Regulatory Matters

12 Months Ended

Dec. 31, 2014

REGULATORY MATTERS

General

IPL is subject to regulation by the IURC as to its services and facilities, the valuation of property, the construction, purchase, or lease of electric generating facilities, the classification of accounts, rates of depreciation, retail rates and charges, the issuance of securities (other than evidences of indebtedness payable less than twelve months after the date of issue), the acquisition and sale of some public utility properties or securities and certain other matters.

In addition, IPL is subject to the jurisdiction of the FERC with respect to short-term borrowing not regulated by the IURC, the sale of electricity at wholesale and the transmission of electric energy in interstate commerce, the classification of accounts, reliability standards, and the acquisition and sale of utility property in certain circumstances as provided by the Federal Power Act. As a regulated entity, IPL is required to use certain accounting methods prescribed by regulatory bodies which may differ from those accounting methods required to be used by unregulated entities.

IPL is also affected by the regulatory jurisdiction of the EPA at the federal level, and the IDEM at the state level. Other significant regulatory agencies affecting IPL include, but are not limited to, the NERC, the U.S. Department of Labor and the IOSHA.

Basic Rates and Charges

Our basic rates and charges represent the largest component of our annual revenues. Our basic rates and charges are determined after giving consideration, on a pro-forma basis, to all allowable costs for ratemaking purposes including a fair return on the fair value of the utility property used and useful in providing service to customers. These basic rates and charges are set and approved by the IURC after public hearings. Such proceedings, which have occurred at irregular intervals, involve IPL, the Indiana Office of Utility Consumer Counselor, and other interested stakeholders. Pursuant to statute, the IURC is to conduct a periodic review of the basic rates and charges of all Indiana utilities at least once every four years, but the IURC has the authority to review the rates of any Indiana utility at any time. Once set, the basic rates and charges authorized do not assure the realization of a fair return on the fair value of property.

Our basic rates and charges were last adjusted in 1996; however, IPL filed a petition with the IURC on December 29, 2014, for authority to increase its basic rates and charges by approximately $67.8 million annually, or 5.6%. An order on this proceeding will likely be issued by the IURC in the fourth quarter of 2015 with any rate change expected to become effective by early 2016. The petition also includes requests to implement rate adjustment mechanisms for short term recovery of fluctuations in the following costs: (1) capacity purchase costs; (2) off-systems sales margins; and (3)MISO non-fuel charges (MISO fuel charges are already included in the FAC rate mechanism as described below). No assurances can be given as to the outcome of this proceeding.

Our declining block rate structure generally provides for residential and commercial customers to be charged a lower per kWh rate at higher consumption levels. Therefore, as volumes increase, the weighted average price per kWh decreases. Numerous factors including, but not limited to, weather, inflation, customer growth and usage, the level of actual operating and maintenance expenditures, capital expenditures including those required by environmental regulations, fuel costs, generating unit availability and purchased power costs, can affect the return realized.

FAC and Authorized Annual Jurisdictional Net Operating Income

IPL may apply to the IURC for a change in IPL’s fuel charge every three months to recover IPL’s estimated fuel costs, including the energy portion of purchased power costs, which may be above or below the levels included in IPL’s basic rates and charges. IPL must present evidence in each FAC proceeding that it has made every reasonable effort to acquire fuel and generate or purchase power or both so as to provide electricity to its retail customers at the lowest fuel cost reasonably possible.

Independent of the IURC’s ability to review basic rates and charges, Indiana law requires electric utilities under the jurisdiction of the IURC to meet operating expense and income test requirements as a condition for approval of requested changes in the FAC. Additionally, customer refunds may result if a utility’s rolling twelve-month operating income, determined at quarterly measurement dates, exceeds a utility’s authorized annual jurisdictional net operating income and there are not sufficient applicable cumulative net operating income deficiencies against which the excess rolling twelve-month jurisdictional net operating income can be offset.

ECCRA

IPL may apply to the IURC for approval of a rate adjustment known as the ECCRA every six months to recover costs to install and/or upgrade CCT equipment. The total amount of IPL’s CCT equipment approved for ECCRA recovery as of December 31, 2014 was $827.0 million. The jurisdictional revenue requirement that was approved by the IURC to be included in IPL’s rates for the six-month period from September 2014 through February 2015 was $56.8 million. During the years ended December 31, 2014, 2013 and 2012, we made total CCT expenditures of $176.3 million, $126.6 million, and $15.0 million, respectively. The vast majority of such costs are recoverable through our ECCRA filings. Also, see “Environmental Matters” for discussion of recovery of costs to comply with current and expected environmental laws and regulations.

DSM

In March 2014, legislation, referred to as the SEA 340, was approved that effectively ended the IURC’s energy efficiency targets established in a 2009 statewide Generic DSM Order. Although SEA 340 puts an end to established efficiency targets, IPL will continue to offer cost-effective energy efficiency and demand response programs as one of many resources to meet future demand for electricity.

In December 2014, we received approval from the IURC of our 2015-2016 DSM plan. The approval includes cost recovery on a set of DSM programs to be offered in 2015-2016 that is similar to the 2014 set of programs. Similar to the current DSM framework, we are eligible to receive performance incentives dependent upon the level of success of the programs. Additionally, we were granted authority to record a regulatory asset for recovery in a future base rate case proceeding for lost margins which result from decreased kWh related to implementation of these DSM programs.

IPL’s Smart Energy Project

In 2010, IPL was awarded a smart grid investment grant for $20.0 million as part of its $48.9 million Smart Energy Project (including smart grid technology), which provides IPL’s customers with tools to help them more efficiently use electricity and included an upgrade of IPL’s electric delivery system infrastructure. Under the grant, the U.S. Department of Energy provided $20.0 million of nontaxable reimbursements to IPL for capitalized costs associated with IPL’s Smart Energy Project. These reimbursements were accounted for as a reduction of the capitalized Smart Energy Project costs. We received the final grant reimbursement in 2013.

Wind and Solar Power Purchase Agreements

We are committed under a power purchase agreement to purchase approximately 100 MW of wind-generated electricity through 2029 from a wind project in Indiana. We are also committed under another agreement to purchase approximately 200 MW of wind-generated electricity for 20 years from a project in Minnesota, which began commercial operation in October 2011. In addition, we have 97 MW of solar-generated electricity in our service territory under contract in 2015, of which 82 MW was in operation as of December 31, 2014. We have authority from the IURC to recover the costs for all of these agreements through an adjustment mechanism administered within the FAC.

MISO Real Time RSG

MISO collects RSG charges from market participants to pay for generation dispatched when the costs of such generation are not recovered in the market clearing price. Over the past several years, there have been disagreements between interested parties regarding the calculation methodology for RSG charges and how such charges should be allocated among the individual MISO participants. Under the methodology currently in effect, RSG charges have little effect on IPL’s financial statements as the vast majority of such charges are considered to be fuel costs and are recoverable through IPL’s FAC, while the remainder is being deferred for future recovery in accordance with GAAP. However, the IURC’s orders in IPL’s FAC 77, 78 and 79 proceedings approved IPL’s FAC factor on an interim basis, subject to refund, pending the outcome of a FERC proceeding regarding RSG charges and any subsequent appeals therefrom. In a recent FAC proceeding, IPL requested that the subject to refund designation be removed and that FAC 77, 78 and 79 proceedings be made final with no modifications. In February 2014, the IURC issued an order approving IPL’s request.

MISO Transmission Expansion Cost Sharing and FERC Order 1000

Beginning in 2007, MISO transmission system owner members including IPL began to share the costs of transmission expansion projects with other transmission system owner members after such projects were approved by the MISO board of directors. Upon approval by the MISO board of directors the transmission system owner members must make a good faith effort to build and/or pay for the projects. Costs allocated to IPL for the projects of other transmission system owner members are collected by MISO per their tariff.

On July 21, 2011, the FERC issued Order 1000, amending the transmission planning and cost allocation requirements established in Order No. 890. Through Order 1000, the FERC:


(1)	requires public utility transmission providers to participate in a regional transmission planning process and produce a regional transmission plan;


(2)	requires public utility transmission providers to amend their open access transmission tariffs to describe how public policy requirements will be considered in local and regional transmission planning processes;


(3)	removes the federal right of first refusal for certain transmission facilities; and


(4)	seeks to improve coordination between neighboring transmission planning regions for interregional facilities.

MISO’s approved tariff in part already complies with Order 1000. However, Order 1000 resulted in changes to transmission expansion costs charged to us by MISO. Such changes relate to public policy requirements for transmission expansion within the MISO footprint, such as to comply with renewable mandates of other states within the footprint. These charges are difficult to estimate, but are expected to be material to us within a few years; however, it is probable, but not certain, that these costs will be recoverable, subject to IURC approval. Through December 31, 2014, we have deferred as a regulatory asset $7.6 million of MISO transmission expansion costs.

Senate Bill 560

In April 2013, Senate Bill 560 became law in Indiana. This law provides more regulatory flexibility to the process for reviewing necessary utility system improvements and determining appropriate rates. Senate Bill 560 allows utilities to propose a seven-year infrastructure plan for distribution, transmission and storage to the IURC and, if the plan is considered reasonable by the IURC, the utility could recover its investment in facilities identified in the plan in a timely manner. In addition, when Indiana utilities apply for a change in their basic rates and charges, if new rates are not approved by the IURC within 300 days after the utility filed its case-in-chief, the bill allows the utility to implement temporary rates including 50% of the proposed increase. Such temporary rates would be subject to a reconciliation implemented via a credit or surcharge in equal amounts each month for six months, if the IURC’s final order established rates were to differ from the temporary rates previously placed into effect. The IURC would be allowed to extend the 300-day deadline by 60 days, for good cause. Both provisions, as well as an additional provision that allows utilities to utilize a forward-looking test year in rate cases, recognize the capital-intensive nature of the energy industry and seek to reduce time between a utility’s investment and the opportunity to recover the investment through rates.

Indianapolis Power And Light Company [Member]

Entity Information [Line Items]

Regulatory Matters

REGULATORY MATTERS

General

Basic Rates and Charges

FAC and Authorized Annual Jurisdictional Net Operating Income

ECCRA

IPL may apply to the IURC for approval of a rate adjustment known as the ECCRA every six months to recover costs to install and/or upgrade CCT equipment. The total amount of IPL’s CCT equipment approved for ECCRA recovery as of December 31, 2014 was $827 million. The jurisdictional revenue requirement that was approved by the IURC to be included in IPL’s rates for the six-month period from September 2014 through February 2015 was $56.8 million. During the years ended December 31, 2014, 2013 and 2012, we made total CCT expenditures of $176.3 million, $126.6 million, and $15.0 million, respectively. The vast majority of such costs are recoverable through our ECCRA filings. Also, see “Environmental Matters” for discussion of recovery of costs to comply with current and expected environmental laws and regulations.

DSM

IPL’s Smart Energy Project

In 2010, IPL was awarded a smart grid investment grant for $20 million as part of its $48.9 million Smart Energy Project (including smart grid technology), which provides IPL’s customers with tools to help them more efficiently use electricity and included an upgrade of IPL’s electric delivery system infrastructure. Under the grant, the U.S. Department of Energy provided $20 million of nontaxable reimbursements to IPL for capitalized costs associated with IPL’s Smart Energy Project. These reimbursements were accounted for as a reduction of the capitalized Smart Energy Project costs. We received the final grant reimbursement in 2013.

Wind and Solar Power Purchase Agreements

MISO Real Time RSG

MISO Transmission Expansion Cost Sharing and FERC Order 1000

On July 21, 2011, the FERC issued Order 1000, amending the transmission planning and cost allocation requirements established in Order No. 890. Through Order 1000, the FERC:


(1)	requires public utility transmission providers to participate in a regional transmission planning process and produce a regional transmission plan;


(2)	requires public utility transmission providers to amend their open access transmission tariffs to describe how public policy requirements will be considered in local and regional transmission planning processes;


(3)	removes the federal right of first refusal for certain transmission facilities; and


(4)	seeks to improve coordination between neighboring transmission planning regions for interregional facilities.

Senate Bill 560

In April 2013, Senate Bill 560became law in Indiana. This law provides more regulatory flexibility to the process for reviewing necessary utility system improvements and determining appropriate rates. Senate Bill 560 allows utilities to propose a seven-year infrastructure plan for distribution, transmission and storage to the IURC and, if the plan is considered reasonable by the IURC, the utility could recover its investment in facilities identified in the plan in a timely manner. In addition, when Indiana utilities apply for a change in their basic rates and charges, if new rates are not approved by the IURC within 300 days after the utility filed its case-in-chief, the bill allows the utility to implement temporary rates including 50% of the proposed increase. Such temporary rates would be subject to a reconciliation implemented via a credit or surcharge in equal amounts each month for six months, if the IURC’s final order established rates were to differ from the temporary rates previously placed into effect. The IURC would be allowed to extend the 300-day deadline by 60 days, for good cause. Both provisions, as well as an additional provision that allows utilities to utilize a forward-looking test year in rate cases, recognize the capital-intensive nature of the energy industry and seek to reduce time between a utility’s investment and the opportunity to recover the investment through rates.