Entergy - 10-Q quarterly report FY2013 Q3

Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days.  Yes þ No o

Indicate by check mark whether the registrants have submitted electronically and posted on Entergy’s corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes þ No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.  See the definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Securities Exchange Act of 1934.

Indicate by check mark whether the registrants are shell companies (as defined in Rule 12b-2 of the Exchange Act).  Yes o  No þ

Entergy Corporation, Entergy Arkansas, Inc., Entergy Gulf States Louisiana, L.L.C., Entergy Louisiana, LLC, Entergy Mississippi, Inc., Entergy New Orleans, Inc., Entergy Texas, Inc., and System Energy Resources, Inc. separately file this combined Quarterly Report on Form 10-Q.  Information contained herein relating to any individual company is filed by such company on its own behalf.  Each company reports herein only as to itself and makes no other representations whatsoever as to any other company.  This combined Quarterly Report on Form 10-Q supplements and updates the Annual Report on Form 10-K for the calendar year ended December 31, 2012 and the Quarterly Reports on Form 10-Q for the quarters ended March 31, 2013 and June 30, 2013, filed by the individual registrants with the SEC, and should be read in conjunction therewith.

In this combined report and from time to time, Entergy Corporation and the Registrant Subsidiaries each makes statements as a registrant concerning its expectations, beliefs, plans, objectives, goals, strategies, and future events or performance.  Such statements are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995.  Words such as “may,” “will,” “could,” “project,” “believe,” “anticipate,” “intend,” “expect,” “estimate,” “continue,” “potential,” “plan,” “predict,” “forecast,” and other similar words or expressions are intended to identify forward-looking statements but are not the only means to identify these statements.  Although each of these registrants believes that these forward-looking statements and the underlying assumptions are reasonable, it cannot provide assurance that they will prove correct.  Any forward-looking statement is based on information current as of the date of this combined report and speaks only as of the date on which such statement is made.  Except to the extent required by the federal securities laws, these registrants undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events, or otherwise.

Forward-looking statements involve a number of risks and uncertainties.  There are factors that could cause actual results to differ materially from those expressed or implied in the forward-looking statements, including those factors discussed or incorporated by reference in (a) Item 1A. Risk Factors in the Form 10-K, (b) Management’s Financial Discussion and Analysis in the Form 10-K and in this report, and (c) the following factors (in addition to others described elsewhere in this combined report and in subsequent securities filings):

Certain abbreviations or acronyms used in the text and notes are defined below:

Entergy operates primarily through two business segments: Utility and Entergy Wholesale Commodities.

Following are income statement variances for Utility, Entergy Wholesale Commodities, Parent & Other, and Entergy comparing the third quarter 2013 to the third quarter 2012 showing how much the line item increased or (decreased) in comparison to the prior period:

Refer to "ENTERGY CORPORATION AND SUBSIDIARIES - SELECTED OPERATING RESULTS" for further information with respect to operating statistics.

In the fourth quarter 2012, Entergy moved two subsidiaries from Parent & Other to the Entergy Wholesale Commodities segment to improve the alignment of certain intercompany items and income tax activity.  The prior period financial information in this Form 10-Q has been restated to reflect this change.

As discussed in more detail in Note 11 to the financial statements, third quarter 2013 results of operations includes $291.5 million ($183.7 million after-tax) of impairment and other related charges to write down the carrying value of Vermont Yankee and related assets to their fair values.

Utility

Following is an analysis of the change in net revenue comparing the third quarter 2013 to the third quarter 2012:

The retail electric price variance is primarily due to:

The fuel recovery variance is primarily due to:

The volume/weather variance is primarily due to an increase of 342 GWh, or 1%, in weather-adjusted usage primarily in the industrial sector and an increase in sales volume in the unbilled sales period.  This was partially offset by the effect of less favorable weather on residential and commercial sales in the third quarter 2013 as compared to the same period in the prior year.  The increase in industrial sales was primarily due to growth in the chemicals and refining segments.

The decommissioning trust variance is primarily due to lower regulatory charges resulting from a decrease in interest earned on ANO and River Bend decommissioning trust investments in 2013 in accordance with regulatory treatment.  There is no effect on net income as this interest is reflected in other income.

The net wholesale revenue variance is primarily due to higher margins on co-owner contracts.

The Hurricane Rita regulatory asset adjustment was recorded in third quarter 2012 in accordance with the rate order from the PUCT issued in September 2012.  See Note 2 to the financial statements in the Form 10-K for further discussion of the PUCT rate order.

The Grand Gulf recovery variance is primarily due to increased recovery of higher costs resulting from the Grand Gulf uprate.

Entergy Wholesale Commodities

Following is an analysis of the change in net revenue comparing the third quarter 2013 to the third quarter 2012:

As shown in the table above, net revenue for Entergy Wholesale Commodities decreased by $1 million in the third quarter 2013 compared to the third quarter 2012 primarily due to:

Following are key performance measures for Entergy Wholesale Commodities for the third quarter 2013 and 2012:

Realized Revenue per MWh Trend for Entergy Wholesale Commodities Nuclear Plants

The economic downturn and negative trends in the energy commodity markets have resulted over the past few years in lower natural gas prices and lower market prices for electricity in the New York and New England power regions, which is where five of the six Entergy Wholesale Commodities nuclear power plants are located.  Entergy Wholesale Commodities’s nuclear business experienced a decrease in realized price per MWh to $50.29 in 2012 from $54.73 in 2011 and $59.16 in 2010.  These price trends present a challenging economic situation for the Entergy Wholesale Commodities plants.  The challenge is greater for some of these plants based on a variety of factors such as their market for both energy and capacity, their size, their contracted positions, and the investment required to maintain the safety and integrity of the plants.  If, in the future, economic conditions or regulatory activity no longer support the continued operation of a plant by Entergy it could adversely affect Entergy’s results of operations through impairment charges, increased depreciation rates, transitional costs, or accelerated decommissioning costs.

On August 27, 2013, Entergy announced its plan to close and decommission Vermont Yankee.  Vermont Yankee is expected to cease power production in the fourth quarter 2014 after its current fuel cycle.  This decision was approved by the Board in August 2013.  The decision to shut down the plant was primarily due to sustained low natural gas and wholesale energy prices, the high cost structure of the plant, and lack of a market structure that adequately compensates merchant nuclear plants for their environmental and fuel diversity benefits in the region in which the plant operates.  See Note 11 to the financial statements herein for discussion of related impairment charges recorded during the third quarter 2013.

Impairment of long-lived assets and nuclear decommissioning costs, and the factors that influence these items, are both discussed in detail in the Form 10-K in “Critical Accounting Estimates.”  See also the discussion below in “Entergy Wholesale Commodities Authorizations to Operate Its Nuclear Power Plants” regarding Entergy Wholesale Commodities nuclear plant operating license and related activity.

Utility

Other operation and maintenance expenses increased from $519 million for the third quarter 2012 to $570 million for the third quarter 2013 primarily due to:

These increases were partially offset by a temporary increase in 2012 of $10 million in storm damage accruals, as approved by the MPSC for a five-month period effective August 2012.

Depreciation and amortization expenses increased primarily due to additions to plant in service, including the Hot Spring and Hinds plant acquisitions in 2012 and the completion of the Waterford 3 steam generator replacement project and the Grand Gulf uprate project in 2012. 

Entergy Wholesale Commodities

The asset impairment variance is due to $291.5 million ($183.7 million after-tax) of impairment and other related charges in the third quarter 2013 to write down the carrying value of Vermont Yankee and related assets to their fair values.  See Note 11 to the financial statements herein for further discussion of these charges.

Other operation and maintenance expenses increased from $245 million for the third quarter 2012 to $264 million for the third quarter 2013 primarily due to an increase of $23 million in compensation and benefits costs primarily due to a decrease in the discount rates used to determine net periodic pension and other postretirement benefit costs and a settlement charge, recognized in September 2013, related to the payment of lump sum benefits out of the non-qualified pension plan.  See "MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS – Critical Accounting Estimates" in the Form 10-K and Note 6 to the financial statements herein for further discussion of benefits costs.

Depreciation and amortization expenses increased primarily due to an adjustment in 2012 resulting from a final court decision in the Entergy Nuclear Indian Point 2 lawsuit against the U.S. Department of Energy related to spent nuclear fuel disposal. The effects of recording the proceeds from the judgment reduced the plant in service balances with a corresponding $19 million reduction to previously-recorded depreciation expense.

The effective income tax rate was 9.1% for the third quarter 2013.  The difference in the effective income tax rate for the third quarter 2013 versus the statutory rate of 35% was primarily due to lower state income taxes resulting from a state deferred tax adjustment and the reversal of a state valuation allowance.  Also contributing to the lower rate was the reversal of a portion of the provision for uncertain tax positions.

The effective income tax rate was 40.4% for the third quarter 2012. The difference in the effective income tax rate versus the statutory rate of 35% for the third quarter 2012 was primarily due to state income taxes.

Following are income statement variances for Utility, Entergy Wholesale Commodities, Parent & Other, and Entergy comparing the nine months ended September 30, 2013 to the nine months ended September 30, 2012 showing how much the line item increased or (decreased) in comparison to the prior period:

Refer to "ENTERGY CORPORATION AND SUBSIDIARIES - SELECTED OPERATING RESULTS" for further information with respect to operating statistics.

In the fourth quarter 2012, Entergy moved two subsidiaries from Parent & Other to the Entergy Wholesale Commodities segment to improve the alignment of certain intercompany items and income tax activity.  The prior period financial information in this Form 10-Q has been restated to reflect this change.

As discussed in more detail in Note 11 to the financial statements herein and Note 1 to the financial statements in the Form 10-K, results of operations for the nine months ended September 30, 2013 and September 30, 2012 include $291.5 million ($183.7 million after-tax) and $355.5 million ($223.5 million after-tax), respectively, of impairment and other related charges to write down the carrying value of Vermont Yankee and related assets to their fair values.  Also, net income for Utility for the nine months ended September 30, 2012 was significantly affected by a settlement with the IRS related to the income tax treatment of the Louisiana Act 55 financing of the Hurricane Katrina and Hurricane Rita

 

storm costs, which resulted in a reduction in income tax expense.  The net income effect was partially offset by a regulatory charge, which reduced net revenue in 2012, associated with the storm costs settlement to reflect the obligation to customers with respect to the settlement.  See Note 3 to the financial statements in the Form 10-K for additional discussion of the tax settlement and savings obligation.

Utility

Following is an analysis of the change in net revenue comparing the nine months ended September 30, 2013 to the nine months ended September 30, 2012:

The retail electric price variance is primarily due to:

The Louisiana Act 55 financing savings obligation variance results from a regulatory charge recorded in the second quarter 2012 because Entergy Gulf States Louisiana and Entergy Louisiana are sharing with customers the savings from an IRS settlement related to the uncertain tax position regarding the Hurricane Katrina and Hurricane Rita Louisiana Act 55 financing.  See Note 3 to the financial statements in the Form 10-K for additional discussion of the tax settlement and savings obligation.

The Grand Gulf recovery variance is primarily due to increased recovery of higher costs resulting from the Grand Gulf uprate.

The fuel recovery variance is primarily due to:

The MISO deferral variance is primarily due to the deferral in April 2013, as approved by the APSC, of costs incurred since March 2010 related to the transition and implementation of joining the MISO RTO.

The volume/weather variance is primarily due to less favorable weather on residential and commercial sales for the nine months ended September 30, 2013 as compared to the same period in the prior year and a decrease of 154 GWh, or 0.2%, in weather-adjusted usage, partially offset by an increase in sales volume in the unbilled sales period.

Entergy Wholesale Commodities

Following is an analysis of the change in net revenue comparing the nine months ended September 30, 2013 to the nine months ended September 30, 2012:

As shown in the table above, net revenue for Entergy Wholesale Commodities decreased by approximately $21 million in the nine months ended September 30, 2013 compared to the nine months ended September 30, 2012 primarily due to:

These decreases were substantially offset by higher capacity prices.

Following are key performance measures for Entergy Wholesale Commodities for the nine months ended September 30, 2013 and 2012:

Utility

Other operation and maintenance expenses increased from $1,531 million for the nine months ended September 30, 2012 to $1,677 million for the nine months ended September 30, 2013 primarily due to:

Taxes other than income taxes increased primarily due to an increase in ad valorem taxes, primarily due to the Hot Spring and Hinds plant acquisitions in 2012, as well as an increase in local franchise taxes resulting from higher residential and commercial revenues as compared with prior year.

Depreciation and amortization expenses increased primarily due to additions to plant in service, including the Hot Spring and Hinds plant acquisitions in 2012 and the completion of the Waterford 3 steam generator replacement project and the Grand Gulf uprate project in 2012.  Also contributing to the increase is an increase in depreciation rates as a result of the rate order approved by the PUCT in September 2012.

Interest expense increased primarily due to net debt issuances by certain of the Utility operating companies.  See Note 5 to the financial statements in the Form 10-K and Note 4 herein for more details of long-term debt activity.

Entergy Wholesale Commodities

Other operation and maintenance expenses increased from $726 million for the nine months ended September 30, 2012 to $748 million for the nine months ended September 30, 2013 primarily due to an increase of $29 million in compensation and benefits costs primarily due to a decrease in the discount rates used to determine net periodic pension and other postretirement benefit costs and a settlement charge, recognized in September 2013, related to the payment of lump sum benefits out of the non-qualified pension plan.  See "MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS – Critical Accounting Estimates" in the Form 10-K and Note 6 to the financial statements herein for further discussion of benefits costs.

Depreciation and amortization expenses increased primarily due to an adjustment in 2012 resulting from a final court decision in the Entergy Nuclear Indian Point 2 lawsuit against the U.S. Department of Energy related to spent nuclear fuel disposal. The effects of recording the proceeds from the judgment reduced the plant in service balances with a corresponding $19 million reduction to previously-recorded depreciation expense.

The asset impairment variance is due to impairment and other related charges of $355.5 million ($223.5 million after-tax) recorded in first quarter 2012 and $291.5 million ($183.7 million after-tax) recorded in third quarter 2013 to write down the carrying value of Vermont Yankee and related assets to their fair values.  See Note 1 to the financial statements in the Form 10-K and Note 11 to the financial statements herein for further discussion of these charges.

Other expenses increased primarily due to a credit to decommissioning expense of $49 million in the second quarter 2012 resulting from a reduction in the decommissioning cost liability for a plant as a result of a revised decommissioning cost study.  See “Critical Accounting Estimates – Nuclear Decommissioning Costs” in the Form 10-K for further discussion.

The effective income tax rate was 27% for the nine months ended September 30, 2013.  The difference in the effective income tax rate for the nine months ended September 30, 2013 versus the statutory rate of 35% was primarily due to the reversal of a portion of the provision for uncertain tax positions, lower state income taxes resulting from a state deferred tax adjustment and the reversal of a state valuation allowance, and book and tax differences related to the allowance for equity funds used during construction, partially offset by certain book and tax differences related to utility plant items.  See Note 10 to the financial statements herein for further discussion of income taxes.

The effective income tax rate was 16.3% for the nine months ended September 30, 2012.  The difference in the effective income tax rate versus the statutory rate of 35% for the nine months ended September 30, 2012 was related to (1) an IRS settlement on how to treat the Louisiana Act 55 Financing of the Hurricane Katrina and Hurricane Rita storm costs, as discussed further in Note 3 to the financial statements in the Form 10-K; and (2) a unanimous court decision from the U.S. Court of Appeals for the Fifth Circuit affirming an earlier decision of the U.S. Tax Court holding that Entergy was entitled to claim a credit against its U.S. tax liability for the U.K. windfall tax that it paid, both of which enabled Entergy to reverse provisions for uncertain tax positions.  See Note 3 to the financial statements in the Form 10-K and Note 10 to the financial statements herein for further discussion of the settlement and tax credit.

See the Form 10-K for a discussion of Entergy’s plan to spin off its transmission business and merge it with a newly formed subsidiary of ITC Holdings Corp.  On April 16, 2013, the ITC shareholders approved the ITC merger proposals.  On June 28, 2013, Entergy and ITC mutually agreed to extend the term of the Merger Agreement to December 31, 2013, after which it may be terminated by either party if the transaction has not been consummated.  The transaction is not expected to close in 2013, and a revised closing date in 2014 has not been settled upon.  Pursuant to the Merger Agreement, and subject to the terms and conditions set forth therein, Entergy will distribute the TransCo common units to its shareholders, excluding any TransCo common units contributed to an exchange trust if Entergy makes the exchange trust election.  At Entergy’s election, it may distribute the TransCo common units by means of a pro rata dividend in a spin-off or pursuant to an exchange offer in a split-off, or a combination of a split-off and a spin-off (the Distribution).  On July 24, 2013, Mid South TransCo LLC (TransCo) filed a registration statement with the SEC on Forms S-1/S-4 under which the Distribution would occur by means of a combination of a split-off and a spin-off.

See the Form 10-K for a discussion of the applications that each of the Utility operating companies has filed with their respective retail regulators seeking approval for the proposal to spin off and merge the transmission business with ITC.

In each retail jurisdiction, the Utility operating companies and ITC have offered certain commitments for consideration should the retail regulators deem it appropriate to impose conditions on the approval of the transaction, including a commitment to mitigate certain effects on customer rates for a period of at least five years.  In the offered commitments, the Utility operating companies and ITC proposed an initial five-year period of wholesale rebates and retail rate mitigation totaling $134.0 million for Entergy Arkansas customers, $48.6 million for Entergy Gulf States Louisiana customers, $59.5 million for Entergy Louisiana customers, $74.1 million for Entergy Mississippi customers, $20.0 million for Entergy New Orleans customers, and $69.6 million for Entergy Texas customers.  The share of the rate mitigation to be borne will vary by Utility operating company, but the Utility is expected to bear, on an aggregate basis, over the initial five-year period, approximately 65% to 70% of the wholesale rebates and retail rate mitigation, with ITC expected to bear the remainder.  At the end of the first five years following the close of the transaction, the economic and performance benefits of ITC’s ownership will be measured and verified by an independent auditor to determine if they offset the ownership cost increase resulting from ITC’s weighted average cost of capital.  If the benefits exceed such costs, rate mitigation will cease.  If they do not, wholesale rebates and retail rate mitigation will continue until the benefits exceed these costs.

The Utility operating companies have offered the following additional retail rate mitigation to address the effects of moving to a forward test year: $6.9 million for Entergy Arkansas customers, $5.4 million for Entergy Gulf States Louisiana customers, $7.2 million for Entergy Louisiana customers, $6.7 million for Entergy Mississippi customers, $0.4 million for Entergy New Orleans customers, and $13.1 million for Entergy Texas customers.  Lastly, Entergy Texas customers will also experience net avoided costs of $10.0 million due to the effects of eliminating transmission cost allocation under the Entergy System Agreement.  Entergy Gulf States Louisiana and Entergy Louisiana customers will also experience net avoided costs of $4.1 million and $12.2 million, respectively, due to the effects of both eliminating transmission cost allocation under the Entergy System Agreement and moving to MISO’s transmission pricing zone structure.

These proposed commitments may change as the regulatory proceedings progress.

In April 2013 the LPSC staff, APSC staff, and other parties filed testimony in the proceedings pending at the LPSC and APSC, respectively, identifying concerns with the proposed transaction and concluding that the transaction in its current form does not satisfy the applicable criteria for approval.  The LPSC staff testimony also included a comprehensive set of conditions should the LPSC determine that the transaction is in the public interest.  Conditions were also recommended by the Arkansas Attorney General should the APSC consider approving the transaction.  In April and May 2013 various parties and the PUCT staff respectively filed testimony in the PUCT proceeding identifying

 

The PUCT hearing on the joint application was held before the ALJs in May 2013.  In July 2013 the ALJs issued a proposal for decision that recommended the denial of the joint application.  The ALJs further recommended that if the PUCT approved the joint application, the PUCT impose certain conditions on Entergy Texas and ITC.  Exceptions to the proposal for decision were filed in July 2013, and on August 9, 2013, the PUCT granted the applicants’ motion to withdraw the application with an opportunity to file a new application in the future that would include evidence not in the record considered by the ALJs.  In September 2013 the applicants filed their updated application with the PUCT, including a request for a decision by December 2013.  The PUCT has adopted a procedural schedule that sets a hearing on the merits for this matter before the Commissioners on November 21-22, 2013.  A final order is not expected until January 2014.

The APSC postponed a previously-scheduled July 9, 2013 hearing to allow the parties to pursue more details regarding the rate mitigation commitments described above.  In August 2013 in response to a motion to suspend the procedural schedule in light of the withdrawal of the application in Texas, the APSC issued an order cancelling a re-scheduled September 2013 evidentiary hearing and ordering the applicants to file monthly status reports (beginning in October 2013) regarding the applications in the other retail jurisdictions.  The order also provided that the parties should work together to establish a schedule that would permit the APSC to conduct the evidentiary hearing, deliberate and develop a final ruling, if reasonably possible, by the end of 2013.  Beginning on October 1, 2013, the applicants began filing the requested status reports.  The evidentiary hearing in Arkansas has not yet been re-scheduled.

LPSC hearings were held in July 2013.  At its July 31, 2013 meeting, the LPSC voted to allow a 45-day discovery period regarding the mitigation commitments offered by the Utility operating companies and ITC.  On August 21, 2013, the LPSC proceeding was suspended pending the LPSC’s receipt of notice that the applicants have filed a new application in Texas.  After providing notice of the filing of the updated application in Texas, a revised LPSC procedural schedule was set that calls for an additional round of testimony and briefing to conclude by November 8, 2013.

In the MPSC proceeding, the parties filed reply briefs and responses to proposed orders on September 25, 2013.  Entergy Mississippi and ITC also submitted filings on that day that indicated whether they would comply with conditions proposed by the Mississippi Public Utilities Staff.  There is no procedural deadline by which the MPSC must issue a decision in this matter.

On October 10, 2013, the City Council granted a motion to suspend the proceeding in light of the withdrawal and re-filing of the Texas application.  The City Council ordered the parties to develop a revised agreed procedural schedule within 14 days or submit proposed alternate schedules thereafter for consideration by the City Council. Pursuant to the City Council’s directive, the parties have agreed to a revised procedural schedule that provides for the advisors and intervenors to submit supplemental surrebuttal testimony on December 20, 2013, an evidentiary hearing (paper only), and supporting briefs by all parties to be filed on December 27, 2013.

 

Because Entergy Arkansas also owns limited transmission facilities in Missouri, on February 14, 2013, Entergy Arkansas together with ITC and related parties filed an application out of an abundance of caution with the Missouri Public Service Commission pertaining to the ITC transaction.  On April 18, 2013, the Missouri Public Service Commission consolidated for purposes of a hearing Entergy Arkansas’s separate MISO case that is related to Entergy Arkansas’s notice of its intent to integrate into MISO with the Entergy and ITC case that is related to the proposal to spin off and merge the transmission business with ITC.  The hearing before the Missouri Public Service Commission took place in June 2013, and post-hearing briefs were filed in July and early August 2013.  The Missouri Public Service Commission has not issued an order in the ITC proceeding and has delayed further consideration of the matter pending procedural developments in the retail jurisdictions.

See the Form 10-K for a discussion of the series of filings with the FERC made by Entergy, ITC, and certain of their subsidiaries to obtain regulatory approvals related to the proposed transfer to ITC subsidiaries of the transmission assets owned by the Utility operating companies.

On September 24, 2012, ITC and Entergy filed a joint application with the FERC seeking all necessary approvals under sections 203 and 205 of the Federal Power Act and the necessary declaration under section 305(a) of the Federal Power Act.   On June 20, 2013, the FERC issued an order authorizing the transactions under section 203 of the Federal Power Act, and also issued a declaration that section 305(a) of the Federal Power Act is not implicated by the transactions because the concerns underlying section 305(a) of the Federal Power Act are not present in the transactions. The FERC order also stated that the exchange trust election will not undermine or interfere with the independence of ITC.  The FERC order rejected, without prejudice, the request to extend by six months the deadline for new employees of ITC to dispose of their Entergy common stock.

The FERC issued a separate order on June 20, 2013, addressing the rate formula proposed by ITC in the September 24, 2012 application, as well as certain ancillary agreements also submitted for FERC’s approval with the application.  In that order, the FERC summarily approved certain aspects of ITC’s rate proposal, such as the 12.38% return on equity, a capital structure of 60% equity/40% debt, and use of a forward-looking formula rate.  However, the FERC found that other aspects of the rate proposal raised issues of material fact that cannot be resolved based on the record before the FERC, and thus ordered hearing and settlement judge procedures.  The FERC also accepted certain transaction-related agreements for filing, but included the transition services agreements and certain other ancillary agreements in the ordered hearing and settlement judge procedures.  The FERC consolidated the issues set for hearing and settlement judge procedures with two other Section 205 proceedings related to the transactions: (1) a proposed ratemaking treatment for certain pension and post-retirement welfare plan costs that relate to the Entergy employees that will become employees of ITC; and (2) the Attachment O formula rate templates filed by Entergy Services, on behalf of the Utility operating companies, on February 15, 2013, which includes the basis for the initial charges to be collected by the new operating subsidiaries of ITC post-closing, as well as the rates proposed to apply under the MISO Tariff in the event the transactions fail to close and Entergy retains its transmission assets.

On June 20, 2013, the FERC also issued an order accepting MISO’s proposed amendment to the MISO Tariff to enable the integration of the new ITC Operating Companies’ transmission facilities into MISO prior to the Utility operating companies becoming market participants in MISO.  In addition, on June 20, 2013, the FERC issued an order accepting Entergy Services’s application under the Federal Power Act section 205 to cancel System Agreement Service Schedule MSS-2 (Transmission Equalization) effective upon closing of the ITC transaction.

On July 22, 2013, various parties filed requests for rehearing of the FERC orders issued on June 20, 2013.  Settlement discussions are ongoing with respect to the matters the FERC set for hearing in the June 20, 2013 orders.

 

In October 2012, Entergy, ITC, and certain subsidiaries submitted filings with the FERC to obtain regulatory approvals under Federal Power Act section 204 for the various financings being undertaken as part of the transaction.  On May 16, 2013, the FERC issued an order authorizing the proposed financings for the ITC Transaction under Federal Power Act section 204 subject to the closing of the transaction, including authorization until October 31, 2013, for the Utility operating companies to provide credit support in the form of guarantees of borrowings during the transaction.  The Utility operating companies will apply to FERC for renewal of that authority through 2014 to facilitate transaction closing.

In July 2012, Entergy Corporation submitted a request to the Internal Revenue Service seeking a private letter ruling substantially to the effect that certain requirements for the tax-free treatment of the distribution of the transmission business are met.  In May 2013, Entergy obtained IRS rulings regarding the tax-free treatment of certain aspects of the transactions.  While the May 2013 IRS rulings provide sufficient guidance for Entergy to execute the spin-merge in a tax-free manner, Entergy requested additional IRS rulings regarding certain other aspects of the transactions during the third quarter 2013.  In September 2012, Entergy submitted an application to the NRC for approval of certain nuclear plant license transfers and amendments as part of the steps to complete the spin-off and merger.  In May 2013 the NRC issued orders approving the license transfers and amendments.

On December 14, 2012, Entergy and ITC filed the required notifications under the Hart-Scott-Rodino Act with the Federal Trade Commission and the Department of Justice related to Entergy’s plan to spin off its transmission business and merge it with a newly formed subsidiary of ITC Holdings Corp.  The waiting period under the Hart-Scott-Rodino Act expired on January 14, 2013.  The ability to close the transaction based on the December 14, 2012 premerger notification filings expires on January 14, 2014, however, and Entergy and ITC are in the process of preparing new notifications to allow for a closing after January 14, 2014.

See the Form 10-K for a discussion of the NRC operating licenses for Indian Point 2 and Indian Point 3 and the NRC license renewal applications in process for these plants.  Following are updates to the discussion regarding the NRC proceedings and related New York State proceedings.

The original expiration date of the NRC license for Indian Point Unit 2 was September 28, 2013.  Indian Point Unit 2 has now entered its “period of extended operation” after expiration of the plant’s initial license term under “timely renewal,” which is a federal statutory rule of general applicability providing for extension of a license for which a renewal application has been timely filed with the licensing agency. The Indian Point license renewal application qualifies for timely renewal protection because it met NRC regulatory standards for timely filing.

In August 2013, Riverkeeper filed with the ASLB a proposed amended Endangered Species Act contention alleging that NRC Staff’s supplemental Final Supplemental Environmental Impact Statement (FSEIS) issued in June 2013 did not document sufficient consultation between NRC Staff and the National Marine Fisheries Service regarding endangered species.  Entergy and NRC Staff have filed answers in opposition.  Riverkeeper’s proposed amended contention and Entergy’s motion to dismiss Riverkeeper’s original admitted contention on endangered species are pending before the ASLB.

Hearings were held in July 2013 before NYSDEC ALJs on environmental issues related to Indian Point’s wedgewire screen proposal for “best technology available.”  The ALJs have issued no partial decisions on the several issues that have been litigated during the past two years and have not announced a schedule for doing so.

The New York State Department of Environmental Conservation (NYSDEC) has taken the position that Indian Point must obtain a new state-issued Clean Water Act Section 401 water quality certification as part of the license renewal process.  Entergy submitted its application for a water quality certification to the NYSDEC in April 2009, with a reservation of rights regarding the applicability of Section 401 in this case.  After Entergy submitted certain additional information in response to NYSDEC requests, in February 2010 the NYSDEC staff determined that Entergy’s water quality certification application was complete.  In April 2010 the NYSDEC staff issued a proposed notice of denial of Entergy’s water quality certification application (the Notice).  NYSDEC staff’s Notice triggered an administrative adjudicatory hearing before NYSDEC ALJs on the proposed Notice.  The NYSDEC staff decision does not restrict Indian Point operations, but the issuance of a certification is potentially required prior to NRC issuance of renewed unit

 

licenses.  In June 2011, Entergy filed notice with the NRC that the NYSDEC, the agency that would issue or deny a water quality certification for the Indian Point license renewal process, has taken longer than one year to take final action on Entergy’s application for a water quality certification and, therefore, has waived its opportunity to require a certification under the provisions of Section 401 of the Clean Water Act.  The NYSDEC has notified the NRC that it disagrees with Entergy’s position and does not believe that it has waived the right to require a certification.  The NYSDEC ALJs overseeing the agency’s certification adjudicatory process stated in a ruling issued in July 2011 that while the waiver issue is pending before the NRC, the NYSDEC hearing process will continue on selected issues.  The judges held a Legislative Hearing (agency public comment session) and an Issues Conference (pre-trial conference) in July 2010.  Issue-by-issue hearings before the NYSDEC ALJs began in October 2011 and are expected to continue, on an episodic basis, into 2014 and perhaps longer.  After hearings and briefing on all issues, the ALJs will issue a recommended decision to the Commissioner or his delegate, who will then issue the final agency decision.  A party to the proceeding can appeal the decision of the Commissioner to state court.

In addition, the consistency of Indian Point’s operations with New York State’s coastal management policies must be resolved to the extent required by the Coastal Zone Management Act (CZMA).  Entergy has undertaken three independent initiatives to resolve CZMA issues.  First, on July 24, 2012, Entergy filed a supplement to the Indian Point license renewal application currently pending before the NRC.  The supplement states that, based on applicable federal law and in light of prior reviews by the State of New York, the NRC may issue the requested renewed operating licenses for Indian Point without the need for an additional consistency review by the State of New York under the CZMA.  On July 30, 2012, Entergy filed a motion for declaratory order with the ASLB seeking confirmation of its position that no further CZMA consistency determination is required before the NRC may issue renewed licenses.  On April 5, 2013, the State of New York and Riverkeeper filed answers opposing Entergy’s motion.  The State of New York also filed a cross-motion for declaratory order seeking confirmation that Indian Point had not been previously reviewed, and that only the New York State Department of State (NYSDOS) could conduct a CZMA review for NRC license renewal purposes.  On April 15, 2013, the NRC Staff filed answers recommending the ASLB deny both Entergy’s and the State of New York’s motions for declaratory order.  On June 12, 2013, the ASLB denied Entergy’s and the State of New York’s motions, without prejudice, on the ground that consultation on the matter of previous review among the NRC, Entergy (as applicant), and the State of New York had not taken place, as the ASLB determined to be required.  There is no prescribed schedule or deadline for the consultation process.

Second, Entergy filed with the NYSDOS in November 2012 a petition for declaratory order that Indian Point is grandfathered under either of two criteria prescribed by the New York Coastal Management Program (NYCMP), which sets forth the state coastal policies applied in a CZMA consistency review.  NYSDOS denied the motion by order dated January 2013.  Entergy filed a petition for judicial review of NYSDOS’s decision with the New York State Supreme Court for Albany County in March 2013.  NYSDOS filed an opposition and oral argument was held in September 2013 on Entergy’s petition for judicial review.  It is uncertain when the court will act on the petition for review.  The losing party may file an appeal as of right with the next level state appellate court.

Third, on December 17, 2012, Entergy filed with NYSDOS a consistency determination explaining why Indian Point satisfies all applicable NYCMP policies.  Entergy included in the consistency determination a “reservation of rights” clarifying that Entergy does not concede NYSDOS’s right to conduct a new CZMA review for Indian Point.    The six-month federal deadline for state decision on a consistency determination runs from the date the submission is complete.  On January 16, 2013, NYSDOS notified Entergy that it deemed the consistency determination incomplete because it did not include the final version of a further supplement to the FSEIS that was targeted for subsequent issuance by NRC staff.  On June 28, 2013, NYSDOS notified Entergy that NYSDOS had received a copy of the final version of the FSEIS on June 20, 2013, and that NYSDOS’s review of the Indian Point consistency determination had begun on June 20, 2013.  In October 2013, Entergy and NYSDOS executed a stay agreement that extends the deadline for NYSDOS to decide Indian Point’s CZMA consistency certification to March 22, 2014.

 

On March 31, 2013, during a scheduled refueling outage at ANO 1, a contractor-owned and operated heavy-lifting apparatus collapsed while moving the generator stator out of the turbine building.  The collapse resulted in the death of an ironworker and injuries to several other contract workers, caused ANO 2 to shut down, and damaged the ANO turbine building.  The turbine building serves both ANO 1 and 2 and is a non-radiological area of the plant.  ANO 2 reconnected to the grid on April 28, 2013 and ANO 1 reconnected to the grid on August 7, 2013.  The total cost of assessment, restoration of off-site power, site restoration, debris removal, and replacement of damaged property and equipment is currently estimated to be approximately $100 million.  In addition, Entergy Arkansas incurred replacement power costs for ANO 2 power during its outage and incurred incremental replacement power costs for ANO 1 power because the outage extended beyond the originally-planned duration of the refueling outage.  Each of the Utility operating companies has recovery mechanisms in place designed to recover its prudently-incurred fuel and purchased power costs.

Entergy Arkansas is assessing its options for recovering damages that resulted from the stator drop, including its insurance coverage and legal action.  Entergy is a member of Nuclear Electric Insurance Limited (NEIL), a mutual insurance company that provides property damage coverage to the members’ nuclear generating plants, including ANO.  NEIL has notified Entergy that it believes that a $50 million course of construction sublimit applies to any loss associated with the lifting apparatus failure and stator drop at ANO.  Entergy has responded that it disagrees with NEIL's position and is evaluating its options for enforcing its rights under the policy.  On July 12, 2013, Entergy Arkansas filed a complaint in the Circuit Court in Pope County, Arkansas against the owner of the heavy-lifting apparatus that collapsed, an engineering firm, a general contractor, and certain individuals asserting claims of breach of contract, negligence, and gross negligence in connection with their responsibility for the stator drop.

In the second quarter 2013, Entergy Arkansas recorded an insurance receivable of $50 million based on the minimum amount that it expects to receive from NEIL.  This $50 million receivable offset approximately $35 million of capital spending, $13 million of operation and maintenance expense, and $2 million of incremental deferred refueling outage costs incurred for the recovery through September 30, 2013.  As of September 30, 2013, Entergy Arkansas has incurred approximately $33 million in capital spending, $11 million in operation and maintenance expense, and $1 million in incremental deferred refueling outage costs in excess of its recorded insurance receivable.

Entergy is engaged in a strategic imperative that is intended to optimize the organization through a process known as human capital management.  In July 2013 management completed a comprehensive review of Entergy’s organization design and processes.  This effort resulted in a new internal organization structure, which management expects to result in the elimination of approximately 800 employee positions.  Costs associated with this phase of human capital management, primarily implementation costs, severance expenses, and the effect on benefit plan expense, are expected to be in the range of $145 million to $185 million.  The majority of these costs are expected to be incurred by the end of 2013 and approximately $18 million has been incurred as of September 30, 2013.

Entergy Solutions District Energy, a business wholly-owned by Entergy in the Entergy Wholesale Commodities segment, owns and operates district energy assets serving the business districts in Houston and New Orleans.  In August 2013, Entergy signed agreements to sell Entergy Solutions District Energy for approximately $130 million, subject to adjustments.  Entergy Solutions District Energy’s book value as of September 30, 2013 was approximately $100 million.  The sale is expected to close in 2013.

See "MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Liquidity and Capital Resources" in the Form 10-K for a discussion of Entergy’s capital structure, capital expenditure plans and other uses of capital, and sources of capital.  Following are updates to that discussion.

Entergy’s capitalization is balanced between equity and debt, as shown in the following table.

Net debt consists of debt less cash and cash equivalents.  Debt consists of notes payable and commercial paper, capital lease obligations, and long-term debt, including the currently maturing portion.  Capital consists of debt, common shareholders’ equity, and subsidiaries’ preferred stock without sinking fund.  Net capital consists of capital less cash and cash equivalents.  Entergy uses the debt to capital ratios excluding securitization bonds in analyzing its financial condition and believes they provide useful information to its investors and creditors in evaluating Entergy’s financial condition because the securitization bonds are non-recourse to Entergy, as more fully described in Note 5 to the financial statements in the Form 10-K.  Entergy also uses the net debt to net capital ratio excluding securitization bonds in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy’s financial condition because net debt indicates Entergy’s outstanding debt position that could not be readily satisfied by cash and cash equivalents on hand.

Entergy Corporation has in place a credit facility that has a borrowing capacity of $3.5 billion and expires in March 2018.  Entergy Corporation has the ability to issue letters of credit against 50% of the total borrowing capacity of the facility.  Following is a summary of the borrowings outstanding and capacity available under the facility as of September 30, 2013:

A covenant in Entergy Corporation’s credit facility requires Entergy to maintain a consolidated debt ratio of 65% or less of its total capitalization.  The calculation of this debt ratio under Entergy Corporation’s credit facility is different than the calculation of the debt to capital ratio above.  Entergy is currently in compliance with the covenant.  If Entergy fails to meet this ratio, or if Entergy or one of the Utility operating companies (except Entergy New Orleans) defaults on other indebtedness or is in bankruptcy or insolvency proceedings, an acceleration of the facility’s maturity date may occur.  See Note 4 to the financial statements for additional discussion of the Entergy Corporation credit facility and discussion of the Registrant Subsidiaries’ credit facilities.

See Note 4 to the financial statements herein for additional discussion of the Entergy Corporation commercial paper program.  In July 2013 the Board increased the commercial paper program limit to $1.5 billion.  As of September 30, 2013, Entergy Corporation had approximately $1,016 million of commercial paper outstanding.

See the table and discussion in the Form 10-K under "MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Liquidity and Capital Resources - Capital Expenditure Plans and Other Uses of Capital," that sets forth the amounts of planned construction and other capital investments by operating segment for 2013 through 2015.  Following are updates to the discussion in the Form 10-K.

Entergy is developing its capital investment plan for 2014 through 2016 and currently anticipates that the Utility will make $5.8 billion in capital investments during that period and that Entergy Wholesale Commodities will make $1.0 billion in capital investments during that period.  In addition to routine capital spending to maintain operations, the Utility capital investment plan includes specific investments and initiatives such as the Ninemile Point Unit 6 self-build project; NRC post-Fukushima requirements for the Utility nuclear fleet; potential scrubbers at the White Bluff plant to meet pending Arkansas state requirements under the Clean Air Visibility Rule and compliance with the EPA’s Mercury and Air Toxic Standard rule;  and transmission spending to support economic development projects, reliability, and new compliance requirements.  The Entergy Wholesale Commodities capital investment plan includes significant projects required to continue the operation of the current generation fleet including component replacements, software, and security; NYPA value sharing; and dry cask storage, license renewal, and NRC post-Fukushima requirements for the Entergy Wholesale Commodities nuclear fleet.

Declarations of dividends on Entergy’s common stock are made at the discretion of the Board.  Among other things, the Board evaluates the level of Entergy’s common stock dividends based upon Entergy’s earnings, financial strength, and future investment opportunities.  At its October 2013 meeting, the Board declared a dividend of $0.83 per share, which is the same quarterly dividend per share that Entergy has paid since the second quarter 2010.

As shown in Entergy’s Consolidated Statements of Cash Flows, cash flows for the nine months ended September 30, 2013 and 2012 were as follows:

Net cash provided by operating activities decreased by approximately $21 million for the nine months ended September 30, 2013 compared to the nine months ended September 30, 2012 primarily due to:

These decreases in cash flow were partially offset by:

Net cash used in investing activities decreased by $265 million for the nine months ended September 30, 2013 compared to the nine months ended September 30, 2012 primarily due to:

The decrease was partially offset by:

 

 

Financing activities used $309 million in net cash for the nine months ended September 30, 2013 compared to providing $159 million in net cash for the nine months ended September 30, 2012 primarily due to:

For details of long-term debt activity and Entergy's commercial paper program in 2013 see Note 4 to the financial statements herein.

See "MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Rate, Cost-recovery, and Other Regulation" in the Form 10-K for discussions of rate regulation, federal regulation, and related regulatory proceedings.

See Note 2 to the financial statements herein for updates to the discussion in the Form 10-K regarding these proceedings.

See the Form 10-K for a discussion of federal regulatory proceedings.  Following are updates to that discussion.

Utility Operating Company Notices of Termination of System Agreement Participation

As discussed in the Form 10-K, in February 2009, Entergy Arkansas and Entergy Mississippi filed with the FERC their notices of cancellation to terminate their participation in the System Agreement, effective December 18, 2013 and November 7, 2015, respectively.  In November 2009 the FERC accepted the notices of cancellation and determined that Entergy Arkansas and Entergy Mississippi are permitted to withdraw from the System Agreement following the 96-month notice period without payment of a fee or the requirement to otherwise compensate the remaining Utility operating companies as a result of withdrawal.  In February 2011 the FERC denied the LPSC’s and the City Council’s rehearing requests.  In September and October 2012 the U.S. Court of Appeals for the D.C. Circuit denied the LPSC’s and the City Council’s appeals of the FERC decisions.  In January 2013 the LPSC and the City Council filed a petition for a writ of certiorari with the U.S. Supreme Court.  On May 13, 2013, the U.S. Supreme Court denied the petition for a writ of certiorari filed by the LPSC and the City Council seeking review of the D.C. Circuit’s decision to affirm the FERC’s orders accepting the notices of cancellation filed by Entergy Arkansas and Entergy Mississippi and determining that Entergy Arkansas and Entergy Mississippi are permitted to withdraw from the System Agreement following the 96-month notice period without payment of a fee or the requirement to otherwise compensate the remaining Utility operating companies as a result of withdrawal.

 

 

In November 2012 the Utility operating companies filed amendments to the System Agreement with the FERC pursuant to section 205 of the Federal Power Act.  The LPSC, MPSC, PUCT, and City Council filed protests at the FERC regarding the amendments and other aspects of the Utility operating companies’ future operating arrangements, including requests that the continued viability of the System Agreement in MISO (among other issues) be set for hearing by the FERC.  On March 12, 2013, the Utility operating companies filed an answer to the protests.  The answer proposed, among other things, that: (1) the FERC allow the System Agreement revisions to go into effect as of December 19, 2013, without a hearing and for an initial two-year transition period; (2) no later than October 18, 2013, Entergy Services submit a filing pursuant to section 205 of the Federal Power Act that provides Entergy Texas’s notice of cancellation to terminate participation in the System Agreement and responds to the PUCT’s position that Entergy Texas be allowed to terminate its participation prior to the end of the mandatory 96-month notice period; and (3) at least six months prior to the end of the two-year transition period, Entergy Services submits an additional filing under section 205 of the Federal Power Act that addresses the allocation of MISO charges and credits among the Utility operating companies that remain in the System Agreement.  The answer further provided that prior to the filing which was to be made no later than October 18, 2013, Entergy Services, Entergy Texas, and Entergy would exercise reasonable best efforts to engage the Utility operating companies and their retail regulators in searching for a consensual means of allowing Entergy Texas to exit the System Agreement prior to the end of the mandatory 96-month notice period.  The matter remains pending at the FERC.

On October 11, 2013 the Utility operating companies filed with the FERC to amend the System Agreement changing the notice period for an operating company to terminate its participation in the System Agreement from ninety-six months to sixty months.  The proposed amendment also clarifies that the revised notice period will apply to any written notice of termination provided by an operating company on or after October 12, 2013.  On October 18, 2013, Entergy Texas provided notice to terminate its participation in the System Agreement effective after expiration of the proposed 60-month notice period or such other period as approved by FERC.  The proposed amendment and Entergy Texas’s termination notice are without prejudice to continuing efforts among affected operating companies and their retail regulators to search for a consensual means of allowing Entergy Texas an early exit from the System Agreement, which could be different from that proposed in the October 11, 2013 FERC filing.  Comments on both filings are due in November 2013.

See the Form 10-K for a discussion of the Utility operating companies’ proposal to join MISO.  Following are updates to that discussion.

On April 8, 2013, the APSC issued an order resolving the outstanding issues in Entergy Arkansas’s change of control docket and granted Entergy Arkansas’s application subject to the conditions set forth in the APSC’s October 2012 order.  On May 23, 2013, the FERC issued an order accepting the changes to Appendix K of the MISO Transmission Owners Agreement proposed by MISO and a majority of the MISO transmission owners to implement MISO governance enhancements consistent with the APSC’s October 2012 order.

Because Entergy Arkansas also owns limited transmission facilities in Missouri, on March 21, 2013, Entergy Arkansas responded to attempts by certain parties to raise issues before the Missouri Public Service Commission pertaining to Entergy Arkansas’s integration into MISO by filing a notice that it was joining MISO.  On October 9, 2013, the Missouri Public Service Commission issued an order approving Entergy Arkansas’s integration of its Missouri transmission assets into MISO, subject to conditions.  The order includes conditions, however, that are beyond Entergy Arkansas’s control to satisfy and that concern wholesale tariffs that fall within the exclusive jurisdiction of the FERC.  Among other things, the order requires Entergy Arkansas and ITC Midwest to hold harmless non-MISO Missouri retail customers from increased costs due to the integration of Entergy Arkansas’s Missouri transmission facilities into MISO.  Entergy Arkansas is evaluating the Missouri Public Service Commission’s order and determining

 

appropriate next steps, including seeking rehearing of that order.  The order is limited, however, to the 87 miles of Entergy Arkansas transmission facilities located in Missouri that are used to provide only interstate transmission service in Missouri; Entergy Arkansas does not have any retail customers in Missouri.  Entergy Arkansas plans to proceed with integration of its non-Missouri assets into the MISO RTO on December 19, 2013, as approved by the APSC.  Assuming the Missouri Public Service Commission’s order remains in force in its current form, Entergy Arkansas will not transfer functional control of its Missouri transmission facilities to MISO on December 19, 2013.  In that event, transmission service over the Missouri transmission facilities will be provided for a period of time by Entergy Arkansas under a FERC-jurisdictional open access transmission tariff, not the MISO tariff.  Entergy Arkansas filed with FERC the open access transmission tariff for its Missouri transmission assets on October 15, 2013, and requested an effective date of December 19, 2013, the date of the Utility operating companies’ planned MISO integration.  On October 16, 2013, Entergy Arkansas and MISO jointly filed an agreement that provides for coordination between the Entergy Arkansas tariff and the MISO tariff with respect to transmission service request processing, transmission rates, congestion management, data submission, and other matters.

On January 23, 2013, Entergy Arkansas filed with the APSC a Motion to Discontinue Activities Necessary to Operate as a True Stand-Alone Electric Utility, with supporting testimony, in which Entergy Arkansas requested an order from the APSC authorizing it to drop the stand-alone option by March 1, 2013.  On April 8, 2013, the APSC issued an order granting Entergy Arkansas’s motion.

On September 18, 2013, the APSC issued an order directing Entergy Arkansas and MISO to appear and show cause why the APSC should not find that Entergy Arkansas and MISO are in violation of certain conditions in a previous order in the proceeding.  The APSC directed Entergy Arkansas to demonstrate its earlier commitment to comply with the conditions by affirming that Entergy Arkansas would comply with five directives enumerated in the show cause order relating to the manner in which Entergy Arkansas conducts transmission planning.  On October 8, 2013, Entergy Arkansas and MISO submitted testimony in compliance with the show cause order.  In its compliance testimony, Entergy Arkansas specifically affirmed its intent to comply with the five directives set forth in the show cause order and provided detail regarding the manner in which it would comply with those directives.

On April 3, 2013, the PUCT staff filed a study performed by its independent consultant assessing Entergy Texas’s January 2013 updated analysis of the effect of termination of certain purchased power agreements on Entergy Texas’s costs upon Entergy Texas’s exit from the System Agreement.  While the independent consultant study concluded that the adjustments made in Entergy Texas’s updated analysis were analytically correct, the consultant also recommended further study regarding the effect of the termination of the purchased power agreements on the benefits associated with Entergy Texas joining MISO.  On April 5, 2013, Entergy Texas filed a response to the consultant study, noting a number of errors in the analysis and recommending against any further study of this matter.  At the direction of the PUCT, Entergy Texas subsequently agreed to fund further analysis, to be performed by a different independent consultant for the PUCT, regarding the effects of termination of these purchased power agreements.  On August 6, 2013, the report of the PUCT’s second independent consultant regarding the effects of termination of these purchased power agreements was filed with the PUCT as part of a larger report addressing the results of the consultant’s comprehensive analysis of Entergy Texas’s transition to operations post-exit of the System Agreement.  The report concluded (consistent with Entergy Texas’s updated analysis) that under both the “Foundation Case” capacity price forecast and the high capacity price sensitivity that were performed, Entergy Texas and its customers would be better off on a present-value basis if these purchased power agreements terminate.  Under the low capacity price sensitivity, there was a net cost to Entergy Texas customers if these purchased power agreements terminate.  Consistent with the requirements of the PUCT conditional order approving the change in control to MISO, Entergy Texas gave notice of cancellation to terminate its participation in the System Agreement on October 18, 2013.

In April 2012 the FERC conditionally accepted MISO’s proposal related to the allocation of transmission upgrade costs in connection with the transition and integration of the Utility operating companies into MISO.  In November 2012 the FERC issued an order denying the requests for rehearing of the April 2012 order, and conditionally accepting MISO’s May 2012 compliance filing, subject to a further compliance filing due within 30 days of the date of the November 2012 order.  In December 2012, MISO and the MISO Transmission Owners submitted to FERC a request for rehearing and proposed revisions to the MISO Tariff in compliance with FERC’s November 2012 order.   On July 11, 2013, the FERC issued an order conditionally accepting MISO’s compliance filing and granting in part and denying in part the request for rehearing.

 

On February 15, 2013, Entergy Services, on behalf of the Utility operating companies, made a filing with the FERC requesting to adopt the standard Attachment O formula rate template used by transmission owners to establish transmission rates within MISO.  The filing proposed four transmission pricing zones for the Utility operating companies, one for Entergy Arkansas, one for Entergy Mississippi, one for Entergy Texas, and one for Entergy Louisiana, Entergy Gulf States Louisiana, and Entergy New Orleans.  On June 20, 2013, the FERC issued an order accepting the use of four transmission pricing zones, consolidated the proposed revisions to the Attachment O templates in this proceeding with certain other proceedings related to the ITC transaction, and set for hearing and settlement judge procedures those issues of material fact that FERC decided could not be resolved based on the existing record.  Several parties, including the City Council, filed requests for rehearing of the June 2013 order.

Also on February 15, 2013, MISO and Entergy Arkansas and Entergy Mississippi filed with the FERC proposed revisions to Attachment P of the MISO Tariff, to list the existing transmission and related agreements between each of Entergy Arkansas and Entergy Mississippi and each of their counterparties as grandfathered agreements.  On May 31, 2013, the FERC issued an order accepting the proposed revisions, effective December 19, 2013, as requested.

In March 2013 the FERC issued an order conditionally accepting MISO’s proposed tariff changes related to the allocation of long-term transmission rights and auction revenue rights, subject to a further compliance filing.  The amendments are intended to address the anticipated integration of the Utility operating companies, as well as other load-serving entities and transmission-owning utilities, into the MISO RTO.  In April 2013, MISO made the required compliance filing.  The FERC issued a letter order in September 2013 accepting MISO’s compliance filing.

On March 19, 2013, the FERC issued an order approving a settlement between Entergy Services and the FERC Enforcement Staff (the Staff) arising from the Staff’s November 20, 2012 “Notice of Alleged Violations” which stated that the Staff had concluded that Entergy Services’s practices in certain areas violated various requirements of the North American Electric Reliability Corporation reliability standards.  Under the terms of the settlement, Entergy Services neither admits nor denies the alleged violations, but agrees to pay a civil penalty of $975,000 and undertake certain mitigation activities agreed to during discussions with Staff.

Power Generation

As a wholesale generator, Entergy Wholesale Commodities’s core business is selling energy, measured in MWh, to its customers.  Entergy Wholesale Commodities enters into forward contracts with its customers and sells energy in the day ahead or spot markets.  In addition to selling the energy produced by its plants, Entergy Wholesale Commodities sells unforced capacity, which allows load-serving entities to meet specified reserve and related requirements placed on them by the ISOs in their respective areas.  Entergy Wholesale Commodities’s forward physical power contracts consist of contracts to sell energy only, contracts to sell capacity only, and bundled contracts in which it sells both capacity and energy.  While the terminology and payment mechanics vary in these contracts, each of these types of contracts requires Entergy Wholesale Commodities to deliver MWh of energy, make capacity available, or both.  In addition to its forward physical power contracts, Entergy Wholesale Commodities also uses a combination of financial contracts, including swaps, collars, put and/or call options, to manage forward commodity price risk.  Certain hedge volumes have price downside and upside relative to market price movement.  The contracted minimum, expected value, and sensitivity are provided to show potential variations.  While the sensitivity reflects the minimum, it does not reflect the total maximum upside potential from higher market prices.  The information contained in the table below represents projections at a point in time and will vary over time based on numerous factors, such as future market prices, contracting activities, and generation.  Following is a summary of Entergy Wholesale Commodities’s current forward capacity and generation contracts as well as total revenue projections based on market prices as of September 30, 2013 (2013 represents the remainder of the year):

 

Entergy estimates that a positive $10 per MWh change in the annual average energy price in the markets in which the Entergy Wholesale Commodities nuclear business sells power, based on September 30, 2013 market conditions, planned generation volumes, and hedged positions, would have a corresponding effect on pre-tax net income of $43 million for the remainder of 2013. A negative $10 per MWh change in the annual average energy price in the markets based on September 30, 2013 market conditions would have a corresponding effect on pre-tax net income of ($26) million for the remainder of 2013.

Some of the agreements to sell the power produced by Entergy Wholesale Commodities’s power plants contain provisions that require an Entergy subsidiary to provide collateral to secure its obligations under the agreements.  The Entergy subsidiary is required to provide collateral based upon the difference between the current market and contracted power prices in the regions where Entergy Wholesale Commodities sells power.  The primary form of collateral to satisfy these requirements is an Entergy Corporation guaranty.  Cash and letters of credit are also acceptable forms of collateral.  At September 30, 2013, based on power prices at that time, Entergy had liquidity exposure of $200 million under the guarantees in place supporting Entergy Wholesale Commodities transactions, $20 million of guarantees that support letters of credit, and $9 million of posted cash collateral.  As of September 30, 2013, the liquidity exposure associated with Entergy Wholesale Commodities assurance requirements, including return of previously posted collateral from counterparties, would increase by $110 million for a $1 per MMBtu increase in gas prices in both the short-and long-term markets.  In the event of a decrease in Entergy Corporation’s credit rating to below investment grade, based on power prices as of September 30, 2013, Entergy would have been required to provide approximately $79 million of additional cash or letters of credit under some of the agreements.

As of September 30, 2013, substantially all of the counterparties or their guarantors for 100% of the planned energy output under contract for Entergy Wholesale Commodities nuclear plants through 2017 have public investment grade credit ratings.

See "MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS – Nuclear Matters" in the Form 10-K for a discussion of nuclear matters.

See "MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Critical Accounting Estimates" in the Form 10-K for a discussion of the estimates and judgments necessary in Entergy’s accounting for nuclear decommissioning costs, unbilled revenue, impairment of long-lived assets and trust fund investments, qualified pension and other postretirement benefits, and other contingencies.  Following is an update to that discussion.

In the first quarter 2013, Entergy Wholesale Commodities recorded a revision to its estimated decommissioning cost liability for a nuclear site as a result of a revised decommissioning cost study.  The revised estimate resulted in a $46.6 million reduction in the decommissioning cost liability, along with a corresponding reduction in the related asset retirement cost asset.

In the third quarter 2013, Entergy Wholesale Commodities recorded a revision to its estimated decommissioning cost liability for Vermont Yankee as a result of a revised decommissioning cost study. The revised estimate resulted in a $58 million increase in the decommissioning cost liability, along with a corresponding increase in the related asset retirement cost asset. The increase in the estimated decommissioning cost liability resulted from the change in expectation regarding the timing of decommissioning cash flows due to the decision to cease operations of the plant.  See Note 11 to the financial statements herein for further discussion of the Vermont Yankee plant.

Assuming the end of Vermont Yankee operations in the fourth quarter 2014, the amount required to meet the NRC minimum for decommissioning financial assurance for license termination is $566 million. The Vermont Yankee decommissioning trust had a balance of approximately $584 million as of September 30, 2013, excluding the $40 million guarantee by Entergy Corporation to satisfy NRC requirements following the 2009 review of financial assurance levels. Filings with the NRC for planned shutdown activities will determine whether any other financial assurance may be required and will specifically address funding for spent fuel management, which will be required until the federal government takes possession of the fuel and removes it from the site, per its current obligations.

The accounting standard-setting process, including projects between the FASB and the International Accounting Standards Board (IASB) to converge U.S. GAAP and International Financial Reporting Standards, is ongoing and the FASB and the IASB are each currently working on several projects that have not yet resulted in final pronouncements.  Final pronouncements that result from these projects could have a material effect on Entergy’s future net income, financial position, or cash flows.