3. Regulatory Matters

Regulatory Assets and Liabilities and Other Deferred Credits

Tornado

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 $3.3 million as of December 31, 2012, have been recorded as a regulatory asset.

Construction Accounting

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 2010 Missouri rate case. As of December 31, 2012 these deferrals totaled $16.1 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 $8.2 million as of December 31, 2012 and are recorded in Current and Non-Current Regulatory Liabilities.

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

There were no changes to regulatory assets and liabilities, with regards to their rate base inclusion or amortizable lives, from December 31, 2011 to December 31, 2012. Changes to regulatory assets and liabilities regarding their rate base inclusion or amortizable lives from December 31, 2010 to December 31, 2011 are as follows: As a result of our 2010 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,

	2012		2011
Regulatory Assets:
Under recovered purchased gas costs — gas segment — current	$	1,689	$	211
Under recovered electric fuel and purchased power costs — current		1,196		7,513
Other		3,492		4,115

Regulatory assets, current⁽¹⁾		6,377		11,839

Pension and other postretirement benefits⁽²⁾		136,480		121,058
Income taxes		48,759		49,631
Deferred construction accounting costs⁽³⁾		16,277		16,717
Unamortized loss on reacquired debt		11,078		10,138
Unsettled derivative losses — electric segment		6,557		7,839
System reliability — vegetation management		8,340		5,908
Storm costs⁽⁴⁾		4,223		4,990
Asset retirement obligation		4,430		3,571
Customer programs		3,916		2,968
Unamortized loss on interest rate derivative		989		1,147
Other		584		1,338
Under recovered purchased gas costs — gas segment		—		1,281
Deferred operating and maintenance expense		2,011		990
Under recovered electric fuel and purchased power costs		314		231

Regulatory assets, long-term		243,958		227,807

TOTAL REGULATORY ASSETS	$	250,335	$	239,646

Regulatory Liabilities
SWPA payment for Ozark Beach lost generation	$	2,774	$	2,833
Other		315		317

Regulatory liabilities, current⁽¹⁾		3,089		3,150

Costs of removal		83,368		73,562
SWPA payment for Ozark Beach lost generation		19,467		22,242
Income taxes		11,972		12,337
Deferred construction accounting costs — fuel		8,011		8,156
Unamortized gain on interest rate derivative		3,371		3,541
Pension and other postretirement benefits⁽⁵⁾		2,007		2,939
Over recovered electric fuel and purchased power costs		5,826		2,513
Other		247		—

Regulatory liabilities, long-term		134,269		125,290

TOTAL REGULATORY LIABILITIES	$	137,358	$	128,440

(1): Reflects over and under recovered costs expected to be returned or recovered as applicable, within the next 12 months in Missouri rates.
(2): Primarily reflects regulatory assets resulting from the unfunded portion of our pension and OPEB liabilities and regulatory accounting for EDG acquisition costs. Approximately $0.5 million in pension and other postretirement benefit costs have been recognized since January 1, 2012 to reflect the amortization of the regulatory assets that were recorded at the time of the EDG acquisition of the Aquila, Inc. gas properties.


(3)	Balances as of December 31, 2012	Deferred Carrying Charges		Deferred O&M		Depreciation		Total
	Iatan 1	$	2,678		1,339		1,622	$	5,639
	Iatan 2	$	3,821		4,155		2,685	$	10,661
	Plum Point	$	64		195		158	$	417

	Total							$	16,717

	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

(4): Reflects ice storm costs incurred in 2007 and costs incurred as a result of the May 2011 tornado.
(5): Includes the effect of costs incurred that are more or less than those allowed in rates for the Missouri (EDE and EDG) and Kansas (EDE) portion of pension and other postretirement benefit costs. Since January 1, 2012, regulatory liabilities and corresponding expenses have been reduced by approximately $0.9 million as a result of ratemaking treatment.

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, 2012, the costs of all of our regulatory assets are currently being recovered except for approximately $130.3 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 1 to 28 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.

RATE MATTERS

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, 2010:

Jurisdiction	Date Requested	Annual Increase Granted

Missouri — Water	May 21, 2012	$	450,000	25.5	%	November 23, 2012
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

Electric Segment

Missouri

2012 Rate Case

On July 6, 2012, we filed a rate increase with the Missouri Public Service Commission (MPSC) for changes in rates for our Missouri electric customers. We are seeking an annual increase in base rate revenues of approximately $30.7 million, or 7.56%, and the continuation of the fuel adjustment clause. After factoring in the fuel adjustment clause revenue of $8.6 million paid by customers during the rate case test year, the impact of the requested annual increase in base rates is approximately $22.1 million, or 5.3%. This request was primarily designed to recover operation and maintenance expenses and capital costs associated with the May 22, 2011 tornado, Southwest Power Pool transmission charges allocated to us, operating systems replacement costs for new software systems, vegetation management costs and new depreciation rates. We are also requesting recovery of a regulatory asset related to the tax benefits of cost of removal, which was approximately $9.6 million at December 31, 2012. We asked the MPSC to implement the $6.2 million portion of the case related to the May 2011 tornado recovery costs and the post-May 2011 cost of service through interim rates. On July 23, 2012, the MPSC suspended the interim rate tariffs and scheduled an evidentiary hearing on September 10, 2012. On October 31, 2012, we received an order rejecting our request for interim tariffs. On February 15, 2013, the MPSC issued an order to delay the procedural schedule, indicating we reached an agreement in principle with the parties to our case. The order also indicated a joint stipulation is anticipated to be filed with the MPSC as early as February 22, 2013, and is still subject to final approval by the MPSC. Details of the stipulation are confidential until it is filed with the MPSC. We do not anticipate the outcome to have a materially negative impact on our financial statements.

The construction costs for our Plum Point Energy Station and Iatan 1 and 2 generating facilities, currently being recovered in rates, are subject to prudency reviews by our regulators. The prudency of these construction costs, as well as other matters previously deferred by the MPSC to future proceedings, were not addressed in our 2010 Missouri rate case, but could be addressed in our current rate proceeding.

On May 21, 2012, we filed a rate increase request with the MPSC for an annual increase in revenues for our Missouri water customers in the amount of approximately $516,400, or 29.6%. On October 18, 2012, we, the MPSC staff and the Office of the Public Counsel filed a unanimous agreement with the MPSC for an increase of $450,000. The MPSC issued an order approving the agreement on October 31, 2012, with rates effective November 23, 2012.

2010 Rate Case

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.

2009 Rate Case

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 $10.0 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 2005-2010 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).

Tornado Recovery

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 $3.3 million has been deferred under this agreement.

Kansas

2011 Rate Case

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.

2009 Rate Case

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.

Oklahoma

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 was 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.

Arkansas

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.

FERC

On May 18, 2012, we filed with the Federal Energy Regulatory Commission (FERC) proposed revisions to our Open Access Transmission Tariff to implement an annual cost-based transmission formula rate to be effective August 1, 2012. The state of Missouri, the Kansas Corporation Commission, Kansas Electric Power Cooperative Inc. and, as a group, the cities of Monett, Mount Vernon, Lockwood and Chetopa filed motions to intervene and requested the FERC suspend the effective date of the filing for a maximum of five months and set the filing for hearing and settlement procedures. On July 31, 2012, the FERC suspended the rate for five months and set the filing for hearing and settlement procedures. These rates became effective, subject to refund, on January 1, 2013.

On March 12, 2010, we filed new annual 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. 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. A GFR update will be completed annually for rates effective June 1.

Gas Segment

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.

COMPETITION AND MARKETS

Electric Segment

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 or Integrated Marketplace). Implementation of the SPP's Integrated Marketplace is scheduled for March 2014, which will replace the existing EIS market described above. As part of the Integrated Marketplace, 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. Our implementation preparedness, as well as SPP and its other members, of the Integrated Marketplace is well underway, including the finalization of FERC's Integrated Marketplace compliance requirements for SPP's Open Access Transmission Tariff (OATT). On December 10, 2012, the Arkansas Public Service Commission approved our continued participation in the SPP RTO, which included full participation in the SPP Integrated Market Place. In early 2012, we filed before the Missouri Public Service Commission for our continued participation in the SPP RTO. We expect the case to be scheduled and concluded in mid to late 2013.

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 are concerned with the SPP's authority, pursuant to the FERC order, 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. We requested a stay of procedures in order to allow the SPP to complete its 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 allocation. On December 16, 2011, the Eighth Circuit U.S. Court of Appeals granted our petition and stay request. On April 4, 2012, we and the other petitioners filed a status report and motion for voluntary dismissal of the petition. Our decision to dismiss the petition was warranted based on the January 2012 approvals of the SPP Board of Directors (BOD) and Regional State Committee for SPP to implement the review process in 2013. SPP's regional cost allocation review and imbalance analysis is underway with initial results to be presented in mid 2013. On April 5, 2012, the Eighth Circuit granted our motion to dismiss and, on April 10, 2012, amended their judgment of the granting of dismissal to clarify that such dismissal would not preclude us from raising similar concerns of any future FERC order. To date, the SPP's BOD has approved $2.8 billion in highway/byway transmission projects to be constructed by 2022 with an additional $745 million to be approved during the first quarter of 2013. 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.

Other FERC Activity

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. On May 17, 2012, the FERC issued Order No. 1000-A setting forth additional clarifications and guidelines for Order 1000 compliance. On October 18, 2012, the FERC issued Order 1000-B, reaffirming its Order 1000 and 1000-A requirements and clarifications. As an incumbent 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 and Order 1000-A 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. SPP stakeholder processes have commenced to determine the policy and tariff provisions for the compliance filings and we will continue to participate in the SPP processes to understand the impact of Orders 1000, 1000-A and 1000-B on our ability to construct new facilities within our service territory as well as their influence on promoting construction of transmission projects on or near our borders with our neighbors. A compliance filing by the SPP to address the ROFR requirements was made in November 2012. The compliance filing for the interregional planning and cost allocation requirements of Order 1000 is expected to occur in May 2013. We and the other SPP members will be working on SPP OATT modifications and providing input to SPP related to joint operating agreement modifications needed for Order 1000 compliance.

As a transmission owning member of the SPP RTO, Order 1000 could directly affect our rights to build transmission facilities within our service territory. The second key element of Order 1000 related to policy and procedures for interregional transmission coordination and interregional cost allocation is also significant to us and will most likely have a direct impact to our customers since we are on the southeastern seam of the SPP. Such impacts could be primarily through potential reductions to our production costs as a result of greater access to lower cost power from within the SPP, and across the seams, and the beneficial cost sharing for new interregional type 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.

On April 23, 2012, we intervened in the SPP's Petition for Review (Case No. 12-1158) of FERC's Orders on Declaratory Order and Rehearing (Docket No. EL11-34-000) on the interpretation of the SPP/MISO Joint Operating Agreement at the United States Court of Appeals for the District of Columbia. We are in agreement with SPP and other SPP members that FERC was incorrect in its determination that MISO's interpretation of the Joint Operating Agreement appropriately enables MISO and Entergy to utilize ours and other SPP members transmission systems to integrate Entergy into the MISO RTO without compensation or consideration of the negative impacts to us and the other SPP members. On June 25, 2012, the SPP interveners made a joint intervention filing at the DC court and a joint brief in October 2012 and reply brief on January 14, 2013. It is in our best interests that the review of the Joint Operating Agreement between SPP and MISO be remanded back to FERC to reevaluate its Orders. Based on the current terms and conditions of MISO membership, Entergy's participation in MISO will not be beneficial to our customers as it will increase transmission delivery costs for our Plum Point power station as well as utilize our transmission system without compensation. In late 2012, ITC Holdings and Entergy announced the sale of transmission assets to ITC and formation of new ITC transmission only companies. Subsequently, ITC, Entergy, and MISO made multiple filings at the FERC for the transfer of ownership of Entergy's transmission facilities as well as full integration into the MISO RTO. We and several other SPP members jointly filed in protest of the filings on January 11, 2013, based on Entergy and MISO's planned utilization of our and the other SPP members' system without mitigation or resolution of the current and expected harm of MISO's interpretation/use of the joint operating agreement to implement the integration. We expect the FERC process to resolve the issues to occur in 2013 as Entergy's planned integration is scheduled for late 2013.

Gas Segment

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.

Other — Rate Matters

In accordance with ASC guidance on regulated operations, we currently have deferred approximately $1.8 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.