue increase of approximately $1.7 million. The Maryland PSC issued a final order approving the Settlement, and new rates went into effect on May 28, 2010. </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt">On December 9, 2009, Northern Indiana filed a Petition with the IURC to extend its alternative regulatory programs which were scheduled to expire on May 1, 2010. On February 12, 2010, Northern Indiana, the OUCC and gas marketers supplying gas to residential and small commercial customers filed a Joint Stipulation and Agreement proposing an extension to the programs through March 31, 2012, which was approved by the IURC on March 31, 2010. </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt">On October 26, 2009, the Kentucky PSC approved a mechanism for recovering the costs of Columbia of Kentucky’s AMRP. In the same Order the Kentucky PSC also approved a mechanism for the recovery of Columbia of Kentucky’s uncollectible expenses associated with the cost of gas. On March 31, 2010, Columbia Gas of Kentucky made its annual filing related to the AMRP Rider and requested an adjustment of those rates related to the Rider. On July 12, 2010, the Commission entered an Order approving the requested annual amount of $1.1 million. The new rates associated with the AMRP Rider will go into effect for bills rendered on or after July 29, 2010. </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt">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 requires 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 has been provided for the full amount of the refund, which Northern Indiana began returning to customers in March 2010. </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt">On June 8, 2009, Columbia of Virginia filed an Application with the VSCC for approval of a CARE Plan for a three-year period beginning January 1, 2010. The CARE Plan included 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 CARE Plan also included a rate decoupling mechanism designed to mitigate the impact of declining customer usage. On October 28, 2009, Columbia of Virginia and other parties to the proceeding presented a unanimous settlement to the Hearing Examiner, which provided for approval of the CARE Plan Application with modifications. The settlement was approved by the VSCC on December 4, 2009, with mechanisms becoming effective January 1, 2010. </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt">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 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. Current law requires that all Indiana gas utilities, including Northern Indiana, deliver a portion of Substitute Natural Gas from this facility, once it is built. The IURC must approve the final contract between the Indiana Finance Authority and Indiana Gasification. </div>   </div>  <div style="font-family: 'Times New Roman',Times,serif"> <div align="justify" style="font-size: 10pt; margin-top: 0pt"> <u> </u> <u> </u> </div> <div align="justify" style="font-size: 10pt; margin-top: 0pt"> <font style="font-variant: small-caps"> <b> </b> </font> <b> </b> </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt">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 will conduct two consecutive one-year long standard service offer auction periods starting April 2010 and April 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 with the implementation of the standard service offer process. </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt"><b><i>Cost Recovery and Trackers. </i></b>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. </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt">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. </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt">Comparability of Gas Distribution Operations line item operating results is impacted by these 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. </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt">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. </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt">On October 30, 2009, the Massachusetts DPU approved a mechanism for the recovery of costs associated with the replacement of Bay State’s infrastructure. Bay State filed an application to increase its Targeted Infrastructure Replacement Factor Rider on April 30, 2010. </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt">On April 30, 2009, Columbia of Ohio filed an application with the PUCO to defer pension and other postretirement benefits expenses above those currently subject to collection in rates, effective January 1, 2009. On July 8, 2009, the PUCO issued an Order approving Columbia of Ohio’s application, although the deferred balances will not accrue carrying charges and Columbia of Ohio may not seek recovery of pension and other postretirement benefits deferrals in a base rate proceeding for a period of five years from the date of the Order. Approximately $4.2 million has been deferred in 2010 and $13.0 million was deferred for the year 2009. </div>   </div>  <div style="font-family: 'Times New Roman',Times,serif"> <div align="justify" style="font-size: 10pt; margin-top: 0pt"> <u> </u> <u> </u> </div> <div align="justify" style="font-size: 10pt; margin-top: 0pt"> <font style="font-variant: small-caps"> <b> </b> </font> <b> </b> </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt"><u>Gas Transmission and Storage Operations Regulatory Matters</u> </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt"><b>Majorsville, PA Project. </b>The Gas Transmission and Storage Operations segment is in the process of executing three separate projects totaling approximately $80.0 million in the Majorsville, PA vicinity to aggregate Marcellus Shale gas production for downstream transmission. Precedent Agreements were executed by anchor shippers in the fourth quarter of 2009. In 2010, Columbia Transmission filed with the FERC two applications to transfer certain pipeline facilities to a newly formed affiliate, NiSource Midstream, LLC, that, once approved, will be part of the facilities providing non-FERC jurisdiction gathering services to producers in the Majorsville, PA vicinity. The Majorsville, PA project is expected to begin service during the third quarter of 2010. </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt"><b>Incentive Fixed Fuel Mechanism. </b>On November 9, 2009, Columbia Gulf filed an application before the FERC for approval to replace Columbia Gulf’s existing Transportation Retainage Adjustment tracker mechanism that Columbia Gulf currently relies upon to recover fuel with a proposed Incentive Fixed Fuel mechanism. The Incentive Fixed Fuel Mechanism would establish a fixed fuel rate and includes incentives to improve pipeline infrastructure and reduce pipeline fuel requirements. The FERC issued an Order July 2, 2010 that included modifications to Columbia Gulf’s proposal. Columbia Gulf is unable to implement the proposal given the modifications and formally withdrew its proposal on July 16, 2010. </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt"><u>Electric Operations Regulatory Matters</u> </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt"><b><i>Significant Rate Developments. </i></b>On June 27, 2008, Northern Indiana filed a petition for new electric base rates and charges. Northern Indiana filed its last electric base rate increase in 1986. The filing requested an increase in base rates calculated to produce additional gross margin of $85.7 million. Several stakeholder groups have intervened in the case, representing customer groups and various counties and towns within Northern Indiana’s electric service territory. Evidentiary hearings concluded on August 6, 2009, and the briefing schedule concluded in January 2010. Northern Indiana is awaiting an IURC Order. </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt">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 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. </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt">Northern Indiana anticipates filing another electric base rate case during 2010. Among other things, the filing is expected to include the effect of increased pension expense, as well as usage levels based on more recent operating experience. </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt">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 new rates take effect based on an IURC order in the 2008 electric rate case. Credits amounting to $29.0 million and $26.3 million were recognized for electric customers for the first six months of 2010 and 2009, respectively. </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt">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. 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 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. </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt"><b><i>MISO. </i></b>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. In its pending base rate case, Northern Indiana proposes 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 date of effective rates in this case. During the first half of 2010, MISO costs of $4.8 million were deferred, while net credits of $0.2 million were deferred in the first half of 2009. As of June 30, 2010, Northern Indiana has deferred a total of $31.2 million of MISO costs. </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt">On November 7, 2008, the FERC issued an Order clarifying the RSG First Pass calculation and requiring the MISO to resettle the RSG market using the correct calculation and to pay refunds, or assess surcharges, to market participants, as appropriate, to correct a misinterpretation of an order issued by FERC in April 2006. Northern Indiana believes that the original Order would have entitled Northern Indiana to a refund, with the amount subject to calculation by MISO. On June 12, 2009, however, FERC issued an Order on rehearing in which it affirmed its prior order clarifying the method to calculate the RSG First Pass rate, but reversed its ruling requiring the MISO to pay refunds, and collect surcharges, on equitable grounds. Northern Indiana has asked FERC to reconsider its decision to deny refunds and that request remains pending. MISO’s implementation of FERC’s April 2006 Order on the RSG First Pass calculation resulted in several million dollars of surcharges to Northern Indiana through market resettlements implemented during the summer of 2007. As a result, Northern Indiana and Ameren jointly filed a complaint with FERC on August 10, 2007, contending that the RSG rates in effect were unjust and unreasonable. On November 10, 2008, the FERC issued an Order granting these complaints and ordering the MISO to calculate refunds and surcharges, as appropriate, back to the date of the complaint filed by Northern Indiana and Ameren, as authorized by Section 206 of the Federal Power Act. On May 6, 2009, however, the FERC issued an Order that upheld its decision granting the complaint, but largely reversed its directive requiring MISO to pay refunds, and collect surcharges, on equitable grounds. The FERC affirmed the refund and surcharge requirement only for those transactions that occurred after the date of the November 10, 2008 Order, instead of August 10, 2007, as it had previously required. Northern Indiana and Ameren have requested rehearing of the FERC’s May 6, 2009 Order, and that request remains pending. </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt">MISO and PJM Interconnection undertook a joint effort in April and May 2009 to identify a source of unaccounted for 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 and MISO and PJM Interconnection are currently in settlement discussions with the FERC that began on October 19, 2009 to determine the financial impact of any resettlements. Initial amounts calculated by PJM Interconnection approximated $78.0 million, while MISO has performed a preliminary estimate of $125.0 to $150.0 million. The impact to Northern Indiana cannot be reasonably estimated until a settlement is reached between MISO and PJM Interconnection, and MISO receives approval from the FERC on an allocation methodology to its market participants. Any adjustment will be neutral or favorable to operations. </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt"><b><i>Cost Recovery and Trackers. </i></b>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 intervenors, 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 – 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 calls 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. </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt">On May 28, 2008, the IURC issued an order approving the purchase of Sugar Creek, and on May 30, 2008 Northern Indiana purchased the 535 mw CCGT for $330.0 million in order to help meet capacity needs. On February 18, 2009, the IURC issued an order approving a settlement agreement filed in this proceeding allowing Northern Indiana to begin deferring carrying costs and depreciation, pending inclusion in rates, on Sugar Creek effective on December 1, 2008, when Sugar Creek was dispatched into MISO, at the agreed to carrying cost rate of 6.5%. 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 terms of recovery of the deferral and inclusion of Sugar Creek in rates will be resolved in Northern Indiana’s current rate proceeding. </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt">As part of a settlement agreement which resolved issues surrounding purchased power costs, Northern Indiana implemented a new “benchmarking standard,” that became effective in October 2007, which defines the price above which purchased power costs must be absorbed by Northern Indiana and are not permitted to be passed on to ratepayers. 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 and a set sharing mechanism. The agreement also contemplated Northern Indiana adding generating capacity to its existing portfolio by providing for the benchmark to be adjusted as new capacity is added. The dispatch of Sugar Creek into MISO on December 1, 2008 triggered a change in the benchmark, whereby the first 500 mw tier of the benchmark provision was eliminated. During the first six months of 2010 and 2009, the amount of purchased power costs exceeding the benchmark amounted to $0.2 million and $1.0 million, respectively, which was recognized as a net reduction of revenues. </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt">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. On July 7, 2010 the IURC approved the revised capital expenditure cost estimate of approximately $361.0 million. On June 18, 2010, Northern Indiana filed for a certificate of public convenience and necessity and associated ratemaking and accounting relief to construct flue gas desulfurization technology on Schahfer Unit 14 with a current estimated construction cost of approximately $154.0 million. Northern Indiana is seeking authority to recover construction and ongoing operating and maintenance costs through the ECT. </div> </div>  <!-- Begin Block Tagged Note false false false us-types:textBlockItemType textblock This element can be used to encapsulate the entire disclosure for public utilities (including data and tables). Reference 1: http://www.xbrl.org/2003/role/presentationRef -Publisher FASB -Name Statement of Financial Accounting Standard (FAS) -Number 71 false 1 2 false UnKnown UnKnown UnKnown false true