2.2.0.25falsefalse006130 - Disclosure - Rate Matters and Regulationtruefalsefalse1falsefalseUSDfalsefalse1/1/2010 - 12/31/2010
USD ($)
$c00039http://www.sec.gov/CIK0000074145duration2010-01-01T00:00:002010-12-31T00:00:00u000Standardhttp://www.xbrl.org/2003/iso4217USDiso42170USDUSD$2true0ogec_NotesToFinancialStatementsAbstractogecfalsenadurationNo definition available.falsefalsefalsefalsefalsefalsefalsefalsefalsefalse1falsefalsefalse00falsefalsefalsefalsefalseOtherxbrli:stringItemTypestringNo definition available.falsefalse3false0ogec_RateMattersAndRegulationTextBlockogecfalsenadurationDescribes all of the specific events that have or may impact rates and amortization of regulatory assets and liabilities (for...falsefalsefalsefalsefalsefalsefalsefalsefalsefalseterselabel1falsefalsefalse00<div style="TEXT-INDENT: 0pt; DISPLAY: block; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"><font style="DISPLAY: inline; FONT-FAMILY: Times New Roman; FONT-SIZE: 12pt; FONT-WEIGHT: bold">13.           Rate Matters and Regulation</font></div><div style="TEXT-INDENT: 0pt; DISPLAY: block; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"> </div><div style="TEXT-INDENT: 0pt; DISPLAY: block; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"><font style="DISPLAY: inline; FONT-FAMILY: Times New Roman; FONT-SIZE: 12pt; FONT-WEIGHT: bold">Regulation and Rates</font></div><div style="TEXT-INDENT: 0pt; DISPLAY: block; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"> </div><div style="TEXT-ALIGN: justify; TEXT-INDENT: 27pt"><font style="FONT-FAMILY: Times New Roman; FONT-SIZE: 12pt">The Company’s retail electric tariffs are regulated by the OCC in Oklahoma and by the APSC in Arkansas. The issuance of certain securities by the Company is also regulated by the OCC and the APSC. The Company’s wholesale electric tariffs, transmission activities, short-term borrowing authorization and accounting practices are subject to the jurisdiction of the FERC. The Secretary of the DOE has jurisdiction over some of the Company’s facilities and operations. For the year ended December 31, 2010, 88 percent of the Company’s electric revenue was subject to the jurisdiction of the OCC, eight percent to the APSC and four percent to the FERC.</font></div><div style="TEXT-INDENT: 0pt; DISPLAY: block; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"> </div><div style="TEXT-INDENT: 40pt; DISPLAY: block; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"><font style="DISPLAY: inline; FONT-FAMILY: Times New Roman; FONT-SIZE: 12pt">The OCC issued an order in 1996 authorizing the Company to reorganize into a subsidiary of OGE Energy.  The order required that, among other things, (i) OGE Energy permit the OCC access to the books and records of OGE Energy and its affiliates relating to transactions with the Company, (ii) OGE Energy employ accounting and other procedures and controls to protect against subsidization of non-utility activities by the Company’s customers and (iii) OGE Energy refrain from pledging Company assets or income for affiliate transactions.  In addition, the Energy Policy Act of 2005 enacted the Public Utility Holding Company Act of 2005, which in turn granted to the FERC access to the books and records of OGE Energy and its affiliates as the FERC deems relevant to costs incurred by the Company or necessary or appropriate for the protection of utility customers with respect to the FERC jurisdictional rates.</font></div><div style="TEXT-INDENT: 0pt; DISPLAY: block; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"> </div><div style="TEXT-INDENT: 0pt; DISPLAY: block; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"><font style="DISPLAY: inline; FONT-FAMILY: Times New Roman; FONT-SIZE: 12pt; FONT-WEIGHT: bold">Completed Regulatory Matters</font></div><div style="TEXT-INDENT: 0pt; DISPLAY: block; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"> </div><div style="TEXT-INDENT: 0pt; DISPLAY: block; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="FONT-STYLE: italic; DISPLAY: inline; FONT-FAMILY: Times New Roman; FONT-SIZE: 12pt; FONT-WEIGHT: bold">OU Spirit Wind Power Project</font></div><div style="TEXT-INDENT: 0pt; DISPLAY: block; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"> </div><div style="TEXT-INDENT: 0pt; DISPLAY: block; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"><div style="TEXT-INDENT: 36pt; DISPLAY: block; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"><font style="DISPLAY: inline; FONT-FAMILY: Times New Roman; FONT-SIZE: 12pt"> As previously disclosed, on November 25, 2009, the Company received an order from the OCC authorizing the Company to recover from Oklahoma customers the cost to construct OU Spirit, with the rider being implemented on December 4, 2009. In January 2008, the Company filed with the SPP for an interconnection agreement for the OU Spirit project.  On May 29, 2009, the Company executed an interim interconnection agreement, allowing OU Spirit to interconnect to the transmission grid, subject to certain conditions. On August 27, 2009, the FERC issued an order accepting the interim interconnection agreement, subject to certain conditions, which enables OU Spirit to interconnect into the transmission grid.  On February 8, 2011, the final interconnection agreement was put in place.</font></div><div style="TEXT-INDENT: 0pt; DISPLAY: block; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"> </div></div><div style="TEXT-INDENT: 40pt; DISPLAY: block; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"><font style="DISPLAY: inline; FONT-FAMILY: Times New Roman; FONT-SIZE: 12pt">On January 19, 2011, the APSC issued an order finding that (i) OU Spirit is prudent and is in the public’s interest and (ii) the $2.1 million of costs associated with OU Spirit from September 1, 2010 through June 30, 2011 should be recovered through the Energy Cost Recovery rider, which is expected to be filed with the APSC by March 15, 2011 (beginning July 1, 2011, OU Spirit costs are expected to be recovered in base rates resulting from the Company’s 2010 Arkansas rate case).</font></div><div style="TEXT-INDENT: 0pt; DISPLAY: block; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"> </div><div style="TEXT-INDENT: 0pt; DISPLAY: block; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"><font style="FONT-STYLE: italic; DISPLAY: inline; FONT-FAMILY: Times New Roman; FONT-SIZE: 12pt; FONT-WEIGHT: bold">Renewable Energy Filing</font></div><div style="TEXT-INDENT: 0pt; DISPLAY: block; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"> </div><div style="TEXT-INDENT: 40pt; DISPLAY: block; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"><font style="DISPLAY: inline; FONT-FAMILY: Times New Roman; FONT-SIZE: 12pt">In September 2009, the Company reached agreements with two developers who are to build two new wind farms, totaling 280 MWs, in northwestern Oklahoma. Under the terms of the agreements, CPV Keenan built a 150 MW wind farm in Woodward County, which was placed in service in December 2010, and Edison Mission Energy is to build a 130 MW facility in Dewey County near Taloga, which is expected to be in service during the second quarter of 2011. The agreements are both 20-year power purchase agreements, under which the developers are to build, own and operate the wind generating facilities and the Company will purchase their electric output.  On January 5, 2010, the Company received an order from the OCC </font><font style="DISPLAY: inline; FONT-FAMILY: Times New Roman; FONT-SIZE: 12pt">approving the power purchase agreements and authorizing the Company to recover the costs of the power purchase agreements through the Company’s fuel adjustment clause.  The Company will continue to evaluate renewable opportunities to add to its power-generation portfolio in the future.</font></div><div style="TEXT-INDENT: 0pt; DISPLAY: block"><br /></div><div style="TEXT-INDENT: 40pt; DISPLAY: block; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"><font style="DISPLAY: inline; FONT-FAMILY: Times New Roman; FONT-SIZE: 12pt">On January 19, 2011, the APSC issued an order finding that the 280 MW wind power purchase agreements are prudent and should be recovered through the Energy Cost Recovery rider.</font></div><div style="TEXT-INDENT: 0pt; DISPLAY: block"><br /></div><div style="TEXT-INDENT: 0pt; DISPLAY: block; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"><font style="FONT-STYLE: italic; DISPLAY: inline; FONT-FAMILY: Times New Roman; FONT-SIZE: 12pt; FONT-WEIGHT: bold">Windspeed Transmission Line Project</font></div><div style="TEXT-INDENT: 0pt; DISPLAY: block; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"> </div><div style="TEXT-INDENT: 40pt; DISPLAY: block; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"><font style="DISPLAY: inline; FONT-FAMILY: Times New Roman; FONT-SIZE: 12pt">The OCC approved the Company’s request to recover construction costs of up to $218 million, including AFUDC, for Windspeed.  Construction costs and AFUDC incurred for Windspeed were $212.3 million.  Windspeed was placed into service on March 31, 2010, with the recovery rider being implemented with the first billing cycle in April 2010.</font></div><div style="TEXT-INDENT: 0pt; DISPLAY: block; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"> </div><div style="TEXT-INDENT: 0pt; DISPLAY: block; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"><font style="FONT-STYLE: italic; DISPLAY: inline; FONT-FAMILY: Times New Roman; FONT-SIZE: 12pt; FONT-WEIGHT: bold">Long-Term Gas Supply Agreements</font></div><div style="TEXT-INDENT: 0pt; DISPLAY: block; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"> </div><div style="TEXT-INDENT: 40pt; DISPLAY: block; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"><font style="DISPLAY: inline; FONT-FAMILY: Times New Roman; FONT-SIZE: 12pt">In May 2010, the OCC approved the Company’s request for a waiver of the competitive bid rules to allow the Company to negotiate desired long-term gas purchase agreements. On June 29, 2010, the Company filed a separate application with the OCC seeking approval of four long-term gas purchase agreements, which would provide a 12-year supply of natural gas to the Company and account for 25 percent of its currently projected natural gas fuel supply needs over the same time period. On September 26, 2010, the Company filed a motion with the OCC to dismiss this case. A hearing in this matter was held on October 7, 2010 and the administrative law judge recommended that the case be dismissed without prejudice.  The Company and the other parties to this matter continue ongoing discussions with the OCC Staff.</font></div><div style="TEXT-INDENT: 0pt; DISPLAY: block"><br /></div><div style="TEXT-INDENT: 0pt; DISPLAY: block; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"><font style="FONT-STYLE: italic; DISPLAY: inline; FONT-FAMILY: Times New Roman; FONT-SIZE: 12pt; FONT-WEIGHT: bold">Review of the Company’s Fuel Adjustment Clause for Calendar Year 2008</font></div><div style="TEXT-INDENT: 0pt; DISPLAY: block; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"> </div><div style="TEXT-INDENT: 40pt; DISPLAY: block; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"><font style="DISPLAY: inline; FONT-FAMILY: Times New Roman; FONT-SIZE: 12pt">On July 20, 2009, the OCC Staff filed an application for a public hearing to review and monitor the Company’s application of the 2008 fuel adjustment clause.  On September 18, 2009, the Company responded by filing the necessary information and documents to satisfy the OCC’s minimum filing requirement rules.  On May 5, 2010, all parties to this case signed a settlement agreement in this matter, stating that the various charges or credits in the Company’s fuel adjustment clause are based upon the actual prices paid for fuel, purchased power or purchased gas.  The parties further stipulated that the charges collected by the Company through its fuel adjustment clause from Oklahoma jurisdictional customers were calculated properly, were mathematically accurate and were collected in accordance with the fuel adjustment clause and all applicable OCC rules and orders for calendar year 2008.  A hearing on the settlement agreement was held on May 26, 2010 and the OCC issued an order approving the settlement agreement on June 18, 2010.</font></div><div style="TEXT-INDENT: 0pt; DISPLAY: block"><br /></div><div style="TEXT-INDENT: 0pt; DISPLAY: block; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"><font style="FONT-STYLE: italic; DISPLAY: inline; FONT-FAMILY: Times New Roman; FONT-SIZE: 12pt; FONT-WEIGHT: bold">Smart Grid Project</font></div><div style="TEXT-INDENT: 0pt; DISPLAY: block"><br /></div><div style="TEXT-INDENT: 40pt; DISPLAY: block; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"><font style="DISPLAY: inline; FONT-FAMILY: Times New Roman; FONT-SIZE: 12pt">Several provisions of the ARRA relate to issues of direct interest to the Company including, in particular, financial incentives to develop smart grid technology, transmission infrastructure and renewable energy. The Company received a $130 million grant from the DOE to be used for the Smart Grid program in the Company the Company’s service territory.   </font></div><div style="TEXT-INDENT: 0pt; DISPLAY: block; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"> </div><div style="TEXT-INDENT: 40pt; DISPLAY: block; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"><font style="DISPLAY: inline; FONT-FAMILY: Times New Roman; FONT-SIZE: 12pt">On March 15, 2010, the Company filed an application with the OCC requesting pre-approval for system-wide deployment of smart grid technology and a recovery rider, including a credit for the Smart Grid grant.  On July 1, 2010, the OCC approved a settlement among all parties to the proceeding.  The key settlement terms were:</font></div><div style="TEXT-INDENT: 0pt; DISPLAY: block; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"> </div><div><table style="FONT-FAMILY: times new roman; FONT-SIZE: 12pt" cellspacing="0" cellpadding="0" width="100%"><tr valign="top"><td style="WIDTH: 72pt" align="right"><div><font style="DISPLAY: inline; FONT-FAMILY: Wingdings; FONT-SIZE: 12pt">Ÿ  </font></div></td><td><div style="TEXT-INDENT: 0pt; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"><font style="DISPLAY: inline; FONT-FAMILY: Times New Roman; FONT-SIZE: 12pt">Pre-approval for system-wide deployment of smart grid technology and authorization for the Company to begin recovering the costs of the system-wide deployment of smart grid technology through a rider mechanism that will become effective in accordance with the order approving the settlement agreement;</font></div></td></tr></table></div><div><table style="FONT-FAMILY: times new roman; FONT-SIZE: 12pt" cellspacing="0" cellpadding="0" width="100%"><tr valign="top"><td style="WIDTH: 72pt" align="right"><div><font style="DISPLAY: inline; FONT-FAMILY: Wingdings; FONT-SIZE: 12pt">Ÿ  </font></div></td><td><div style="TEXT-INDENT: 0pt; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"><font style="DISPLAY: inline; FONT-FAMILY: Times New Roman; FONT-SIZE: 12pt">The Company’s total project costs eligible for recovery (those costs expended or accrued by the Company prior to the termination of the period authorized by the DOE as eligible for grant funds) shall be capped at $366.4 million, inclusive of the DOE grant award amount. The Smart Grid project cost includes the cost of implementing the Norman, Oklahoma smart grid pilot program previously authorized by the OCC.  Under the terms of the settlement, the Smart Grid project cost would be deemed to represent an investment that is fair, just and reasonable and in the public interest and to be prudent and will be recognized in the Company’s 2013 general rate case;</font></div></td></tr></table></div><div><table style="FONT-FAMILY: times new roman; FONT-SIZE: 12pt" cellspacing="0" cellpadding="0" width="100%"><tr valign="top"><td style="WIDTH: 72pt" align="right"><div><font style="DISPLAY: inline; FONT-FAMILY: Wingdings; FONT-SIZE: 12pt">Ÿ  </font></div></td><td><div style="TEXT-INDENT: 0pt; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"><font style="DISPLAY: inline; FONT-FAMILY: Times New Roman; FONT-SIZE: 12pt">To the extent that the Company’s total expenditure for system-wide deployment of smart grid technology during the eligible period exceeds the Smart Grid project cost, the Company shall be entitled to offer evidence and seek to establish that the excess above the Smart Grid project cost was prudently incurred and any such contention may be addressed in the Company’s 2013 rate case;</font></div></td></tr></table></div><div><table style="FONT-FAMILY: times new roman; FONT-SIZE: 12pt" cellspacing="0" cellpadding="0" width="100%"><tr valign="top"><td style="WIDTH: 72pt" align="right"><div><font style="DISPLAY: inline; FONT-FAMILY: Wingdings; FONT-SIZE: 12pt">Ÿ  </font></div></td><td><div style="TEXT-INDENT: 0pt; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"><font style="DISPLAY: inline; FONT-FAMILY: Times New Roman; FONT-SIZE: 12pt">Implementation of the recovery rider would commence with the first billing cycle in July 2010;</font></div></td></tr></table></div><div><table style="FONT-FAMILY: times new roman; FONT-SIZE: 12pt" cellspacing="0" cellpadding="0" width="100%"><tr valign="top"><td style="WIDTH: 72pt" align="right"><div><font style="DISPLAY: inline; FONT-FAMILY: Wingdings; FONT-SIZE: 12pt">Ÿ  </font></div></td><td><div style="TEXT-INDENT: 0pt; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"><font style="DISPLAY: inline; FONT-FAMILY: Times New Roman; FONT-SIZE: 12pt">Continued utilization of a return on equity previously approved by the OCC for other various recovery riders;</font></div></td></tr></table></div><div><table style="FONT-FAMILY: times new roman; FONT-SIZE: 12pt" cellspacing="0" cellpadding="0" width="100%"><tr valign="top"><td style="WIDTH: 72pt" align="right"><div><font style="DISPLAY: inline; FONT-FAMILY: Wingdings; FONT-SIZE: 12pt">Ÿ  </font></div></td><td><div style="TEXT-INDENT: 0pt; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"><font style="DISPLAY: inline; FONT-FAMILY: Times New Roman; FONT-SIZE: 12pt">The recovery rider shall be designed to collect, on a levelized basis, the revenue requirement associated with the estimated project cost of $357.4 million and shall be subject to a true-up in 2014 after the recovery rider expires, including a true-up for project costs, if any, in excess of $357.4 million but less than the Smart Grid project cost. Any over/under recovery remaining will be passed or credited through the Company’s fuel adjustment clause;</font></div></td></tr></table></div><div><table style="FONT-FAMILY: times new roman; FONT-SIZE: 12pt" cellspacing="0" cellpadding="0" width="100%"><tr valign="top"><td style="WIDTH: 72pt" align="right"><div><font style="DISPLAY: inline; FONT-FAMILY: Wingdings; FONT-SIZE: 12pt">Ÿ  </font></div></td><td><div style="TEXT-INDENT: 0pt; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"><font style="DISPLAY: inline; FONT-FAMILY: Times New Roman; FONT-SIZE: 12pt">The Company guarantees that customers will receive the benefit of certain operations and maintenance cost reductions resulting from the smart grid deployment as a credit to the recovery rider;</font></div></td></tr></table></div><div><table style="FONT-FAMILY: times new roman; FONT-SIZE: 12pt" cellspacing="0" cellpadding="0" width="100%"><tr valign="top"><td style="WIDTH: 72pt" align="right"><div><font style="DISPLAY: inline; FONT-FAMILY: Wingdings; FONT-SIZE: 12pt">Ÿ  </font></div></td><td><div style="TEXT-INDENT: 0pt; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"><font style="DISPLAY: inline; FONT-FAMILY: Times New Roman; FONT-SIZE: 12pt">Beginning January 1, 2011, the Company shall make available the smart grid web portal to all customers having a smart meter. The Company shall expend funds to educate customers regarding the best use of the information available on the portal. In addition, the Company shall make available to all customers who do not have internet access the opportunity to receive a monthly home energy report. This report shall be made available, free of charge, to customers eligible for the Company’s Low Income Home Energy Assistance Program and/or Senior Citizen program who are without internet service. The incremental costs for web portal access, education and the providing of home energy reports free of charge are to be accumulated as a regulatory asset in an amount up to $6.9 million and recovered in base rates beginning in 2014;</font></div></td></tr></table></div><div><table style="FONT-FAMILY: times new roman; FONT-SIZE: 12pt" cellspacing="0" cellpadding="0" width="100%"><tr valign="top"><td style="WIDTH: 72pt" align="right"><div><font style="DISPLAY: inline; FONT-FAMILY: Wingdings; FONT-SIZE: 12pt">Ÿ  </font></div></td><td><div style="TEXT-INDENT: 0pt; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"><font style="DISPLAY: inline; FONT-FAMILY: Times New Roman; FONT-SIZE: 12pt">The stranded costs associated with the Company’s existing meters which are being replaced by smart meters will be accumulated in a regulatory asset and recovered in base rates beginning in 2014; and</font></div></td></tr></table></div><div><table style="FONT-FAMILY: times new roman; FONT-SIZE: 12pt" cellspacing="0" cellpadding="0" width="100%"><tr valign="top"><td style="WIDTH: 72pt" align="right"><div><font style="DISPLAY: inline; FONT-FAMILY: Wingdings; FONT-SIZE: 12pt">Ÿ  </font></div></td><td><div style="TEXT-INDENT: 0pt; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"><font style="DISPLAY: inline; FONT-FAMILY: Times New Roman; FONT-SIZE: 12pt">The Company will file an application with the APSC related to the deployment of smart grid technology by the end of 2010.</font></div></td></tr></table></div><div style="TEXT-INDENT: 0pt; DISPLAY: block"><br /></div><div style="TEXT-INDENT: 40pt; DISPLAY: block; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"><font style="DISPLAY: inline; FONT-FAMILY: Times New Roman; FONT-SIZE: 12pt">On December 17, 2010, the Company filed an application with the APSC requesting pre-approval for system-wide deployment of smart grid technology and a recovery rider, including a credit for the Smart Grid grant. A procedural schedule has not been established in this matter.</font></div><div style="TEXT-INDENT: 0pt; DISPLAY: block; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"> </div><div style="TEXT-INDENT: 0pt; DISPLAY: block; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"><font style="FONT-STYLE: italic; DISPLAY: inline; FONT-FAMILY: Times New Roman; FONT-SIZE: 12pt; FONT-WEIGHT: bold">Crossroads Wind Project</font></div><div style="TEXT-INDENT: 0pt; DISPLAY: block; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"> </div><div style="TEXT-INDENT: 40pt; DISPLAY: block; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"><font style="DISPLAY: inline; FONT-FAMILY: Times New Roman; FONT-SIZE: 12pt">In February 2010, the Company signed memoranda of understanding for 197.8 MWs of wind turbine generators and certain related balance of plant engineering, procurement and construction services associated with Crossroads.  On July 29, 2010, the OCC approved a settlement that would allow the Company to build, own and operate the wind farm.  The key settlement terms approved by the OCC were:</font></div><div style="TEXT-INDENT: 0pt; DISPLAY: block; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"> </div><div><table style="FONT-FAMILY: times new roman; FONT-SIZE: 12pt" cellspacing="0" cellpadding="0" width="100%"><tr valign="top"><td style="WIDTH: 72pt" align="right"><div><font style="DISPLAY: inline; FONT-FAMILY: Wingdings; FONT-SIZE: 12pt">Ÿ  </font></div></td><td><div style="TEXT-INDENT: 0pt; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"><font style="DISPLAY: inline; FONT-FAMILY: Times New Roman; FONT-SIZE: 12pt">Authorization for the Company to begin recovering the costs of Crossroads through a rider mechanism that will be effective until new rates are implemented after the Company’s 2013 general rate case;</font></div></td></tr></table></div><div><table style="FONT-FAMILY: times new roman; FONT-SIZE: 12pt" cellspacing="0" cellpadding="0" width="100%"><tr valign="top"><td style="WIDTH: 72pt" align="right"><div><font style="DISPLAY: inline; FONT-FAMILY: Wingdings; FONT-SIZE: 12pt">Ÿ  </font></div></td><td><div style="TEXT-INDENT: 0pt; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"><font style="DISPLAY: inline; FONT-FAMILY: Times New Roman; FONT-SIZE: 12pt">Continued utilization of a return on equity previously approved by the OCC for other various recovery riders, subject to adjustment in the future to reflect the return on equity authorized in subsequent general rate cases;</font></div></td></tr></table></div><div><table style="FONT-FAMILY: times new roman; FONT-SIZE: 12pt" cellspacing="0" cellpadding="0" width="100%"><tr valign="top"><td style="WIDTH: 72pt" align="right"><div><font style="DISPLAY: inline; FONT-FAMILY: Wingdings; FONT-SIZE: 12pt">Ÿ  </font></div></td><td><div style="TEXT-INDENT: 0pt; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"><font style="DISPLAY: inline; FONT-FAMILY: Times New Roman; FONT-SIZE: 12pt">The Company’s capital costs for which it is entitled recovery for a 197.8 MW wind farm are $407.7 million;</font></div></td></tr></table></div><div><table style="FONT-FAMILY: times new roman; FONT-SIZE: 12pt" cellspacing="0" cellpadding="0" width="100%"><tr valign="top"><td style="WIDTH: 72pt" align="right"><div><font style="DISPLAY: inline; FONT-FAMILY: Wingdings; FONT-SIZE: 12pt">Ÿ  </font></div></td><td><div style="TEXT-INDENT: 0pt; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"><font style="DISPLAY: inline; FONT-FAMILY: Times New Roman; FONT-SIZE: 12pt">To the extent the Company’s total investment in Crossroads exceeds the amount for which it is entitled recovery, the Company shall be entitled to offer evidence and seek to establish that the excess amount was prudently incurred and should be included in the Company’s rate base; and</font></div></td></tr></table></div><div><table style="FONT-FAMILY: times new roman; FONT-SIZE: 12pt" cellspacing="0" cellpadding="0" width="100%"><tr valign="top"><td style="WIDTH: 72pt" align="right"><div><font style="DISPLAY: inline; FONT-FAMILY: Wingdings; FONT-SIZE: 12pt">Ÿ  </font></div></td><td><div style="TEXT-INDENT: 0pt; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"><font style="DISPLAY: inline; FONT-FAMILY: Times New Roman; FONT-SIZE: 12pt">If the three-year rolling average of Crossroads MWHs of production (including a credit for energy not produced due to curtailments or other events caused by system emergencies, force majeure events, or transmission system issues) falls below 712,844 MWHs, the Company shall file testimony demonstrating the appropriate operation of Crossroads as part of its fuel cost recovery filing.</font></div></td></tr></table></div><div style="TEXT-INDENT: 0pt; DISPLAY: block"><br /></div><div style="TEXT-INDENT: 40pt; DISPLAY: block; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"><font style="DISPLAY: inline; FONT-FAMILY: Times New Roman; FONT-SIZE: 12pt">Pursuant to the terms of the settlement, the Company chose to expand Crossroads by an additional 29.7 MWs.  As a result of the expansion, the amount of capital costs which the Company is entitled to recover and the three-year rolling average of MWH production were adjusted to $469.7 million and 819,879 MWHs, respectively.  The total projected cost of the 227.5 MW expanded project, including AFUDC, is $450 million, which is below the adjusted recovery amount of $469.7 million.  The Company entered into a turbine supply agreement with Siemens whereby the Company is to acquire 227.5 MWs of wind turbine generation at a cost in excess of $300 million.  The Company expects Crossroads to be in service by the end of 2011.</font></div><div style="TEXT-INDENT: 0pt; DISPLAY: block"><br /></div><div style="TEXT-INDENT: 40pt; DISPLAY: block; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"><font style="DISPLAY: inline; FONT-FAMILY: Times New Roman; FONT-SIZE: 12pt">The Company is in the process of entering into an interconnection agreement with the SPP for Crossroads.  As part of the multi-study interconnection process, the SPP conducted an interim operational study to determine the impact Crossroads will have on the existing transmission system.  The SPP verbally indicated that limited interconnection would be necessary to address system stability limitations.  In order to enable full interconnection of Crossroads, the Company put forth a mitigation proposal, consisting of a system protection relay system, which has recently received all the necessary SPP working group and </font><font style="DISPLAY: inline; FONT-FAMILY: Times New Roman; FONT-SIZE: 12pt">December 30, 2010, the SPP posted the results of its interim operational study to reflect the SPP approval of the mitigation strategy.  The Company expects a final interconnection agreement to be put in place by the second quarter of 2011.</font></div><div style="TEXT-INDENT: 0pt; DISPLAY: block"><br /></div><div style="TEXT-INDENT: 0pt; DISPLAY: block; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="FONT-STYLE: italic; DISPLAY: inline; FONT-FAMILY: Times New Roman; FONT-SIZE: 12pt; FONT-WEIGHT: bold">Market-Based Rate Authority</font></div><div style="TEXT-INDENT: 0pt; DISPLAY: block; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"> </div><div style="TEXT-INDENT: 40pt; DISPLAY: block; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"><font style="DISPLAY: inline; FONT-FAMILY: Times New Roman; FONT-SIZE: 12pt">On December 22, 2003, the Company and OER filed a triennial market power update with the FERC based on the supply margin assessment test.  On May 13, 2004, the FERC directed all utilities with pending three year market-based reviews to revise the generation market power portion of their three year review to address two new interim tests, a pivotal supplier screen test and a market share screen test.  On February 7, 2005, the Company and OER submitted a compliance filing to the FERC that applied the interim tests to the Company and OER.  On June 7, 2005, the FERC issued an order finding that the Company and OER had failed the market share screen test meant to determine whether entities with market-based rate authority have market power in wholesale power markets.  Based on the failed market share screen test, the FERC established a rebuttable presumption that the Company and OER have the ability to exercise market power in the Company’s control area.  On August 8, 2005, the Company and OER informed the FERC that they would:  (i) adopt the FERC default rate mechanism for sales of one week or less to loads that sink in the Company’s control area and (ii) commit not to enter into any sales with a duration of between one week and one year to loads that sink in the Company’s control area.  The Company and OER also informed the FERC that any new agreements for long-term sales (one year or longer in duration) to loads that sink in the Company’s control area would be filed with the FERC and that the Company and OER would not make such sales under their respective market-based rate tariffs.  On March 21, 2006, the FERC issued an order conditionally accepting the Company’s and OER’s proposal to mitigate the presumption of market power in the Company’s control area.  First, the FERC accepted the additional information related to first-tier markets submitted by the Company and OER, and concluded that the Company and OER satisfy the FERC’s generation market power standard for directly interconnected first-tier control areas.  Second, the FERC directed the Company and OER to make certain revisions to its mitigation proposal and file a cost-based rate tariff for short-term sales (one week or less) made within the Company’s control area. The FERC also expanded the scope of the proposed mitigation to all sales made within the Company’s control area (instead of only to sales sinking to load within the Company’s control area).  As part of the market-based rate matter, the Company and OER have filed a series of tariff revisions to comply with the FERC orders and such revisions have been accepted by the FERC.  Also, as part of the mitigation for the failed market share screen test discussed above, on an ongoing basis, the Company and OER file change of status reports and triennial market power reports according to the FERC orders and regulations.  In July 2009, the Company and OER filed a triennial market power update with the FERC which reported that there have been no significant changes to the Company’s and OER’s market-based rate authority. On July 21, 2010, the FERC issued an order accepting the Company’s July 2009 triennial market power update and found no change from the previous market-based rate authorizations.</font></div><div style="TEXT-INDENT: 0pt; DISPLAY: block; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"> </div><div style="TEXT-INDENT: 40pt; DISPLAY: block; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"><font style="DISPLAY: inline; FONT-FAMILY: Times New Roman; FONT-SIZE: 12pt">On October 14, 2010, OER filed with the FERC a Notice of Cancellation of OER’s market-based rate tariff.  OER does not currently make wholesale sales pursuant to its market-based rate authorization, has not done so in several years and does not anticipate doing so in the foreseeable future. Additionally, OER has no outstanding transactions under its market-based rate tariff, so no customers will be affected by the filing.  OER also requested a waiver of the prior notice filing requirement to allow termination of its market-based rate tariff effective as of October 13, 2010. On November 22, 2010, the FERC issued an order approving OER’s Notice of Cancellation, effective December 13, 2010.</font></div><div style="TEXT-INDENT: 0pt; DISPLAY: block; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"> </div><div style="TEXT-INDENT: 40pt; DISPLAY: block; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"><font style="DISPLAY: inline; FONT-FAMILY: Times New Roman; FONT-SIZE: 12pt">On November 9, 2010, OER filed with the FERC a Notice of Cancellation of OER’s cost-based rate tariff. OER does not currently make wholesale sales pursuant to its cost-based rate authorization, has not done so in several years and does not anticipate doing so in the foreseeable future. Additionally, OER has no outstanding transactions under its cost-based rate tariff, so no customers will be affected by the filing. OER also requested a waiver of the prior notice filing requirement to allow termination of its cost-based rate tariff effective as of October 13, 2010.  On December 15, 2010, the FERC issued an order approving OER’s Notice of Cancellation, effective October 13, 2010.</font></div><div style="TEXT-INDENT: 0pt; DISPLAY: block; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"> </div><div style="TEXT-INDENT: 0pt; DISPLAY: block; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"><font style="DISPLAY: inline; FONT-FAMILY: Times New Roman; FONT-SIZE: 12pt; FONT-WEIGHT: bold">Pending Regulatory Matters</font></div><div style="TEXT-INDENT: 0pt; DISPLAY: block; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"> </div><div style="TEXT-INDENT: 0pt; DISPLAY: block; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"><font style="FONT-STYLE: italic; DISPLAY: inline; FONT-FAMILY: Times New Roman; FONT-SIZE: 12pt; FONT-WEIGHT: bold">2010 Arkansas Rate Case Filing</font></div><div style="TEXT-INDENT: 0pt; DISPLAY: block; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"> </div><div style="TEXT-INDENT: 40pt; DISPLAY: block; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"><font style="DISPLAY: inline; FONT-FAMILY: Times New Roman; FONT-SIZE: 12pt">On September 28, 2010, the Company filed a rate case with the APSC requesting a rate increase of $17.7 million, to recover the cost of significant electric system expansions and upgrades, including high-voltage transmission lines and wind energy, that have been completed since the last rate filing in August 2008, as well as rising operating costs. If approved, the targeted implementation date for new electric rates is expected to be during the third quarter of 2011. A hearing in this matter is scheduled for May 24, 2011.</font></div><div style="TEXT-INDENT: 0pt; DISPLAY: block; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"> </div><div style="TEXT-INDENT: 0pt; DISPLAY: block; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"><font style="FONT-STYLE: italic; DISPLAY: inline; FONT-FAMILY: Times New Roman; FONT-SIZE: 12pt; FONT-WEIGHT: bold">SPP Cost Tracker</font></div><div style="TEXT-INDENT: 0pt; DISPLAY: block; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"> </div><div style="TEXT-INDENT: 40pt; DISPLAY: block; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"><div style="TEXT-INDENT: 36pt; DISPLAY: block; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"><font style="DISPLAY: inline; FONT-FAMILY: Times New Roman; FONT-SIZE: 12pt">On October 7, 2010, the Company filed an application with the OCC seeking recovery of the Oklahoma jurisdictional portion of (i) costs associated with transmission upgrades and facilities that have been approved by the SPP in its regional planning processes and constructed by other transmission owners throughout the SPP that have been allocated to the Company through the FERC-approved transmission rates and (ii) SPP administrative fees. The Company requested authorization to implement a cost tracker in order to recover from its retail customers the third-party project costs discussed above and to collect its administrative SPP cost assessment levied under Schedule 1A of the SPP open access transmission tariff, which is currently recovered in base rates.  The Company also requested authorization to establish a regulatory asset effective January 1, 2011 in order to give the Company the opportunity to recover such costs that will be paid but not recovered until the cost tracker is made effective. On February 8, 2011, all parties signed a settlement agreement in this matter which would allow the Company to begin recovering the incremental transmission costs allocated to the Company by the SPP for base plan transmission projects built by other transmission owners in the SPP through a recovery rider effective January 1, 2011. The Company anticipates recovering $1.8 million of incremental revenues in 2011 through the rider. The Company had requested the inclusion of the incremental SPP administrative fee assessment in the recovery rider. Rather than including these costs in the recovery rider, the stipulating parties agreed to allow the Company to include the projected 2012 level of the SPP administrative fee assessment in its anticipated Oklahoma rate case to be filed in the summer of 2011. A hearing on the settlement is scheduled for February 17, 2011. The Company expects to receive an order from the OCC in this matter during the second quarter of 2011.</font></div></div><div style="TEXT-INDENT: 0pt; DISPLAY: block"><br /></div><div style="TEXT-INDENT: 0pt; DISPLAY: block; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"><font style="FONT-STYLE: italic; DISPLAY: inline; FONT-FAMILY: Times New Roman; FONT-SIZE: 12pt; FONT-WEIGHT: bold">FERC Transmission Rate Incentive Filing</font></div><div style="TEXT-INDENT: 0pt; DISPLAY: block; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"> </div><div style="TEXT-INDENT: 40pt; DISPLAY: block; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"><div style="TEXT-INDENT: 36pt; DISPLAY: block; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"><font style="DISPLAY: inline; FONT-FAMILY: Times New Roman; FONT-SIZE: 12pt">On October 12, 2010, the Company submitted to the FERC revised tariff sheets to its open access transmission tariff and to the SPP open access transmission tariff to implement two limited transmission rate incentives.  If approved by the FERC, the revised tariff sheets will authorize recovery of 100 percent of all prudently incurred construction work in progress in rate base for specific 345 kV EHV transmission projects to be constructed and owned by the Company within the SPP’s region.  In addition, if approved by the FERC, the revised tariff sheets will authorize the Company to recover 100 percent of all prudently incurred development and construction costs if the transmission projects are abandoned or cancelled, in whole or in part, for reasons beyond the Company’s control.  On December 30, 2010, the FERC granted these two incentives for the Priority Projects discussed below.  Also, the Company plans to make a filing with the FERC in February 2011 to seek the incentives for at least five other projects.</font></div></div><div style="TEXT-INDENT: 0pt; DISPLAY: block"><br /></div><div style="TEXT-INDENT: 0pt; DISPLAY: block; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"><font style="FONT-STYLE: italic; DISPLAY: inline; FONT-FAMILY: Times New Roman; FONT-SIZE: 12pt; FONT-WEIGHT: bold">SPP Transmission/Substation Projects</font></div><div style="TEXT-INDENT: 0pt; DISPLAY: block; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"> </div><div style="TEXT-INDENT: 40pt; DISPLAY: block; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"><font style="DISPLAY: inline; FONT-FAMILY: Times New Roman; FONT-SIZE: 12pt"><font style="DISPLAY: inline; FONT-FAMILY: Times New Roman">The SPP is a regional transmission organization under the jurisdiction of the FERC that was created to ensure reliable supplies of power, adequate transmission infrastructure and competitive wholesale prices of electricity. </font>The SPP does not build transmission though <font style="DISPLAY: inline; FONT-FAMILY: Times New Roman">the SPP’s tariff contains</font> rules that govern the transmission construction process.  Transmission owners complete the construction and then own, operate and maintain transmission assets within the SPP region. When the SPP Board of Directors approves a project, the transmission provider in the area where the project is needed has the first obligation to build. </font></div><div style="TEXT-INDENT: 0pt; DISPLAY: block; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"> </div><div style="TEXT-INDENT: 40pt; DISPLAY: block; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"><font style="DISPLAY: inline; FONT-FAMILY: Times New Roman; FONT-SIZE: 12pt"><font style="DISPLAY: inline; FONT-FAMILY: Times New Roman">There are several studies currently under review at the SPP including a 20-year plan</font> to address issues of regional and interregional importance. The <font style="DISPLAY: inline; FONT-FAMILY: Times New Roman">20-year plan</font> suggests overlaying the SPP footprint with a 345 <font style="DISPLAY: inline; FONT-FAMILY: Times New Roman">kV</font> transmission system and integrating it with neighboring regional entities. In 2009, the SPP Board of Directors approved a new report that recommended restructuring the SPP’s regional planning processes to focus on the construction of a robust transmission system, large enough in both scale and geography, to provide flexibility to meet the SPP’s future needs. T<font style="DISPLAY: inline; FONT-FAMILY: Times New Roman">he Company </font>expects to actively participate in the ongoing study, development and transmission growth that may result from the SPP’s plans.</font></div><div style="TEXT-INDENT: 0pt; DISPLAY: block; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"> </div><div style="TEXT-INDENT: 40pt; DISPLAY: block; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"><font style="DISPLAY: inline; FONT-FAMILY: Times New Roman; FONT-SIZE: 12pt">In 2007, the SPP notified the Company to construct 44 miles of a new 345 kV transmission line which will originate at the Company’s existing Sooner 345 kV substation and proceed generally in a northerly direction to the Oklahoma/Kansas Stateline (referred to as the Sooner-Rose Hill project). At the Oklahoma/Kansas Stateline, the line will connect to the companion line being constructed in Kansas by Westar Energy. Construction of the line is estimated to begin in mid-2011 and the line is estimated to be in service by June 2012. </font></div><div style="TEXT-INDENT: 40pt; DISPLAY: block; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"> </div><div style="TEXT-INDENT: 40pt; DISPLAY: block; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"><div style="TEXT-INDENT: 40pt; DISPLAY: block; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"><div style="TEXT-ALIGN: justify; TEXT-INDENT: 36pt; DISPLAY: block; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt"><font style="DISPLAY: inline; FONT-FAMILY: Times New Roman; FONT-SIZE: 12pt"> In January 2009, the Company received notification from the SPP to begin construction on 50 miles of a new 345 kV transmission line and substation upgrades at the Company’s Sunnyside substation, among other projects. In April 2009, Western Farmers Electric Cooperative assigned to the Company the construction of 50 miles of line designated by the SPP to be built by Western Farmers Electric Cooperative.  The new line will extend from the <font style="FONT-FAMILY: Times New Roman; FONT-SIZE: 12pt">Company’s</font> Sunnyside substation near Ardmore, Oklahoma, 123.5 miles to the Hugo substation owned by Western Farmers Electric Cooperative near Hugo, </font><font style="DISPLAY: inline; FONT-FAMILY: Times New Roman; FONT-SIZE: 12pt">Oklahoma.  The Company began preliminary line routing and acquisition of rights-of-way in June 2009. Construction began in January 2011. When construction is completed, which is expected in April 2012, the SPP will allocate a portion of the annual revenue requirement to Company customers according to the regional cost allocation mechanism as provided in the SPP tariff for application to such improvements. </font></div></div></div><div style="TEXT-INDENT: 0pt; DISPLAY: block; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"> </div><div style="TEXT-INDENT: 40pt; DISPLAY: block; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"><font style="DISPLAY: inline; FONT-FAMILY: Times New Roman; FONT-SIZE: 12pt">On April 28, 2009, the SPP approved the Balanced Portfolio 3E projects.  Balanced Portfolio 3E includes four projects to be built by the Company and includes: (i) construction of 120 miles of transmission line from the Company’s Seminole substation in a northeastern direction to the Company’s Muskogee substation at a cost of $180 million for the Company, which is expected to be in service by December 2013, (ii) construction of 72 miles of transmission line from the Company’s Woodward District EHV substation in a southwestern direction to the Oklahoma/Texas Stateline to a companion transmission line to be built by Southwestern Public Service to its Tuco substation at a cost of $120 million for the Company, which is expected to be in service by April 2014, (iii) construction of 38 miles of transmission line from the Company’s Sooner substation in an eastern direction to the Grand River Dam Authority Cleveland substation at an estimated cost of $65 million for the Company, which is expected to be in service by December 2012 and (iv) construction of a new substation near Anadarko which is expected to consist of a 345/138 kV transformer and substation breakers and will be built in the Company’s portion of the Cimarron-Lawton East Side 345 kV line at an estimated cost of $15 million for the Company, which is expected to be in service by December 2011.  On June 19, 2009, the Company received a notice to construct the Balanced Portfolio 3E projects from the SPP.  On July 23, 2009, the Company responded to the SPP that the Company will construct the Balanced Portfolio 3E projects discussed above beginning in early 2011.   </font></div><div style="TEXT-INDENT: 0pt; DISPLAY: block; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"> </div><div style="TEXT-INDENT: 40pt; DISPLAY: block; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"><font style="DISPLAY: inline; FONT-FAMILY: Times New Roman; FONT-SIZE: 12pt">On April 27, 2010, the SPP approved, contingent upon approval by the FERC of a regional cost allocation methodology filed with the FERC by the SPP, a set of transmission projects titled “Priority Projects.” The Priority Projects consist of several transmission projects, two of which have been assigned to the Company. The 345 kV projects include: (i) construction of 92 miles of transmission line from the Company’s Woodward District EHV substation to a companion transmission line to be built by Southwestern Public Service to its Hitchland substation in the Texas Panhandle at a cost of $180 million for the Company, which is expected to be in service by June 2014 and (ii) construction of 80 miles of transmission line from the Company’s Woodward District EHV substation to a companion transmission line at the Kansas border to be built by either Mid-Kansas Electric Company or another company assigned by Mid-Kansas Electric Company at a cost of $135 million to the Company, which is expected to be in service by December 2014. On June 17, 2010, the FERC approved the cost allocation filed by the SPP and notices to construct these Priority Projects were issued by the SPP on June 30, 2010. On September 27, 2010, the Company responded to the SPP that the Company will construct the Priority Projects discussed above beginning in June 2012. The scope of the Woodward District EHV substation/Kansas border Priority Project was subsequently revised and the SPP Board of Directors approved this revision in October 2010. The SPP issued a revised notice to construct for this Priority Project on November 22, 2010. On February 4, 2011, the Company responded to the SPP that the Company will construct the revised Priority Project.</font></div><div style="TEXT-INDENT: 0pt; DISPLAY: block; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"> </div><div style="TEXT-INDENT: 40pt; DISPLAY: block; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"><font style="DISPLAY: inline; FONT-FAMILY: Times New Roman; FONT-SIZE: 12pt">The capital expenditures related to the Sooner-Rose Hill, Sunnyside-Hugo, Balanced Portfolio 3E and Priority Projects are presented in the summary of capital expenditures for known and committed projects in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources – Future Capital Requirements and Financing Activities.”</font></div><div style="TEXT-INDENT: 0pt; DISPLAY: block; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"> </div><div style="TEXT-INDENT: 0pt; DISPLAY: block; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"><font style="FONT-STYLE: italic; DISPLAY: inline; FONT-FAMILY: Times New Roman; FONT-SIZE: 12pt; FONT-WEIGHT: bold">Review of the Company’s Fuel Adjustment Clause for Calendar Year 2009</font></div><div style="TEXT-INDENT: 0pt; DISPLAY: block; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"> </div><div style="TEXT-INDENT: 40pt; DISPLAY: block; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"><font style="DISPLAY: inline; FONT-FAMILY: Times New Roman; FONT-SIZE: 12pt">On October 29, 2010, the OCC Staff filed an application for a public hearing to review and monitor the Company’s application of the 2009 fuel adjustment clause.  On December 28, 2010, the Company responded by filing the necessary information and documents to satisfy the OCC’s minimum filing requirement rules. A procedural schedule was established in this matter with a hearing scheduled to begin on April 28, 2011.</font></div><div style="TEXT-INDENT: 0pt; DISPLAY: block; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"> </div><div style="TEXT-INDENT: 0pt; DISPLAY: block; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="left"><font style="FONT-STYLE: italic; DISPLAY: inline; FONT-FAMILY: Times New Roman; FONT-SIZE: 12pt; FONT-WEIGHT: bold">North American Electric Reliability Corporation</font></div><div style="TEXT-INDENT: 0pt; DISPLAY: block; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"> </div><div style="TEXT-INDENT: 40pt; DISPLAY: block; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"><font style="DISPLAY: inline; FONT-FAMILY: Times New Roman; FONT-SIZE: 12pt">The Energy Policy Act of 2005 gave the FERC authority to establish mandatory electric reliability rules enforceable with monetary penalties.  The FERC approved the NERC as the Electric Reliability Organization for North America and delegated to it the development and enforcement of electric transmission reliability rules.  In September 2009, the Company completed a NERC CIP spot check audit. Resolution of any audit findings is expected in early 2011; however, the Company does not expect the resolution of any audit findings to have a material impact on its operations.  The Company is subject to a NERC compliance audit every three years as well as periodic spot check audits.  The next compliance audit is scheduled for April 2011, which will incorporate both NERC CIP and non-CIP standards.</font></div><div style="TEXT-INDENT: 0pt; DISPLAY: block; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"> </div><div style="TEXT-INDENT: 0pt; DISPLAY: block; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"><font style="FONT-STYLE: italic; DISPLAY: inline; FONT-FAMILY: Times New Roman; FONT-SIZE: 12pt; FONT-WEIGHT: bold">State Legislative Initiative</font></div><div style="TEXT-INDENT: 0pt; DISPLAY: block; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"> </div><div style="TEXT-INDENT: 40pt; DISPLAY: block; MARGIN-LEFT: 0pt; MARGIN-RIGHT: 0pt" align="justify"><font style="DISPLAY: inline; FONT-FAMILY: Times New Roman; FONT-SIZE: 12pt">House Bill 3028 became effective in May 2010 and established an Oklahoma renewable portfolio standard with a statewide goal of renewable energy capacity (on an installed electric generation capacity basis) of 15 percent by year 2015. House Bill 3028 also designated natural gas as the preferred fuel for all new fossil fuel electric generation in Oklahoma until year 2020, but provides that the OCC may determine that a fossil fuel other than natural gas is in the best interest of customers.  By the year 2012, the Company expects that its installed electric generation capacity basis for wind-powered units will be 10 percent.</font></div>13.           Rate Matters and Regulation Regulation and Rates The Company’s retailfalsefalsefalsefalsefalseOtherus-types:textBlockItemTypestringDescribes all of the specific events that have or may impact rates and amortization of regulatory assets and liabilities (for example, pending or recently concluded regulatory proceedings). Specifics may include quantifications related to rates, costs, and earnings. Events may relate to rate moratoriums or price tags.No authoritative reference available.falsefalse12Rate Matters and RegulationUnKnownUnKnownUnKnownUnKnownfalsetrue