The Missouri Public Service Commission (MPSC) approved a joint settlement agreement allowing us to defer actual incremental operating and maintenance expenses associated with the repair, restoration and rebuilding activities resulting from the tornado which hit our service territory on May 22, 2011. In addition, depreciation related to the capital expenditures will be deferred and a carrying charge will be accrued. These amounts, which were approximately $1.6 million as of December 31, 2011, have been recorded as a regulatory asset.

Construction accounting, as approved by the MPSC in our 2005 regulatory plan, permitted the deferral of charges for depreciation, operations and maintenance and carrying costs related to the operation of Iatan 1 and Iatan 2 until they were ultimately included in our rates. Construction accounting was also applied to Plum Point construction costs incurred subsequent to February 28, 2010. All of these deferrals began at the plants' respective in-service dates, and ended when recovery began in rates. All of these deferrals are being amortized over the life of the plants beginning on June 15, 2011, the effective date of rates for our recently completed Missouri rate case. As of December 31, 2011 these deferrals totaled $17.1 million and were recorded as regulatory assets. The regulatory plan also required us to continue to defer the fuel and purchased power expense impacts of Iatan 2, which were approximately $8.3 million as of December 31, 2011 and are recorded in Non-Current Regulatory Liabilities. Through December 31, 2011, $6.6 million in regulatory plan amortization had been recognized.

As part of a stipulated agreement in our 2009 Kansas rate case, approved by the KCC on June 25, 2010, we also defered depreciation and operating and maintenance expense on both Plum Point and Iatan 2 from their respective in-service dates until the effective date for rates from the next Kansas case, which was January 1, 2012. These deferrals will be recovered over a 4 year period.

Changes to regulatory assets and liabilities regarding their rate base inclusion or amortizable lives since December 31, 2010 are as follows: As a result of our recently completed Missouri rate case, a tracking mechanism has been created to flow the 2010 SWPA payment, net of associated taxes, back to our customers (see Note 9). The Missouri, Kansas and Oklahoma jurisdictional portions of the payment will be amortized over ten years and reflected as a reduction to fuel expense, while the Arkansas jurisdictional portion of the 2010 SWPA payment will be amortized on a straight-line basis over a 50 year period. A tracking mechanism was also created by Missouri related to the Plum Point, Iatan 2 and Iatan common plant operating expenses. The Missouri tracker is to exclude consumables and SO₂ allowances which are recovered through the fuel adjustment clause. A regulatory asset or liability will be recorded for the difference between the Missouri jurisdictional portion of actual expenses and the annual recovery allowance with a corresponding charge or credit to regulated operating expense.

The following table sets forth the components of our regulatory assets and regulatory liabilities on our consolidated balance sheet (in thousands).

	December 31,

	2011		2010
Regulatory Assets:
Under recovered purchased gas costs — gas segment — current	$	211	$	—
Under recovered electric fuel and purchased power costs — current		7,513		4,974

Regulatory assets, current⁽¹⁾		7,724		4,974

Pension and other postretirement benefits⁽²⁾		121,058		92,192
Income taxes		49,631		50,188
Deferred construction accounting costs⁽³⁾		17,095		10,521
Unamortized loss on reacquired debt		11,610		13,099
Unsettled derivative losses — electric segment		7,839		3,166
System reliability — vegetation management		6,569		3,338
Storm costs⁽⁴⁾		5,303		7,733
Asset retirement obligation		3,571		3,412
Customer programs		3,408		2,119
Unamortized loss on interest rate derivative		1,462		1,776
Other		1,420		473
Under recovered purchased gas costs — gas segment		1,281		439
Deferred operating and maintenance expense		952		—
Asbury five-year maintenance		492		948
Under recovered electric fuel and purchased power costs		231		—

Regulatory assets, long-term		231,922		189,404

TOTAL REGULATORY ASSETS	$	239,646	$	194,378

Regulatory Liabilities
Over recovered purchased gas costs — gas segment — current	$	—	$	1,243

Regulatory liabilities, current⁽¹⁾		—		1,243

Costs of removal		73,562		62,756
SWPA payment for Ozark Beach lost generation		25,074		—
Income taxes		12,337		12,715
Deferred construction accounting costs — fuel		8,304		3,126
Unamortized gain on interest rate derivative		3,711		3,881
Pension and other postretirement benefits⁽⁵⁾		2,939		4,604
Over recovered electric fuel and purchased power costs		2,513		409
Other		—		88

Regulatory liabilities, long-term		128,440		87,579

TOTAL REGULATORY LIABILITIES	$	128,440	$	88,822


(3)	Balances as of December 31, 2011	Deferred Carrying Charges		Deferred O&M		Depreciation		Total
	Iatan 1	$	2,728		1,363		1,652	$	5,743
	Iatan 2	$	3,891		4,271		2,728	$	10,890
	Plum Point	$	65		239		158	$	462

	Total							$	17,095

	Balances as of December 31, 2011	Deferred Carrying Charges		Deferred O&M		Depreciation		Total
	Iatan 1	$	2,779		1,388		1,682	$	5,849
	Iatan 2	$	1,770		1,643		1,111	$	4,524
	Plum Point	$	33		70		45	$	148

	Total							$	10,521

Unamortized losses on debt and losses on interest rate derivatives are not included in rate base, but are included in our capital structure for rate base purposes. The remainder of our regulatory assets are not included in rate base, generally because they are not cash items or they are earning carrying costs. However, as of December 31, 2011, the costs of all of our regulatory assets are currently being recovered except for approximately $113.8 million of pension and other postretirement costs primarily related to the unfunded liabilities for future pension and OPEB costs. The amount and timing of recovery of this item will be based on the changing funded status of the pension and OPEB plans in future periods.

The regulatory income tax assets and liabilities are generally amortized over the average depreciable life of the related assets. The loss on reacquired debt and the loss and gain on interest rate derivatives are amortized over the life of the related new debt issue, which currently ranges from 2 to 30 years. The unrecovered fuel costs are generally recovered within a year following their recognition. Severe storm costs and the Asbury five-year maintenance costs are recovered over five years. Pension and other postretirement benefit tracking mechanisms are recovered over a five year period. The cost of removal regulatory liability is amortized as removal costs are incurred.

We continually assess the need for rate relief in all of the jurisdictions we serve and file for such relief when necessary.

Our rates for retail electric and natural gas services (other than specially negotiated retail rates for industrial or large commercial customers, which are subject to regulatory review and approval) are determined on a "cost of service" basis. Rates are designed to provide, after recovery of allowable operating expenses, an opportunity for us to earn a reasonable return on "rate base." "Rate base" is generally determined by reference to the original cost (net of accumulated depreciation and amortization) of utility plant in service, subject to various adjustments for deferred taxes and other items. Over time, rate base is increased by additions to utility plant in service and reduced by depreciation, amortization and retirement of utility plant or write-off's as ordered by the utility commissions. In general, a request of new rates is made on the basis of a "rate base" as of a date prior to the date of the request and allowable operating expenses for a 12-month test period ended prior to the date of the request. Although the current rate making process provides recovery of some future changes in rate base and operating costs, it does not reflect all changes in costs for the period in which new retail rates will be in place. This results in a lag (commonly referred to as "regulatory lag") between the time we incur costs and the time when we can start recovering the costs through rates.

The following table sets forth information regarding electric and water rate increases since January 1, 2009:

Jurisdiction	Date Requested	Annual Increase Granted

Missouri — Electric	September 28, 2010	$	18,700,000	4.70	%	June 15, 2011
Missouri — Electric	October 29, 2009	$	46,800,000	13.40	%	September 10, 2010
Kansas — Electric	June 17, 2011	$	1,250,000	5.20	%	January 1, 2012
Kansas — Electric	November 4, 2009	$	2,800,000	12.40	%	July 1, 2010
Oklahoma — Electric	June 30, 2011	$	240,722	1.66	%	January 4, 2012
Oklahoma — Electric	January 28, 2011	$	1,063,100	9.32	%	March 1, 2011
Oklahoma — Electric	March 25, 2010	$	1,456,979	15.70	%	September 1, 2010
Arkansas — Electric	August 19, 2010	$	2,104,321	19.00	%	April 13, 2011
Missouri — Gas	June 5, 2009	$	2,600,000	4.37	%	April 1, 2010

On September 28, 2010, we filed a rate increase request with the MPSC for an annual increase in base rates for our Missouri electric customers in the amount of $36.5 million, or 9.2% to recover the Iatan 2 costs and other cost of service items not included in our 2009 Missouri rate case, effective September 10, 2010. A settlement agreement among the parties to the case was reached and filed with the MPSC on May 27, 2011 reflecting an overall annual increase in rates of $18.7 million, or approximately 4.7% effective on June 15, 2011. Due to rate design changes, this rate increase, however, primarily impacts our winter season rates which generally run from October through May. Also as part of the settlement, regulatory amortization expense of $14.5 million annually and construction accounting terminated as of June 15, 2011. The MPSC approved the settlement agreement on June 1, 2011 and the new rates were effective on June 15, 2011. The approved settlement included authorization of a tracker mechanism for the SWPA payment associated with the capacity restrictions to be implemented for our Ozark Beach hydro facility. We agreed to flow the SWPA payment, net of tax, back to our customers over a ten year period using a tracker mechanism resulting in an annual decrease to expenses of approximately $1.4 million. The settlement agreement also allowed for a tracker mechanism related to Plum Point, Iatan 2 and Iatan common plant operating expenses. We will record a regulatory asset or liability for the difference between actual expenses (excluding fuel and fuel related expenses) and the amount of expense included in base rates.

On October 29, 2009, we filed a request with the MPSC for an annual increase in base rates for our Missouri electric customers in the amount of $68.2 million, or 19.6%. This request was primarily designed to allow us to recover capital expenditures associated with environmental upgrades at Iatan 1 and our investment in new generating units at Iatan 2 and the Plum Point Generating Station. As a result of the delay in the Iatan 2 project, however, we agreed to not seek a permanent increase in this rate case for any costs associated with the Iatan 2 unit with the exception of that portion of the Iatan common plant needed to operate Iatan 1.

A stipulated agreement was filed on May 12, 2010, calling for an annual increase of $46.8 million, provided the Plum Point Generating Station met its in-service criteria by August 15, 2010. If the in-service criteria were not met by such date, a base rate increase of $33.1 million was stipulated. The Plum Point Generating Station completed its in-service criteria testing on August 12, 2010, with an in-service date of August 13, 2010, thus new rates, providing for the full increase of $46.8 million, were effective September 10, 2010. The $46.8 million authorized increase in annual revenues includes $36.8 million in base rate revenue and $10 million in regulatory amortization. The regulatory amortization, which is treated as additional book depreciation for rate-making purposes and is reflected in the financial statements, was granted to provide additional cash flow through rates. This regulatory amortization is related to our investments in facilities and environmental upgrades completed during the recent construction cycle. As agreed in our regulatory plan, we used construction accounting for our Iatan 2 project. As noted above, regulatory amortization expense of $14.5 million annually and construction accounting terminated as of June 15, 2011 as a result of our 2010 rate case (See Note 3 and Note 11). We also agreed to commence an eighteen year amortization of a deferred asset related to the tax benefits of cost of removal. These tax benefits were flowed through to customers from 1981 to 2008 and totaled approximately $11.1 million. We had previously recorded a regulatory asset expecting to recover these benefits from customers in future periods. We estimated the portion of the amortization period where rate recovery would no longer be probable for this item and wrote off approximately $1.2 million in the first quarter of 2010. Amortization of the remaining regulatory tax asset began during the third quarter of 2011 (See Note 9).

The MPSC issued an order on July 30, 2008 in response to a request filed with the MPSC on October 1, 2007 for an annual increase in base rates for our Missouri electric customers. This order granted an annual increase in revenues for our Missouri electric customers in the amount of $22.0 million, or 6.7%, based on a 10.8% return on equity. The new rates went into effect August 23, 2008.

The MPSC also authorized a fuel adjustment clause for our Missouri customers effective September 1, 2008. The MPSC established a base cost for the recovery of fuel and purchased power expenses used to supply energy. The clause permits the distribution to customers of 95% of the changes in fuel and purchased power costs above or below the base cost. Off-system sales margins are also part of the recovery of fuel and purchased power costs. As a result, the off-system sales margin flows back to the customer. Rates related to the recovery of fuel and purchased power costs will be modified twice a year subject to the review and approval by the MPSC. In accordance with accounting guidance for regulated activities, 95% of the difference between the actual cost of fuel and purchased power and the base cost of fuel and purchased power recovered from our customers is recorded as an adjustment to fuel and purchased power expense with a corresponding regulatory asset or a regulatory liability. If the actual fuel and purchased power costs are higher or lower than the base fuel and purchased power costs billed to customers, 95% of these amounts will be recovered or refunded to our customers when the fuel adjustment clause is modified.

The MPSC issued its Report and Order on July 30, 2008, effective August 9, 2008. The OPC and intervenors Praxair, Inc. and Explorer Pipeline Company filed applications for rehearing with the MPSC regarding this order. On August 12, 2008, the MPSC issued its Order Granting Expedited Treatment and Approving Compliance Tariff Sheets, effective August 23, 2008, in which the MPSC approved our tariff sheets containing our base rates for service rendered on and after August 23, 2008, and approved our fuel adjustment clause tariff sheets effective September 1, 2008. On September 3, 2008, the MPSC denied all pending applications for rehearing.

On October 2, 2008, the OPC and intervenors Praxair, Inc. and Explorer Pipeline Company filed Petitions for Writ of Review with the Cole County Circuit Court. These actions were consolidated into one proceeding, briefs were filed and the Cole County Circuit Court heard oral arguments on September 29, 2009. The Cole County Circuit Court issued a ruling on December 31, 2009, affirming the Commission's Report and Order. OPC, Praxair and Explorer Pipeline filed appeals with the Western District Court of Appeals. On August 2, 2011, the Western District Court of Appeals issued a ruling affirming the Commission's Report and Order.

On June 6, 2011, we filed an Accounting Authority Order with the MPSC requesting authorization to defer expenses associated with the tornado and to allow for recovery of the loss of the fixed cost component included in our rates resulting from the lost sales. On June 23, 2011, Praxair, Inc. and Explorer Pipeline Company filed as intervenors with the MPSC, who granted their request on July 6, 2011. On November 15, 2011, following extensive negotiations, the parties filed a joint settlement agreement with the MPSC allowing us to defer actual incremental operating and maintenance expenses associated with the repair, restoration and rebuilding activities resulting from the tornado. In addition, depreciation related to the capital expenditures will be deferred and a carrying charge will be accrued. In the event that an electric rate request is filed in Missouri by June 1, 2013, a ten-year amortization of the deferral will begin. The settlement does not include deferral of the fixed cost component associated with the reduction in customers served by us as a result of the tornado. On November 30, 2011, the MPSC issued an order approving the settlement agreement, effective December 7, 2011. Approximately $1.6 million has been deferred under this agreement.

On June 17, 2011, we filed an application with the KCC seeking a rate increase of $1.5 million, or 6.39%. The rate increase was requested to recover the costs associated with our investment in the Iatan 1, Iatan 2 and Plum Point generating units and the depreciation and operation and maintenance costs deferred since the in-service dates of the units. The June 17, 2011 filing was made under the KCC's abbreviated rate case rules which the KCC authorized in our 2009 Kansas rate case. The case included a request to recover the Iatan and Plum Point cost deferrals over a 3-year period. A joint settlement agreement was filed on November 10, 2011 and approved by the KCC on December 21, 2011, resulting in an increase in annual revenues of $1.25 million, or approximately 5.2%. The new rates became effective on January 1, 2012.

On November 4, 2009, we filed a request with the KCC for an annual increase in base rates for our Kansas electric customers in the amount of $5.2 million, or 24.6%. This request was primarily to allow us to recover capital expenditures associated with environmental upgrades at Iatan 1 completed in 2009 and at our Asbury plant completed in 2008 and our investment in new generating units at Iatan 2, the Plum Point Generating Station and our Riverton 12 unit that went on line in 2007. A stipulated agreement was filed on May 4, 2010, and approved by the KCC on June 25, 2010, calling for a $2.8 million, or 12.4%, increase in base rates effective July 1, 2010. We agreed to defer depreciation and operating and maintenance expense on both Plum Point and Iatan 2 from their respective in-service dates until the effective date of the rates from the next Kansas case, which was filed on June 17, 2011. We recorded AFUDC on all Plum Point and Iatan 2 capital expenditures incurred after January 31, 2010.

On March 25, 2010, we requested a capital cost recovery rider (CCRR) at the OCC. The rider was designed to recover the carrying costs on our capital investment for generation, transmission and distribution assets that have been added to the system since our last Oklahoma general rate case (May 2003), as well as investments made on an ongoing basis. As requested, the operation of the CCRR would have increased our operating revenue by approximately $3 million, or approximately 33%, in Oklahoma in a series of three steps to be followed with a general rate case in 2011. On August 30, 2010, we were granted a two-phase Capital Reliability Rider (CRR) by the OCC. The first phase of the rider was put into place for Oklahoma customers for usage on and after September 1, 2010, and resulted in an overall annual base revenue increase of approximately $1.5 million, or 15.7%. In total, the CRR revenue has been specifically limited by the OCC to an overall annual revenue increase of $2.6 million, or 27.67% increase. On January 28, 2011 we requested the approval by the OCC of the phase 2 rates of the CRR. We requested an additional $1.1 million, which brought the total annual revenue under the OCC to approximately $2.5 million. On June 30, 2011, we filed a request with the OCC for an annual increase in base rates for our Oklahoma electric customers in the amount of $0.6 million, or 4.1% over the base rate and CRR revenues that were currently in effect. A stipulation and agreement, reached by all parties participating in the case, was filed on November 16, 2011. This agreement, which was approved by the OCC on January 4, 2012, made rates previously collected under the CRR permanent, and will result in a net overall increase of total annual revenues of $0.2 million, or approximately 1.66%. The agreement also removes fuel and purchase power costs from base rates. Fuel and purchase power costs will be listed as a separate line item, identified as the Fuel Adjustment Charge, on customer bills.

On August 19, 2010, we filed a rate increase request with the Arkansas Public Service Commission (APSC) for an annual increase in base rates for our Arkansas electric customers in the amount of $3.2 million, or 27.3%. On February 2, 2011 we entered into a unanimous settlement agreement with the parties involved. The settlement included a general rate increase of $2.1 million, or 19%, and called for the implementation of a new tariff, the Transmission Cost Recovery Rider (TCR) designed to track changes in the cost of transmission charges from the Southwest Power Pool, Inc. The existing Energy Cost Recovery Rider was also modified to include the recovery of the costs associated with certain air quality control materials. The APSC approved the settlement on April 12, 2011 with the new rates effective April 13, 2011.

On March 12, 2010, we filed GFR tariffs with the FERC which we propose to be utilized for our wholesale customers. On May 28, 2010, the FERC issued an order that conditionally approved our GFR filing subject to refund effective June 1, 2010. As of December 31, 2010, we had collected $0.6 million in rates subject to refund. On June 30, 2010, three of our on-system wholesale customers were granted intervention in the GFR rate case. Also on May 28, 2010, we filed a notice with the FERC requesting termination of the current bundled service agreements for our wholesale customers effective July 31, 2010. On July 28, 2010, the FERC issued an order accepting and suspending the proposed terminations for a nominal period to become effective July 31, 2010, subject to refund. The FERC's order also consolidated the GFR and termination proceedings. On September 15, 2010, the parties agreed to a settlement in principle and on May 24, 2011, we, the Missouri Public Utility Alliance and the cities of Monett, Mt. Vernon and Lockwood, Missouri filed a Settlement Agreement and Offer of Settlement with the FERC. We refunded approximately $1.3 million, including interest, in November 2011 as a result of this settlement.

On June 5, 2009, we filed a request with the MPSC for an annual increase in base rates for our Missouri gas customers in the amount of $2.9 million, or 4.9%. In this filing, we requested recovery of the ongoing cost of operating and maintaining our 1,200-mile gas distribution system and a return on equity of 11.3%. On February 24, 2010, the MPSC unanimously approved an agreement among the Office of the Public Counsel (OPC), the MPSC staff and Empire for an increase of $2.6 million. Pursuant to the Agreement, new rates went into effect on April 1, 2010.

Energy Imbalance Services: The Southwest Power Pool (SPP) regional transmission organization (RTO) energy imbalance services market (EIS) provides real time energy for most participating members within the SPP regional footprint. Imbalance energy prices are based on market bids and status/availability of dispatchable generation and transmission within the SPP market footprint. In addition to energy imbalance service, the SPP RTO performs a real time security-constrained economic dispatch of all generation voluntarily offered into the EIS market to the market participants to also serve the native load.

Day Ahead Market: On April 28, 2009, the SPP Regional State Committee (SPP RSC), whose members include state commissioners from our four state commissions, and the SPP Board of Directors (SPP BOD) endorsed a cost benefit report that recommended the SPP RTO move forward with the development of a day-ahead market with unit commitment and co-optimized ancillary services market (Day-Ahead Market). Implementation of the SPP's Day-Ahead Market is scheduled for March 2014. As part of the Day-Ahead Market, the SPP RTO will create, prior to implementation of such market, a single NERC approved balancing authority to take over balancing authority responsibilities for its members, including Empire, which is expected to provide operational and economic benefits for our customers. The implementation of the Day-Ahead Market will replace the existing EIS market described above.

SPP Regional Transmission Development: On October 27, 2009, the SPP BOD endorsed a new transmission cost allocation method to replace the existing FERC accepted cost allocation method for new transmission facilities needed to continue to reliably and economically serve SPP customers, including ours, well into the future. On April 19, 2010, SPP filed revisions to its open access transmission pro forma tariff (OATT) to adopt a new highway/byway cost allocation methodology which require SPP BOD approved transmission projects of 300 kV or larger to be funded by the region at 100%, transmission projects between 100 kV and 300 kV to receive 33% regional funding with individual constructing zones to pay 67% of those projects built within the zone. For projects under 100kV, the constructing zones would pay 100% of the cost. On May 17, 2010, we filed a joint protest at the FERC with other SPP members based on our disagreement with the SPP on the allocation percentages and various other issues. On June 17, 2010, the FERC unconditionally approved the new highway/byway cost allocation method. We and other members of the SPP filed a Request for Rehearing on July 19, 2010. On October 20, 2011, the FERC issued its Order on Rehearing denying our request to review various aspects of its June 17, 2010 order. In mid December 2011, we, along with the other SPP member joint protestors, filed a Petition for Review and Motion for Stay of Procedures with the U. S. Court of Appeals for the Eight Circuit. We believe we are aggrieved by the FERC's orders because the orders authorize the SPP to allocate to us the costs of transmission projects from which we would receive either no benefits or benefits that are not roughly commensurate with the allocated costs. Our request for a stay of procedures directly relates to the SPP's efforts to adopt a method satisfactory to us for analyzing the reasonableness of the highway/byway cost allocation approach and an effective remediation process for imbalanced cost allocations. On December 16, 2011, the Eighth Circuit U.S. Court of Appeals granted our petition and stay request. We are required to make an update filing to the Court regarding the SPP Board's actions and progress of the regional allocation review process by May 2012. To date, the SPP's BOD has approved $1.4 billion in highway/byway projects to be constructed by 2017 with an additional $1.5 billion in transmission projects expected to receive approval during the first quarter of 2012. As these projects are constructed, we will be allocated a share of the costs of the projects pursuant to the FERC accepted highway/byway regional cost allocation method. We expect that these operating costs will be material, but that they will be recoverable in future rates.

On June 17, 2010, FERC issued a Notice of Proposed Rulemaking (NOPR) proposing to amend the transmission planning and cost allocation requirements established in Order No. 890 to ensure that FERC-jurisdictional services are provided on a basis that is just, reasonable and not unduly discriminatory or preferential. With respect to transmission planning, FERC said that the proposed rule would: (1) provide that local and regional transmission planning processes account for transmission needs driven by public policy requirements established by state or federal laws or regulations; (2) improve coordination between neighboring transmission planning regions with respect to interregional facilities; and (3) remove from FERC-approved tariffs or agreements a right of first refusal (ROFR) created by those documents that provides an incumbent transmission provider with an undue advantage over a non-incumbent transmission developer. Neither incumbent nor non-incumbent transmission facility developers should, as a result of a FERC-approved tariff or agreement, receive different treatment in a regional transmission planning process, FERC contended. Further, both should share similar benefits and obligations commensurate with that participation, including the right, consistent with state or local laws or regulations, to construct and own a facility that it sponsors in a regional transmission planning process and that is selected for inclusion in the regional transmission plan. With respect to cost allocation, the proposed rule would establish a closer link between transmission planning processes and cost allocation and would require cost allocation methods for intraregional and interregional transmission facilities to satisfy newly established cost allocation principles.

On July 21, 2011, the FERC issued Order No. 1000 (Transmission Planning and Cost Allocation by Transmission Owning and Operating Public Utilities). Order 1000 requires all public utility transmission providers to (among other things) facilitate non-incumbent transmission developer participation in regional transmission planning by removing from FERC-approved tariffs and agreements any language creating a federal ROFR for an incumbent transmission provider to construct transmission facilities selected in a regional transmission plan for cost allocation. As a transmission owning member of the SPP RTO, this could directly affect our rights to build transmission facilities within our service territory. A second key element of Order 1000 directed transmission providers to develop policy and procedures for interregional transmission coordination and interregional cost allocation. Since we are on the southeastern seam of the SPP, this policy will most likely have a direct impact on our customers, primarily through a potential reduction to our production costs as a result of greater access to lower cost power from within the SPP, and across this seam and the possible reduction because of the cost sharing for new transmission projects. We will continue to participate in the SPP stakeholder processes to understand the impact of Order 1000 on our ability to construct new facilities within our service territory as well as its influence on promoting construction of transmission projects on/near our borders with our neighbors. Compliance filings by the SPP to address the ROFR requirements are currently scheduled to be due October 11, 2012 and April 13, 2013 for interregional/seams planning and cost allocation.

Non-residential gas customers whose annual usage exceeds certain amounts may purchase natural gas from a source other than EDG. EDG does not have a non-regulated energy marketing service that sells natural gas in competition with outside sources. EDG continues to receive non-gas related revenues for distribution and other services if natural gas is purchased from another source by our eligible customers.

In accordance with ASC guidance on regulated operations, we currently have deferred approximately $2.0 million of expense related to rate cases under other non-current assets and deferred charges. These amounts will be amortized over varying periods based upon the completion of the specific cases. Based on past history, we expect all these expenses to be recovered in rates.