Catastrophic events such as fires, earthquakes, solar events, floods, hurricanes, tornadoes, pandemics, wars, national emergencies, terrorist activities, and other similar events, especially if these events occur in or near TVA’sTVA's service area;
Accounts receivable primarily consist of amounts due from customers for power sales. The table below summarizes the types and amounts of TVA’s accounts receivable:
base rate structure, customers are billed in the current month.4. Inventories, Net
The table below summarizes the types and amounts of TVA’s inventories:inventories:
Inventories, Net | |
| | | At June 30, 2011 | | | At September 30, 2010 | |
| | | | | | | |
| Fuel inventory | | $ | 546 | | | $ | 539 | |
| Materials and supplies inventory | | | 530 | | | | 486 | |
| Emission allowance inventory | | | 10 | | | | 11 | |
| Allowance for inventory obsolescence | | | (26 | ) | | | (24 | ) |
| | | | | | | | | |
| Inventories, net | | $ | 1,060 | | | $ | 1,012 | |
|
| | | | | | | |
Inventories, Net |
| | At December 31, 2011 | | At September 30, 2011 |
| Fuel inventory | $ | 614 |
| | $ | 489 |
|
| Materials and supplies inventory | 581 |
| | 555 |
|
| Emission allowance inventory | 11 |
| | 11 |
|
| Allowance for inventory obsolescence | (29 | ) | | (27 | ) |
| Inventories, net | $ | 1,177 |
| | $ | 1,028 |
|
The table below summarizes the types and amounts of TVA’s other long-term assets:assets:
Other Long-Term Assets | |
| | | At June 30, 2011 | | | At September 30, 2010 | |
| | | | | | | |
| Coal contract derivative assets | | $ | 252 | | | $ | 103 | |
| Loans and other long-term receivables, net | | | 75 | | | | 68 | |
| Currency swap assets | | | 14 | | | | – | |
| Other long-term assets | | | 33 | | | | 20 | |
| | | | | | | | | |
| Total other long-term assets | | $ | 374 | | | $ | 191 | |
|
| | | | | | | |
Other Long-Term Assets |
| | At December 31, 2011 | | At September 30, 2011 |
| Coal contract derivative assets | $ | 202 |
| | $ | 285 |
|
| Loans and other long-term receivables, net | 76 |
| | 74 |
|
| Other | 11 |
| | 13 |
|
| Total other long-term assets | $ | 289 |
| | $ | 372 |
|
Regulatory assets generally represent incurred costs that have been deferred because such costs are probable of future recovery in customer rates. Regulatory liabilities generally represent obligations to make refunds to customers for previous collections for costs that are not likely to be incurred or deferral of gains that will be credited to customers in future periods. Components of regulatory assets and regulatory liabilities are summarized in the table below.
Regulatory Assets and Liabilities | |
| | | At June 30, 2011 | | | At September 30, 2010 | |
| Current regulatory assets | | | | | | |
| Deferred nuclear generating units | | $ | 391 | | | $ | 391 | |
| Unrealized losses on commodity derivatives | | | 218 | | | | 184 | |
| Environmental cleanup costs – Kingston ash spill | | | 74 | | | | 76 | |
| Fuel cost adjustment receivable | | | 69 | | | | 84 | |
| Deferred outage costs | | | 4 | | | | 42 | |
| Deferred capital lease | | | 1 | | | | 14 | |
| Total current regulatory assets | | | 757 | | | | 791 | |
| | | | | | | | | |
| Non-current regulatory assets | | | | | | | | |
| Deferred pension costs | | | 4,254 | | | | 4,456 | |
| Deferred nuclear generating units | | | 1,271 | | | | 1,565 | |
| Environmental cleanup costs – Kingston ash spill | | | 892 | | | | 987 | |
| Nuclear decommissioning costs | | | 857 | | | | 898 | |
| Other non-current regulatory assets | | | 577 | | | | 499 | |
| Unrealized losses on swaps and swaptions | | | 512 | | | | 797 | |
| Non-nuclear decommissioning costs | | | 481 | | | | 410 | |
| EPA agreement | | | 350 | | | | — | |
| Unrealized losses related to commodity derivatives | | | 222 | | | | 144 | |
| Total non-current regulatory assets | | | 9,416 | | | | 9,756 | |
| | | | | | | | | |
| Total regulatory assets | | $ | 10,173 | | | $ | 10,547 | |
| Current regulatory liabilities | | | | | | | | |
| Unrealized gains on commodity contracts | | $ | 147 | | | $ | 57 | |
| Fuel cost adjustment tax equivalents | | | 68 | | | | — | |
| Capital leases | | | — | | | | 6 | |
| Total current regulatory liabilities | | | 215 | | | | 63 | |
Non-current regulatory liabilities | | | | | | | | |
| Unrealized gains on commodity contracts | | | 261 | | | | 106 | |
| | | | | | | | | |
| Total regulatory liabilities | | $ | 476 | | | $ | 169 | |
|
| | | | | | | |
Regulatory Assets and Liabilities |
| | At December 31, 2011 | | At September 30, 2011 |
| Current regulatory assets | | | |
| Unrealized losses on commodity derivatives | $ | 371 |
| | $ | 225 |
|
| Deferred nuclear generating units | 236 |
| | 236 |
|
| Environmental agreements | 87 |
| | — |
|
| Environmental cleanup costs – Kingston ash spill | 73 |
| | 73 |
|
| Deferred capital leases | 2 |
| | 2 |
|
| Fuel cost adjustment receivable | — |
| | 7 |
|
| Total current regulatory assets | 769 |
| | 543 |
|
| Non-current regulatory assets | |
| | |
|
| Deferred pension costs and other post-retirement benefits costs | 5,718 |
| | 5,807 |
|
| Unrealized losses on swaps and swaptions | 1,220 |
| | 1,164 |
|
| Nuclear decommissioning costs | 964 |
| | 1,012 |
|
| Environmental cleanup costs - Kingston ash spill | 856 |
| | 874 |
|
| Deferred nuclear generating units | 650 |
| | 709 |
|
| Construction costs | 619 |
| | 619 |
|
| Non-nuclear decommissioning costs | 526 |
| | 519 |
|
| Unrealized losses on commodity derivatives | 347 |
| | 221 |
|
| Environmental agreements | 253 |
| | 346 |
|
| Other non-current regulatory assets | 231 |
| | 234 |
|
| Total non-current regulatory assets | 11,384 |
| | 11,505 |
|
| Total regulatory assets | $ | 12,153 |
| | $ | 12,048 |
|
| | | | |
| Current regulatory liabilities | |
| | |
|
| Fuel cost adjustment tax equivalents | $ | 137 |
| | $ | 127 |
|
| Unrealized gains on commodity derivatives | 81 |
| | 153 |
|
| Fuel cost adjustment liability | 79 |
|
| — |
|
| Total current regulatory liabilities | 297 |
| | 280 |
|
| Non-current regulatory liabilities | |
| | |
|
| Unrealized gains on commodity derivatives | 205 |
| | 285 |
|
| Total regulatory liabilities | $ | 502 |
| | $ | 565 |
|
Preconstruction Costs. Certain preliminary work and costs associated with engineering, design, and licensing activities, as well as the procurement of long lead-time components for the partially completed Bellefonte Nuclear Plant (“Bellefonte”) Unit 1, have been deferred as a regulatory asset pending the TVA Board’s decision on the completion of the project. If the TVA Board decides to complete Bellefonte Unit 1, the costs will be moved to construction in progress and amortized over a cost recovery period equivalent to the expected useful life of the future operating nuclear unit. If the TVA Board decides not to complete the unit, the costs will be expensed at the time of the decision. The preconstruction costs were $103 million as of June 30, 2011, and are included in other non-current regulatory assets. At September 30, 2010, no such preconstruction asset had been established.
Environmental Agreement. In conjunction with the agreements with the Environmental Protection Agency (“EPA”) and others (see Note 16 — EPA Settlement), TVA recorded certain liabilities totaling $360 million ($290 million investment in energy efficiency projects, demand response projects, renewable energy projects, and other TVA projects; $60 million to be provided to Alabama, Kentucky, North Carolina, and Tennessee to fund environmental projects [with preference for projects in the TVA watershed]; and $10 million in civil penalties). The TVA Board determined that these costs would be collected in customer rates in the future and, accordingly, the amounts were deferred as a regulatory asset. During the three months ended June 30, 2011, the civil penalties of $10 million were expensed, and they were subsequently paid in July 2011. The remaining amounts will be charged to expense and recovered in rates over future periods as payments are made.
The Event
In December 2008,, one of the dredge cells at the Kingston Fossil Plant (“Kingston”("Kingston") failed,, and approximately five million cubic yards of water and coal fly ash flowed out of the cell. TVA is continuing cleanup and recovery efforts in conjunction with federal and state agencies. TVA completed the removal of time-critical ash from the river during the third quarter of 2010,, and removal of the remaining ash is considered to be non-time-critical. TVA estimates that the physical cleanup work (final removal) will be completed in the last quarter of 2014. A final assessment, a completion report, and approval by Tennessee and EPAthe Environmental Protection Agency ("EPA") is expected to occur by the second quarter of 2015. Surveillance and monitoring of the site will continue, but this work is beyond the scope of the cleanup project.
Claims and Litigation
See Note 16 — Litigation — Legal Proceedings Related to the Kingston Ash Spilland and — Civil Penalty and Natural Resource Damages for the Kingston Ash Spill.
Financial Impact
Because of the uncertainty at this time of the final costs to complete the work prescribed by the ash disposal plan, a range of reasonable estimates has been developed by cost category.category. Known amounts, most likely scenarios, or the low end of the range for each category have been accumulated and evaluated to determine the total estimate. The range of estimated costs varies from approximately $1.1 billion to approximately $1.2 billion.
TVA recorded an estimate of $1.1 billion for the cost of cleanup related to this event. In August 2009, TVA began using regulatory accounting treatment to defer all actual costs already incurred and expected future costs related to the ash spill. The cost is being charged to expense as it is collected in rates over 15 years, beginning October 1, 2009. As the estimate changes, additional costs may be deferred and charged to expense prospectively as they are collected in future rates.
As work continues to progress and more information is available, TVA will review its estimates and revise them as appropriate. TVA has accrued a portion of the estimated cost in current liabilities, with the remaining portion shown as a long-term liability on TVA’sTVA's balance sheets. Amounts spent since the event through June 30,December 31, 2011, totaled $714$774 million. The remaining estimated liability at June 30,December 31, 2011, was $411$351 million.
TVA has not included the following categories of costs in the above estimate since it has been determined that these costs are currently either not probable or not reasonably estimable: penalties (other than the penalties set out in the June 2010 Tennessee Department of Environment &and Conservation (“TDEC”("TDEC") order), regulatory directives, natural resources damages (other than payments required under a memorandum of agreement with TDEC and the U.S. Fish and Wildlife Service establishing a process and a method for resolving the natural resource damages claim), outcomes offuture lawsuits, future claims, long-term environmental impact costs, final long-term disposition of the ash processing area, costs associated with new laws and regulations, or cost of remediating any mixed waste discovered during the ash which is comingled with radioactive material from non-TVA operations, to the extent it would have to be managed as low-level radioactive waste.removal process. There are certain other costs that will be incurred that have not been included in the estimate as they are appropriately accounted for in other areas of the financial statements. Associated capital asset purchases are recorded in property, plant, and equipment.equipment. Ash handling and disposition costs from current plant operations are recorded in operating expenses. A portion of the pond and dredge cell closure costs is also not included in the estimate as it is included in the non-nuclear assetAsset retirement obligation (“ARO”("ARO") liability.
Insurance
TVA had property and excess liability insurance programs in place at the time of the Kingston ash spill. TVA pursued claims under both the property and excess liability programs and has settled all of its property insurance claims and some of its excess liability insurance claims. Through June 30December 31, 2011, 2011, TVA received proceeds of $40 million. TVA continues to provide information about the nature and extent of TVA’sTVA's claims under the policies to some of the remaining excess liability insurance companies. It is unclear at this time whether the parties will be able to resolve the outstanding claims without resorting to the policies’policies' dispute resolution procedures. Any amounts received related to insurance settlements are being recorded as reductions to the regulatory asset and will reduce amounts collected in future rates.
Other long-term liabilities consist primarily of liabilities related to certain derivative agreements.agreements as well as liabilities under agreements in respect of compliance with certain environmental regulations (see Note 16 — Environmental Agreements). The table below summarizes the types and amounts of liabilities:
Other Long-Term Liabilities | |
| | | At June 30, 2011 | | | At September 30, 2010 | |
| | | | | | | |
| Swaption liability | | $ | 629 | | | $ | 804 | |
| EPA settlement liabilities | | | 350 | | | | — | |
| Interest rate swap liabilities | | | 259 | | | | 371 | |
| Coal contract derivative liabilities | | | 143 | | | | 2 | |
| Commodity swap derivative liabilities | | | 71 | | | | 118 | |
| Currency swap liabilities | | | 44 | | | | 81 | |
| Other long-term liabilities | | | 202 | | | | 150 | |
| | | | | | | | | |
| Total other long-term liabilities | | $ | 1,698 | | | $ | 1,526 | |
|
| | | | | | | |
| Other Long-Term Liabilities |
| | At December 31, 2011 | | At September 30, 2011 |
| Swaption liability | $ | 1,128 |
| | $ | 1,077 |
|
| Interest rate swap liabilities | 467 |
| | 463 |
|
| Environmental Agreements liability | 254 |
| | 346 |
|
| Other | 194 |
| | 191 |
|
| Coal contract derivative liabilities | 155 |
| | 119 |
|
| Commodity swap derivative liabilities | 101 |
| | 78 |
|
| Currency swap liabilities | 89 |
| | 131 |
|
| Total other long-term liabilities | $ | 2,388 |
| | $ | 2,405 |
|
During the ninethree months ended June 30,December 31, 2011 TVA’s, TVA's total ARO liability increased $145 million.$37 million due to normal accretion. The increase was comprised of $39 million of new revisions in the cost estimates related to TVA’s nuclear AROs and $118 million of ARO accretion. This increaseliability was partially offset by ash area settlement projects that were conducted during the first ninethree months of 2011.ended December 31, 2011. The nuclear and non-nuclear accretion were deferred as regulatory assets. During the nine months ended June 30, 2011, $36assets, and $14 million of the related regulatory assets were amortized into expense since this amount wasthese amounts were collected in rates.
Reconciliation of Asset Retirement Obligation Liability Nine Months Ended June 30, 2011 | |
| | | Nuclear | | | Non-nuclear | | | Total | |
| | | | | | | | |
| | | | | | | | | | |
| Balance at beginning of period | | $ | 1,940 | | | $ | 1,023 | | | $ | 2,963 | |
| | | | | | | | | | | | | |
| Settlements (ash storage areas) | | | — | | | | (12 | ) | | | (12 | ) |
| Accretion (recorded as regulatory asset) | | | 82 | | | | 36 | | | | 118 | |
| Change in nuclear estimate | | | 39 | | | | — | | | | 39 | |
| | | | | | | | | | | | | |
| Balance at end of period | | $ | 2,061 | | | $ | 1,047 | | | $ | 3,108 | |
|
| | | | | | | | | | | |
Reconciliation of Asset Retirement Obligation Liability
|
| | | | | | |
| | Nuclear | | Non-nuclear | | Total |
| Balance at September 30, 2011 | $ | 2,091 |
| | $ | 1,047 |
| | $ | 3,138 |
|
| Settlements (ash storage areas) | — |
| | (5 | ) | | (5 | ) |
| Accretion (recorded as regulatory asset) | 29 |
| | 13 |
| | 42 |
|
| Change in estimate | — |
| | — |
| | — |
|
| Balance at December 31, 2011 | $ | 2,120 |
| | $ | 1,055 |
| | $ | 3,175 |
|
10. Debt
Debt Outstanding
The TVA Act authorizes TVA to issue Bonds in an amount not to exceed $30$30.0 billion outstanding at any time. Debt outstanding at JuneDecember 31, 2011, and September 30, 2011 and September 30, 2010,, including the effect of translations related to Bonds denominated in foreign currencies, consisted of the following:
Debt Outstanding | |
| | | At June 30, 2011 | | | At September 30, 2010 | |
| | | | | | | |
| Current debt | | | | | | |
| Short-term debt, net | | $ | — | | | $ | 27 | |
| Current maturities of long-term debt | | | 1,523 | | | | 1,008 | |
| Total current debt | | | 1,523 | | | | 1,035 | |
| | | | | | | | | |
| Long-term debt | | | | | | | | |
| Long-term debt | | | 22,673 | | | | 22,605 | |
| Unamortized discount | | | (235 | ) | | | (216 | ) |
| Total long-term debt, net | | | 22,438 | | | | 22,389 | |
| Total outstanding debt | | $ | 23,961 | | | $ | 23,424 | |
|
| | | | | | | |
Debt Outstanding |
| | At December 31, 2011 | | At September 30, 2011 |
| Short-term debt | | | |
| Discount notes (net of discount) | $ | 785 |
| | $ | 482 |
|
| Current maturities of long-term debt | 1,558 |
| | 1,537 |
|
| Total short-term debt, net | 2,343 |
| | 2,019 |
|
| Long-term debt | |
| | |
|
| Long-term outstanding power bonds | 22,604 |
| | 22,647 |
|
| Unamortized discount, premiums and other | (235 | ) | | (235 | ) |
| Total long-term debt, net | 22,369 |
| | 22,412 |
|
| Total outstanding debt | $ | 24,712 |
| | $ | 24,431 |
|
Debt Securities Activity
The table below summarizes TVA’s long-term Bond activity for the period from October 1, 2010,2011, to June 30,December 31, 2011.
|
| | | | | | | | | | | | | |
| | Date | | Amount | | Interest Rate |
| Redemptions/Maturities: | | | | | |
| 2009 Series A | November 2011 | | $ | 2 |
| | 2.25% |
| 2009 Series B | December 2011 | | 1 |
| | 3.77% |
electronotes® | Three Months Ended December 31, 2011 | | 16 |
| | 4.82% |
| Total | | | $ | 19 |
| | |
| | Date | | Amount | | Interest Rate | |
Issuances: | | | | | | |
| 2011 Series A | February 2011 | | $ 1,500 | | 3.88% | |
| | | | | | | |
electronotes®(1) | Three months ended March 31, 2011 | | 40 | | 4.25% | |
| | | | | | | |
| | Three months ended June 30, 2011 | | 42 | | 4.33% | |
| | | | | | | |
| | | | | | | |
| Total | | | $ 1,582 | | | |
Redemptions/Maturities: | | | | | | |
| 2009 Series A | November 2010 | | $ 2 | | 2.25% | |
| 2009 Series B | December 2010 | | 1 | | 3.77% | |
| 2001 Series A | January 2011 | | 1,000 | | 5.63% | |
| 2009 Series A | May 2011 | | 2 | | 2.25% | |
| 2009 Series B | June 2011 | | 1 | | 3.77% | |
| | | | | | | |
electronotes®(2) | Three months ended December 31, 2010 | | 2 | | 3.62% | |
| | | | | | | |
| | Three months ended March 31, 2011 | | 10 | | 5.47% | |
| | | | | | | | | |
| | Three months ended June 30, 2011 | | 2 | | 3.12% | |
| | | | | | | |
| Total | | | $ 1,020 | | | |
Note (1) The electronotes® interest rate is the weighted average of the interest rates of the notes issued during that period. (2) The electronotes® interest rate is the weighted average of the interest rates of the notes redeemed during that period. |
Credit Facility Agreements. TVA and the U.S. Treasury have entered into a memorandum of understanding under which the U.S. Treasury provides TVA with a $150 million credit facility. This credit facility matures on September 30, 2011,2012, and is expected to be renewed. This arrangement is pursuant to the TVA Act. TVA plans to use the U.S. Treasury credit facility as a secondary source of liquidity. The interest rate on any borrowing under this facility is based on the average rate on outstanding marketable obligations of the United States with maturities from date of issue of one year or less. There were no borrowings outstanding under the facility at June 30,December 31, 2011.
TVA also has funding available in the form of three long-term revolving credit facilities totaling $2.5 billion. Both the $0.5 billion and one of the $1.0 billion credit facilities mature on January 14, 2014, and the other $1.0 billion credit facility matures on May 11, 2014. The credit facilities also accommodate the issuance of letters of credit. The interest rate on any borrowing under these facilities is variable based on market factors and the rating of TVA’sTVA's senior unsecured long-term non-credit enhanced debt. TVA is required to pay an unused facility fee on the portion of the total $2.5 billion which TVA has not borrowed or committed under letters of credit. This fee, along with letter of credit fees, fluctuates depending on the rating of TVA’sTVA's senior unsecured long-term non-credit enhanced debt. At JuneDecember 31, 2011, and September 30, 2011 and September 30, 2010,, there were $224$756 million and $411$575 million, respectively, of letters of credit outstanding under the facilities, in place at those times, and there were no borrowings outstanding. See Note 12 — Other Derivative Instruments — Collateral.
11. Leaseback Obligations
Prior to 2004, TVA received approximately $945 million in proceeds by entering into leaseback transactions for 24 new peaking combustion turbine units (“CTs”). TVA also received approximately $389 million in proceeds by entering into a leaseback transaction for qualified technological equipment and software (“QTE”) in 2003. Due to TVA's continuing involvement in the operation and maintenance of the leased units and equipment and its control over the distribution of power produced by the combustion turbine facilities during the leaseback term, TVA accounted for the lease proceeds as financing obligations. At December 31, 2011 and September 30, 2011, the outstanding leaseback obligations, related to CTs and QTE,
were $885 million.
("Seven States Power Corporation (“Seven States”States"), through its subsidiary, Seven States Southaven, LLC (“SSSL”("SSSL"), exercised Seven States’sits option to purchase from TVA an undivided 90-percent90 percent interest in a combined cycle combustion turbine facility in Southaven, Mississippi. As part of interim joint-ownership arrangements, Seven States has the right at any time, and for any reason, until the earlier of the date long-term operational and power sales arrangements are in place or April 23, 2013, to require TVA to buy back Seven States’sStates's interest in the facility. TVA will buy back the Seven StatesStates's interest if long-term operational and power sales arrangements for the facility among TVA, Seven States, and SSSL, or
alternative arrangements, are not in place by April 23, 2013. TVA’sTVA's buy-back obligation will terminate if such long-term arrangements are in place by that date. In the event of a buy-back, TVA will re-acquire the Seven StatesStates's interest in the facility and the related assets. As of June 30, 2011, and September 30, 2010, theThe carrying amount of the Southaven obligation on TVA's balance sheets was approximately $401$392 million at December 31, 2011, and $413$397 million respectively.at September 30, 2011.
On August 8, 2011, a credit rating agency lowered the long-term rating of TVA's rated Bonds from AAA to AA+. This downgrade constituted an event of default under the Amended and Restated Credit Agreement between Seven States and its lenders. Upon the occurrence of such an event of default, Seven States's lenders may either impose a higher default interest rate on the loan or exercise an option to require TVA to re-acquire its interest in the Southaven facility and the related assets.
On November 1, 2011, Seven States and its lenders, with the consent of TVA, executed an Amendment to the Amended and Restated Credit Agreement. In this amendment, Seven States's lenders agreed to waive this event of default and thus waive the lenders' right to force TVA to re-acquire Seven States's interest in the Southaven facility and the related assets or to force Seven States to pay the default interest rate for this event of default. Also, the amendment ties the interest rate on Seven States's credit facilities to TVA's credit rating. Seven States will pay interest on the loan at either 1) LIBOR plus 62.5 basis points if TVA's corporate credit rating is AAA (or its equivalent) by all credit rating agencies, or 2) LIBOR plus 87.5 basis points if TVA's corporate credit rating is AA+ (or its equivalent) by one or more credit rating agencies and AAA (or its equivalent) by the other nationally recognized credit agencies.
Lease Ratings Downgrade
On November 29, 2011, one credit rating agency downgraded its ratings on various TVA long-term lease obligations from AA+ to AA-, and set the outlook on the ratings to stable. The downgrades include TVA's obligations under long-term leasebacks for various generation facilities and technological equipment, and office real estate. According to the rating agency, the downgrade reflects the application of newer criteria to the leases, rather than any TVA action, event, or change in business conditions. At December 31, 2011 and September 30, 2011, the total balances of the leaseback obligations were $1.3 billion.
12. Risk Management Activities and Derivative Transactions
TVA is exposed to various market risks. These market risks include risks related to commodity prices, investment prices, interest rates, currency exchange rates, inflation, and counterparty credit and counterparty performance risk. To help manage certain of these risks, TVA has entered into various derivative transactions, principally commodity option contracts, forward contracts, swaps, swaptions, futures, and options on futures. Other than certain derivative instruments in investment funds, it is TVA’sTVA's policy to enter into these derivative transactions solely for hedging purposes and not for speculative purposes.
Overview of Accounting Treatment
TVA recognizes certain of its derivative instruments as either assets or liabilities on its balance sheets at fair value. The accounting for changes in the fair value of these instruments depends on (1) whether TVA uses regulatory accounting to defer the derivative gains and losses, or(2) whether the derivative instrument has been designated and qualifies for hedge accounting treatment,, and (3) if so, the type of hedge relationship (e.g., cash flow hedge).
The following tables summarize the accounting treatment that certain of TVA’sTVA's financial derivative transactions receive.
Summary of Derivative Instruments That Receive Hedge Accounting Treatment (part 1) |
| Derivatives in Cash Flow Hedging Relationship | | Objective of Hedge Transaction | | Accounting for Derivative Hedging Instrument | | Amount of Mark-to-Market Gain (Loss) Recognized in Other Comprehensive Income (Loss) (“OCI”) Three Months Ended June 30 | | Amount of Mark-to-Market Gain (Loss) Recognized in OCI Nine Months Ended June 30 |
| | | | | | | 2011 | | 2010 | | 2011 | | 2010 |
| | | | | | | | | | | | | |
| Currency swaps | | To protect against changes in cash flows caused by changes in foreign currency exchange rates (exchange rate risk) | | Cumulative unrealized gains and losses are recorded in OCI and reclassified to interest expense to the extent they are offset by cumulative gains and losses on the hedged transaction | | $ (12) | | $ (76) | | $ 51 | | $ (55) |
|
| | | | | | | | | | | | |
Summary of Derivative Instruments That Receive Hedge Accounting Treatment (part 1) |
| Derivatives in Cash Flow Hedging Relationship | | Objective of Hedge Transaction | | Accounting for Derivative Hedging Instrument | | Amount of Mark-to-Market ("MtM") Gain (Loss) Recognized in Other Comprehensive Income (Loss) (“OCI”) Three Months Ended December 31 |
| | | | | | | 2011 | | 2010 |
| Currency swaps | | To protect against changes in cash flows caused by changes in foreign currency exchange rates (exchange rate risk) | | Cumulative unrealized gains and losses are recorded in OCI and reclassified to interest expense to the extent they are offset by cumulative gains and losses on the hedged transaction | | $ | 42 |
| | $ | 49 |
|
|
| | | | | | | | | |
Summary of Derivative Instruments That Receive Hedge Accounting Treatment (part 2) |
Derivatives in Cash Flow Hedging Relationship | | Amount of Gain (Loss) Reclassified from OCI to Interest Expense Three Months Ended December 31(1) | |
| | | 2011 | | 2010 | |
| Currency swaps | | $ | 3 |
| | $ | 7 |
| |
Note (1) There were no ineffective portions or amounts excluded from effectiveness testing for any of the periods presented. |
Summary of Derivative Instruments That Receive Hedge Accounting Treatment (part 2) |
Derivatives in Cash Flow Hedging Relationship | | Amount of Exchange Gain (Loss) Reclassified from OCI to Interest Expense Three Months Ended June 30 (1) | | Amount of Exchange Gain (Loss) Reclassified from OCI to Interest Expense Nine Months Ended June 30 (1) |
| | | 2011 | | 2010 | | 2011 | | 2010 |
| | | | | | | | | |
| Currency swaps | | $ (1) | | $ 14 | | $ (21) | | $ 63 |
Note (1) There were no ineffective portions or amounts excluded from effectiveness testing for any of the periods presented. |
|
| | | | | | | | | | | |
| Summary of Derivative Instruments That Do Not Receive Hedge Accounting Treatment |
| Derivative Type | | Objective of Derivative | | Accounting for Derivative Instrument | | Amount of Gain (Loss) Recognized in Income on Derivatives Three Months Ended December 31(1) | |
| | | | | | | 2011 | | 2010 | |
| Swaption | | To protect against decreases in value of the embedded call (interest rate risk) | | MtM gains and losses are recorded as regulatory assets or liabilities until settlement, at which time the gains/losses (if any) are recognized in gain/loss on derivative contracts. | | $ — |
| | $ — |
| |
| | | | | | | | | | |
| Interest rate swaps | | To fix short-term debt variable rate to a fixed rate (interest rate risk) | | MtM gains and losses are recorded as regulatory assets or liabilities until settlement, at which time the gains/losses (if any) are recognized in gain/loss on derivative contracts. | | — |
| | — |
| |
| | | | | | | | | | |
| Commodity contract derivatives | | To protect against fluctuations in market prices of purchased coal or natural gas (price risk) | | MtM gains and losses are recorded as regulatory assets or liabilities. Realized gains and losses (if any) due to contract settlements are recognized in fuel expense as incurred.
| | — |
| | — |
| |
| | | | | | | | | | |
Commodity derivatives under financial trading program ("FTP") | | To protect against fluctuations in market prices of purchased commodities (price risk) | | MtM gains and losses are recorded as regulatory assets or liabilities. Realized gains and losses are recognized in fuel and purchased power expense when the related commodity is used in production. | | (56 | ) | | (42 | ) | |
Notes (1) All of TVA's derivative instruments that do not receive hedge accounting treatment have unrealized gains (losses) that would otherwise be recognized in income but instead are deferred as regulatory assets and liabilities. As such, there was no related gain (loss) recognized in income for these unrealized gains (losses) for the three months ended December 31, 2011 and 2010. |
Summary of Derivative Instruments That Do Not Receive Hedge Accounting Treatment |
| Derivative Type | | Objective of Derivative | | Accounting for Derivative Instrument | | Amount of Gain (Loss) Recognized in Income on Derivatives Three Months Ended June 30 (1) | | Amount of Gain (Loss) Recognized in Income on Derivatives Nine Months Ended June 30 (1) |
| | | | | | | 2011 | | 2010 | | 2011 | | 2010 |
Swaption | | To protect against decreases in value of the embedded call (interest rate risk) | | Mark-to-market gains and losses are recorded as regulatory assets or liabilities until settlement, at which time the gains/losses (if any) are recognized in gain/loss on derivative contracts. | | $ — | | $ — | | $ — | | $ — |
| | | | | | | | | | | | | |
Interest rate swaps | | To fix short-term debt variable rate to a fixed rate (interest rate risk) | | Mark-to-market gains and losses are recorded as regulatory assets or liabilities until settlement, at which time the gains/losses (if any) are recognized in gain/loss on derivative contracts.(2) | | — | | — | | — | | — |
| | | | | | | | | | | | | |
Commodity contract derivatives | | To protect against fluctuations in market prices of purchased coal or natural gas (price risk) | | Mark-to-market gains and losses are recorded as regulatory assets or liabilities. Realized gains and losses are recognized in fuel expense when the related commodity is used in production. | | — | | — | | — | | — |
| | | | | | | | | | | | | |
Commodity derivatives under financial trading program | | To protect against fluctuations in market prices of purchased commodities (price risk) | | Mark-to-market gains and losses are recorded as regulatory assets or liabilities. Realized gains and losses are recognized in fuel expense when the related commodity is used in production. | | (29) | | (26) | | (106) | | (98) |
Note (1) All of TVA’s derivative instruments that do not receive hedge accounting treatment have unrealized gains (losses) that would otherwise be recognized in income but instead are deferred as regulatory assets and liabilities. As such, there was no related gain (loss) recognized in income for these unrealized gains (losses) for the three and nine months ended June 30, 2011 and 2010. (2) Generally, TVA maintains a level of outstanding discount notes equal to or greater than the notional amount of the interest rate swaps. However, in February 2011 and September 2010 TVA issued long-term Bonds in anticipation of the maturity of other long-term debt, and used the proceeds to pay down discount notes, which caused the balance of discount notes outstanding at June 30, 2011, to remain below the notional amount of the interest rate swaps. There is no impact on the statements of operations due to the use of regulatory accounting for these items. |
MARK-TO-MARKET VALUES OF TVA DERIVATIVES |
| | At June 30, 2011 | | At September 30, 2010 |
| |
| Derivatives that Receive Hedge Accounting Treatment: |
| |
| | Balance | | Balance Sheet Presentation | | Balance | | Balance Sheet Presentation |
| Currency swaps: | | | | | | | |
£200 million Sterling | $ (29) | | Other long-term liabilities | | $ (42) | | Other long-term liabilities |
£250 million Sterling | 14 | | Other long-term assets | | (5) | | Other long-term liabilities |
£150 million Sterling | (15) | | Other long-term liabilities | | (34) | | Other long-term liabilities |
| |
| Derivatives that Do Not Receive Hedge Accounting Treatment: |
| |
| | Balance | | Balance Sheet Presentation | | Balance | | Balance Sheet Presentation |
Swaption: | | | | | | | |
| $1.0 billion notional | $ (629) | | Other long-term liabilities | | $ (804) | | Other long-term liabilities |
| Interest rate swaps: | | | | | | | |
| $476 million notional | (247) | | Other long-term liabilities | | (356) | | Other long-term liabilities |
| $42 million notional | (12) | | Other long-term liabilities | | (15) | | Other long-term liabilities |
| Commodity contract derivatives | 124 | | Other long-term assets $252; Other current assets $131; Other long-term liabilities ($143); Accounts payable and accrued liabilities ($116) | | 103 | | Other long-term assets $103; Other current assets $49; Other long-term liabilities ($2); Accounts payable and accrued liabilities ($47) |
| | | | | | | | |
| Derivatives under financial trading program: | | | | | | | |
Margin cash account(1) | 33 | | Other current assets | | 12 | | Other current assets |
Derivatives under financial trading program(2) | (142) | | Current regulatory liabilities $16; Regulatory liabilities $9; Current regulatory assets ($88); Regulatory assets ($79) | | (254) | | Current regulatory liabilities $6; Regulatory liabilities $3; Current regulatory assets ($136); Regulatory assets ($127) |
Note (1) In accordance with certain credit terms, TVA uses leverage to trade financial instruments under the financial trading program. Therefore, the margin cash account balance does not represent 100 percent of the net market value of the derivative positions outstanding as shown in the Derivatives Under financial trading program table. (2) The June 30, 2011, and September 30, 2010, balances in Derivatives under financial trading program show all open derivative positions in the financial trading program. TVA previously included both open derivative positions and closed derivative gains and losses in this amount. TVA changed the presentation at June 30, 2011, to be consistent with the other derivatives in this table, which only show open positions, and revised the September 30, 2010 balances accordingly. |
|
| | | | | | | | | | | |
MARK-TO-MARKET VALUES OF TVA DERIVATIVES |
| | At December 31, 2011 | | At September 30, 2011 |
| Derivatives that Receive Hedge Accounting Treatment: |
| | Balance | | Balance Sheet Presentation | | Balance | | Balance Sheet Presentation |
| Currency swaps: | | | | | | | |
| £200 million Sterling | $ | (37 | ) | | Other long-term liabilities | | $ | (44 | ) | | Other long-term liabilities |
| £250 million Sterling | (2 | ) | | Other long-term liabilities | | (24 | ) | | Other long-term liabilities |
| £150 million Sterling | (50 | ) | | Other long-term liabilities | | (63 | ) | | Other long-term liabilities |
| | | | | | | | |
| Derivatives that Do Not Receive Hedge Accounting Treatment: |
| | Balance | | Balance Sheet Presentation | | Balance | | Balance Sheet Presentation |
Swaption: | | | | | | | |
| $1.0 billion notional | $ | (1,128 | ) | | Other long-term liabilities | | $ | (1,077 | ) | | Other long-term liabilities |
| Interest rate swaps: | | | | | | | |
| $476 million notional | (450 | ) | | Other long-term liabilities | | (446 | ) | | Other long-term liabilities |
| $42 million notional | (17 | ) | | Other long-term liabilities | | (17 | ) | | Other long-term liabilities |
| Commodity contract derivatives | 4 |
| | Other long-term assets $202; Other current assets $73; Other long-term liabilities $(155); Accounts payable and accrued liabilities $(116) | | 239 |
| | Other long-term assets $285; Other current assets $150; Other long-term liabilities $(119); Accounts payable and accrued liabilities $(77) |
| Derivatives under FTP: | | | | | | | |
Margin cash account(1) | 60 |
| | Other current assets | | 34 |
| | Other current assets |
Derivatives under FTP(2) | (412 | ) | | Current regulatory assets $(230); Regulatory assets $(192); Current regulatory liabilities $7; Regulatory liabilities $3 | | (234 | ) | | Current regulatory assets $(135); Regulatory assets $(102); Current regulatory liabilities $3 |
Note (1) In accordance with certain credit terms, TVA uses leverage to trade financial instruments under the FTP. Therefore, the margin cash account balance does not represent 100 percent of the net market value of the derivative positions outstanding as shown in the Derivatives Under Financial Trading Program table. This balance also includes the $26 million currently being held by the MF Global Trustee. See Counterparty Credit Risk for details. (2) The December 31, 2011 and September 30, 2011 balances in the Derivatives under Financial Trading Program table show all open derivative positions in the FTP. |
Cash Flow Hedging Strategy for Currency Swaps
To protect against exchange rate risk related to three British pound sterling denominated Bond transactions, TVA entered into foreign currency hedges at the time the Bond transactions occurred. TVA had the following currency swaps outstanding as of June 30, 2011:December 31, 2011:
Currency Swaps Outstanding At June 30, 2011 |
| Effective Date of Currency Swap Contract | | Associated TVA Bond Issues Currency Exposure | | Expiration Date of Swap | | Overall Effective Cost to TVA |
| 2003 | | £150 million | | 2043 | | 4.96% |
| 2001 | | £250 million | | 2032 | | 6.59% |
| 1999 | | £200 million | | 2021 | | 5.81% |
|
| | | | | | |
Currency Swaps Outstanding At December 31, 2011 |
| Effective Date of Currency Swap Contract | | Associated TVA Bond Issues Currency Exposure | | Expiration Date of Swap | | Overall Effective Cost to TVA |
| 1999 | | £200 million | | 2021 | | 5.81% |
| 2001 | | £250 million | | 2032 | | 6.59% |
| 2003 | | £150 million | | 2043 | | 4.96% |
When the dollar strengthens against the British pound sterling, the transaction gain on the Bond liability is offset by an exchange loss on the swap contract. Conversely, when the dollar weakens against the British pound sterling, the transaction loss on the Bond liability is offset by an exchange gain on the swap contract. All such exchange gains or losses on the Bond
liability are included in Long-term debt, net.net. The offsetting exchange losses or gains on the swap contracts are recognized in Accumulated other comprehensive lossincome (loss). If any gain (loss) were to be incurred as a result of the early termination of the foreign currency swap contract, the resulting income (expense) would be amortized over the remaining life of the associated Bond as a component of Interest expense.expense.
Derivatives Not Receiving Hedge Accounting Treatment
Swaption and Interest Rate Swaps. Prior to 2006,, TVA entered into four swaption transactions to monetize the value of call provisions on certain of its Bond issues. A swaption grants a third party the right to enter into a swap agreement with TVA under which TVA receives a floating rate of interest and pays the third party a fixed rate of interest equal to the interest rate on the Bond issue whose call provision TVA has monetized.monetized. Subsequently, the counterparties to three of the swaptions exercised their rights to enter into interest rate swaps with TVA.
TVA uses regulatory accounting treatment to defer the mark-to-marketMtM gains and losses on these swaps and swaption and includes the gain or loss in the ratemaking formula when these transactions settle. The values of the swaps and swaption and related deferred unrealized gains and losses are recorded on TVA’sTVA's balance sheets with realized gains or losses, if any, recorded on TVA’sTVA's statements of operations. There were no realized gains or losses for the ninethree months ended June 30,December 31, 2011 and 2010.2010.
For the three and nine months ended June 30,December 31, 2011 and 2010, the changes in market value resulted in deferred unrealized gains (losses) on the value of the interest rate swaps and swaption of $(93)$(55) million and $287$337 million, respectively. All net deferred unrealized gains and losses are reclassified as regulatory assets or liabilities on the balance sheet.
Commodity Derivatives. Derivatives. TVA enters into certain derivative contracts for coal and natural gas and electricity that require physical delivery of the contracted quantity of the commodity. TVA expects to take or make delivery, as appropriate, under the electricity contract derivatives. Accordingly, these contracts qualify for normal purchases and normal sales accounting.
TVA marks to market all of its natural gas derivative contracts that require physical delivery. The total market value of these natural gas derivative contracts at June 30, 2011, and September 30, 2010, was less than $1 million. At June 30, 2011, these natural gas derivative contracts had terms of up to four months.
During the three months ended December 31, 2010, TVA determined that certain quantities under the coal contract derivatives were no longer probable of physical delivery; therefore, these contracts were no longer eligible for normal purchases and normal sales accounting. Accordingly, TVA began marking to market all of its coal contract derivatives to market as of at December 31, 2010. At June 30December 31, 2011, 2011, and September 30, 2010, TVA’s2011, TVA's coal contract derivatives had net market values of $123$4 million and $103$239 million, respectively, which TVA deferred as regulatory assets and liabilities on a gross basis. At June 30,December 31, 2011 TVA’s, TVA's coal contract derivatives had terms of up to six years.
TVA marks to market all of its natural gas derivative contracts that require physical delivery. The total market value of these natural gas derivative contracts at December 31, 2011, and September 30, 2011, was less than $1 million. At December 31, 2011, these natural gas derivative contracts had terms of up to one month.
| | Commodity Contract Derivatives | Commodity Contract Derivatives | Commodity Contract Derivatives |
| | At June 30, 2011 | | At September 30, 2010 | At December 31, 2011 | | At September 30, 2011 |
| | Number of Contracts | Notional Amount | Fair Value (MtM) | | Number of Contracts | Notional Amount | Fair Value (MtM) | Number of Contracts | | Notional Amount | | Fair Value (MtM) | | Number of Contracts | | Notional Amount | | Fair Value (MtM) |
| | | | | |
| Coal Contract Derivatives | 41 | 74 million tons | $ 123 | | 11 | 27 million tons | $ 103 | 20 | | 61 million tons | | $4 | | 38 | | 66 million tons | | $239 |
| | | | | |
| Natural Gas Contract Derivatives | 15 | 24 million mmBtu | $ 1 | | 3 | 1 million mmBtu | $ — | 9 | | 8 million mmBtu | | $— | | 13 | | 5 million mmBtu | | $— |
Derivatives Under Financial Trading Program. FTP.TVA has a financial trading program (“FTP”)FTP under which it purchases and sells futures, swaps, options, and combinations of these instruments (as long as they are standard in the industry) to hedge TVA’s exposure to (1) the price of natural gas, fuel oil, electricity, coal, emission allowances, nuclear fuel, and other commodities included in TVA’s fuel cost adjustment (“FCA”) calculation, (2) the price of construction materials, and (3) contracts for goods priced in or indexed to foreign currencies. The combined transaction limit for the FCAfuel cost adjustment and construction material transactions is $130 million (based on one-day value at risk). In addition, the maximum hedge volume for the construction material transactions is 75 percent of the underlying net notional volume of the material that TVA anticipates using in approved TVA projects, and the market value of all outstanding hedging transactions involving construction materials is limited to $100 million at the execution of any new transaction. The portfolio value at risk limit for the foreign currency transactions is $5 million and is separate and distinct from the $130 million transaction limit discussed above. TVA is prohibited from trading financial instruments under the FTP for speculative purposes.
At June 30,December 31, 2011, the risks hedged under the FTP were the economic risks associated with the prices of natural gas, fuel oil, crude oil, coal, and power.coal. Futures contracts and option contracts under the FTP had remaining terms of less than one year or less.year. Swap contracts under the FTP had remaining terms of six years or less.
Derivatives Under Financial Trading Program | | |
| | | | | | | | | | | | | | |
| | | At June 30, 2011 | | | At September 30, 2010 | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
| Derivatives Under Financial Trading Program | | Derivatives Under Financial Trading Program |
| | | Notional Amount | | | Fair Value (MtM) (in millions) | | | Notional Amount | | | Fair Value (MtM) (in millions) | | At December 31, 2011 | | At September 30, 2011 |
| | | | | | | | | | | | | | Notional Amount | | Fair Value (MtM) (in millions) | | Notional Amount | | Fair Value (MtM) (in millions) |
| Natural gas (in mmBtu) | | | | | | | | | | | | | | | | | | | |
| Futures contracts | | | 2,550,000 | | | $ | (6 | ) | | | 7,920,000 | | | $ | (21 | ) | 400,000 |
| | $ | (2 | ) | | 1,300,000 |
| | $ | (4 | ) |
| Swap contracts | | | 171,915,000 | | | | (159 | ) | | | 137,110,000 | | | | (241 | ) | 321,707,500 |
| | (417 | ) | | 232,295,000 |
| | (223 | ) |
| Option contracts | | | 1,250,000 | | | | (1 | ) | | | 5,250,000 | | | | (2 | ) | — |
| | (2 | ) | | — |
| | (1 | ) |
| Natural gas financial positions | | | 175,715,000 | | | $ | (166 | ) | | | 150,280,000 | | | $ | (264 | ) | 322,107,500 |
| | $ | (421 | ) | | 233,595,000 |
| | $ | (228 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | |
| Fuel oil/crude oil (in barrels) | Fuel oil/crude oil (in barrels) | | | | | | | | | | | | | | Fuel oil/crude oil (in barrels) | | |
| | |
| | |
|
| Futures contracts | | | - | | | $ | - | | | | 125,000 | | | $ | 2 | | — |
| | $ | — |
| | — |
| | $ | — |
|
| Swap contracts | | | 1,495,000 | | | | 22 | | | | 1,711,000 | | | | 8 | | 1,408,000 |
| | 9 |
| | 1,591,000 |
| | (7 | ) |
| Option contracts | | | 180,000 | | | | - | | | | 495,000 | | | | - | | — |
| | — |
| | 90,000 |
| | — |
|
| Fuel oil/crude oil financial positions | | | 1,675,000 | | | $ | 22 | | | | 2,331,000 | | | $ | 10 | | 1,408,000 |
| | $ | 9 |
| | 1,681,000 |
| | $ | (7 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | |
| Coal (in tons) | | | | | | | | | | | | | | | | | |
| | |
| | |
| | |
|
| Futures contracts | | | - | | | $ | - | | | | - | | | $ | - | | — |
| | $ | — |
| | — |
| | $ | — |
|
| Swap contracts | | | 120,000 | | | | 2 | | | | 480,000 | | | | - | | 120,000 |
| | — |
| | 120,000 |
| | 1 |
|
| Option contracts | | | - | | | | - | | | | - | | | | - | | — |
| | — |
| | — |
| | — |
|
| Coal financial positions | | | 120,000 | | | $ | 2 | | | | 480,000 | | | $ | - | | 120,000 |
| | $ | — |
| | 120,000 |
| | $ | 1 |
|
| | | | | | | | | | | | | | | | | | |
| Power (in MWh) | | | | | | | | | | | | | | | | | |
| Swap contracts | | | 16,800 | | | $ | - | | | | - | | | $ | - | | |
| Power financial positions | | | 16,800 | | | $ | - | | | | - | | | $ | - | | |
| | | | | | | | | | | | | | | | | | |
Note Due to the right of setoff and method of settlement, TVA elects to record commodity derivatives under the FTP based on its net commodity position with the broker or other counterparty. Notional amounts disclosed represent the net absolute value of contractual amounts. | Note Due to the right of setoff and method of settlement, TVA elects to record commodity derivatives under the FTP based on its net commodity position with the broker or other counterparty. Notional amounts disclosed represent the net absolute value of contractual amounts. | Note Due to the right of setoff and method of settlement, TVA elects to record commodity derivatives under the FTP based on its net commodity position with the broker or other counterparty. Notional amounts disclosed represent the net absolute value of contractual amounts. |
TVA defers all FTP unrealized gains (losses) as regulatory liabilities (assets) and records only realized gains or losses to match the delivery period of the underlying commodity product.contract. In addition to the open commodity derivatives disclosed above, TVA had closed derivative contracts with market values of $(14)$25 million at JuneDecember 31, 2011, and $(13) million at September 30, 2011. TVA experienced the following unrealized and $(15) million at September 30, 2010. The deferred unrealizedrealized gains and losses related to natural gas hedges were $(166) million at June 30, 2011, and $(264) million at September 30, 2010. For the nine months ended June 30, 2011 and 2010, TVA recognized realized losses on natural gas hedges of $(121) million and $(110) million, respectively, which were recorded as increases to Fuel expense. The deferred unrealized gains related to fuel oil/crude oil hedges were $22 million at June 30, 2011, and $10 million at September 30, 2010. ForFTP during the nine months ended June 30, 2011 and 2010, TVA recognized realized gains on fuel oil/crude oil hedges of $17 million and $12 million, respectively, which were recorded as decreases to Fuel expense. The deferred unrealized gain related to coal hedges was $2 million at June 30, 2011. For the nine months ended June 30, 2011, TVA recognized realized gains on coal hedges of less than $1 million, which was recorded as a decrease to Fuel expense. There were no deferred unrealized gains or losses related to coal hedges at June 30, 2010.period:
|
| | | | | | | | |
| FTP Unrealized Gains (Losses) |
| | | | | |
| FTP unrealized gains (losses) deferred as regulatory liabilities (assets) | | At December 31, 2011 | | At September 30, 2011 |
| | | | | |
| Natural gas | | $ | (421 | ) | | $ | (228 | ) |
| Fuel oil/crude oil | | 9 |
| | (7 | ) |
| Coal | | — |
| | 1 |
|
|
| | | | | | | | |
| FTP Realized Gains (Losses) |
| | | | | |
| | | For the Three Months Ended December 31 |
| Decrease (increase) in fuel expense | | 2011 | | 2010 |
| | | | | |
| Fuel oil/crude oil | | $ | 5 |
| | $ | 6 |
|
| Coal | | — |
| | — |
|
|
| | | | | | | | |
| FTP Realized Gains (Losses) |
| | | | | |
| | | For the Three Months Ended December 31 |
| Decrease (increase) in purchased power expense | | 2011 | | 2010 |
| | | | | |
| Natural gas | | $ | (61 | ) | | $ | (48 | ) |
Other Derivative Instruments
Investment Fund Derivatives. Derivatives. Investment funds consist primarily of funds held in the Nuclear Decommissioning Trust (“NDT”("NDT"), the Asset Retirement Trust (“ART”("ART"), and the Supplemental Executive Retirement Plan (“SERP”("SERP"). All securities in the trusts are classified as trading. See Note 13 — Investmentsfor a discussion of the trusts’trusts' objectives and the types of investments included in the various trusts. Derivative instruments in these trusts include swaps, futures, options, forwards, and other instruments. As of JuneAt December 31, 2011 and September 30, 2011 and September 30, 2010,, the fair value of derivative instruments in these trusts was not material to TVA’sTVA's financial statements.
Collateral. TVA’sTVA's interest rate swaps, its currency swaps, and its swaption contain contract provisions that require a party to post collateral (in a form such as cash or a letter
of credit) when the party’sparty's liability balance under the agreement exceeds a certain threshold. As of June 30,At December 31, 2011, the aggregate fair value of all derivative instruments with credit-risk related contingent features that were in a liability position was $932 million. TVA’s$1.7 billion. TVA's collateral obligation as of June 30,obligations at December 31, 2011, under these arrangements was $224$756 million, for which TVA had posted $224$756 million under a letterin letters of credit. These letterletters of credit postings reduce the available balance under the related credit facility. TVA’sTVA's assessment of the risk of its nonperformance includes a reduction in its exposure under the contract as a result of this posted collateral.
For all of its derivative instruments with credit-risk related contingent features:
If TVA remains a majority-owned U.S. government entity but Standard & PoorsPoor's (“S&P”) or Moody’s InvestorMoody's Investors Service (“Moody’s”("Moody's") downgrades TVA’sTVA's credit rating to AA or Aa2, respectively, TVA would be required to post an additional $175$75 million of collateral in excess of its June 30,December 31, 2011, obligation; and
If TVA ceases to be majority-owned by the U.S. government, itsTVA's credit rating would likely changebe downgraded and TVA would be required to post additional collateral.
capital.
Counterparty Credit Risk
Credit risk is the exposure to economic loss that would occur as a result of a counterparty’scounterparty's nonperformance of its contractual obligations. Where exposed to counterparty credit risk, TVA analyzes the counterparty’scounterparty's financial condition prior to entering into an agreement, establishes credit limits, monitors the appropriateness of those limits, as well as any changes in the creditworthiness of the counterparty on an ongoing basis, and employs credit mitigation measures, such as collateral or prepayment arrangements and master purchase and sale agreements, to mitigate credit risk.
On October 31, 2011, MF Global Holding Ltd. and its subsidiary MF Global Finance USA Inc. filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. On the same date, a Securities Investor Protection Act proceeding was filed against MF Global Inc. ("MF Global"). TVA had used MF Global to clear certain trades and the MF Global Trustee held $33 million of TVA's cash collateral at that time. TVA has recovered $7 million of this balance from the Trustee. TVA has filed a claim to recover the funds currently being held by the MF Global Trustee and expects to recover some or all of these funds; however, the timing and the amount of the funds' returned and the amount of any potential loss cannot be estimated at this time.
Credit of Customers.Customers. The majority of TVA’sTVA's counterparty credit risk is associated with trade accounts receivable from delivered power sales to municipal and cooperative distributor customers, all located in the Tennessee Valley region. To a lesser extent, TVA is exposed to credit risk from industries and federal agencies directly served and from exchange power arrangements with a small number of investor-owned regional utilities related to either delivered power or the replacement of open positions of longer-term purchased power or fuel agreements. TVA had concentrations of accounts receivable from four customers that represented 27 percent of total outstanding accounts receivable at December 31, 2011. TVA had concentrations of accounts receivable from three customers that represented 26 percent of total outstanding accounts receivable at September 30, 2011. Power sales to TVA’sTVA's largest directly served industrial customer directly served represented fivesix percent of TVA’sTVA's total operating revenues for the ninethree months ended June 30, 2011.December 31, 2011. This customer’scustomer's senior unsecured credit ratings are currently CCC- by S&P and Caa2 by Moody’s.Moody's. As a result of its credit ratings, this customer has provided credit assurance to TVA under the terms of its power contract. TVA had concentrations of accounts receivable from four customers that represented 31 percent of total outstanding accounts receivable at June 30, 2011. TVA had concentrations of accounts receivable from five customers that represented 36 percent of total outstanding accounts receivable at September 30, 2010.
Credit of Derivative Counterparties. Counterparties. TVA has entered into derivative contracts for hedging purposes, and TVA’sTVA's NDT fund and defined benefit pension plan have entered into derivative contracts for investment purposes. If a counterparty to one of TVA’s
TVA's hedging transactions defaults, TVA might incur substantial costs in connection with entering into a replacement hedging transaction. If a counterparty to the derivative contracts into which the NDT fund and the pension fundplan have entered for investment purposes defaults, the value of the investment could decline significantly or perhaps become worthless. TVA has concentrations of credit risk from the banking and coal industries because multiple companies in these industries serve as counterparties to TVA in various derivative transactions. As of June 30,At December 31, 2011, the swaption and all of TVA’sTVA's currency swaps, interest rate swaps, and commodity derivatives under the FTP were with counterparties whose Moody’sMoody's credit rating was A2 or higher. As of June 30,At December 31, 2011, all of TVA’sTVA's coal contract derivatives were with counterparties whose Moody’sMoody's credit rating, or TVA’sTVA's internal analysis when such information was unavailable, was Caa1 or higher.
Credit of Suppliers. Suppliers. If one of TVA’sTVA's fuel or purchased power suppliers fails to perform under the terms of its contract with TVA, TVA might lose the money that it paid to the supplier under the contract and have to purchase replacement fuel or power on the spot market, perhaps at a significantly higher price than TVA was entitled to pay under the contract. In addition, TVA might not be able to acquire replacement fuel or power in a timely manner and thus might be unable to satisfy its own obligations to deliver power. To help ensure a reliable supply of coal, TVA had coal contracts with 2311 different suppliers at June 30, 2011.December 31, 2011. The contracted supply of coal is sourced from multiple geographic regions of the United States and is to be delivered via various transportation methods (e.g., barge, rail, and truck). TVA purchases all of its natural gas requirements from a variety of suppliers under short-term contracts.
TVA has a power purchase agreement that expires on March 31, 2032, with a supplier of electricity for 440 megawatts (“MW”("MW") of summer net capability from a lignite-fired generating plant that expires on March 31, 2032.plant. The supplier’ssupplier's senior secured credit ratings are currently B+CCC- by S&P and B2Caa1 by Moody’s.Moody's. As a result of its credit ratings, the supplier has provided credit assurance to TVA under the terms of its agreement. Additionally, the
The senior unsecured credit ratings of TVA’sTVA's largest supplier of uranium enrichment services, which is also TVA's largest industrial customer directly served, are currently CCC-CCC- by S&P and Caa2 by Moody's. Any nonperformance by this company could result in TVA incurring additional costs.
Fair value is determined based on the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in TVA’sthe asset or liability's principal market, or in the absence of a principal market, the most advantageous market for the asset or liability in an orderly transaction between market participants. TVA uses market or observable inputs as the preferred source of values, followed by assumptions based on hypothetical transactions in the absence of market inputs.
Valuation Techniques
The measurement of fair value results in classification into a hierarchy by the inputs used to determine the fair value as follows:
|
| | | |
| Level 1 | — | | Unadjusted quoted prices in active markets accessible by the reporting entity for identical assets or liabilities. Active markets are those in which transactions for the asset or liability occur with sufficient frequency and volume to provide pricing. |
Level 2 | — | | Pricing inputs other than quoted market prices included in Level 1 that are based on observable market data and that are directly or indirectly observable for substantially the full term of the asset or liability. These include quoted market prices for similar assets or liabilities, quoted market prices for identical or similar assets in markets that are not active, adjusted quoted market prices, inputs from observable data such as interest rate and yield curves, volatilities and default rates observable at commonly quoted intervals, and inputs derived from observable market data by correlation or other means. |
| Level 3 | — | | Pricing inputs that are unobservable, or less observable, from objective sources. Unobservable inputs are only to be used to the extent observable inputs are not available. These inputs maintain the concept of an exit price from the perspective of a market participant and should reflect assumptions of other market participants. An entity should consider all market participant assumptions that are available without unreasonable cost and effort. These are given the lowest priority and are generally used in internally developed methodologies to generate management's best estimate of the fair value when no observable market data is available. |
A financial instrument's level within the fair value hierarchy (where Level 3 is the lowest and Level 1 is the highest) is based on the lowest level of input significant to the fair value measurement.
The following sections describe the valuation methodologies TVA uses to measure different financial instruments at fair value. Except for gains and losses on SERP assets, all changes in fair value of these assets and liabilities have been reflected as changes in Regulatoryregulatory assets,, Regulatory regulatory liabilities,, or Accumulatedaccumulated other comprehensive loss on TVA’sTVA's Balance Sheet as of June 30,December 31, 2011, and Statements of Changes in Proprietary Capital for the three and nine months ended June 30, 2011.December 31,
2011. Except for gains and losses on SERP assets, there has been no impact to the Statements of Operations for the three and nine months ended June 30, 2011, or the Statements of Cash Flows for the nine months ended June 30, 2011, related to these fair value measurements.
Investments
At June 30,December 31, 2011 TVA’s, investment funds were composed of $1.3 billion of securities classified as trading and measured at fair value and $2 million of equity investments not required to be measured at fair value. Trading securities are held in the NDT, ART, and SERP. The NDT holds funds for the ultimate decommissioning of TVA’sTVA's nuclear power plants. The ART holds funds for the costs related to the future closure and retirement of TVA’sTVA's long-lived assets. TVA established a SERP for certain executives in critical positions to provide supplemental pension benefits tied to compensation that exceeds limits imposed by Internal Revenue Service (“IRS”) rules applicable to the qualified defined benefit pension plan. The NDT, ART and SERP are invested in securities generally designed to achieve a return in line with overall equity market performance. The ART is presently invested to achieve a return in line with fixed-income market performance.
The NDT, ART, and SERP are composed of multiple types of investments and are managed by external institutional managers. Most U.S. and international equities, Treasury inflation-protected securities, real estate investment trust (“REIT”) securities, and cash securities, and certain derivative instruments are measured based on quoted exchange prices in active markets and are classified as Level 1 valuations. Fixed-income investments, high-yield fixed-income investments, currencies, and most derivative instruments are non-exchange traded and are classified as Level 2 valuations. These measurements are based on market and income approaches with observable market inputs.
Private partnership investments may include venture capital, buyout, mezzanine or subordinated debt, restructuring or distressed debt, and special situations. Investments in private partnerships generally involve a three- to four-year period where the investor contributes capital. This is followed by a period of distribution, typically over several years. The investment period is generally, at a minimum, a 10-yearten-year or longer investment commitment. The NDT had unfunded commitments related to private partnerships of $82$72 million at June 30, 2011.December 31, 2011. These investments have no redemption or limited redemption options and may also restricthave imposed restrictions on the NDT’sNDT's ability to liquidate its investment interest. The private partnerships and other similar alternative investments are reported at fair value which is derived by independent appraisals or judgment of the general partners of each such investment. The inputs used in estimating the fair value of the limited partnerships include the original transaction prices, recent transactions in the same or similar instruments, completed or pending third-party transactions in the underlying investments of comparable issuers, subsequent rounds of financing, recapitalizations and other transactions across the capital structure, offerings in the equity or debt capital markets, and changes in financial ratios or cash flows of the limited partnerships. The fair value of these investments may also be adjusted to reflect illiquidity and/or non-transferability, with the amount of such discounts estimated by the general partners in the absence of market information. Due to the lack of observable inputs, the determination of the fair value by the general partners may differ materially from the value ultimately realized from the private partnership investments. TVA classifies its interest in these types of investment as Level 3 within the fair value hierarchy.
Commingled funds represent investment funds comprising multiple individual financial instruments. The commingled funds held by the NDT, ART and SERP consist either of a single class of security,securities, such as equity, debt, or foreign currency securities, or multiple classes of securities. All underlying positions in these commingled funds are either exchange traded (Level 1) or measured using observable inputs for similar instruments (Level 2). The fair value of commingled funds is based on net asset values (“NAV”) per fund share (the unit of account), derived from the prices of the underlying securities in the funds. These commingled funds can be liquidated at the measurement date NAV price and are classified as Level 2 valuations. Required notification periods range from zero to 30 days. The funds can be redeemed unless doing so would violate regulations to which the fund is subject, would be unreasonable or impracticable, or would be seriously prejudicial to the fund.
Realized and unrealized gains and losses on trading securities are recognized in current earnings and are based on average cost. The SERP had unrealized gains (losses) of less than $(1)$1 million and $4$2 million for the three and nine months ended June 30,December 31, 2011 respectively, compared with unrealized gains (losses) of $(2) million, and $1 million for the three and nine months ended June 30,December 31, 2010, respectively. The gains and losses of the NDT and ART are subsequently reclassified to a regulatory liability or asset account in accordance with TVA’sTVA's regulatory accounting policy. The NDT had unrealized (losses)gains of $(8)$58 million and $(61)$23 million for the three months ended June 30,December 31, 2011 and 2010, respectively, and the ART had an unrealized (loss)gains of $(1)$9 million for the three months ended June 30, 2011, compared to an unrealized gain ofand less than $1 million for the three months ended June 30, 2010.December 31, 2011 and 2010, respectively.
Currency Swaps, Swaption, and Interest Rate Swaps
See Note 12 — Cash Flow Hedging Strategy for Currency Swaps and Derivatives Not Receiving Hedge Accounting Treatment for a discussion of the nature, purpose, and contingent features of TVA’sTVA's currency swaps, swaption, and interest rate swaps.
The currency swaps and interest rate swaps are classified as Level 2 valuations and are valued based on income approaches using observable market inputs for similar instruments. The swaption is classified as a Level 3 valuation and is valued based on an income approach. The valuation is computed using a broker-provided pricing model utilizing interest and volatility rates. While most of the fair value measurement is based on observable inputs, volatility for TVA’sTVA's swaption is generally unobservable. Therefore, the valuation is derived from an observable volatility measure with adjustments.
Commodity Contract Derivatives and Commodity Derivatives under FTP
Commodity Contract and Commodity Derivatives
Commodity Contract Derivatives. These contracts are classified as Level 3 valuations and are valued based on income approaches. TVA develops an overall coal price forecast using widely-used short-term and mid-range market data from an external pricing specialist in addition to long-term internal estimates. To value the volume option component of applicable coal contracts, TVA uses a Black-Scholes pricing model which includes inputs from the overall coal price forecasts,forecast, contract-specific terms, and other market inputs.
Commodity Derivatives Under Financial Trading Program.FTP. These contracts are valued based on market approaches which utilize Chicago Mercantile Exchange (“CME”) quoted prices and other observable inputs. Futures and options contracts settled on the CME are classified as Level 1 valuations. Swap contracts are valued using a pricing model based on CME inputs and are subject to nonperformance risk outside of the exit price. These contracts are classified as Level 2 valuations.
See Note 12 — Derivatives Not Receiving Hedge Accounting Treatment — Commodity Derivatives and Derivatives Under Financial Trading ProgramFTP for a discussion of the nature and purpose of coal contracts and derivatives under TVA’s FTP.TVA's FTP.
Nonperformance Risk. Risk
The impactassessment of nonperformance risk, which includes credit risk, considers changes in current market conditions, readily available information on nonperformance risk, letters of credit, collateral, other arrangements available, and the nature of master netting arrangements. TVA is a counterparty to currency swaps, a swaption, interest rate swaps, commodity contracts, and other derivatives which subject TVA to nonperformance risk. Nonperformance risk on the majority of investments and certain exchange-traded instruments held by TVA is incorporated into the exit price that is derived from quoted market data that is used to mark the investment to market.
Nonperformance risk for most of TVA’sTVA's derivative instruments is an adjustment to the initial asset/liability fair value. TVA adjusts for nonperformance risk, both of TVA (for liabilities) and the counterparty (for assets), by applying a Credit Valuation Adjustmentvaluation adjustment (“CVA”). TVA determines an appropriate CVA for each applicable financial instrument based on the term of the instrument and TVA’sTVA's or counterparty’sthe counterparty's credit rating as obtained from Moody’s.Moody's. For companies that do not have an observable credit rating, TVA uses internal analysis to assign a comparable rating to the company. TVA discounts each financial instrument using the historical default rate (as reported by Moody’sMoody's for CY 1983 to CY 2010) for companies with a similar credit rating over a time period consistent with the remaining term of the contract. The application of CVAs resulted in a $77an $85 million decrease in the fair value of assets and a $2 million decrease in the fair value of liabilities at June 30, 2011.December 31, 2011.
The following tables set forth by level, within the fair value hierarchy, TVA's financial assets and liabilities that were measured at fair value on a recurring basis as of JuneDecember 31, 2011, and September 30, 2011 and September 30, 2010.. Financial assets and liabilities have been classified in their entirety based on the lowest level of input that is significant to the fair value measurement. TVA's assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the determination of the fair value of the assets and liabilities and their classification in the fair value hierarchy levels.
Fair Value Measurements |
| | | At June 30, 2011 |
| Assets | | Quoted Prices in Active Markets for Identical Assets (Level 1) | | | Significant Other Observable Inputs (Level 2) | | | Significant Unobservable Inputs (Level 3) | | | Netting(1) | | | Total |
| Description |
| | | | | | | | | | | | | | | |
| Currency swaps | | $ | — | | | $ | 14 | | | $ | — | | | $ | — | | | $ | 14 | |
| Investments | | | | | | | | | | | | | | | | | | |
| Equity securities | | | 106 | | | | — | | | | — | | | | — | | | | 106 | |
| Debt securities | | | | | | | | | | | | | | | | | | |
| U.S. government corporations and agencies | | | 110 | | | | 39 | | | | — | | | | — | | | | 149 | |
| Corporate debt securities | | | — | | | | 240 | | | | — | | | | — | | | | 240 | |
| Residential mortgage-backed securities | | | — | | | | 19 | | | | — | | | | — | | | | 19 | |
| Commercial mortgage-backed securities | | | — | | | | 4 | | | | — | | | | — | | | | 4 | |
| Collateralized debt obligations | | | — | | | | 5 | | | | — | | | | — | | | | 5 | |
| Private partnerships | | | — | | | | — | | | | 18 | | | | — | | | | 18 | |
Commingled funds(2) | | | | | | | | | | | | | | | | | | |
| Equity security commingled funds | | | — | | | | 451 | | | | — | | | | — | | | | 451 | |
| Debt security commingled funds | | | — | | | | 224 | | | | — | | | | — | | | | 224 | |
| Other commingled funds | | | — | | | | 38 | | | | — | | | | — | | | | 38 | |
| Total investments | | | 216 | | | | 1,020 | | | | 18 | | | | — | | | | 1,254 | |
| Commodity contract derivatives | | | — | | | | — | | | | 383 | | | | — | | | | 383 | |
| Commodity derivatives under FTP | | | | | | | | | | | | | | | | | | |
| Futures contracts | | | — | | | | — | | | | — | | | | — | | | | — | |
| Swap contracts | | | — | | | | 34 | | | | — | | | | (9 | ) | | | 25 | |
| Option contracts | | | — | | | | — | | | | — | | | | — | | | | — | |
| Total commodity derivatives under FTP | | | — | | | | 34 | | | | — | | | | (9 | ) | | | 25 | |
Total | | $ | 216 | | | $ | 1,068 | | | $ | 401 | | | $ | (9 | ) | | $ | 1,676 | |
| | | | | | | | | | | | | | | | | | | |
| | | Quoted Prices in Active Markets for Identical Liabilities (Level 1) | | | Significant Other Observable Inputs (Level 2) | | | Significant Unobservable Inputs (Level 3) | | | Netting(1) | | | Total |
Liabilities Description |
| | | | | | | | | | | | | | | | | | | |
| Currency swaps | | $ | — | | | $ | 44 | | | $ | — | | | $ | — | | | $ | 44 | |
| Interest rate swaps | | | — | | | | 259 | | | | — | | | | — | | | | 259 | |
| Swaption | | | — | | | | — | | | | 629 | | | | — | | | | 629 | |
| Commodity contract derivatives | | | — | | | | — | | | | 259 | | | | — | | | | 259 | |
| Commodity derivatives under FTP | | | | | | | | | | | | | | | | | | |
| Futures contracts | | | 6 | | | | — | | | | — | | | | — | | | | 6 | |
| Swap contracts | | | — | | | | 169 | | | | — | | | | (9 | ) | | | 160 | |
| Option contracts | | | 1 | | | | — | | | | — | | | | — | | | | 1 | |
| Total commodity derivatives under FTP | | | 7 | | | | 169 | | | | — | | | | (9 | ) | | | 167 | |
Total | | $ | 7 | | | $ | 472 | | | $ | 888 | | | $ | (9 | ) | | $ | 1,358 | |
Notes (1) Due to the right of setoff and method of settlement, TVA elects to record commodity derivatives under the FTP based on its net commodity position with the counterparty or broker. (2) Commingled funds represent investment funds comprising multiple individual financial instruments and are classified in the table based on their existing investment portfolio as of the measurement date. Commingled funds exclusively composed of one class of security are classified in that category. Commingled funds comprising multiple classes of securities are classified as “other commingled funds.” |
| Fair Value Measurements | | |
| | | | | | | | | | | | | | | | | |
| | | At September 30, 2010 | | | | | | | | | | | | | | | | |
Fair Value Measurements At December 31, 2011
| | Fair Value Measurements At December 31, 2011
|
| Assets | | | | | | | | | | | | | | | | Quoted Prices in Active Markets for Identical Assets (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Unobservable Inputs (Level 3) | | Netting(1) | | Total |
| Description | | Quoted Prices in Active Markets for Identical Assets (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Unobservable Inputs (Level 3) | | Netting (1) | | Total | | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Investments | | | | | | | | | | | | | | | | | | | | | | | | |
| Equity securities | | $ | 96 | | | $ | - | | | $ | - | | | $ | - | | | $ | 96 | | $ | 94 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 94 |
|
| Debt securities | | | | | | | | | | | | | | | | | | | | | |
| | |
| | |
| | |
| | |
|
| U.S. government corporations and agencies | | | 136 | | | | 57 | | | | - | | | | - | | | | 193 | | 107 |
| | 101 |
| | — |
| | — |
| | 208 |
|
| Corporate debt securities | | | - | | | | 193 | | | | - | | | | - | | | | 193 | | — |
| | 155 |
| | — |
| | — |
| | 155 |
|
| Residential mortgage-backed securities | | | - | | | | 22 | | | | - | | | | - | | | | 22 | | — |
| | 16 |
| | — |
| | — |
| | 16 |
|
| Commercial mortgage-backed securities | | | - | | | | 2 | | | | - | | | | - | | | | 2 | | — |
| | 3 |
| | — |
| | — |
| | 3 |
|
| Collateralized debt obligations | | | - | | | | 3 | | | | - | | | | - | | | | 3 | | — |
| | 3 |
| | — |
| | — |
| | 3 |
|
| Private partnerships | | | - | | | | - | | | | 13 | | | | - | | | | 13 | | — |
| | — |
| | 28 |
| | — |
| | 28 |
|
Commingled funds (2) | | | | | | | | | | | | | | | | | | | | | |
| | |
| | |
| | |
| | — |
|
| Equity security commingled funds | | | - | | | | 340 | | | | - | | | | - | | | | 340 | | — |
| | 543 |
| | — |
| | — |
| | 543 |
|
| Debt security commingled funds | | | - | | | | 209 | | | | - | | | | - | | | | 209 | | — |
| | 204 |
| | — |
| | — |
| | 204 |
|
| Foreign currency commingled funds | | | - | | | | 12 | | | | - | | | | - | | | | 12 | | — |
| | — |
| | — |
| | — |
| | — |
|
| Other commingled funds | | | - | | | | 45 | | | | - | | | | - | | | | 45 | | — |
| | — |
| | — |
| | — |
| | — |
|
| Total investments | | | 232 | | | | 883 | | | | 13 | | | | - | | | | 1,128 | | 201 |
| | 1,025 |
| | 28 |
| | — |
| | 1,254 |
|
| Commodity contract derivatives | | | - | | | | - | | | | 152 | | | | - | | | | 152 | | — |
| | — |
| | 275 |
| | — |
| | 275 |
|
| Commodity derivatives under FTP | | | | | | | | | | | | | | | | | | | | | |
| | |
| | |
| | |
| | |
|
| Futures contracts | | | 2 | | | | - | | | | - | | | | - | | | | 2 | | |
| Swap contracts | | | - | | | | 9 | | | | - | | | | (1 | ) | | | 8 | | — |
| | 149 |
| | — |
| | (139 | ) | | 10 |
|
| Total commodity derivatives under FTP | | | 2 | | | | 9 | | | | - | | | | (1 | ) | | | 10 | | — |
| | 149 |
| | — |
| | (139 | ) | | 10 |
|
| | | | | | | | | | | |
| Total | | $ | 234 | | | $ | 892 | | | $ | 165 | | | $ | (1 | ) | | $ | 1,290 | | $ | 201 |
| | $ | 1,174 |
| | $ | 303 |
| | $ | (139 | ) | | $ | 1,539 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Liabilities | | | | | | | | | | | | | | | | | | | | | Quoted Prices in Active Markets for Identical Liabilities (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Unobservable Inputs (Level 3) | | Netting(1) | | Total |
| Description | | Quoted Prices in Active Markets for Identical Liabilities (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Unobservable Inputs (Level 3) | | Netting (1) | | Total | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Currency swaps | | $ | - | | | $ | 81 | | | $ | - | | | $ | - | | | $ | 81 | | $ | — |
| | $ | 89 |
| | $ | — |
| | $ | — |
| | $ | 89 |
|
| Interest rate swaps | | | - | | | | 371 | | | | - | | | | - | | | | 371 | | — |
| | 467 |
| | — |
| | — |
| | 467 |
|
| Swaption | | | - | | | | - | | | | 804 | | | | - | | | | 804 | | — |
| | — |
| | 1,128 |
| | — |
| | 1,128 |
|
| Commodity contract derivatives | | | - | | | | - | | | | 49 | | | | - | | | | 49 | | — |
| | — |
| | 271 |
| | — |
| | 271 |
|
| Commodity derivatives under FTP | | | | | | | | | | | | | | | | | | | | | |
| | |
| | |
| | |
| | |
|
| Futures contracts | | | 21 | | | | - | | | | - | | | | - | | | | 21 | | 2 |
| | — |
| | — |
| | — |
| | 2 |
|
| Swap contracts | | | 15 | | | | 227 | | | | - | | | | (1 | ) | | | 241 | | — |
| | 557 |
| | — |
| | (139 | ) | | 418 |
|
| Option contracts | | | 2 | | | | - | | | | - | | | | - | | | | 2 | | 2 |
| | — |
| | — |
| | — |
| | 2 |
|
| Total commodity derivatives under FTP | | | 38 | | | | 227 | | | | - | | | | (1 | ) | | | 264 | | 4 |
| | 557 |
| | — |
| | (139 | ) | | 422 |
|
| | | | | | | | | | | |
| Total | | $ | 38 | | | $ | 679 | | | $ | 853 | | | $ | (1 | ) | | $ | 1,569 | | $ | 4 |
| | $ | 1,113 |
| | $ | 1,399 |
| | $ | (139 | ) | | $ | 2,377 |
|
| | | | | | | | | | | | | | | | | | | | | | |
Note (1) Due to the right of setoff and method of settlement, TVA elects to record commodity derivatives under the FTP based on its net commodity position with the counterparty or broker. (2) Commingled funds represent investment funds comprising multiple individual financial instruments and are classified in the table based on their existing investment portfolio as of the measurement date. Commingled funds exclusively composed of one class of security are classified in that category. Commingled funds comprising multiple classes of securities are classified as "other commingled funds." | | |
Notes (1) Due to the right of setoff and method of settlement, TVA elects to record commodity derivatives under the FTP based on its net commodity position with the counterparty or broker. (2) Commingled funds represent investment funds comprising multiple individual financial instruments and are classified in the table based on their existing investment portfolio as of the measurement date. Commingled funds exclusively composed of one class of security are classified in that category. Commingled funds comprising multiple classes of securities are classified as “other commingled funds.” | | Notes (1) Due to the right of setoff and method of settlement, TVA elects to record commodity derivatives under the FTP based on its net commodity position with the counterparty or broker. (2) Commingled funds represent investment funds comprising multiple individual financial instruments and are classified in the table based on their existing investment portfolio as of the measurement date. Commingled funds exclusively composed of one class of security are classified in that category. Commingled funds comprising multiple classes of securities are classified as “other commingled funds.” |
|
| | | | | | | | | | | | | | | | | | | |
Fair Value Measurements At September 30, 2011 |
| Assets | Quoted Prices in Active Markets for Identical Assets (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Unobservable Inputs (Level 3) | | Netting(1) | | Total |
| | | | | | | | | | |
| Investments | | | | | | | | | |
| Equity securities | $ | 73 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 73 |
|
| Debt securities | |
| | |
| | |
| | |
| | |
|
U.S. government corporations and agencies | 117 |
| | 79 |
| | — |
| | — |
| | 196 |
|
| Corporate debt securities | — |
| | 164 |
| | — |
| | — |
| | 164 |
|
| Residential mortgage-backed securities | — |
| | 17 |
| | — |
| | — |
| | 17 |
|
| Commercial mortgage-backed securities | — |
| | 3 |
| | — |
| | — |
| | 3 |
|
| Collateralized debt obligations | — |
| | 3 |
| | — |
| | — |
| | 3 |
|
| Private partnerships | — |
| | — |
| | 22 |
| | — |
| | 22 |
|
Commingled funds(2) | |
| | |
| | |
| | |
| |
|
|
| Equity security commingled funds | — |
| | 467 |
| | — |
| | — |
| | 467 |
|
| Debt security commingled funds | — |
| | 221 |
| | — |
| | — |
| | 221 |
|
| Foreign currency commingled funds | — |
| | — |
| | — |
| | — |
| | — |
|
| Other commingled funds | — |
| | — |
| | — |
| | — |
| | — |
|
| Total investments | 190 |
| | 954 |
| | 22 |
| | — |
| | 1,166 |
|
| Commodity contract derivatives | — |
| | — |
| | 436 |
| | — |
| | 436 |
|
| Commodity derivatives under FTP | |
| | |
| | |
| | |
| | |
|
| Swap contracts | — |
| | 15 |
| | — |
| | (14 | ) | | 1 |
|
| Total commodity derivatives under FTP | — |
| | 15 |
| | — |
| | (14 | ) | | 1 |
|
| | | | | | | | | | |
| Total | $ | 190 |
| | $ | 969 |
| | $ | 458 |
| | $ | (14 | ) | | $ | 1,603 |
|
| | | | | | | | | | |
| Liabilities | Quoted Prices in Active Markets for Identical Liabilities (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Unobservable Inputs (Level 3) | | Netting(1) | | Total |
| | | | | | | | | | |
| Currency swaps | $ | — |
| | $ | 131 |
| | $ | — |
| | $ | — |
| | $ | 131 |
|
| Interest rate swaps | — |
| | 463 |
| | — |
| | — |
| | 463 |
|
| Swaption | — |
| | — |
| | 1,077 |
| | — |
| | 1,077 |
|
| Commodity contract derivatives | — |
| | — |
| | 197 |
| | — |
| | 197 |
|
| Commodity derivatives under FTP | |
| | |
| | |
| | |
| | |
|
| Futures contracts | 4 |
| | — |
| | — |
| | — |
| | 4 |
|
| Swap contracts | — |
| | 244 |
| | — |
| | (14 | ) | | 230 |
|
| Option contracts | 1 |
| | — |
| | — |
| | — |
| | 1 |
|
| Total commodity derivatives under FTP | 5 |
| | 244 |
| | — |
| | (14 | ) | | 235 |
|
| | | | | | | | | | |
| Total | $ | 5 |
| | $ | 838 |
| | $ | 1,274 |
| | $ | (14 | ) | | $ | 2,103 |
|
Notes (1) Due to the right of setoff and method of settlement, TVA elects to record commodity derivatives under the FTP based on its net commodity position with the counterparty or broker. (2) Commingled funds represent investment funds comprising multiple individual financial instruments and are classified in the table based on their existing investment portfolio as of the measurement date. Commingled funds exclusively composed of one class of security are classified in that category. Commingled funds comprising multiple classes of securities are classified as “other commingled funds.” |
The following table presents a reconciliation of all assets and liabilities measured at fair value on a recurring basis using significant unobservable inputs (Level 3):
Fair Value Measurements Using Significant Unobservable Inputs | |
| | | Three Months Ended June 30, 2011 | | | Nine Months Ended June 30, 2011 | |
| | | Private Partnerships | | | Commodity Contract Derivatives | | | Swaption | | | Private Partnerships | | | Commodity Contract Derivatives | | | Swaption | |
| | | | | | | | | | | | | | | | | | | |
| Balances at the beginning of the period | | $ | 14 | | | $ | 73 | | | $ | (554 | ) | | $ | 13 | | | $ | 103 | | | $ | (804 | ) |
| Purchases | | | 4 | | | | — | | | | — | | | | 13 | | | | — | | | | — | |
| Issuances | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | |
| Settlements | | | — | | | | — | | | | — | | | | (7 | ) | | | — | | | | — | |
| Total gains or losses (realized or unrealized): | | | | | | | | | | | | | | | | | | | | | | | | |
| Net unrealized gains (losses) deferred as regulatory assets and liabilities | | | — | | | | 51 | | | | (75 | ) | | | (1 | ) | | | 21 | | | | 175 | |
| Balances at June 30, 2011 | | $ | 18 | | | $ | 124 | | | $ | (629 | ) | | $ | 18 | | | $ | 124 | | | $ | (629 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Three Months Ended June 30, 2010 | | | Nine Months Ended June 30, 2010 | | |
| | | Private Partnerships | | | Commodity Contract Derivatives | | | Swaption | | | Private Partnerships | | | Commodity Contract Derivatives | | | Swaption | | | | | | | | | | |
Fair Value Measurements Using Significant Unobservable Inputs For the Three Months Ended December 31 | | Fair Value Measurements Using Significant Unobservable Inputs For the Three Months Ended December 31 |
| | | | | | | | | | | | | | | | | | | | Private Partnerships | | Commodity Contract Derivatives | | Swaption |
| Balances at the beginning of the period | | $ | — | | | $ | — | | | $ | (448 | ) | | $ | — | | | $ | 7 | | | $ | (592 | ) | |
| Balances at September 30, 2010 | | $ | 13 |
| | $ | 103 |
| | $ | (804 | ) |
| Purchases | | | 2 | | | | — | | | | — | | | | 2 | | | | — | | | | — | | 4 |
| | — |
| | — |
|
| Issuances | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | — |
| | — |
| | — |
|
| Sales | | — |
| | — |
| | — |
|
| Settlements | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | — |
| | — |
| | — |
|
| Total gains or losses (realized or unrealized): | | | | | | | | | | | | | | | | | | | | | | | | | |
| Total gains or losses (realized or unrealized) | | |
| | |
| | |
|
| Net unrealized gains (losses) deferred as regulatory assets and liabilities | | | — | | | | 13 | | | | (226 | ) | | | — | | | | 6 | | | | ( 82 | ) | 2 |
| | (109 | ) | | 221 |
|
| Balances at June 30, 2010 | | $ | 2 | | | $ | 13 | | | $ | (674 | ) | | $ | 2 | | | $ | 13 | | | $ | (674 | ) | |
| Balances at December 31, 2010 | | $ | 19 |
| | $ | (6 | ) | | $ | (583 | ) |
| | | | | | | |
| Balances at September 30, 2011 | | $ | 22 |
| | $ | 239 |
| | $ | (1,077 | ) |
| Purchases | | 6 |
| | — |
| | — |
|
| Issuances | | — |
| | — |
| | — |
|
| Sales | | (1 | ) | | — |
| | — |
|
| Settlements | | — |
| | — |
| | — |
|
| Total gains or losses (realized or unrealized) | | |
| | |
| | |
|
| Net unrealized gains (losses) deferred as regulatory assets and liabilities | | 1 |
| | (235 | ) | | (51 | ) |
| Balances at December 31, 2011 | | $ | 28 |
| | $ | 4 |
| | $ | (1,128 | ) |
There were no realized gains or losses related to the instruments measured at fair value using significant unobservable inputs that affected net income during the three and nine months ended June 30, 2011.December 31, 2011. All unrealized gains and losses related to these instruments have been reflected as increases or decreases in regulatory assets and liabilities. See Note 6.
Other Financial Instruments Not Recorded at Fair Value
TVA uses the methods and assumptions described below to estimate the fair value of each significant class of financial instrument. The fair market value of the financial instruments held at JuneDecember 31, 2011, and September 30, 2011 and September 30, 2010,, may not be representative of the actual gains or losses that will be recorded when these instruments mature or are called or presented for early redemption. The estimated values of TVA’sTVA's financial instruments not recorded at fair value at JuneDecember 31, 2011, and September 30, 2011 and September 30, 2010,, were as follows:
Estimated Values of Financial Instruments | |
| | | At June 30, 2011 | | | At September 30, 2010 | |
| | | Carrying Amount | | | Fair Value | | | Carrying Amount | | | Fair Value | |
| | | | | | | | | | | | | |
| Loans and other long-term receivables, net | | $ | 75 | | | $ | 69 | | | $ | 68 | | | $ | 60 | |
| | | | | | | | | | | | | | | | | |
| Long-term debt (including current portion), net | | | 23,961 | | | | 26,208 | | | | 23,397 | | | | 27,193 | |
|
| | | | | | | | | | | | | | | |
Estimated Values of Financial Instruments |
| | At December 31, 2011 | | At September 30, 2011 |
| | Carrying Amount | | Fair Value | | Carrying Amount | | Fair Value |
| Loans and other long-term receivables, net | $ | 76 |
| | $ | 70 |
| | $ | 74 |
| | $ | 68 |
|
| | | | | | | | |
| Long-term debt (including current portion), net | 23,927 |
| | 28,931 |
| | 23,949 |
| | 29,190 |
|
Because of the short-term maturity of cash and cash equivalents, restricted cash and investments, and short-term debt, net, the carrying amounts of these instruments approximate their fair values.
Fair value of long-term debt traded in the public market is determined by multiplying the par value of the debt by the indicative market price at the balance sheet date.
Fair values for loans and other long-term receivables are estimated by determining the present value of future cash flows using a discount rate equal to lending rates for similar loans made to borrowers with similar credit ratings and for similar remaining maturities, where applicable.
14. Other Income (Expense), Net
Income and expenses not related to TVA’s operating activities are summarized in the following table:
Other Income (Expense), Net | |
| | | For the three months ended June 30 | | | For the nine months ended June 30 | |
| | | 2011 | | | 2010 | | | 2011 | | | 2010 | |
| | | | | | | | | | | | | |
| External services | | $ | 2 | | | $ | 3 | | | $ | 13 | | | $ | 9 | |
| Interest income | | | 2 | | | | 1 | | | | 6 | | | | 4 | |
| Gains (losses) on investments | | | — | | | | (2 | ) | | | 4 | | | | 1 | |
| Miscellaneous | | | — | | | | 4 | | | | 2 | | | | 6 | |
| | | | | | | | | | | | | | | | | |
| Total other income (expense), net | | $ | 4 | | | $ | 6 | | | $ | 25 | | | $ | 20 | |
|
| | | | | | | |
Other Income (Expense), Net |
| | For the Three Months Ended December 31 |
| | 2011 | | 2010 |
| External services | $ | 4 |
| | $ | 5 |
|
| Interest income | 2 |
| | 2 |
|
| Gains (losses) on investments | 1 |
| | 2 |
|
| Miscellaneous | 2 |
| | 2 |
|
| Total other income (expense), net | $ | 9 |
| | $ | 11 |
|
15. Benefit Plans
TVA sponsors a qualified defined benefit pension plan andthat covers most of its full-time employees, a qualified defined contribution plan that cover eligiblecovers most of its full-time employees, two unfunded post-retirement health care plans that provide for non-vested contributions toward the cost of certain eligible retirees’retirees' medical coverage, other postemployment benefits such as workers’workers' compensation, and the SERP.
The components of net periodic benefit cost and other amounts recognized as changes in regulatory assets for the three and nine months ended June 30,December 31, 2011 and 2010 were as follows:
| | Components of TVA’s Benefit Plans | Components of TVA’s Benefit Plans | | Components of TVA’s Benefit Plans |
| | | For the Three Months Ended June 30 | | | For the Nine Months Ended June 30 | | |
| | | Pension Benefits | | | Other Post-retirement Benefits | | | Pension Benefits | | | Other Post-retirement Benefits | | For the Three Months Ended December 31 |
| | | 2011 | | | 2010 | | | 2011 | | | 2010 | | | 2011 | | | 2010 | | | 2011 | | | 2010 | | Pension Benefits | | Other Post-retirement Benefits |
| | | | | | | | | | | | | | | | | | | | | | | | | | 2011 | | 2010 | | 2011 | | 2010 |
| Service cost | | $ | 30 | | | $ | 24 | | | $ | 4 | | | $ | 3 | | | $ | 90 | | | $ | 74 | | | $ | 10 | | | $ | 9 | | $ | 35 |
| | $ | 30 |
| | $ | 5 |
| | $ | 3 |
|
| Interest cost | | | 126 | | | | 128 | | | | 8 | | | | 10 | | | | 377 | | | | 384 | | | | 24 | | | | 28 | | 122 |
| | 125 |
| | 9 |
| | 8 |
|
| Expected return on plan assets | | | (122 | ) | | | (140 | ) | | | — | | | | — | | | | (366 | ) | | | (404 | ) | | | — | | | | — | | (109 | ) | | (122 | ) | | — |
| | — |
|
| Amortization of prior service cost | | | (6 | ) | | | (6 | ) | | | (2 | ) | | | 1 | | | | (18 | ) | | | (18 | ) | | | (5 | ) | | | 4 | | (6 | ) | | (6 | ) | | (2 | ) | | (1 | ) |
| Recognized net actuarial loss | | | 71 | | | | 41 | | | | 5 | | | | 4 | | | | 212 | | | | 143 | | | | 16 | | | | 13 | | 90 |
| | 71 |
| | 7 |
| | 5 |
|
| Net periodic benefit cost as actuarially determined | | | 99 | | | | 47 | | | | 15 | | | | 18 | | | | 295 | | | | 179 | | | | 45 | | | | 54 | | 132 |
| | 98 |
| | 19 |
| | 15 |
|
| Amount charged (capitalized) due to actions of regulator | | | 3 | | | | 24 | | | | — | | | | — | | | | 9 | | | | 38 | | | | — | | | | — | | — |
| | 3 |
| | — |
| | — |
|
| Total net periodic benefit cost recognized | | $ | 102 | | | $ | 71 | | | $ | 15 | | | $ | 18 | | | $ | 304 | | | $ | 217 | | | $ | 45 | | | $ | 54 | | $ | 132 |
| | $ | 101 |
| | $ | 19 |
| | $ | 15 |
|
During the ninethree months ended June 30,December 31, 2011, TVA did not make contributions to its qualified defined benefit pension plan. TVA does not separately set aside assets to fund other benefit costs, but rather funds such costs on an as-paid basis. TVA provided approximately $30$13 million and $27$12 million for other benefit costs during the ninethree months ended June 30,December 31, 2011 and 2010, respectively. Net amounts capitalized due to regulatory actions of regulators include amounts that have been deemed probable of recovery in future rates.
General
From time to time, TVA is a party to or otherwise involved in lawsuits, claims, proceedings, investigations, and other legal matters (“("Legal Proceedings”Proceedings") that have arisen in the ordinary course of conducting TVA’sTVA's activities, as a result of a catastrophic event or otherwise.
General. TVA had accrued approximately $385$386 million of potential losses with respect to Legal Proceedings as of June 30, 2011.through December 31, 2011. Of this amount, $350$254 million is included in Other long-term liabilities, and $35$122 million is included in Accounts payable and accrued liabilities,. and $10 million is included in Regulatory assets. No assurance can be given that TVA will not be subject to significant additional claims and liabilities. If actual liabilities significantly exceed the estimates made, TVA’sTVA's results of operations, liquidity, and financial condition could be materially adversely affected.
EPA Settlement
On April 14,Environmental Agreements. In 2011, TVA entered into two substantively similar agreements that generally absolve TVA from any liability under the New Source Review (“NSR”) requirementswith EPA and with
Alabama, Kentucky, North Carolina, Tennessee, and three environmental advocacy groups: the Sierra Club, National Parks Conservation Association, and Our Children’s Earth Foundation (the “Consent Decree”(collectively, the "Environmental Agreements”). The two agreements (collectively, “the Environmental Agreements”) are substantially the same and are parts of a collective undertaking and are described below.
Under the agreements:
· | Most existing and possible claims against TVA based on alleged NSR and associated violations are waived and cannot be brought against TVA. Some possible claims for sulfuric acid mist and greenhouse gases (“GHG”) can still be brought against TVA. Additionally, the agreements do not address compliance with new laws and regulations or the cost associated with such compliance. |
· | EPA generally will not enforce NSR requirements for new plant maintenance, repair, and component replacement projects against TVA until 2019. Possible claims for NSR violations involving increases in GHG and sulfuric acid mist from projects can still be pursued in the future. Claims for increases in particulates also can be pursued except at TVA’s Allen Fossil Plant, Bull Run Fossil Plant (“Bull Run”), Kingston, and Gallatin Fossil Plant and Unit 5 at TVA’s Colbert Fossil Plant. |
They became effective on June 13, 2011.
· | TVA commits to retiring on a phased schedule two units at the John Sevier Fossil Plant (“John Sevier”), the six small units at the Widows Creek Fossil Plant (“Widows Creek”), and 10 units at the Johnsonville Fossil Plant (“Johnsonville”). This is a total of approximately 2,700 MW (nameplate capacity) or 2,200 MW (summer net dependable capability). The majority of these retirement costs have been previously included in the ARO liability. Further, the depreciation expense related to these facilities was changed beginning in April 2011 in order to depreciate the assets over their remaining useful lives. |
· | Of the remaining 5,600 MW (nameplate capacity) or 4,500 MW (summer net dependable capability) coal-fired fleet capacity that is not already fully equipped with advanced sulfur dioxide (“SO2”) or nitrogen oxides (“NOx”) controls, TVA must decide whether to control, convert, or retire 4,300 MW (nameplate capacity) or 3,500 MW (summer net dependable capability) on a unit by unit schedule which can extend until 2019.
|
· | Annual, declining emission caps are set for SO2 and NOx.
|
· | TVA, with EPA approval, will invest $290 million in energy efficiency projects, demand response projects, renewable energy projects, and other TVA projects by June 2016. This amount is included on the June 30, 2011 Balance Sheet as a regulatory asset. |
· | TVA will provide Alabama, Kentucky, North Carolina, and Tennessee a total of $60 million in annual installments beginning in 2011 through 2016 to fund environmental projects, giving a preference for projects in the TVA watershed or service area. This amount is included on the June 30, 2011 Balance Sheet as a regulatory asset. |
· | The civil penalties of $10 million were expensed during the period ended June 30, 2011, and subsequently paid in July 2011. The civil penalty was divided among EPA, Alabama, Kentucky, and Tennessee. |
The $290 million andliabilities related to the $60 million detailed aboveEnvironmental Agreements are included in Other long-term liabilities on the June 30,December 31, 2011 Balance Sheet. In conjunction with the approval of the agreements,Environmental Agreements, the TVA Board determined that it was appropriate to record the amounts detailed above as regulatory assets. Therefore,assets, and they are included as such on the amountsDecember 31, 2011 Balance Sheet and will be recovered in rates in future periods.
The agreement with EPA was noticed in the Federal Register, and the public comment period expired with no changes made to the agreement. That agreement became effective on June 13, 2011. The United States District Court for the Eastern District of Tennessee (“Eastern District of Tennessee”) entered the Consent Decree on June 30, 2011. In connection with the agreement and the entry of the Consent Decree, the following legal and administrative clean air proceedings discussed below are expected to be terminated or narrowed in scope:
· | The Proceeding Involving the John Sevier CAA Permit, and |
· | The Proceeding Involving the Shawnee Fossil Plant (“Shawnee”) CAA Permit. |
Additionally, the following Several legal and administrative clean air proceedings have already been terminated in connection with the agreement Environmental Agreements. Additionally, the proceedings discussed below involving the John Sevier Fossil Plant ("John Sevier")and the Consent Decree:
· | The Case Involving Alleged Violations of New Source Review Regulations at Bull Run, |
· | The Case Brought by North Carolina Alleging Public Nuisance, and |
· | The Proceeding Involving the Paradise Fossil Plant (“Paradise”) CAA Permit. |
Demand and sales projections for the TVA systemShawnee Fossil Plant (“Shawnee”) Clean Air Act ("CAA") permits are expected to require that TVA replace the retired capacity over time. The cost of this is uncertain and depends on demand and the energy resources chosen for this replacement capacity. TVA anticipates meeting this need with a mix of generating assets and investmentsbe narrowed in energy efficiency and demand reduction programs so as to minimize the total costs of replacing the generation lost as a result of retiring these units.scope.
Litigation
Legal Proceedings Related to the Kingston Ash Spill. Sixty-oneSeventy-eight lawsuits based on the Kingston ash spill have been filed in the United States District Court for the Eastern District of Tennessee. EightFifteen of those actionsthese lawsuits have been voluntarily dismissed. Thedismissed, and 63 lawsuits filed byare active and in various stages of litigation. Plaintiffs are residents, businesses, and property owners in the Kingston area and allege various causes of action in tort – includingclaims for damage to property, e.g. nuisance, strict liability, trespass, and negligence, with some plaintiffs also alleging claims for personal injury, business loss, and property damage – as well as inverse condemnation, and generallycondemnation. Plaintiffs seek unspecified compensatory and punitive damages, court orders to clean up the plaintiffs’ properties and surrounding properties and other relief. The lawsuits seeking class certification have been voluntarily consolidated so there is now only one
complaint, Chesney, seeking class certification. The court has denied the request for class certification. TVA is the soleonly active defendant in all actions, since the two non-TVA defendants in Chesney have been dismissed from the lawsuit. On March 26, 2010, the court issued a decision finding (1) the discretionary function doctrine is applicable to TVA’s ash pond design decisions and its spill response activities, (2) plaintiffs cannot recover punitive damages against TVA, and (3) plaintiffs have no right to a jury trial against TVA. The court denied TVA’s motions with regard to plaintiffs’ tort claims concerning TVA's maintenance and upkeep of the ash pond, along with the inverse condemnation claims raised by certain plaintiffs. The court has scheduled the seven earliest-filed cases for trial beginning on September 13, 2011, and the remaining cases for trial beginning November 1, 2011.
On March 22, 2011, the court issued decisions on two motions filed by TVA. With respect to the TVA motions, the court held that (1) a plaintiff could not bring a claim for TVA’s allegedly having caused a nuisance with regard to property if the plaintiff did not have a valid property interest in that property and (2) a plaintiff who filed for bankruptcy after bringing suit against TVA but did not include the suit in the bankruptcy proceeding was barred from pursuing the suit against TVA.
On March 24, 2011, the court issued a decision which granted TVA’s motion for summary judgment on any claim related to activities the court had previously ruled as being protected by the discretionary function doctrine (ash pond design and spill response activities). The court denied TVA’s motion with regard to any alleged failures to adequately inform or train personnel in applicable policies or procedures or negligent maintenance. The court also held that while TVA’s design and construction decisions concerning the ash pond were protected by the discretionary function doctrine, the court would not grant summary judgment on claims related to alleged negligence in carrying out such design and construction decisions. these actions.
On April 19, 2011, plaintiffs in one of the lawsuits requested permission from the court to file an amended complaint which asserts only claims based on alleged property damage, including nuisance and trespass. The court allowed the amended complaint and the case with regard to these plaintiffs will proceed on the property damage claims and not on any personal injury or related claims, including requests for medical monitoring.
On August 2, 2011, the court granted summary judgment in favor of TVA on plaintiffs’ personal injury, emotional distress, and inverse condemnation claims. The court denied summary judgment on the trespass, nuisance, and property injury claims, and the litigation now will proceed to the scheduledA bench trial on those claims.the issue of dike failure causation in the seven earliest cases was held in September and October, 2011 (“Phase I trial”), and a decision on the dike failure causation issues is expected in the spring or summer of 2012. The district court also approved stipulations in 53 of the remaining 56 cases in which plaintiffs and TVA agreed to adopt the Phase I trial record and be bound by the Court’s Phase I trial decision and a temporary stay of proceedings pending the court’s trial decision.
TVA has received several notices of intent to sue under various environmental statutes from both individuals and environmental groups. In addition, TVA has received substantial other claims from individuals and companies allegedly affected by the ash spill and may receive additional claims.groups, but no such suits have been filed.
Civil Penalty and Natural Resource Damages for the Kingston Ash Spill. On June 14, 2010, the TDEC issued a civil penalty order of approximately $12 million to TVA for the Kingston ash spill, citing violations of the Tennessee Solid Waste Disposal Act and the Tennessee Water Quality Control Act. Of the $12 million, TVA has already satisfied $6$8 million, of the obligation and may also be credited up toTDEC has approved environmental projects valued at $2 million for performing environmental projects approved by TDEC.as a credit against the penalty amount. The remaining $2 million obligation will be paid in installments througha final installment due on or before July 15, 2012. On January 24, 2011, TVA entered into a memorandum of agreement with the TDEC and the U.S. Fish and Wildlife Service establishing a process and a method for resolving the natural resource damage claim associated with the Kingston ash spill. As part of this memorandum of agreement, TVA agreed to pay $250 thousand each year for three years as a down payment on the amount of natural resource damages ultimately established. TVA is also required to reimburse TDEC and the U.S. Fish and Wildlife Service for their costs.
Case Brought by North Carolina Alleging Public Nuisance. On January 30, 2006, North Carolina filed suit against TVA in the United States District Court for the Western District of North Carolina, alleging that TVA’s operation of its coal-fired power plants in Tennessee, Alabama, and Kentucky constitutes a public nuisance. On January 13, 2009, the court held that emissions from Bull Run, Kingston, and John Sevier, located in Tennessee, and Widows Creek, located in Alabama, constitute a public nuisance.
The court issued an order that required TVA to operate existing flue gas scrubbers and selective catalytic reduction systems (“SCRs”) at the units that have them, add scrubbers and SCRs by certain dates at the units that do not have them, and meet specified emission rates and annual tonnage caps for NOx and SO2 after the applicable operation dates for the scrubbers.
TVA appealed the decision to the United States Court of Appeals for the Fourth Circuit (“Fourth Circuit”), which on July 26, 2010, reversed the holding of the district court and directed the district court to dismiss the action against TVA. In its decision, the Fourth Circuit held that (1) state laws, including nuisance laws, could not be used to bypass the regulatory structure established by Congress and EPA for controlling emissions; (2) the district court improperly applied North Carolina law to power plants located in Alabama and Tennessee; and (3) the plant operations in Alabama and Tennessee could not be considered nuisances because both states had specifically approved these operations. North Carolina requested an en banc rehearing, but the Fourth Circuit denied this request on September 21, 2010. The district court dismissed the case with prejudice on October 1, 2010. North Carolina filed a petition for review of the Fourth Circuit’s decision with the U.S. Supreme Court on February 2, 2011. On July 22, 2011, the U.S. Supreme Court granted the parties joint motion to withdraw the petition for review, ending this case. See EPA Settlement.
Case Involving Alleged Violations of the New Source Review Regulations at Bull Run. The National Parks Conservation Association and the Sierra Club filed suit against TVA on February 13, 2001, in the Eastern District of Tennessee, alleging that TVA did not comply with the NSR requirements of the Clean Air Act when TVA repaired Bull Run. On March 31, 2010, the court ruled in TVA’s favor, holding that two maintenance projects at Bull Run fell under the exception for “routine maintenance repair and replacement” and therefore did not require NSR permits. The plaintiffs appealed this decision to the United States Court of Appeals for the Sixth Circuit (“Sixth Circuit”). On July 6, 2011, the Sixth Circuit granted the parties’ joint motion to dismiss this case. See EPA Settlement.
Case Involving Tennessee Valley Authority Retirement System. On March 5, 2010, eight current and former participants in and beneficiaries of the Tennessee Valley Authority Retirement System (“TVARS”("TVARS") filed suit in the United States District Court for the Middle District of Tennessee against the six then-current members of the TVARS Board.Board of Directors ("TVARS Board"). The lawsuit challenged the TVARS Board’sBoard's decision to suspend the TVA contribution requirements for 2010 through 2013, and to amend the TVARS Rules and Regulations to (1) reduce the calculation for cost of living adjustment (“COLA”("COLA") benefits for CY 2010 through CY 2013, (2) reduce the interest crediting rate for the fixed fund accounts, and (3) increase the eligibility age to receive COLAs from age 55 to 60. The plaintiffs allege that these actions violated the TVARS Board members’members' fiduciary duties to the plaintiffs (and the purported class) and the plaintiffs’plaintiffs' contractual rights, among other claims. The plaintiffs sought, among other things, unspecified damages, an order directing the TVARS Board to rescind the amendments, and the appointment of a seventh TVARS Board member. member. Five of the six individual defendants filed motions to dismiss the lawsuit, while the remaining defendant filed an answer to the complaint. On July 28, 2010, TVA moved to intervene in the suit in the event it was not dismissed. On September 7, 2010, the district court dismissed the breach of fiduciary duty claim against the directors without prejudice, allowing the plaintiffs to file an amended complaint within 14 days against TVARS and TVA but not the individual directors. The plaintiffs previously had voluntarily withdrawn their constitutional claims, so the court also dismissed those claims without prejudice. The court dismissed with prejudice the plaintiffs’plaintiffs' claims for breach of contract, violation of the Internal Revenue Code, and appointment of a seventh TVARS Board member.
On September 21, 2010, the plaintiffs filed an amended complaint against TVARS and TVA. The plaintiffs allege, among other things, violations of their constitutional rights (due process, equal protection,, and property rights), violations of the Administrative Procedure Act, and breach of statutory duties owed to the plaintiffs. They seek a declaratory judgment and appropriate relief for the alleged statutory and constitutional violations and breaches of duty. TVA filed its answer to the amended complaint on December 27, 2010. A briefing schedule has been issued and final dispositive motions are due inon October 12, 2012.
Case Arising out of Hurricane Katrina. In April 2006, TVA was added as a defendant to a class action lawsuit brought in
the United States District Court for the Southern District of Mississippi by 14 Mississippi residents allegedly injured by Hurricane Katrina. The plaintiffs sued seven large oil companies and an oil company trade association, three large chemical companies and a chemical trade association, and 31 large companies involved in the mining and/or burning of coal, alleging that the defendants’defendants' greenhouse gas ("GHG") emissions contributed to global warming and were a proximate and direct cause of Hurricane Katrina’sKatrina's increased destructive force. Action by the United States Supreme Court on January 10, 2011, ended this case in a manner favorable to TVA.
On May 27, 2011, under a Mississippi state statute that permits the re-filing of lawsuits that were dismissed on procedural grounds, the plaintiffs filed another lawsuit against the same and additional defendants, again alleging that the defendants’ greenhouse gasdefendants' GHG emissions contributed to global warming and were a proximate and direct cause of Hurricane Katrina' s increased destructive force. A number of defendants, including TVA, have filed motions to dismiss the complaint.
Global Warming Cases, Southern District of New York. On July 21, 2004, two lawsuits were filed in the United States District Court for the Southern District of New York against TVA and other companies that generate power from fossil-fuel electric generating facilities alleging that global warming is a public nuisance andfacilities. The plaintiffs alleged that carbon dioxide (“("CO2”") emissions from fossil-fuel electric generatingsuch facilities should be ordered abated because they contributecontributed to causing the nuisance. The first case was filed by various states (California, Connecticut, Iowa, New Jersey, New York, Rhode Island, Vermont, and Wisconsin) and the City of New York against TVA and other power suppliers. The second case, which also alleges private nuisance, was filed against the same defendants by Open Space Institute, Inc., Open Space Conservancy, Inc., and the Audubon Society of New Hampshire. The plaintiffs seek a court order requiring each defendant to cap its CO2 emissions and then reduce these emissions by an unspecified percentage each year for at least a decade.global warming. In September 2005, the district court dismissed both lawsuits because they raised political questions that should not be decided by the courts. The plaintiffs appealed toFollowing appellate proceedings, the United States Court of Appeals for the Second Circuit (“Second Circuit”). On September 21, 2009, the Second Circuit reversed the district court’s decision and remanded the cases to the district court for further proceedings. On November 5, 2009, TVA and the other defendants filed a petition seeking a rehearing by the entire Second Circuit, which petition was denied on March 5, 2010. On December 6, 2010, the U.S. Supreme Court granted a petition requesting that the Supreme Court review the Second Circuit’s decision. The U.S. Solicitor General filed a brief on behalf of TVA on January 31, 2011. Oral arguments were held on April 19, 2011. On June 16, 2011, the Supreme Court issued a decision reversing the Second Circuit’s ruling, and
holdingon June 16, 2011, that any federal common law cause of action was displaced by the CAA and its implementing regulations. The Supreme Court did not address the plaintiffs’plaintiffs' state law claims, but instead remanded the casecase. The district court entered orders on December 5, 2011, dismissing the federal common law claims in both lawsuits. On December 6, 2011, the plaintiffs voluntarily dismissed the state law claims, ending the lawsuits in a manner favorable to the Second Circuit for consideration of these claims.
TVA.
Case Regarding Bellefonte Nuclear Plant Units 1 and 2. On March 9, 2009, in response to a request by TVA, the Nuclear Regulatory Commission (“NRC”("NRC") issued an order reinstating the construction permits for Bellefonte Units 1 and 2 and returning the Bellefonte construction permits to a terminated status. (They are currently in deferred status.Nuclear Plant ("Bellefonte"). On March 30, 2009, Blue Ridge Environmental Defense League (“BREDL”) filed a petition in the United States Court of Appeals for the District of Columbia Circuit (“D.C. Circuit”) challenging NRC’sthe NRC's authority to reinstate the construction permits and alleging that the NRC failed to follow the requirements of the National Environmental Policy Act (“NEPA”). TVA was permitted to intervene in this proceeding. On June 11, 2009, the D.C. Circuit issued an order holding the case in abeyance pending further order of the court. On March 8, 2010, BREDL filed a second petition in the D.C. Circuit, again challenging NRC’sthe NRC's compliance with NEPA and NRC’sthe NRC's authority to reinstate the construction permits. TVA was granted intervenor status in this case as well, and requested that the court dismiss this second petition. On July 26, 2010, the D.C. Circuit consolidated the two BREDL petitions and continued the stay of the case pending the conclusion of an administrative proceeding concerning the same issues. The administrative proceeding, in which BREDL challenged the reinstatement of the construction permits before an NRC Atomic Safety and Licensing Board (“ASLB”), was completed on September 29, 2010, with the dismissal of all contentions. Upon completion of the administrative proceeding, the D.C. Circuit on November 5, 2010, issued an order returning the two cases to the court’scourt's active docket. Final briefs have been submitted, and oral arguments have been scheduled to taketook place on October 20, 2011.
Administrative Proceedings Regarding Bellefonte Units 3 and 4. TVA submitted its Combined Constructioncombined construction and Operating License Applicationoperating license application ("CCOLA") for two Advanced Passive 1000 reactors at Bellefonte Units 3 and 4 to the NRC in October 2007. On June 6, 2008, Bellefonte Efficiency and Sustainability Team (“BEST”), BREDL, and Southern Alliance for Clean Energy (“SACE”) submitted to the NRC a joint petition for intervention and a request for a hearing. The petition raised 20 potential contentions with respect to TVA’s Combined Construction and Operating License Application.TVA's CCOLA. The ASLB denied standing to BEST and admitted four of the 20 contentions submitted by BREDL and SACE. The NRC later reversed the ASLB’sASLB's decision to admit two of the four contentions, leaving only two contentions (which involve questions about the estimated costs of the new nuclear plant and the impact of the facility’sfacility's operations, in particular the plant intake, on aquatic ecology) to be litigated in a future hearing. No hearing will take place until NRC issues a final Environmental Impact Statement and final Safety Evaluation Report for the units. On September 29, 2010, TVA notified the NRC that the recently completed Finalfinal Supplemental Environmental Impact Statement had determined that completion of the partially constructed Bellefonte Unit 1 is the preferred alternative for near-term additional generating capacity at the Bellefonte site. Consequently, withTVA has requested, and the exceptionNRC has agreed, to place the CCOLA in “suspended” status indefinitely. On January 6, 2012, TVA also notified the ASLB of the ongoing review of hydrology-related portionssuspended status of the application, TVACCOLA, and requested that NRC defer review of the Bellefonte Units 3 and 4 Combined Construction and Operating License ApplicationASLB hold the proceeding in abeyance pending a final decision ofby TVA regarding the TVA Board regarding new generation capacity atbest path forward with regards to the Bellefonte site. On April 21, 2011, the ASLB requested that TVA provide the ASLB with a status report that describes in as much detail as practicable TVA’s plans for reaching a decision regarding howCCOLA. TVA expects to proceed withcontinue to request that the licensingproceeding be held in abeyance until the risks of Bellefonte. TVA providedcompleting Bellefonte Unit 1 are substantially understood and construction is resumed.
On August 11, 2011, BREDL and SACE petitioned for the admission of a status reportnew, late-filed contention to require the ASLB on May 6, 2011, indicating that while TVA intendsenvironmental analysis completed for the CCOLA to continueconsider the ongoing licensing efforts for Bellefonte, a decision by the TVA Board had been delayed pending considerationfindings of the impacts ofNRC's Near-Term Task Force on the Fukushima Event regarding the events at the Fukushima Daiichi facility in Japan. TVA committed to informNuclear Power Plant ("Fukushima Daiichi"). On November 30, 2011, the ASLB, after considering the submissions of any subsequent decisionthe parties, determined that the proposed contention failed to meet the standards for admission of a new contention in this regard as soon as practicable.the proceeding.
Administrative Proceedings Regarding Watts Bar Nuclear Plant Unit 2. On July 13, 2009, SACE, the Tennessee Environmental Council, the Sierra Club, We the People, and BREDL filed a request for a hearing and petition to intervene in the NRC administrative process reviewing TVA’sTVA's application for an operating license for Watts Bar Nuclear Plant (“("Watts Bar”Bar") Unit 2. The petitioners raised seven contentions related to TVA’sTVA's environmental review of the project and NRC’sthe NRC's basis for confidence in the availability of safe storage options for spent nuclear fuel. On November 19, 2009, the ASLB granted SACE’s SACE's
request for hearing, admitted two of SACE’sSACE's seven contentions for hearing, and denied the request for hearing submitted on behalf of the other four petitioners. On March 26, 2010, the NRC affirmed the ASLB’sASLB's decision denying the other petitioners the opportunity to participate. After providing additional information to the NRC on April 9, 2010, which addressed one of the two admitted contentions, TVA submitted a motion asking the ASLB to dismiss the contention as moot. The motion was unopposed by SACE and on June 2, 2010, the ASLB granted TVA’sTVA's motion to dismiss the contention. SACE also asked the ASLB to waive NRC’sthe NRC's longstanding regulations establishing that, for the purposes of the NEPA, the need for power and alternative energy source issues will not be considered in operating license proceedings. On June 29, 2010, the ASLB denied this request and declined to refer the waiver petition to the NRC for consideration. SACE subsequently filed a petition for interlocutory review of this decision with the NRC, which the NRC denied on November 30, 2010.2010. Regarding the sole remaining contention which raises concerns about the aquatic impacts of two-unit operation, several additional reports have been provided to the NRC providing up to dateup-to-date information to address this contention. These reports include a mussel survey report and an entrainment report, both issued on March 24, 2011, and an impingement report issued on March 29, 2011. A supplement to the impingement report was submitted on April 28, 2011. A hearing on the remaining contention is expected to take place in the latter part of 2012. On August 11, 2011, SACE petitioned for the admission of a new, late-filed contention to require the environmental analysis completed for TVA's operating license application to consider the findings of the NRC's Near-Term Task Force on the Fukushima Event regarding the events at the Fukushima Daiichi reactors. TVA submitted a reply brief on September 6, 2011, opposing admission of such a contention on the grounds it does not satisfy the standards for non-timely contentions or the standards for admitting a new contention. On November 21, 2011, TVA filed a motion for summary disposition, arguing that additional aquatic studies conducted by TVA meant there is no longer a genuine issue of material fact. SACE and the NRC staff filed their answers to the motion on December 20, 2011; SACE opposed TVA's motion while the NRC staff supported it.
John Sevier Fossil Plant Clean Air ActCAA Permit. On September 20, 2010, the Environmental Integrity Project, the Southern Environmental Law Center, and the Tennessee Environmental Council filed a petition with the EPA, requesting that the EPA Administrator object to the CAA permit issued to TVA for operation of John Sevier. Among other things, the petitioners allege that repair, maintenance, or replacement activities undertaken at John Sevier Unit 3 in 1986 triggered the Prevention of Significant Deterioration (“PSD”) requirements for sulfer dioxide ("SO2") and nitrogen oxides ("NOx"). The CAA permit, issued by the TDEC, remains in effect pending the disposition of EPA’sthe EPA's petition. The Environmental Agreements should narrow the scope of this proceeding. See EPA SettlementEnvironmental Agreements.
Paradise Fossil Plant Clean Air ActShawnee CAA Permit. On December 21, 2007, the Sierra Club, the Center for Biological Diversity, Kentucky Heartwood, Preston Forsythe, and Hilary Lambert filed a petition with EPA raising objections to the conditions of TVA’s current CAA permit at Paradise. Among other things, the petitioners allege that activities at Paradise triggered the NSR requirements for NOx and that the monitoring of opacity at Units 1 and 2 of the plant is deficient. In an order issued in July 2009, EPA agreed that the permit failed to include a proper PSD analysis for NOx emission increases as a result of physical changes made to the plant’s three main boilers in the 1984-1986 period, that the permit failed to require adequate monitoring systems for opacity and NOx, and that the monitoring of soot emissions from the coal washing and handling plant was inadequate. TVA’s permit at Paradise is issued by the Kentucky Division for Air Quality (“KDAQ”). In November 2009, KDAQ determined that the actions at Paradise had not triggered NSR requirements and reissued the operating permit without including NSR compliance milestones. On January 9, 2010, the Sierra Club petitioned EPA to object to the operating permit, alleging that KDAQ had failed to properly take into account the PSD requirements for the physical changes made in 1986. On May 21, 2010, the Sierra Club filed a lawsuit seeking to compel EPA to act on the petition. To resolve this lawsuit, EPA entered into a consent decree with the Sierra Club under which EPA agreed to respond to the petition. On May 2, 2011, EPA denied the petition, citing the Environmental Agreements. SeeEPA Settlement.
Shawnee Fossil Plant Clean Air Act Permit. On December 16, 2010, the Environmental Integrity Project and the Southern Alliance for Clean EnergySACE filed a petition with the EPA requesting that the EPA Administrator object to the proposed CAA renewal permit issued to TVA for operations at Shawnee. Among other things, the petitioners allege that repair, maintenance, or replacement undertaken at Shawnee Units 1 and 4 in the 1989-90 period triggered the PSD requirements for SO2and NOx. The current permit remains in effect pending KDAQ’sKentucky Division for Air Quality finalization of the renewal permit. The Environmental Agreements should narrow the scope of this proceeding. See EPA SettlementEnvironmental Agreements.
Notice of Violation at Widows Creek Unit 7. On July 16, 2007, TVA received a Notice of Violation (“NOV”) from EPA alleging, among other violations, that TVA failed to properly maintain ductwork at Widows Creek Unit 7. TVA repaired the ductwork in 2005. On March 5, 2008, TVA and Alabama entered into an agreed order in which TVA agreed to pay the state $100 thousand. On March 15, 2011, TVA and EPA entered into an agreed order which resolves this matter, and under which TVA paid $450 thousand and retired 1,000 SO2 and NOx allowances.
Kingston NPDES Permit Appeal. The Sierra Club filed a challenge to the National Pollutant Discharge Elimination System (“NPDES”) permit issued by Tennessee for the scrubber-gypsum pond discharge at Kingston in November 2009 before the Tennessee Water Quality Control Board (“TWQCB”). This is the second such challenge nationally. In addition to its allegation that Tennessee violated the Clean Water Act by failing to set specific limits on certain toxic discharges, the Sierra Club alleges that no discharges from the pond infrastructure should be allowed because zero-discharge scrubbers exist. TDEC is the defendant in the challenge, and TVA has intervened in support of TDEC’sTDEC's decision to issue the permit. The matter was set for a hearing before the TWQCB in February 2011 but has since been stayed by agreement of the parties. parties. The other similar challenge involves an Allegheny Power NPDES permit for its scrubber discharge at a Pennsylvania plant.
Bull Run NDPES Permit Appeal. The SACE and the Tennessee Clean Water Network (“TCWN”) filed a challenge to the NPDES permit for Bull Run on November 1, 2010. TDEC is the defendant in the challenge and TVA’sTVA's petition to intervene to support TDEC’sTDEC's decision to issue the permit was granted on January 12, 2011. The matter is expected to go to a hearing before the TWQCB in the spring of 2012.
Johnsonville Fossil Plant NDPES Permit Appeal. SACE and TCWN filed a challenge to the NPDES permit for Johnsonville Fossil Plant ("Johnsonville") on or about March 10, 2011. TDEC is the defendant in the challenge. TVA has filed aTVA's motion to intervene in this administrative challenge.was granted on August 3, 2011. The matter has not yet been given a hearing date before the TWQCB.
John Sevier Fossil Plant NDPES Permit Appeal. SACE and TCWN filed a challenge to the NPDES permit for John Sevier on or about May 31, 2011. TDEC is the defendant in the challenge. TVA has filed aTVA's motion to intervene in this administrative challenge.was granted on August 3, 2011. The matter has not yet been given a hearing date before the TWQCB.
Information Request from the EPA. On April 25, 2008, TVA received a request from the EPA under Section 114 of the CAA requesting extensive information about maintenance, repair, and replacement projects at and the operations of 14 of TVA’s coal-fired units. These 14 units are located in Alabama, Kentucky, and Tennessee. The Environmental Agreements have resolved most issues related to this information request, excluding claims related to sulfuric acid mist. See EPA SettlementEnvironmental Agreements.
Petitions Resulting from Japanese Nuclear Events
Events.As a result of the March 11, 2011 Japanese nuclear events, precipitated by the March 11, 2011 earthquake and tsunami at the Japanese nuclear power stations, petitions have been filed with NRC which could impact TVA’s nuclear program. These petitions include: |
· | Petition Seeking Enforcement Action Against Licensees of NRC |
Saprodani Associates filed a petition on March 12, 2011, under the 10 CFR 2.206 process requesting that NRC take enforcement action, issue a Notice of Violation, and immediately shutdown all U.S. reactors known to be near an earthquake fault line. On June 29, 2011, NRC rejected the petition but committed to continue analyzing the events at Fukushima Daiichi and to take any actions deemed appropriate following its analysis.
· | Emergency Petition to Suspend All Pending Reactor Licensing Decisions and Related Rulemaking Decisions Pending Investigation of Lessons Learned From Fukushima Daiichi Nuclear Power Station Accident |
Separate but essentially identical petitions have been filed by almost 50 petitioners in 24 ongoingwith the NRC licensing proceedings, including Watts Bar Unit 2 (filed April 14, 2011 by SACE)which could impact TVA's nuclear program. While some petitions have been dismissed
after review, petitions that remain open include the following:
Petition to Immediately Suspend the Operating Licenses of GE BWR Mark I Units Pending the Full NRC Review With Independent Expert and Bellefonte Units 3 and 4 (filed April 18, 2011 by BREDL). Filed under NRC’s general authority to regulate the U.S. nuclear industry, the petitions seek to suspend all licensing decisions and other major licensing activities pending completion of NRC’s Fukushima Task Force investigation and subsequent issuance of any proposed regulatory decisions and/or environmental analyses.Public Participation From Affected Emergency Planning Zone Communities
· | Petition to Suspend AP1000 Design Certification Rulemaking Pending Evaluation of Fukushima Accident Implications on Design and Operational Procedures and Request for Expedited Consideration |
A petition was filed by 13 petitioners on April 6, 2011, requesting that NRC suspend the AP1000® design certification rulemaking while NRC investigates the Fukushima accident and determines appropriate lessons learned to be incorporated into the design and operational procedures. The AP1000® is a pressurized water nuclear reactor designed by the Westinghouse Electric Company, LLC, and is the nuclear reactor technology TVA has referenced in its Bellefonte Units 3 and 4 combined license application. Granting of this petition could potentially impact the licensing proceeding for these units.
· | Petition to Immediately Suspend the Operating Licenses of GE BWR Mark I Units Pending Full NRC Review With Independent Expert and Public Participation From Affected Emergency Planning Zone Communities |
Beyond Nuclear filed a petition on April 13, 2011, requesting that the NRC take emergency enforcement action against all nuclear reactor licensees that operate units that use the General Electric Mark I BWR design. TVA uses this design at Browns Ferry Nuclear Plant ("Browns Ferry") Units 1, 2, and 3. The petition requests NRC to take an enforcement action and requeststhe NRC to take several actions, including the suspension of the operating licenses at the affected nuclear units, including Browns Ferry, Units 1, 2, and 3, until several milestones have been met.
Issuance On December 13, 2011, the NRC provided its initial response to the petition. The NRC accepted five specific requests that would apply directly or indirectly to TVA's Browns Ferry, including issues relating to spent fuel pool use and location, Mark I containment hardened vent systems and design, and backup electrical power. Each of Debt
In July 2011, TVA issued $17.4 million of electronotes® with an interest rate of 4.3 percent which mature in 2041 and are callable beginning in 2016.these items was accepted for further investigation, but the requests for immediate action were rejected.
Credit Rating
On July 13, 2011, a national rating agency placed the sovereign ratings of the United StatesTwelve separate petitions on review for possible downgrade due to increasing possibility that the government’s statutory debt limit would not be raised on a timely basis, potentially leading to a default on U.S. Treasury debt obligations. On July 14, 2011, the agency placed TVA’s senior secured and unsecured credit ratings on review for possible downgrade. On July 14, 2011, another rating agency placed the sovereign ratings of the United States on review for possible downgrade, and on July 15, 2011, placed TVA’s ratings on review for downgrade. The agencies informed TVA that the actions on TVA were based on the actions on the United States and do not reflect a change in TVA’s financial condition or any TVA-specific event. various issues
On August 2, 2011, one of the rating agencies confirmed the Aaa rating of the United States and assigned a Negative rating outlook following the government’s action to raise the debt limit and avoid default on the government’s obligations. On August 3, 2011, this same agency confirmed the Aaa senior secured and unsecured ratings of TVA and assigned a Stable rating outlook.
On August 5, 2011, one of the rating agencies lowered its long-term rating on the United States to AA+ from AAA and affirmed the A-1+ short-term rating. This action was based on concerns regarding the fiscal and economic position ofoperating nuclear facilities in the United States. The outlookNRC is treating these as a single 2.206 Petition, and the issues are currently under review.
Petition Pursuant to 10 CFR 2.206 - Demand For Information Regarding Compliance with 10 CFR 50, Appendix A, General Design Criterion 44, Cooling Water, and 10 CFR 50.49, Environmental Qualification
A petition was filed by the Union of Concerned Scientists on July 29, 2011, requesting that a demand for information be issued for affected licensees, including TVA with regards to Browns Ferry, to describe how the long-term ratingfacility complies with General Design Criterion 44, Cooling Water, within Appendix A to 10 CFR Part 50, and with 10 CFR 50.49, Environmental Qualification of Electric Equipment Important to Safety for Nuclear Power Plants, for all applicable design and licensing bases events. This petition is Negative.under review.
17. Subsequent Events
Bond Redemption
On January 15, 2012, TVA redeemed all of its 2008 4.75 percent electronotes ® due January 15, 2028, CUSIP number 88059TEE7. The rating agency removed the short-notes were redeemed at 100 percent of par value for a total of $39 million.
John Sevier Combined Cycle Transaction
On January 17, 2012, TVA entered into a $1.0 billion leasing transaction with John Sevier Combined Cycle Generation LLC (“JSCCG”), a newly formed entity. In connection with this transaction, TVA and long-term ratings of the United States from reviewof America agreed to lease the John Sevier Combined Cycle Facility (“John Sevier CCF”) located in Hawkins County, Tennessee, to JSCCG for possible downgrade.a term of fifty years (the “Head Lease”). TVA also entered into a construction management agreement (“CMA”) with JSCCG under which TVA is obligated to use commercially reasonable efforts to cause the John Sevier CCF to achieve substantial completion by January 14, 2013, or as soon thereafter as commercially practicable. On August 8, 2011, this same rating agency loweredJanuary 17, 2012, JSCCG raised $1.0 billion through a secured note issuance and an equity investment and, in accordance with the long-term rating on TVA to AA+ from AAA and removed the rating on review for possible downgrade. The outlook on TVA’s rating is Negative. The action taken on TVA’s rating was based on the applicationterms of the rating agency’s government-related entities criteria.Head Lease and CMA, paid approximately $970 million to TVA on January 17, 2012. In addition, JSCCG deposited approximately $30 million with a lease indenture trustee to fund JSCCG's first debt service payment and payment of return on equity investment from January 17, 2012 through the first debt service payment date. TVA intends to use the proceeds from the transaction for the benefit of its power program. TVA continues to expect the John Sevier CCF to commence commercial operations by June 2012.
Also on January 17, 2012, TVA and JSCCG entered into an agreement under which TVA will lease the John Sevier CCF from JSCCG (the “Facility Lease”) through January 15, 2042. In accordance with the Facility Lease, TVA will make rental payments to JSCCG on each January 15 and July 15, commencing on July 15, 2012 and ending on January 15, 2042. The downgraderental payments are equal to JSCCG's semi-annual debt service payments and payments of TVA’s ratingreturn on equity and return of equity to AA+the equity investor and range from approximately $30 million to approximately $44 million. Throughout the term of the Facility Lease, TVA will operate and maintain (and improve to the extent required by applicable law) John Sevier CCF and will take all power generated by the facility. As long as all payments are made as prescribed by the Facility Lease and there is no significant lease event of default with respect to which JSCCG has exercised dispossessory remedies, the Head Lease will expire on January 17, 2042 and TVA will own John Sevier CCF at no additional cost to TVA. Certain agreements related to this one rating agency may increase TVA’stransaction contain default and acceleration provisions.
JSCCG is a special single purpose limited liability company formed to finance the John Sevier CCF through a $900 million secured note issuance and a $100 million equity investment, both of which are secured by TVA's rental payments. The secured notes bear interest expense by increasingat a rate of 4.626 percent and mature on January 15, 2042. Due to its participation in the design,
business conduct and financial support of JSCCG, TVA is deemed to have a variable interest ratesin JSCCG. Accordingly,TVA has made a qualitative evaluation of which interest holders have the power to direct the activities that most significantly impact the economic performance of JSCCG and have the obligation to absorb losses or receive benefits that could be significant to JSCCG. Based on its analysis, TVA pays on debt securitieshas determined for accounting purposes that it issues. The downgrade requires TVAis the primary beneficiary of JSCCG and, as such, is required to post $100 million of additional collateral under certain physical and financial contracts that contain rating triggers.
Impacts of Recent Financial Market Conditionsaccount for the variable interest entity on Investment Portfolios
Financial markets have experienced significant uncertainty from late July to early August due to the U.S. debt limit debate, indications of expected slower economic growth by the Federal Reserve, and downgrade of U.S. debt to AA+ by a national rating agency. The volatility has resulted in lower market valuations for many investments. TVA's and the Retirement System’s investment portfolios contain a variety of diversified investments, including securities directly impacted by these events. The impact of these events on the TVA Retirement System, the nuclear decommissioning trust, and asset retirement trust investment portfolios is reflected in changes in these portfolio values from June 30, 2011, to August 9, 2011, which are outlined in the following table:consolidated basis.
| | | June 30, 2011(1) | | | August 9, 2011(2) | | | Percent Change | |
| | | | | | | | | | | | | |
Retirement system(3) | | $ | 7,069 | | | $ | 6,592 | | | | (7 | %) |
| Nuclear decommissioning trust | | | 1,071 | | | | 982 | | | | (8 | %) |
| Asset retirement trust | | | 156 | | | | 144 | | | | (8 | %) |
Note (1) Investment balances at June 30, 2011, are based on final trustee statements and estimates for certain private equity and real estate investments. (2) Investment balances at August 9, 2011, are based on preliminary trustee balances and estimates. (3) The August 9, 2011 Retirement System balance is net of July 2011 benefit payments of approximately $50 million. |
During the period of June 30, 2011, through August 9, 2011, the change in the S&P 500 Stock Index was a decrease of 11 percent.
(Dollars in millions except where noted)
Management’sManagement's Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”) explains the results of operations and general financial condition of Tennessee Valley Authority (“TVA”("TVA"). The MD&A should be read in conjunction with the accompanying financial statements and TVA’sTVA's Annual Report on Form 10-K for the fiscal year ended September 30, 20102011 (the “Annual Report”).
TVA’s service area experienced unprecedented weather during a seriesSales for the first quarter of storms which came through the area during April 27, 2011, and April 28, 2011, causing significant damage to the TVA power system. The hardest hit areas2012 were central and northern Mississippi, northern Alabama, and the eastern portion of Tennessee. Local power distributors also sustained significant damage. At the end of the storms on April 28, 2011, there were approximately 850,000 distributor-served customers without power, 128 customer delivery points out of service, and morelower than 90 large transmission lines taken out of service, including 25 of TVA’s 500-kilovolt lines. All transmission lines were repaired by mid-July 2011.
TVA’s Browns Ferry Nuclear Plant (“Browns Ferry”), located in northern Alabama, and the switchyard at Browns Ferry sustained only minimal damage from the storms, but damage to the TVA transmission system at offsite locations resulted in the plant being without sufficient external electricity supply. Emergency backup power systems, including on-site diesel generators, provided power to safely cool down the reactors during the ensuing shutdown. TVA declared a Notification of Unusual Event (“NOUE”), the lowest of the four levels of nuclear plant emergency classifications, and notified the Nuclear Regulatory Commission (“NRC”). The NOUE was terminated on May 2, 2011. All Browns Ferry units returned to full availability status by early June 2011.
Additionally, transmission lines at Widows Creek Fossil Plant (“Widows Creek”), also located in north Alabama, were damaged as a result of this storm system. The interruption in transmission service resulted in one generating unit at Widows Creek being taken off-line. The unit returned to availability status on May 9, 2011.
TVA estimates the cost of the events, described above, to be $39 million for structural repairs including capitalized expenditures of $29 million and operating and maintenance expenditures of $10 million. The cost of power purchased to meet demand while Browns Ferry and other generating units were not connected to the electric grid was $95 million. The increase in TVA’s fuel rate from May 2011 to July 2011 is due in part to help recover the cost of the replacement power purchased as a result of these storms.
expected. During the three-monththree month period ended June 30,December 31, 2011, TVA had a five percent decrease in sales of electricity as compared to the same period of the prior year. Sales also decreased three percent during the nine-month period ended June 30, 2011,Milder weather as compared to the abnormally cold weather for the same period of the prior year.year was responsible for a six percent decrease in sales of electricity to TVA's municipalities and cooperatives. Customers of municipalities and cooperatives are primarily residential customers whose usage of electricity is typically more temperature sensitive than that of industrial customers.
TVA projected revenue to be $12.1 billion in 2012, which included the estimated impact of fuel cost recovery. TVA has revised its 2012 sales forecast downward by two percent. The lower demandthan expected sales and resulting lower revenue, exclusive of fuel and purchased power cost recovery, is causing TVA to revisit expenditures for electricity by the distributor-served customers was primarily weather driven. Lower sales2012 which may include project scope and schedule revisions related to directly served customers during the same three-monthoperations, revisions of certain programs and nine-month periods from the prior year periods were attributable to lower demand by TVA’s largest industrial customer, which has been curtailing operationsinitiatives and to a lesser extent, weather conditions.other productivity enhancement initiatives.
TVA had a net loss for the three months ended June 30,December 31, 2011, of $240$173 million as compared to a net incomeloss of $199$48 million for the three-month periodthree months ended June 30, 2010. ExpensesDecember 31, 2010. The $125 million increase in net loss was primarily due to lower revenues of $260 million and was partially offset by lower expenses of $127 million. A decrease in revenue of $102 million from the recovery of fuel costs from customers was directly related to repair of damage caused by storms, higher operating and maintenance expenses related to outages at generating plants, the agreements with the Environmental Protection Agency (“EPA”) and others (described below), and increases in employee benefit expenses all contributed to lower net income for the quarter ended June 30, 2011, as compared to the same period of 2010. In addition, fuel and purchased power costs increased and becausecosts. Lower sales volume resulted in a further decrease of the timing of the total fuel rate adjustments, were only partially recovered in fuel-related revenue$100 million due to slightly warmer than normal temperatures during the three-month period. TVA had a net lossfirst quarter of 2012 as compared with temperatures which were well below normal for the nine months ended June 30,same period in 2011. The new wholesale base rates implemented in April 2011, of $35 million as compared to net income of $779 millionaccounted for the nine months ended June 30, 2010. Primary drivers for the declineremaining decrease in net income between the nine-month periods were essentially the same as for the three-month periods.
Rate Changerevenue of $58 million.
In April 2011, TVA implemented aThe purpose of the new wholesale rate design implemented in April 2011 was to better align rates with costs. TVA's costs tend to be higher in the summer than in the spring and fall. As such, TVA designed wholesale rates to better reflect those cost relationships. TVA expected the new wholesale structure which includeswould produce lower base revenue in the spring and fall due to the new seasonal and time of use wholesale rates. This changeSimilarly, TVA anticipated the new wholesale structure would produce higher base revenue in summer. Seasonal differences in the weather impact TVA's base revenue under both wholesale structures. Under the new wholesale structure, will not materiallyweather can positively and negatively impact TVA’s annual revenue recovery but will more closely align TVA’s revenues with its costs. There will, however, be some seasonal structural changes that may impactboth volume and average rates while under the timingformer wholesale structure only volume was impacted. The milder weather in the first quarter of the revenue between seasons.
The power contracts between TVA and the distributor customers provide for purchase of power by the distributor customers at the wholesale rates established by the TVA Board of Directors (“TVA Board”). These contracts include a monthly adjustment to reflect the total costs of fuel commodity and other fuel-related costs, variable purchased power, and emission costs.
Major changes by the TVA Board related2012, relative to the rates are:
· | Conversionabnormally colder weather in the first quarter of 2011, produced lower maximum load requirements which resulted in lower base revenue for the first quarter of 2012 relative to the first quarter of the fuel cost adjustment (“FCA”) formula from quarterly operation to monthly operation in October 2009; |
· | Revision of the formula to allow seasonal cost differences to flow through the FCA in October 2009; and |
· | Removal of the 1.851 cents per kWh “base fuel rate” from the formula so that all fuel and other fuel-eligible and purchased power and emission costs would flow through to the customer as a monthly “total fuel rate” separate from the base rates in April 2011. |
The table below identifiesLower demand for electricity affected generation of energy which was two percent lower for the monthly FCA amounts during the period from October 2010 to Marchthree months ended December 31, 2011, as well as total fuel rate impact through August 2011. In order to compare the months more meaningfully, the former base fuel rate is shown, in additioncompared to the total monthly fuel cost rate.three months ended
Month | Base Fuel Rate (¢/kWh) | FCA Rate (¢/kWh) | Total Fuel Rate (¢/kWh) | Impact on Total Average Wholesale Firm Rate |
| | | | | |
| October 2010 | 1.851 | 1.127 | 2.978 | 6.4% |
| November 2010 | 1.851 | 0.735 | 2.586 | (5.0%) |
| December 2010 | 1.851 | 0.476 | 2.327 | (3.5%) |
| January 2011 | 1.851 | 0.548 | 2.399 | 1.0% |
| February 2011 | 1.851 | 0.436 | 2.287 | (1.5%) |
| March 2011 | 1.851 | 0.613 | 2.464 | 2.5% |
| April 2011 | n/a | n/a | 2.376 | (1.2%) |
| May 2011 | n/a | n/a | 2.347 | (0.4%) |
| June 2011 | n/a | n/a | 2.366 | 0.3% |
| July 2011 | n/a | n/a | 2.689 | 4.5% |
| August 2011 | n/a | n/a | 2.741 | 0.7% |
Regulatory Compliance
Browns Ferry Unit 1 NRC Finding. December 31, 2010A problem involving the Browns Ferry Unit 1 low pressure coolant injection valve was discovered by TVA when the reactor was shut down for refueling in October 2010. TVA repaired the valve and reported the problem to NRC. On March 2, 2011, NRC identified an apparent violation of greater-than-very-low safety significance in connection with the valve failure. The valveHigher-cost coal-fired generation was repaired29 percent lower primarily due to outages and returnedeconomic dispatch of units as demand was met by units using lower-cost fuels and/or lower-cost purchased power. Generation from nuclear units increased 18 percent, generation from natural gas-fired combined cycle units increased 71 percent, and hydroelectric generation, comprised of conventional hydroelectric and pumped storage, increased 31 percent for the three months ended December 31, 2011, as compared to service during the refueling outagethree-months ended ,December 31, 2010. Hydroelectric generation was 111 percent of normal and NRC determined that there15 percent above plan. This was no immediate safety concern. However, NRC determined that the event had the potential for greater-than-low safety significance, because the valve’s failure adversely affected TVA’s ability to achieve safe shutdown in certain conditions. TVA met with NRC on April 4, 2011, and presented its conclusion that the valve failure wasprimarily due to a manufacturing deficiency,41 percent increase in rainfall, a 120 percent increase in runoff within the Tennessee River Basin between those same periods, and that the failure did not constitute an event of high safety significance. On May 9, 2011, TVA was notified that NRC issued a “red finding” related to the valve’s performance, which denotes “high safety significance.” This “red” finding would move Browns Ferry Unit 1 to Reactor Oversight Program Action Matrix Column Four, resulting in increased oversight and inspection of the plant. On June 8, 2011, TVA submitted a letter to NRC appealing the “red” finding determination. On June 23, 2011, NRC notified TVA that its appeal of the performance deficiency part of the regulatory finding at Browns Ferry did not meet the acceptance criteria for NRC review of the appeal, but NRC will have an independent review to ensure NRC has taken appropriate regulatory action. The review is expected to be completed in August 2011. TVA is taking actions to address the performance deficiency and contributors to the safety significance.
Transmission System. TVA is subject to federal reliability standards that are set forth by the North American Electric Reliability Corporation (“NERC”) and approved by the Federal Energy Regulatory Commission (“FERC”). These standards are designed to maintain the reliability of the bulk electric system, including TVA’s generation and transmission system. These standards include areas such as maintenance, training, operations, planning, modeling, critical infrastructure, physical and cyber security, vegetation management, and facility ratings. TVA believes itself to be compliant with the majority of these standards, but as a result of self-examination and audits by NERC’s regional entity, the SERC Reliability Corporation (“SERC”), some issues have been identified. TVA is working with SERC on acceptable mitigation plans, based on findings during recent audits, and is negotiating financial settlements where issues have arisen.
TVA recognizes that reliability standards and expectations are becoming more complex and stringent for transmission systems. Compliance with these standards and
expectations may necessitate the need to expand manpowerrelease water to maintain flood storage levels.This generation mix resulted in fuel costs being $98 million, or 13 percent, lower for the three months ended December 31, 2011, as compared to the three months ended December 31, 2010, and programs to address the associated exposure to risk of noncompliance. TVA continues to evaluate its options to meet these new measures.
Environmental Agreements. On April 14, 2011, TVA entered into two agreements that generally absolve TVA from any liability under the New Source Review (“NSR”) requirements of the Clean Air Act (“CAA”)purchased power cost being $41 million, or 11 percent, lower for maintenance, repair, and component replacement projects at TVA’s coal-fired units. The first agreement is a Federal Facilities Compliance Agreement with EPA. The second agreement is a consent decree with Alabama, Kentucky, North Carolina, and Tennessee, and three environmental advocacy groups: the Sierra Club, National Parks Conservation Association, and Our Children’s Earth Foundation (the “Consent Decree”). The two agreements (collectively, the “Environmental Agreements”) are substantially the same and are parts of a collective undertaking. As part of the Environmental Agreements, EPA generally will not enforce NSR requirements for new plant maintenance, repair, and component replacement projects against TVA until 2019. Possible claims for NSR violations involving increases in greenhouse gases (“GHG”) and sulfuric acid mist from projects can still be pursued in the future. Claims for increases in particulates also can be pursued except at TVA’s Allen Fossil Plant, Bull Run Fossil Plant, Kingston Fossil Plant (“Kingston”), and Gallatin Fossil Plant and Unit 5 at TVA’s Colbert Fossil Plant.period.
These agreements also contain provisions with a direct monetary impact on TVA’s operations during the three-month period ended June 30, 2011, as well as on future operations. During the three months ended June 30, 2011, the civil penalty of $10 million was expensed2012 Challenges and it was subsequently paid in July 2011. TVA will also provide $60 million to be divided by Alabama, Kentucky, North Carolina, and Tennessee to fund environmental projects, giving a preference for projects in the TVA watershed. In addition, TVA will invest $290 million in energy efficiency projects, demand response projects, renewable energy projects, and other projects.Key Initiatives
In connection with the agreements, certain legal and administrative proceedings have been or are expected to be terminated. See Note 16 — EPA Settlement for more information regarding these proceedings.
The Environmental Agreements will also require TVA to take actions with respect to some of its coal-fired units. See Generation Resources for more information regarding these actions.
Environmental Matters
In December 2010, EPA issued a report that evaluated progress under its Acid Rain Program (“ARP”). ARP, established under Title IV of the 1990 CAA Amendments, requires major emission reductions of sulfur dioxide (“SO2”) and nitrogen oxide (“NOx”) from the electric power industry. The December 2010 report contains information examining emission reductions, reviewing compliance results and market activity, and comparing changes in emissions to changes in pollutant concentrations. Data contained in this report indicates TVA has reduced SO2 emissions from its coal-fired generating plants at a faster rate than the national average for the industry and that TVA’s SO2 emissions have been significantly reduced during the past three decades. Furthermore, the report indicates that TVA’s NOx emissions have been significantly reduced since CY 1990 and that the reduction in these emissions has been at a rate faster than the national average during the past two decades.
Generation Resources
At its April 14, 2011 meeting,John Sevier Combined Cycle Facility. TVA is in the process of completing the John Sevier Combined Cycle Facility (“John Sevier CCF”) in northeastern Tennessee. John Sevier CCF was connected to the TVA Board accepted an Integrated Resource Plan (“IRP”) which was developed utilizing extensive business, technical, and economic analyses, as well as public input. The plan outlines a strategic direction focusingelectrical grid for the first time on a diverse mix of electricity generation sources, including nuclear power, renewable energy, natural gas, and energy efficiency, as well as traditional coal and hydroelectric power.
TVA’s intention to transition more toward generation sources with low or no emissions and to retire coal-fired units from service will likely result in a need for new generating capacity. Additionally, installing scrubbers or other emission controls to meet increasingly stringent environmental regulations facing coal-fired power plants could require TVA to make substantial capital investments inDecember 17, 2011. This event marked the current year as well as future years and lead to increased liquidity needs and financing requirements.
Coal-Fired Generation. With the acceptancebeginning of the IRPstartup testing for the project and is the Environmental Agreements, the TVA Board approved the retirement of 18 older coal-fired generation units at three power plants. In June 2011, TVA idled Widows Creek Units 1 and 3 and in August 2011, TVA idled Widows Creek Unit 4, resulting in a reduction of approximately 330 megawatt ("MW") of net summer dependable capability. TVA continues to evaluate the possibility of idling Widows Creek Unit 6. This potential action will result in a further reduction of approximately 110 MW of summer net dependable capability. As parttransition of the Environmental Agreements, TVA announced the retirement of twoproject from full construction to pre-commercial testing. John Sevier Fossil Plant (“John Sevier”) units with approximately 350 MW of net summer dependable capability by December 31, 2012, and Johnsonville Fossil Plant’s (“Johnsonville”)
10 units with approximately 1,100 MW of net summer dependable capability by December 31, 2015 (six units) and December 31, 2017 (four units). These actions will permanently remove these unitsCCF is currently scheduled to begin commercial operations in June 2012. See Note 17 — from service under their current operating permits and reduce TVA’s coal-fired fleet by approximately 13 percent by the end of 2017. In addition, TVA is also required to remove from service (idle) the other two John Sevier units by December 31, 2012, and either retire these units, install emission control equipment at the units, or convert them to biomass by December 31, 2015. These two remaining John Sevier units have approximately 350 MW of summer net dependable capability. Combined Cycle TransactionTVA has determined that it is economically advantageous to idle these remaining two John Sevier units and plans to remove them from service by December 31, 2012. TVA had previously idled Widows Creek Unit 5 in September 2010 and Widows Creek Unit 2 and Shawnee Fossil Plant (“Shawnee”) Unit 10 in October 2010. These earlier actions resulted in a reduction of nearly 350 MW of net summer dependable capability.
Although TVA may decide to idle additional coal units, there may still be some risks related to TVA’s ability to meet customer demand for low-cost power in the future. These risks, however, are being addressed through TVA’s integrated planning process, diversification of fuel sources and fuel type, as well as physical and financial hedging programs for fuel and purchased power.
Additionally, as part of the Environmental Agreements, and consistent with the strategic direction outlined in the IRP, TVA’s long-range plans will continue to attempt to balance the costs and benefits of significant investments at its remaining, coal-fired plants without emissions controls and decide whether to control, convert, or retire the remaining uncontrolled coal-fired capacity on a unit by unit schedule which can extend until 2019. TVA anticipates having to take action to reduce emissions earlier than required by the Environmental Agreements in response to new EPA regulations. TVA estimates that it may invest an additional $3.7 billion in the next 10 years on new emission-control equipment and upgrades of existing equipment at its coal-fired plants. See Environmental Matters.
Kingston Fossil PlantNuclear Generation.. Under environmental agreements reached with the Environmental Protection Agency (“EPA”) and others in 2011, TVA management has establishedwas generally not allowed to operate Kingston Fossil Plant (“Kingston”) after September 20, 2011, without scrubbers in operation, and scrubbers could not be operated unless TVA had the ability to store the gypsum the
scrubbers produced. Accordingly, TVA stopped operating Kingston on September 19, 2011, until work could be completed on the first phase of a response teamnew synthetic-lined gypsum storage facility which it completed on October 21, 2011. Approval to analyze events resultingplace the facility back in operation was received from the Japanese nuclear eventsTennessee Department of Environment and Conservation on November 16, 2011. A comprehensive review isOn November 27, 2011, the first Kingston units were returned to service and on December 17, 2011, all units were available for dispatch. The Kingston units are currently not on-line as they are in progressnot in demand status due to determine the status of safety-related equipment and other aspects of plant operations that affect nuclear, radiological, and personal safety in order to make changes as needed for safety. The response team is also analyzing the ability of TVA’s plants to safely shut down and safely remain in that state during simultaneous natural disasters such as floods, earthquakes, and/or tornadoes.low load demand. See Note 16 — Environmental Agreements.
The team will also provide short, intermediate, and long-term recommendations for TVA sites related to additional precautionary actions TVA may adopt. Possible short-term actions include adding additional satellite phones for emergency responders when normal communications are damaged and adding small portable electric generators for lights, charging batteries, and other vital equipment. Longer-term actions may include changes to the storage methods for spent nuclear fuel. Finally, TVA will further evaluate its switch-yards for seismic vulnerabilities and may provide additional backup power sources at its nuclear plants.
Browns Ferry Nuclear Plant. The TVA service area experienced a hotter than normal summer in 2010. The hot summer resulted in TVA having to curtail the use of some of its generating facilities including generation at some of its nuclear units, primarily Browns Ferry, because of water temperature. To better address the water temperature issues at Browns Ferry, TVA has initiated a capital project to construct a new cooling tower. Completion of the tower, originally scheduled to be operational before the summer of 2011, has been delayed because of the April 27, 2011 and April 28, 2011 storms. Current plans are for the tower to be operational by the fall of 2011.
Watts Bar Nuclear Plant Unit 2. The current and past estimates of the construction project cost and schedule for Watts Bar Nuclear Plant (“Watts Bar”) Unit 2 are currentlyproject is experiencing challenges with schedule and costs. Lower productivity has slowed the pace of construction and it is anticipated that regulatory considerations resulting from the Nuclear Regulatory Commission's ("NRC") Near-Term Task Force on the Fukushima event, as well as other causes, will result in additional costs being reviewed by TVA.incurred. The project’s schedule has experienced some delays as a result of lower than expected construction productivity, and the construction ofcost estimates are currently under assessment and will be revised. The revised completion date for Watts Bar Unit 2 will take longer than originally planned.
It is also virtually certain that the project’s schedule could be adversely affected by licensing-related delays, including a delay resulting from a hearing to be scheduled to take place before an Atomic Safety and Licensing Board to resolve a pending aquatic contention.
On July 13, 2011, NRC’s Japan Task Force released its review of insights from the Fukushima Daiichi accident proposing safety improvements in areas ranging from loss of power to earthquakes, flooding, spent fuel pools, containment venting, and preparedness. The report has been sent to the five NRC Commissioners and could result in TVA being required to make changes to its operating nuclear units and Watts Bar Unit 2. Such changes could also possibly impact the cost and schedule of the project.
As a result of one or more of the above developments, TVA believes that the Watts Bar Unit 2 completion date willmay extend intopast CY 2013, rather than being in the last quarter of CY 2012 as currently scheduled. Projecthad been previously scheduled and project costs could alsoare expected to significantly exceed the currentprevious estimate of approximately $2.5 billion.
TVA is performing a root cause analysis to better understand the factors that are driving the construction delays and contributing to the project's extended schedule and higher costs. Once the root cause analysis is finalized, TVA will implement additional corrective actions as appropriate to minimize future project schedule and cost risks. The extent of exceedance is not known at this time.
As planned, TVA received a license from NRCrevised schedule and cost estimates and associated root cause analysis are expected to bring fuel to Watts Bar for its ultimate usebe completed in the Unit 2 reactor. The license allows TVA to receive, inspect, and store new nuclear fuel at the sitesecond quarter of Unit 2. New fuel is expected to begin arriving at the Watts Bar site during the summer of 2011. Nuclear fuel will be loaded into the Unit 2 reactor following receipt of the operating license.
FY 2012. For legal proceedings related to Watts Bar Unit 2, see Note 16 — Litigation — Administrative Proceedings Regarding Watts Bar Nuclear Plant Unit 2.
Bellefonte Nuclear Plant. Engineering work at the Bellefonte Nuclear Plant (“Bellefonte”) site in northern Alabama is proceeding on schedule as feasibility studies related to the completion of Bellefonte Unit 1 continue. TVA management will ask the TVA Board to make a decision on whether to move ahead with construction of Unit 1. Should TVA proceed with construction of Bellefonte Unit 1, TVA is evaluating the design for additional defense-in-depth improvements for the project.2.
For legal proceedings related to Bellefonte, see Note 16 — Litigation — Case Regarding Bellefonte Nuclear Plant Units 1 and 2 and Administrative Proceedings Regarding Bellefonte Units 3 and 4.
Future Plans for TVA’s Nuclear Program. TVA believes that the Japanese nuclear events could translate into changesDelays in plant operations, design, or safety and the imposition of additional requirements by NRC or other regulatory bodies. Should potential changes prove to be significant, the schedule for the commercial operationcompletion of Watts Bar Unit 2, may affect the timing of the commencement of construction of Bellefonte Nuclear Plant ("Bellefonte") Unit 1 which, as provided in the TVA Board’s approval of the Bellefonte Unit 1 project in August 2011, will not begin until after initial fuel loading at Watts Bar Unit 2. However, TVA does not anticipate that delays to Watts Bar Unit 2 will have a significant adverse affect on TVA’s ability to provide for the power needs of its customers, due to factors such as the forecasted outlook for electricity demand as well as future plans for construction at Bellefonte or other facilities, could be affected. To date, six petitions have been filed with NRC that seek to take actions inthe impacts of energy efficiency and demand response to the Japanese nuclear events that could impact TVA nuclear operations or licensing activities if the requested actions are taken by NRC. See Note 16 — Petitions Resulting from Japanese Nuclear Events.initiatives.
Johnsonville Fossil Plant. Natural Gas-Fired Generation. DespiteAs of March 1, 2012, TVA plans to idle Units 7, 8, 9, and 10 at its Johnsonville Fossil Plant (“Johnsonville”) in west Tennessee. The schedule has been accelerated as part of an effort to address operational challenges at Johnsonville and to reduce costs. This is earlier than the impactsretirement dates required by Environmental Agreements with the EPA and other parties, and is earlier than the expected compliance date for the Utility MACT Rule (Mercury and Air Toxics Standards (“MATS”)).Sixty days after the idle date of these units, TVA plans to put the units in inactive reserve status. Units in inactive reserve status are unavailable for service but can be brought back into service after some maintenance in a relatively short duration of time. Because of the recession of 2008-2009, which reduced TVA sales by approximately seven percent at its peak, and a relatively sluggish economic recovery, TVA believes new generation sources will be needed to meet anticipated load growth under most likely scenarios. Additionally, increasingly stringent environmental regulations facing coal-fired power plants, coupled with TVA’s announced intention to transition more toward generation sources with low or no emissions, and the retirement of 18 coal-fired units, are highly likely to result in a need for new generating capacity. Accordingly, TVA intends to make capital investments in the current year as well as future years.
In keeping with its generation strategy to assemble a balanced generation portfolio comprised of efficient resources at favorable life-cycle costs with little or no emissions, TVA continues to evaluate natural gas-fired resource options. Existing combined cycle plants located within or closely adjacent to the TVA service territory generally meet these criteria and provide suitable opportunities for acquisition or long-term purchased power contracts. TVA completed its evaluation of a site in western Tennessee for a natural gas-fired generation facility but does not plan to pursue this option at this time.
On July 7, 2011, TVA entered into an agreement, subject to TVA Board and FERC approvals, to acquire the Magnolia Combined Cycle Power Plant (“Magnolia”) from Magnolia Energy L.P., a subsidiary of Kelson Energy. The Magnolia facility is a three-unit natural gas-fired combined cycle plant with approximately 900 MW of net summer dependable capacity located in Benton County, Mississippi, and has been a source of purchased power for TVA since the plant began operation in 2003. Finalizationacceleration of the purchase is contingent on several conditions, including the approvalidling of FERC and thethese units, TVA Board.
Hydroelectric Generation. Weather was also a driverrecognized an additional $25 million of hydroelectric generation for the three-month period ended June 30, 2011. March 2011 was wetter than normal (123 percent of normal rainfall), resulting in 126 percent of normal runoff and 114 percent of normal hydroelectric generation. The effects of the increase in rain and runoff in late March 2011 allowed for increased hydroelectric generation in April, May, and June 2011. Hydroelectric generation was 47 percent higher during the three months ended June 30, 2011, than during the same period of the prior year. Totalsdepreciation expense for the three months ended June 30,December 31, 2011, and also expects to recognize accelerated depreciation expense of approximately $45 million for rainfall, runoff, and hydroelectric generation were 134 percent, 144 percent, and 147 percentthe remainder of 2012. See Note 16 — Environmental Agreements.
Regulatory Compliance
Watts Bar Greater than Green Finding. The NRC notified TVA in December 2011 of its final determination of a “greater than green” inspection finding associated with the Nuclear Security organization at Watts Bar. A "green finding" indicates a finding of very low safety significance. The NRC greater than green finding was identified during a recent inspection of the same periodplant's physical security (fences, cameras, detection and intrusion systems, etc.). Upon notification of 2010, respectively.the NRC's finding, TVA took immediate compensatory action to address the issue. TVA is in the process of conducting a root cause analysis to determine the cause of the NRC finding within security and will implement a series of corrective actions to enhance performance. The NRC will conduct a supplemental inspection known as a 95001 inspection in the coming months to evaluate TVA's root cause analysis and corrective actions.
Coal Combustion Products FacilitiesSequoyah Nuclear Plant ("Sequoyah") Unit 1 NRC Performance Indicator Moved to White. During the first quarter of 2012, the NRC changed the color designator for one of Sequoyah Unit 1's performance indicators from green to white due to the number of unplanned reactor shutdowns in a seven thousand hour period. The "white" band indicates that performance is outside of the nominal, expected range and can be characterized as of low to moderate safety significance, but performance remains acceptable. The NRC did not place any operating restrictions on the plant, but as a result of the white performance indicator the NRC will conduct an inspection of Sequoyah Unit 1 during the second quarter of 2012 in order to ensure that TVA has developed a detailed root cause for the reactor shutdowns and that TVA has put in place the right corrective actions to ensure improved performance.
TVA retained anSequoyah Tritium Sample. On December 16, 2011, one of sixteen groundwater monitoring wells at Sequoyah detected increased levels of tritium. Tritium is a radioactive form of hydrogen that occurs both naturally within the earth's atmosphere and from the operation of nuclear power plants. The adjacent monitoring wells have not detected any elevated tritium levels. The sample of concern was from a newly drilled well, and independent third-party engineering firm to performanalysis indicates that its source was a multi-phased evaluation ofspill that occurred in the overall stability1980’s, and that no active leak exists. The groundwater is located directly under Sequoyah and is not used for drinking or irrigation purposes. There are no known public health or safety of all existing embankmentsissues associated with TVA’s wet coal combustion product (“CCP”) facilities. Phases onethis issue. TVA notified the NRC and two were completed by the end of 2010. The studies indicated that none of TVA’s other coal-fired plants showed the same set of conditions that existed at Kingston at the time of the ash spill,government agencies on December 19, 2011, and the ongoing remediation work at the plants is expected to bring all of them to within industry standards in terms of stability. The third phase of the program, which is implementation of recommended actions, is ongoing. This phase includes risk mitigation steps such as performance monitoring, designing and completing repairs, developing planning documents, obtaining permits, and generally implementing the lessons learned from the Kingston ash spill at TVA’s other CCP facilities. As a part of this effort, CCP facilities have been incorporated into TVA’s dam oversight program, with additional training in dam safety and monitoring provided.will take any necessary corrective actions.
Hydrology Issues for Nuclear Plants. A preliminary analysis, performed as part of an update to TVA’s hydrology model indicated that under "probable maximum flood" assumptions, four of TVA's dams would not be high enough to contain the flood waters. A "maximum flood” is an extremely unlikely event, and TVA is converting its wet fly ash, bottom ash,taking actions with the aim of ensuring that flood waters would pass safely. TVA implemented interim dam modifications in the second quarter of 2010, by installing sand baskets. These baskets are engineered, interconnected, fabric-lined, and gypsum facilitiessand-filled containers that have been used successfully to dry collection facilities and remediating or eliminating the CCP facilities that were classified as “high” risk during the preliminary reassessment. The classifications,protect flood prone areas such as “high,” do not measure the structural integrity of the facility or the possibility of whether a failure could occur. Rather, they are designed to identify where loss of life or significant economic or environmental damage could occur in the event of a failure. The expected cost of the CCP work is between $1.5 billion and $2.0 billion, and the work is expected to be completed over the next 10 years. The work is proceeding on schedule and is prioritized based on structural needs, plant storage requirements, and ongoing studies related to idling TVA’s older coal-fired facilities.Mississippi River.
On December 15, 2010,The NRC notified TVA on January 25, 2012, that the sand baskets installed at dams to help protect the nuclear plants from a small leak was identified in the clay linerworst-case flood are not capable of resisting debris impact and are not acceptable as a long-term solution. Based on completion of the gypsum pondhydrology work taking several years, the NRC has requested TVA to provide a status update at least annually or after any major changes are made to the Kingston facility.plan. TVA identifiedwill review the leak during a routine inspection and immediately notified the state and EPA and isolated the leak. The Tennessee Department of Environment & Conservation (“TDEC”) sent TVA an order outlining the requirements to return the gypsum pond to an operational status. TVA is complying with TDEC’s order and has submitted the repair plan to install a synthetic liner on the gypsum pond. The gypsumlatest information from the plant is scheduledNRC and continue to be dewateredkeep the agency informed of its progress in 2012, and the material will be dry stacked in the facility after 2012. The synthetic liner will be designed and installed to meet the proposed new EPA rules on coal combustion residue storage and thereby extend the life of the facility. Once TDEC has approved TVA’s repair plans, the estimate as to how much the liner installation will cost and how long it will take to install will be developed by TVA.addressing hydrology issues.
Natural ResourcesRenewable Power
In January 2012, TVA completedbegan receiving 535 megawatts of renewable power from four wind power contracts with third-party providers. These newly added wind power sources are among contracts TVA has entered into with eight wind farms from a 2008 Request for Proposals ("RFP") for more renewable and released its proposed Natural Resource Plan (“NRP”) in July 2011. The NRPclean energy. TVA’s total energy activated under the 2008 RFP is designed to enhance stewardship of public recreation facilities, water resources, wildlife and plants, and historic and cultural sites on TVA-managed reservoir lands by helping to guide TVA management to better meet public stewardship objectives while responding to the needs of the TVA region’s communities and residents. Implementation of the NRP is expected to be staged over a 20-year period and reviewed and updated every five years. The NRP is scheduled to be presented for TVA Board consideration in August of 2011.now 950 megawatts, or more than 3 million megawatt hours annually.
Financial FlexibilityCustomers/Counterparties Risk
The TVA Act specifies that TVA’s bonds, notes, and other evidences of indebtedness (“Bonds”) may not exceed $30.0 billion outstanding at any one time. As of June 30, 2011, TVA had $24.2 billion of Bonds outstanding. TVA’s challenge to meet the economic, environmental, and energy demands facing the Tennessee Valley region puts further pressure on its $30.0 billion borrowing authority, which has not been changed since 1979. Increased future capital expenditures, alongcurrent contract with restrictive borrowing authority, may pose a challenge to TVA’s ability to maintain low and competitive power rates.
On April 18, 2011, a national rating agency affirmed the AAA sovereign credit rating on the United States, but revised the outlook to Negative from Stable. On April 25, 2011, the agency affirmed the AAA long-term rating and AAA issuer credit rating (“ICR”) on TVA, but revised the outlook for TVA to Negative from Stable. The change in the agency’s outlook on TVA was the result of the change in outlook on the United States and does not reflect a change in TVA’s financial condition or any TVA-specific event. TVA is completely self-funded and does not rely on financial support from the government.
On concerns that the United States Congress and the Administration might not act to raise the statutory debt limit on a timely basis, two national rating agencies took action on July 13 and 14, 2011, and placed the triple-A sovereign credit rating on the United States on review for possible downgrade. Subsequently, these same two rating agencies took similar actions on TVA’s credit rating, placing TVA’s triple-A rating on review for possible downgrade. These actions were the result of the change on the credit rating of the United States and do not reflect a change in TVA’s financial condition or any TVA-specific event.
On August 2, 2011, one of the rating agencies confirmed the Aaa rating of the United States and assigned a Negative rating outlook following the government’s action earlier that same day to raise the debt limit and avoid default on the government’s obligations. The next day, this same agency confirmed the Aaa senior secured and unsecured ratings of TVA and assigned a Stable rating outlook.
On August 5, 2011, one of the rating agencies lowered its long-term rating on the United States to AA+ from AAA and affirmed the A-1+ short-term rating. This action was based on concerns regarding the fiscal and economic position of the United States. The outlook on the long-term rating is Negative. The rating agency removed the short- and long-term ratings of the United States from review for possible downgrade. On August 8, 2011, this same rating agency lowered the long-term rating on TVA to AA+ from AAA and removed the rating from review for possible downgrade. The outlook on TVA’s rating is Negative. The action taken on TVA’s rating was based on the application
of the rating agency’s government-related entities criteria.
The downgrade of TVA’s rating to AA+ by this one rating agency may increase TVA’s interest expense by increasing the interest rates TVA pays on short-term or long-term debt securities it issues. The downgrade requires TVA to post $100 million of additional collateral under certain physical and financial contracts that contain rating triggers.
As of August 10, 2011, the third national rating agency that provides a rating on TVA securities had not taken any action on either the United States government or TVA. See Note 17 — Credit Ratings.
Customer Contracts
TVA continues to monitor the financial stability of itsTVA's largest directly served customer. The current power supply contract with this customer expires in May 2012. Although2012 and, although TVA and the customer is pursuing optionshave been negotiating a renewal of the contract to extend operations of its plant, there is currently no contract in place past that date, the customer has yet to continue powercommit to an extension. Power sales to the customer. Sales to this customer amounted to nearly 43 percent of revenue from industriesTVA's largest directly served and fiveindustrial customer represented six percent of TVA's total operating revenues during 2010. See Note 12 — for the three months ended Counterparty Credit Risk — Credit of CustomersDecember 31, 2011. This customer's senior unsecured credit ratings are currently CCC- by Standard & Poor's ("S&P") and Caa2 by Moody's Investors Service ("Moody's").
Future Workforce NeedsThe customer is also a supplier of enrichment services for uranium for fueling TVA's nuclear units. Currently the customer is giving the required notices to be able to discontinue operation of the facility at the end of their current power contract and Developmentturn the facility back over to the United States Department of Energy. TVA has sufficient nuclear fuel inventory available to mitigate near-term supply risks.
For the long-term, deliveries from this supplier through the end of the contract periods are not expected to be affected by the discontinuation of operations of its plant. If necessary, TVA's material can be pre-produced and stored until it is needed. The supplier also has other sources of supply from which to provide enrichment services.
From a risk of supply exposure perspective, TVA contracts with other suppliers and has sufficient inventory to cover near-term fuel needs. TVA expects to be able to procure material at reasonable rates in the liquid nuclear fuel market in case the customer is not able to deliver.
Effectively addressing workforce needs is a priorityMF Global. On October 31, 2011, MF Global Holding Ltd. and its subsidiary MF Global Finance USA Inc. filed for TVA. Although TVA traditionally experiences low employee turnover, potential emerging risks exist because of retirements, competition for talent from other companies, new nuclear construction and installation of new environmental equipment, additional environmental controls construction, new regulations, and evolving employee skill sets required to meet TVA’s vision of being onebankruptcy protection under Chapter 11 of the nation’s leading providers of low-cost and cleaner energy by 2020. During 2010,U.S. Bankruptcy Code. On the same date, a Securities Investor Protection Act proceeding was filed against MF Global Inc. ("MF Global"). TVA established a new organizationhad used MF Global to focus on human capital, including recruiting programs and outreach to high school, trade school, and college students. In addition, a workforce planning program is being revised in 2011,clear certain trades and the program is targeted for implementation agency-wide inMF Global Trustee held $33 million of TVA's cash collateral at that time. TVA has recovered $7 million of this balance from the first quarter of 2012. The goalTrustee. TVA has filed a claim to recover the funds currently being held by the MF Global Trustee and expects to recover some or all of these initiatives isfunds; however, the recruitment, retentiontiming and motivationthe amount of the talent required to achievefunds' returned and the TVA vision. Achievingamount of any potential loss cannot be estimated at this goal may be challenging in light of the salary freeze for federal employees enacted on December 22, 2010. See Legislative and Regulatory Matters for a discussion of the salary freeze.time.
Safeguarding AssetsGovernment Accountability Office Audit Findings
Physical Security.The U.S. Government Accountability Office (“GAO”) released a report December 1, 2011, on TVA's energy efficiency and capital expenditures planning. The report was requested by the chairman of the United States Senate Committee on Environment and Public Works. The GAO stated that TVA could benefit from a pending consultants' study on regional energy efficiency potential to ensure that TVA is responsible for assetsmaking the most cost-effective resource decisions to meet its vision of leadership in energy efficiency improvements. TVA agreed with the GAO findings and the potential benefit from the pending commissioned study by the outside firm. The results of the study are intended to assist with future resource planning processes at TVA related to continued progress in energy efficiency and demand response initiatives across its service area, and views the protection of its critical infrastructures, employees, and the public as a priority. In seeking to protect these assets, TVA follows numerous regulatory requirements that set minimum standards for physical security and uses a combination of threat analysis, technology, and partnerships with the public to help deter, detect, and respond to specific threats to critical assets. In addition, training programs for TVA’s workforce are being developed in order to help foster a strong culture of security awareness throughout TVA. TVA is likely to invest in future protective measures based on security assessments being performed in 2011 and 2012 that are expected to identify opportunities for improvement.territory.
Nuclear Security. Nuclear security is carried out in accordance with federal regulations as set forth by NRC. These regulations are designed forThe GAO also recommended that TVA develop a written capital expenditure plan that includes the protection of TVA’s nuclear power plants and for the health and safetyfull costs of the public and employees from the threat of radiological sabotage and other nuclear-related terrorist threats. TVA has nuclear security forces to guard against such threats. TVA currently plans to spend between $100 million and $140 million between 2011 and 2013 on upgrades to its nuclear security infrastructure.
Cyber Security. Cyber security and the protection of TVA operations and activities are a priority. TVA uses a defense-in-depth security modelassets in an effort to prevent, detect, respond to, and recover from threats against its systems.which TVA plans to modifyinvest and upgrade its protections as technology advancesthe sources of funding for acquiring those assets. Although TVA already has a number of interrelated and threat environmentscoordinated planning processes for capital expenditures, it understands the GAO recommendation for a more formal process which has the potential to promote greater effectiveness in the financial planning processes. TVA is continuously working to refine and business requirements change. TVA currently plans to spend approximately $20 million to $40 million in cyber security updates between 2011 and 2013.improve these processes.
Investment Performance
The performance of debt, equity, and other markets during the summer of 2011 negatively impacted the asset values of investments held in TVA’s decommissioning trust funds and pension fund.
During the period from June 30, 2011 to August 9, 2011, the nuclear decommissioning trust portfolio declined in value $89 million, or eight percent. As of August 9, 2011, TVA’s nuclear decommissioning trust funding was 119 percent of the estimated present value of the funding requirements established by NRC.40
TVA’s asset retirement trust portfolio, which is invested entirely in fixed income funds, decreased in value $12 million, or eight percent, during the period from June 30, 2011 to August 9, 2011.
As of September 30, 2010, TVA's pension plan had assets of $6.8 billion compared with liabilities of $10.4 billion. TVA's plan remained underfunded at June 30, 2011. Assets in the plan at June 30, 2011, were approximately $7.1 billion. During the period from June 30, 2011 to August 9, 2011, the investments in the TVA Retirement System declined in value $477 million, or seven percent. The ability of the plan’s funded status to quickly improve is limited because of the significant amount of benefits paid each year to plan beneficiaries. The plan currently has nearly 23,000 participants receiving benefits of approximately $600 million per year.
TVA’s investment policies are based on the objective of meeting long-term obligations, and the allocation of investments is based on the assumption of encountering distressed market conditions from time to time. TVA does not anticipate making significant changes in its basic investment policies as a result of current market conditions.
Sources of Liquidity
To meet cash needs and contingencies, TVA depends on various sources of liquidity. TVA’s primary sources of liquidity are cash from operations and proceeds from the issuance of short-term and long-term debt. Net working capitalCurrent liabilities may be negativeexceed current assets from time to time andin part because TVA uses short-term debt to fund short-term cash needs as well as to pay scheduled maturities and other redemptions of long-term debt. The daily balance of cash and cash equivalents maintained is based on near-term expectations for cash expenditures and funding needs.
In addition to cash from operations and proceeds from the issuance of short-term and long-term debt, TVA's sources of liquidity include a $150 million credit facility with the U.S. Treasury, three long-term revolving credit facilities totaling $2.5 billion, and proceeds from any other financing arrangements such as call monetization transactions, sales of assets, and sales of receivables and loans. Management expects these sources, certain of which are described below, to provide adequate liquidity to TVA for the foreseeable future. However, the limit on theThe TVA Act authorizes TVA to issue bonds, notes, and other evidences of indebtedness (“Bonds”) in an amount of Bonds TVA may havenot to exceed $30.0 billion outstanding at any one time is $30.0 billion. Duetime. However, due to thethis limit on Bonds, TVA may not be able to use Bonds to finance all of the capital investments neededplanned over the next decade. Capital spending needsHowever, TVA believes that other forms of financing not subject to the $30.0 billion limit on Bonds, such as certain forms of lease financing, could be met with a
combinationprovide additional funding. Also, the impact of Bonds, alternative financing, additional power revenues through rate increases, costs reductions, or other ways. Certain sources of liquidity are discussed below. Additionally, energy efficiency and demand response initiatives may reduce generation requirements and thereby resulting in lowerreduce capital needs.
Capital spending needs could be met with a combination of Bonds, lease arrangements (such as the lease-purchase transaction involving the John Sevier CCF), energy prepayments, additional power revenues through rate increases, cost reductions, or other ways.
Issuance of Debt. Debt. TVA Bonds are not obligations of the United States, and the United States does not guarantee the payments of principal or interest on Bonds. AsAt December 31, 2011, TVA had only two types of June 30, 2011, all of TVA’s Bonds were rated by at least one rating agency except for two issues ofoutstanding: power bonds and TVA’s discount notes. RatingsPower bonds have maturities of between one and 50 years, and discount notes have maturities of less than one year. Power bonds and discount notes have a first priority and equal claim of payment out of net power proceeds. Net power proceeds are not recommendationsdefined as the remainder of TVA's gross power revenues after deducting the costs of operating, maintaining, and administering its power properties and payments to buy, sell,states and counties in lieu of taxes, but before deducting depreciation accruals or holdother charges representing the amortization of capital expenditures, plus the net proceeds from the sale or other disposition of any TVA securities and may be subject to revisionpower facility or withdrawal at any time by the rating agencies. Ratings are assigned independently, and each should be evaluated as such.interest therein.
TVA uses the proceeds from the issuance of discount notes, in addition to other sources of liquidity, to fund short-term cash needs and scheduled maturities of long-term debt. The following table provides additional information regarding TVA’sTVA's short-term borrowings.
| Short-Term Borrowing Table | |
| | | | | | | | | | | | | | | | | | | |
| | At June 30, 2011 | | For the three months ended June 30, 2011 | | | For the nine months ended June 30, 2011 | | | At June 30, 2010 | | | For the three months ended June 30, 2010 | | | For the nine months ended June 30, 2010 | |
| | | | | | | | | | | | | | | | | | | |
Amount Outstanding (at End of Period) or Average Amount Outstanding (During Period) |
| | | | | | | | | | | | | | | | | | | |
| Discount Notes | | | $ - | | | | $ 138 | | | | $ 256 | | | | $ 834 | | | | $ 1,003 | | | | $ 959 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Weighted Average Interest Rate |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Discount Notes | | | N/A | | | | 0.01 | % | | | 0.09 | % | | | 0.07 | % | | | 0.12 | % | | | 0.07 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | |
Maximum Month-End Amount Outstanding (During Period) |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Discount Notes | | | N/A | | | | $ 150 | | | | $ 1,401 | | | | N/A | | | | $ 1,176 | | | | $ 1,176 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
The balance of Discount Notes was approximately $834 million lower at June 30, 2011, than June 30, 2010, because a portion of the proceeds from long-term debt issuance in February 2011 was used to reduce short-term debt. Differences in the average balances of short-term debt from year to year are a function of the timing of debt issuances, debt
redemptions, and other cash flows.
|
| | | | | | | | | | | | | | | |
| Short-Term Borrowing Table |
| | At December 31, 2011 | | For the three months ended
December 31, 2011 | | At December 31, 2010 | | For the three months ended
December 31, 2010 |
Amount Outstanding (at End of Period) or Average Amount Outstanding (During Period) |
| Discount Notes | $ | 785 |
| | $ | 444 |
| | $ | 219 |
| | $ | 39 |
|
| Weighted Average Interest Rate |
| Discount Notes | 0.000% |
| | 0.001 | % | | 0.038 | % | | 0.076 | % |
Maximum Month-End Amount Outstanding (During Period) |
| Discount Notes | N/A |
| | $ | 785 |
| | N/A |
| | $ | 219 |
|
Credit Facility Agreements. TVA and the U.S. Treasury have entered into a memorandum of understanding under which the U.S. Treasury provides TVA with a $150 million credit facility. This credit facility matures on September 30, 2011,2012, and is expected to be renewed. This arrangement is pursuant to the TVA Act. Access to this credit facility or other similar financing arrangements has been available to TVA since the 1960s. TVA plans to use the U.S. Treasury credit facility as a secondary source of liquidity. The interest rate on any borrowing under this facility is based on the average rate on outstanding marketable obligations of the United States with maturities from date of issue of one year or less. There were no outstanding borrowings outstanding under the facility at June 30,December 31, 2011.
TVA also has funding available in the form of three long-term revolving credit facilities totaling $2.5 billion. Both the $0.5 billion and one
|
| | | | | | | | | | | | | | | |
Summary of Long-Term Credit Facilities At December 31, 2011 (in billions) |
| Maturity Date | Facility Limit | | Letters of Credit Outstanding | | Cash Borrowings | | Availability |
| January 2014 | $ | 0.5 |
| | $ | 0.5 |
| | $ | — |
| | $ | — |
|
| January 2014 | 1.0 |
| | — |
| | — |
| | 1.0 |
|
| May 2014 | 1.0 |
| | 0.3 |
| | — |
| | 0.7 |
|
| | $ | 2.5 |
| | $ | 0.8 |
| | $ | — |
| | $ | 1.7 |
|
The credit facilities also accommodate the issuance of letters of credit. The interest rate on any borrowing under these facilities is variable based on market factors and the
rating of TVA’sTVA's senior unsecured long-term non-credit enhanced debt. TVA is required to pay an unused facility fee on the portion of the total $2.5 billion which TVA has not borrowed or committed under letters of credit. This fee, along with letter of credit fees, may fluctuate depending on the rating of TVA’sTVA's senior unsecured long-term non-credit enhanced debt. At June 30,December 31, 2011, there were $224$756 million of letters of credit outstanding under the credit facilities, and there were no borrowings outstanding. TVA anticipates renewing each credit facility or replacing it with a different credit facility as it matures. See Note 1012 — Debt Securities ActivityOther Derivative Instruments — Collateral.
Lease Financing. On January 17, 2012, TVA entered into a $1.0 billion leasing transaction whereby it agreed to lease its John Sevier CCF to a special single purpose limited liability company for a term of fifty years. TVA received proceeds of approximately $970 million. On the same date, TVA agreed to lease the facility back from the special single purpose limited liability company for a term of thirty years. TVA intends to use the proceeds from the transaction for the benefit of its power program. See Note 17 — John Sevier Combined Cycle Transaction.
TVA may seek to enter into similar arrangements for other assets under construction, such as natural gas units, nuclear units, or pollution control equipment. While such leasing transactions allow TVA to diversify its asset financing program, financing an asset by using the proceeds of leasing transactions is typically more costly to TVA than financing an asset with the proceeds of Bonds.
Summary Cash Flows
A major source of TVA’sTVA's liquidity is operating cash flows resulting from the generationand sales of electricity. A summary of cash flow components for the ninethree months ended June 30,December 31, 2011, and 2010, follows:
Summary Cash Flows |
| For the nine months ended June 30 |
| | | 2011 | | | 2010 | |
| Cash provided by (used in): | | | | | | |
| Operating activities | | $ | 1,703 | | | $ | 1,210 | |
| Investing activities | | | (1,880 | ) | | | (1,773 | ) |
| Financing activities | | | 391 | | | | 560 | |
| | | | | | | | | |
| Net increase (decrease) in cash and cash equivalents | | $ | 214 | | | $ | (3 | ) |
|
| | | | | | | |
Summary Cash Flows |
| | For the three months ended
December 31 |
| | 2011 | | 2010 |
| Cash provided by (used in): | | | |
| Operating activities | $ | 257 |
| | $ | 528 |
|
| Investing activities | (822 | ) | | (747 | ) |
| Financing activities | 271 |
| | 133 |
|
| Net increase (decrease) in cash and cash equivalents | $ | (294 | ) | | $ | (86 | ) |
Operating ActivitiesActivities. . Net cash flows from operating activities increased $493decreased $271 million for the ninethree months ended June 30,December 31, 2011 compared to the same period in the prior year. This increase was primarily due to the timing of revenues related to fuel cost recovery, as well as a decrease in the cash spent on the Kingston ash spill environmental cleanup costs as compared to the same period in the prior year. See Results of Operations.
Investing Activities. Net cash flows used in investing activities increased $107 million for the nine months ended June 30, 2011, compared to the same period in the prior year. The change resulted from a $165 million increase resulted primarily from anin the funding of Financial Trading Program ("FTP") margin accounts, a $115 million increase related to the timing of $187 million in construction expenditures due to ongoing construction of Watts Bar Unit 2accounts payable and accrued liabilities payments and an increase in base capital spendingchange in inventory of $165 million due to improve asset performance and condition. This increase was partiallylower coal generation. These changes were offset by a decreasean $86 million increase in nuclear fuelsaccounts receivable collections.
The increase in margin funding is primarily due to TVA increasing its natural gas hedged positions due to the sharp decline of natural gas prices relative to coal prices. The notional amount of natural gas positions held at December 31, 2011 and 2010, was 322 million mmBtu and 161 million mmBtu, respectively.
Investing Activities. The majority of TVA's investing cash flows are related to investments in property, plant, and equipment for new generating assets, as well as additions and upgrades to existing facilities. The $40 million increase in construction expenditures of $98 million resulting from less purchases of uranium and enrichment services duringfor the current yearthree months ended December 31, 2011, as compared to the same period in the prior year.year, is due primarily to milestone payments made in the first quarter of 2012 for major projects completed shortly before or after the end of 2011, as well as an increase on spending for clean air projects and converting wet coal combustion residual (“CCR”) facilities
to dry collection facilities.
Nuclear fuel expenditures increased $48 million for the three months ended December 31, 2011, as compared to the same period in the prior year, due to the purchase of nuclear fuel to be used in the five scheduled nuclear refueling outages during CY 2012 as opposed to the two scheduled nuclear refueling outages during CY 2011. The increase was also due to higher prices for enrichment services in 2012.
Financing Activities. Net cash flows provided by financing activities decreased $169increased $138 million during the ninethree months ended June 30,December 31, 2011, as compared to the same period of the prior year, due to an increase in the issuance of short-term debt and a decrease in payments on leases. The issuance of debt exceeding redemptions was $284 million for the three months ended December 31, 2011, as compared to $187 million for the three months ended December 31, 2010. This increase is due to a decrease in the net working capital as a result of the lower sales of electricity for the three months ended December 31, 2011, as compared to the same period of the prior year.
The decrease was primarily due to net issuances of debt of $535 million during the nine months ended June 30, 2011, as compared to net issuances of debt of $662 million during the nine months ended June 30, 2010. This decrease wasincrease in cash flows provided by financing activities is also partially due to a $30$41 million increasedecrease in payments on leases and leaseback financing primarilyfor the three months ended December 31, 2011, as compared to the same period of the prior year due to the purchase of an office building previously under a capital lease.
Cash Requirements and Contractual Obligations
The estimated cash requirements and contractual obligations for TVA as of June 30,December 31, 2011, are detailed in the following table.
Commitments and Contingencies Payments due in the year ending September 30 | |
| | | 2011(1) | | 2012 | | 2013 | | 2014 | | 2015 | | Thereafter | | Total | |
| | | | | | | | | | | | | | | | |
Debt(2) | | $ | — | | $ | 1,523 | | $ | 2,308 | | $ | 32 | | $ | 1,032 | | $ | 19,266 | | $ | 24,161 | |
| Interest payments relating to debt | | | 268 | | | 1,371 | | | 1,227 | | | 1,142 | | | 1,141 | | | 20,296 | | | 25,445 | |
| Lease obligations | | | | | | | | | | | | | | | | | | | | | | |
| Capital | | | 3 | | | 6 | | | — | | | — | | | — | | | 3 | | | 12 | |
| Non-cancelable operating | | | 18 | | | 52 | | | 48 | | | 31 | | | 24 | | | 169 | | | 342 | |
| Purchase obligations | | | | | | | | | | | | | | | | | | | | | | |
| Power | | | 73 | | | 223 | | | 158 | | | 158 | | | 161 | | | 4,376 | | | 5,149 | |
| Fuel | | | 574 | | | 1,683 | | | 1,449 | | | 1,124 | | | 949 | | | 2,589 | | | 8,368 | |
| Other | | | 32 | | | 98 | | | 78 | | | 72 | | | 68 | | | 1,014 | | | 1,362 | |
| EPA settlement | | | 2 | | | 87 | | | 87 | | | 87 | | | 87 | | | — | | | 350 | |
| Other settlements | | | 1 | | | 3 | | | 3 | | | 3 | | | — | | | — | | | 10 | |
| Environmental cleanup costs-Kingston ash spill | | | 58 | | | 168 | | | 97 | | | 88 | | | — | | | — | | | 411 | |
| Payments on other financings | | | 27 | | | 136 | | | 488 | | | 100 | | | 104 | | | 713 | | | 1,568 | |
| Payments to U.S. Treasury | | | | | | | | | | | | | | | | | | | | | | |
Return of Power Program Appropriation Investment | | | 20 | | | 20 | | | 20 | | | 10 | | | — | | | — | | | 70 | |
Return on Power Program Appropriation Investment | | | 8 | | | 22 | | | 20 | | | 19 | | | 18 | | | 235 | | | 322 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Total | | $ | 1,084 | | $ | 5,392 | | $ | 5,983 | | $ | 2,866 | | $ | 3,584 | | $ | 48,661 | | $ | 67,570 | |
Notes (1) Period July 1 – September 30, 2011 | |
| (2) Does not include noncash items of foreign currency exchange loss of $35 million and net discount on sale of Bonds of $235 million. | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
Commitments and Contingencies Payments due in the year ending September 30 |
| | 2012(1) | | 2013 | | 2014 | | 2015 | | 2016 | | Thereafter | | Total |
Debt(2) | $ | 2,339 |
| | $ | 2,308 |
| | $ | 32 |
| | $ | 1,032 |
| | $ | 32 |
| | $ | 19,200 |
| | $ | 24,943 |
|
| Interest payments relating to debt | 971 |
| | 1,226 |
| | 1,140 |
| | 1,139 |
| | 1,094 |
| | 19,192 |
| | 24,762 |
|
| Lease obligations | |
| | |
| | |
| | |
| | |
| | |
| | |
|
| Capital | 4 |
| | — |
| | — |
| | — |
| | — |
| | 3 |
| | 7 |
|
| Non-cancelable operating | 50 |
| | 52 |
| | 33 |
| | 24 |
| | 24 |
| | 146 |
| | 329 |
|
| Purchase obligations | |
| | |
| | |
| | |
| | |
| | |
| | |
|
| Power | 161 |
| | 157 |
| | 159 |
| | 161 |
| | 168 |
| | 3,371 |
| | 4,177 |
|
| Fuel | 1,243 |
| | 1,544 |
| | 1,231 |
| | 1,180 |
| | 751 |
| | 1,951 |
| | 7,900 |
|
| Other | 107 |
| | 100 |
| | 91 |
| | 87 |
| | 86 |
| | 697 |
| | 1,168 |
|
| Environmental Agreements | 79 |
| | 87 |
| | 87 |
| | 87 |
| | — |
| | — |
| | 340 |
|
| Litigation settlements | 28 |
| | 3 |
| | 3 |
| | 1 |
| | — |
| | — |
| | 35 |
|
| Environmental cleanup costs-Kingston ash spill | 99 |
| | 147 |
| | 105 |
| | — |
| | — |
| | — |
| | 351 |
|
| Payments on other financings | 123 |
| | 488 |
| | 100 |
| | 104 |
| | 104 |
| | 609 |
| | 1,528 |
|
| Payments to U.S. Treasury | | | |
| | |
| | |
| | |
| | |
| | |
|
Return of Power Program Appropriation Investment | 20 |
| | 20 |
| | 10 |
| | — |
| | — |
| | — |
| | 50 |
|
Return on Power Program Appropriation Investment | 7 |
| | 20 |
| | 19 |
| | 18 |
| | 18 |
| | 217 |
| | 299 |
|
| Total | $ | 5,231 |
| | $ | 6,152 |
| | $ | 3,010 |
| | $ | 3,833 |
| | $ | 2,277 |
| | $ | 45,386 |
| | $ | 65,889 |
|
Notes (1) Period January 1 – September 30, 2012 (2) Does not include noncash items of foreign currency exchange loss of $4 million and net discount on sale of Bonds of $235 million. |
In addition to the cash requirements above, TVA has contractual obligations in the form of revenue discounts related to energy prepayments.
Energy Prepayment Obligations Payments due in the year ending September 30 | |
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | |
| | | 2011 (1) | | 2012 | | 2013 | | 2014 | | 2015 | | Thereafter | | Total | |
| | | | | | | | | | | | | | | | | | |
| Energy Prepayment Obligations | | $ | 26 | | | $ | 105 | | $ | 102 | | $ | 100 | | $ | 100 | | $ | 310 | | | $ | 743 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
Note | | | | | | | | | | | | | | | | | | | | | | | | |
| (1) Period July 1 - September 30, 2011 | | | | | | | | | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
Energy Prepayment Obligations Payments due in the year ending September 30 |
| | 2012(1) | | 2013 | | 2014 | | 2015 | | 2016 | | Thereafter | | Total |
| Energy Prepayment Obligations | $ | 79 |
| | $ | 102 |
| | $ | 100 |
| | $ | 100 |
| | $ | 100 |
| | $ | 210 |
| | $ | 691 |
|
Note (1) Period January 1 - September 30, 2012 |
Sales of Electricity
The following table compares TVA’s energy sales statistics for the three and nine months ended June 30,December 31, 2011, and 2010:2010:
Sales of Electricity (millions of kWh) | |
| | | For the three months ended June 30 | | | For the nine months ended June 30 | |
| | | 2011 | | | 2010 | | | Percent Change | | | 2011 | | | 2010 | | | Percent Change | |
| | | | | | | | | | | | | | | | | | | |
| Municipalities and cooperatives | | | 32,129 | | | | 33,004 | | | | (2.7 | %) | | | 98,822 | | | | 101,026 | | | | (2.2 | %) |
| Industries directly served | | | 6,240 | | | | 7,242 | | | | (13.8 | %) | | | 22,513 | | | | 24,267 | | | | (7.2 | %) |
| Federal agencies and other | | | 486 | | | | 505 | | | | (3.8 | %) | | | 1,549 | | | | 1,479 | | | | 4.7 | % |
| Total sales of electricity | | | 38,855 | | | | 40,751 | | | | (4.7 | %) | | | 122,884 | | | | 126,772 | | | | (3.1 | %) |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
Heating degree days(1) (normal 228 and 3,343, respectively) | | | 199 | | | | 123 | | | | 61.8 | % | | | 3,405 | | | | 3,694 | | | | (7.8 | %) |
| | | | | | | | | | | | | | | | | | | | | | | | | |
Cooling degree days(1) (normal 586 and 666, respectively) | | | 761 | | | | 826 | | | | (7.9 | %) | | | 831 | | | | 845 | | | | (1.7 | %) |
| | | | | | | | | | | | | | | | | | | | | | | | | |
Combined degree days(1) (normal 814 and 4,008, respectively) | | | 960 | | | | 949 | | | | 1.2 | % | | | 4,236 | | | | 4,539 | | | | (6.7 | %) |
| | | | | | | | | | | | | | | | | | | | | | | | | |
Note (1) The prior year degree day information has been adjusted in order to incorporate a change in TVA’s current calculation of this information. Every five years this calculation is updated in order to incorporate the most recent 30 years of weather history. The most recent update, to incorporate CYs 2006-2010, occurred during the second quarter of 2011. |
|
| | | | | | | | |
Sales of Electricity (millions of kWh) |
| | Three Months Ended December 31 |
| | 2011 | | 2010 | | Percent Change |
| Municipalities and cooperatives | 30,475 |
| | 32,479 |
| | (6.2 | )% |
| Industries directly served | 8,026 |
| | 8,105 |
| | (1.0 | )% |
| Federal agencies and other | 527 |
| | 535 |
| | (1.5 | )% |
| Total sales of electricity | 39,028 |
| | 41,119 |
| | (5.1 | )% |
Heating degree days (normal 1,302)(1) | 1,170 |
| | 1,417 |
| | (17.4 | )% |
Cooling degree days (normal 67)(1) | 46 |
| | 54 |
| | (14.8 | )% |
Combined degree days (normal 1,369)(1) | 1,216 |
| | 1,471 |
| | (17.3 | )% |
Note (1) The prior year degree day information has been adjusted in order to incorporate a change in TVA’s current calculation of this information. Every five years this calculation is updated in order to include the most recent 30 years of weather history. The most recent update, to incorporate CYs 2006-2010, occurred during the second quarter of 2011. |
Significant items contributing to the 1.9 billion kilowatt-hour (“kWh”) decrease in salesSales of electricity decreased 2.1 billion kilowatt-hours ("kWh") for the three months ended June 30,December 31, 2011, compared to the same period inthree months ended December 31, 2010 included:
The 875 million kWh, almost entirely due to a decrease in sales to Municipalitiesmunicipalities and cooperatives. Sales to municipalities and cooperatives decreased by 2.0 billion kWh for the was primarily weather driven. There was an increase in both heating and cooling degree days during Aprilthree months ended December 31, 2011 as compared to April 2010. However, cooler weather in May and June 2011 resulted in a net decrease in cooling degree days,, as compared to the same period in the prior year. In addition, the power outages caused by the storms of April 27, 2011, and April 28, 2011, contributed2010. This change was primarily related to the decrease in sales.
The 1.0 billion kWh decrease in sales to Industries directly served was primarily due to a decrease in sales to TVA’s largest directly served industrial customer, which has been curtailing operations.
The 19 million kWh decrease in sales to Federal agencies and other was primarily due to a decrease of 37 million kWh in sales to federal agencies directly served and was partially offset by an increase of 18 million kWh sold off-system. The decrease in sales to federal agencies was primarily due to a decline in sales to a large directly served federal agency customer.
Significant items contributing to the 3.9 billion kWh decrease in sales of electricitymilder weather for the ninethree months ended June 30,December 31, 2011 as compared to the abnormally cold weather for the same period in 2010 included:of the prior year.
The 2.2 billion kWh decrease in sales to Municipalities and cooperatives was primarily due to a decrease in both heating and cooling degree days. This was the result of a cooler than normal summer and a warmer than normal winter.
The 1.8 billion kWh decrease in sales to Industries directly served was primarily due to a decrease in sales to TVA’s largest directly served industrial customer, which has been curtailing operations.
The 70 million kWh increase in sales to Federal agencies and other was primarily due to an increase of 77 million kWh in off-system sales and was partially offset by a decrease of seven million kWh in sales to federal agencies directly served. The increase in off-system sales was primarily due to an increase in excess generation available for resale.
Financial Results
The following table compares operating results for the three and nine months ended June 30,December 31, 2011, and 2010:2010:
Summary Statements of Operations | |
| | | For the three months ended June 30 | | | For the nine months ended June 30 | |
| | | 2011 | | | 2010 | | | 2011 | | | 2010 | |
| | | | | | | | | | | | | |
| Operating revenues | | $ | 2,657 | | | $ | 2,587 | | | $ | 8,453 | | | $ | 7,558 | |
| Operating expenses | | | (2,575 | ) | | | (2,073 | ) | | | (7,534 | ) | | | (5,826 | ) |
| Operating income | | | 82 | | | | 514 | | | | 919 | | | | 1,732 | |
| Other income, net | | | 4 | | | | 6 | | | | 25 | | | | 20 | |
| Interest expense, net | | | (326 | ) | | | (321 | ) | | | (979 | ) | | | (973 | ) |
| | | | | | | | | | | | | | | | | |
| Net income (loss) | | $ | (240 | ) | | $ | 199 | | | $ | (35 | ) | | $ | 779 | |
| | | | | | | | | | | | | | | | | |
|
| | | | | | | |
Summary Statements of Operations |
| | Three Months Ended December 31 |
| | 2011 | | 2010 |
| Operating revenues | $ | 2,568 |
| | $ | 2,828 |
|
| Operating expenses | (2,431 | ) | | (2,558 | ) |
| Operating income | 137 |
| | 270 |
|
| Other income, net | 9 |
| | 11 |
|
| Interest expense, net | (319 | ) | | (329 | ) |
| Net income (loss) | $ | (173 | ) | | $ | (48 | ) |
Operating Revenues. Operating revenues for the three and nine months ended June 30,December 31, 2011, and 2010, consisted of the following:
|
| | | | | | | | | | |
Operating Revenues |
| | Three Months Ended December 31 |
| | 2011 | | 2010 | | Percent Change |
| Sales of electricity | | | | | |
| Municipalities and cooperatives | $ | 2,144 |
| | $ | 2,386 |
| | (10.1 | )% |
| Industries directly served | 367 |
| | 382 |
| | (3.9 | )% |
| Federal agencies and other | 29 |
| | 32 |
| | (9.4 | )% |
| Total sales of electricity | 2,540 |
| | 2,800 |
| | (9.3 | )% |
| Other revenue | 28 |
| | 28 |
| | — | % |
| Total operating revenues | $ | 2,568 |
| | $ | 2,828 |
| | (9.2 | )% |
Operating revenues decreased $260 million in the three months ended December 31, 2011, compared to the three months ended December 31, 2010, due to the following:
|
| | | |
| | Three Month Change |
| Fuel cost recovery | $ | (102 | ) |
| Base volume | (100 | ) |
| Base rates | (58 | ) |
| Total | $ | (260 | ) |
Operating revenues decreased $260 million for the three months ended December 31, 2011, compared to the three months ended December 31, 2010, primarily due to a $102 million decrease in fuel cost recovery and a $100 million decrease in base volume. Of the $102 million decrease in fuel cost recovery, $53 million was due to lower sales volume and $49 million was due to lower fuel cost. See Operating Expenses for further discussion of the change in fuel expense. The $100 million decrease in base volume was driven primarily by a $97 million decrease in revenues from municipalities and cooperatives primarily as a result of milder weather conditions during the three months ended December 31, 2011 as compared to the same period in 2010. There was a 17 percent decrease in heating degree days and a 15 percent decrease in cooling degree days during the three months ended December 31, 2011, as compared to the three months ended December 31, 2010.
The decrease in base rates also resulted in a $58 million decrease in operating revenues for the three months ended December 31, 2011, compared to the three months ended December 31, 2010. This overall decrease in base rates was primarily due to a change in the wholesale rate structure of municipalities and cooperatives, which was implemented in April 2011, and was slightly offset by a two percent rate increase that went into effect in October 2011. See Changes in Ratemaking Impacting Accounting for further discussion of the increase in base rates. The purpose of the new wholesale rate design was to better align rates with costs. TVA's costs tend to be higher in the summer than in the spring and fall and as such TVA designed wholesale rates to better reflect those cost relationships. TVA expected the new wholesale structure would produce lower base revenue in the spring and fall due to the new seasonal and time of use wholesale rates. Similarly, TVA anticipated the new wholesale structure would produce higher base revenue in summer. Seasonal differences in the weather impact TVA's base revenue under both wholesale structures. Under the new wholesale structure, weather can positively and negatively impact both volume and average rates while under the former wholesale structure only volume was impacted. The milder weather in the first quarter of 2012, relative to the abnormally colder weather in the first quarter of 2011, produced lower maximum load requirements which have led to lower base revenue for the first quarter of 2012 relative to the first quarter of 2011.
Operating Expenses. Operating expenses for the three months ended December 31, 2011, and 2010, consisted of the following:
Operating Revenues | |
| | | For the three months ended June 30 | | | For the nine months ended June 30 | |
| | | 2011 | | | 2010 | | | Percent Change | | | 2011 | | | 2010 | | | Percent Change | |
| | | | | | | | | | | | | | | | | | | |
| Sales of electricity | | | | | | | | | | | | | | | | | | |
| Municipalities and cooperatives | | $ | 2,287 | | | $ | 2,204 | | | | 3.8 | % | | $ | 7,190 | | | $ | 6,367 | | | | 12.9 | % |
| Industries directly served | | | 310 | | | | 324 | | | | (4.3 | %) | | | 1,077 | | | | 1,019 | | | | 5.7 | % |
| Federal agencies and other | | | 31 | | | | 31 | | | | 0.0 | % | | | 95 | | | | 83 | | | | 14.5 | % |
| Other revenue | | | 29 | | | | 28 | | | | 3.6 | % | | | 91 | | | | 89 | | | | 2.2 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Total operating revenues | | $ | 2,657 | | | $ | 2,587 | | | | 2.7 | % | | $ | 8,453 | | | $ | 7,558 | | | | 11.8 | % |
|
| | | | | | | | | | |
Operating Expenses |
| | Three Months Ended December 31 |
| | 2011 | | 2010 | | Percent Change |
| Fuel | $ | 640 |
| | $ | 738 |
| | (13.3 | )% |
| Purchased power | 319 |
| | 360 |
| | (11.4 | )% |
| Operating and maintenance | 880 |
| | 883 |
| | (0.3 | )% |
| Depreciation and amortization | 441 |
| | 432 |
| | 2.1 | % |
| Tax equivalents | 151 |
| | 145 |
| | 4.1 | % |
| Total operating expenses | $ | 2,431 |
| | $ | 2,558 |
| | (5.0 | )% |
Operating revenues increased $70expenses decreased $127 million and $895 million in the three and nine months ended June 30,December 31, 2011, compared to the three and nine months ended June 30, 2010, due to the following:
| | | Three Month Change | | | Nine Month Change | |
| | | | | | | |
| Fuel rate | | $ | 224 | | | $ | 1,219 | |
| Volume | | | (105 | ) | | | (213 | ) |
| Base rates | | | (50 | ) | | | (117 | ) |
| Off system sales and other | | | — | | | | 4 | |
| Other revenue | | | 1 | | | | 2 | |
| Total | | $ | 70 | | | $ | 895 | |
| | | | | | | | | |
Note Components of operating revenue related to rates during the first six months of 2011 have been adjusted in order to incorporate the change in TVA’s rate structure implemented in April 2011. See Rate Change for a discussion of the new wholesale rate structure. |
The increase of fuel rates for the three and nine months ended June 30, 2011, compared to the three and nine months ended June 30, 2010, was primarily due to overcollection of the FCA in 2009 since the amount overcollected in that year was refunded to customers in 2010 through FCA rate reductions.
December 31, 2010. Significant itemsdrivers contributing to the $70decrease in total operating expenses are described below.
Fuel expense decreased $98 million increase in operating revenues for the three months ended June 30,December 31, 2011, as compared to the same period of the prior year. A five percent decrease in 2010 included:
An $83sales and overall favorable fuel rates, as a result of the change in the mix of generation sources, account for $77 million increaseof the decrease. Coal-fired generation decreased 29 percent while nuclear generation increased 18 percent. There were two nuclear units in revenue from refueling outages during Municipalitiesthree months ended December 31, 2010, while there were no units in refueling outages during the three months ended December 31, 2011. Additionally, hydroelectric generation, TVA's least expensive type of generation, helped to offset the reduction in coal-fired generation. Hydroelectric generation, comprised of conventional hydroelectric and cooperativespumped storage, was 31 percent higher in the three months ended December 31, 2011, as compared to the same period of the prior year, primarily due to fuel rate increases which increased revenues by $203 million. Thisa 41 percent increase was partially offset byin rainfall, a decrease120 percent increase in base rates which decreased revenues by $61 millionrunoff within the Tennessee River Basin in the three months ended December 31, 2011, as compared to the same period of the prior year, and a decrease in sales volume which decreased revenues by $59 million.
A $14the need to release water to maintain flood storage levels. The remaining $21 million decrease in revenue from Industries directly served primarilyfuel cost in the three months ended December 31, 2011, as compared to the same period of the prior year was driven by the timing of the fuel cost adjustment mechanism. The fuel cost adjustment provides a means to regularly alter rates to reflect changing fuel and purchased power costs, including realized gains and losses relating to transactions under TVA's FTP. There is typically a lag between the occurrence of a change in fuel and purchased power costs and the reflection of the change in rates due to a portion of the fuel rate being based on forecasted information. A “true-up” between actual and forecasted costs is performed on a monthly basis, and the difference is recorded as a regulatory liability or asset. These amounts represent overcollected revenues (regulatory liabilities) or undercollected revenues (regulatory assets), which are subsequently used to offset fuel and purchased power costs and are recovered or refunded in fuel rates on an ongoing basis.
Purchased power expense decreased $41 million during the the three months ended December 31, 2011, as compared to the same period of the prior year. Purchased power expense decreased $49 million as a result of the decreased sales volume decreases which decreased revenues by $45 million.discussed above. This decrease was partially offset by the fuel rate and base rate increases whichcost adjustment of $8 million. Purchased power volume decreased 22 percent compared with same period of the prior year. This change in volume decreased purchased power expense by $73 million. In addition, the average price of purchased power increased revenues by $18 million and $13 million, respectively.
Federal agencies and other revenue remained relatively flat foreight percent in the period. This was primarily due to fuel rate increases which increased revenues by $3 million. The increase was offset by base rate and sales volume decreases of approximately $2 million.
Significant items contributing to the $895 million increase in operating revenues for the ninethree months ended June 30,December 31, 2011, as compared to the same period in 2010 included:
An $823 million increase in revenue from Municipalities and cooperatives primarily due to fuel rate increases which increased revenues by $1.1 billion. This increase was partially offset by a decrease in base rates which decreased revenues by $109 million and a decrease in sales volume which decreased revenues by $139 million.
A $58 million increase in revenue from Industries directly served primarily due to fuel rate increases which increased revenues by $134 million. This increase was partially offset by sales volume and base rate decreases which decreased revenues by $73 million and $3 million, respectively.
A $12 million increase in revenue from Federal agencies and other was primarily due to fuel rate increases which increased revenues by $14 million and increases in off-system sales which increased revenue by $4 million. These increases were partially offset by base rate decreases of $6 million.
Operating Expenses. Operating expenses for the three and nine months ended June 30, 2011 and 2010, consisted of the following:
Operating Expenses | |
| | | For the three months ended June 30 | | | For the nine months ended June 30 | |
| | | 2011 | | | 2010 | | | Percent Change | | | 2011 | | | 2010 | | | Percent Change | |
| | | | | | | | | | | | | | | | | | | |
| Fuel | | $ | 584 | | | $ | 509 | | | | 14.7 | % | | $ | 2,071 | | | $ | 1,343 | | | | 54.2 | % |
| Purchased power | | | 387 | | | | 277 | | | | 39.7 | % | | | 1,026 | | | | 656 | | | | 56.4 | % |
| Operating and maintenance | | | 994 | | | | 757 | | | | 31.3 | % | | | 2,677 | | | | 2,267 | | | | 18.1 | % |
| Depreciation and amortization | | | 436 | | | | 416 | | | | 4.8 | % | | | 1,296 | | | | 1,240 | | | | 4.5 | % |
| Tax equivalents | | | 174 | | | | 114 | | | | 52.6 | % | | | 464 | | | | 320 | | | | 45.0 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Total operating expenses | | $ | 2,575 | | | $ | 2,073 | | | | 24.2 | % | | $ | 7,534 | | | $ | 5,826 | | | | 29.3 | % |
Operating expenses increased $502 million for the three months ended June 30, 2011, and $1.7 billion for the nine months ended June 30, 2011, compared to the same periods in 2010.
For the three months ended June 30, 2011, significant drivers contributing to the $502 million increase compared to the same period in 2010 are described below:
Fuel expense increased $75 million due to:
A $120 million increase in fuel expense resulting primarily from a 30 percent increase in the average fuel cost per kWh of net thermal generation, which increased fuel expense by $91 million and from an increase of $25 million in fuel-related expense that does not qualify for inclusion in the fuel rate. Additionally, net thermal generation decreased 12 percent during the quarter primarily due to a decrease in nuclear generation. The decrease in nuclear generation was due to the April 27, 2011, and April 28, 2011, storms which caused Browns Ferry to go offline for nearly a month. The decrease in nuclear generation was replaced with higher cost gas and coal-fired generation which resulted in a $4 million increase in expense.
A $45 million decrease in fuel expense related to the fuel cost mechanism which matches the recognition of fuel expense with the period it is collected in revenue.
Purchased Power expense increased $110 million due to:
A $62 million increase in purchased power expense related to the fuel cost mechanism which matches the recognition of purchased power expense with the period it is collected in revenue.
A $48 million increase in purchased power expense primarily because of an increase in purchased power volume of 675 million kWh, or 10 percent,prior year, which increased purchased power expense by $32$23 million.
Operating and maintenance expense decreased $3 million in the three months ended December 31, 2011, as compared to the same period of the prior year. The timing of nuclear refueling outages resulted in a decrease of $60 million due to two nuclear refueling outages in the three months ended December 31, 2010 compared to no nuclear refueling outages during the three months ended December 31, 2011. Rent expense was $17 million lower during the three months ended December 31, 2011, as compared to the same period of the prior year, due to the purchase of the Chattanooga Office Complex in Chattanooga, Tennessee in January 2011. These decreases were partially offset by a $35 million increase in purchased power volume was due to Browns Ferry being offlinepension and post-retirement benefits as a result of the storms on April 27, 2011, and April 28, 2011. Additionally, an increaseuse of a lower assumed discount rate in the average priceactuarial calculation of purchased power of four percent increased purchased power expensepost-retirement liabilities. The decreases were also offset by $16 million.
Operating and maintenance expense increased $237 million. The primary driver for the increase was a $134$32 million increase in operating and maintenance expense related to increased operations at nuclear plants due tothe Lagoon Creek Combined Cycle Plant and the Magnolia Combined Cycle Plant, the timing and duration of refuelingfossil-fuel unit maintenance outages, maintenance projects to increase plant reliability, and increased security costs due to regulatory requirements. Additional items contributing to the increase in Operating and maintenance expense included a $25 million increase in pension and postretirement benefit expense, a $21 million increase at coal-fired and combustion turbine plants due to an increase in base maintenance costs to address material condition and regulatory requirements and increased costs associated with the Lagoon Creek Combined Cycle Facility (“Lagoon Creek”), which began commercial operations in September 2010, a $16 million increase due to capital project write-offs, a $13 million increase in other employee benefits, a $10 million increase due to the Environmental Agreements, and a $9 million increase in costs to support energy efficiency and demand response initiatives.litigation-related expenditures.
Depreciation and amortization expense increased $20$9 million in the three months ended December 31, 2011, as compared to the same period of the prior year primarily because ofdue to an increase in net plant additions and the accelerationimplementation of accelerated depreciation rates on certain coal-fired units due to the decisionidling of those units. The $46 million increase in depreciation expense was partially offset by a $37 million decrease in amortization expense due to idle those units.the treatment of certain regulatory assets as a result of the approval of Bellefonte Unit 1 in August 2011.
Tax equivalents expense increased $60 million.$6 million in the three months ended December 31, 2011, as compared to the same period of the prior year. This increasechange primarily reflects an increase in the accrued tax equivalent expense related to the FCA.expense. The accrued tax equivalent expense, which is equal to five percent of the FCAfuel-cost related revenues, and increased for the three months ended June 30, 2011, since the FCA revenues were higher than in the three months ended June 30, 2010.December 31, 2011, due to the new wholesale rate structure implemented on April 1, 2011, whereby the fuel rate was separated out from the base rate. Due to regulatory accounting, tax equivalents related to fuel-cost related revenues are recognized in the same period the revenues are recognized. Tax equivalents related to all other revenues are recognized in the year paid.
For the nine months ended June 30, 2011, significant drivers contributing to the $1.7 billion increase in operating expenses, compared to the same period in 2010, are described below:
Fuel expense increased $728 million due to:
A $503 million increase in fuel expense related to the fuel cost mechanism which matches the recognition of fuel expense with the period it is collected in revenue.
A $225 million increase in fuel expense resulting primarily from a 14 percent increase in the average fuel cost per kWh of net thermal generation, which increased fuel expense by $141 million and from an increase of $25 million in fuel-related expense that does not qualify for inclusion in the fuel rate. Additionally, net thermal generation decreased three percent primarily due to a decrease in nuclear generation. The decrease in nuclear generation was due to the April 27, 2011, and April 28, 2011, storms which caused Browns Ferry to go offline for nearly a month. The decrease in nuclear generation was replaced with higher cost gas and coal-fired generation which resulted in a $59 million increase in expense.
Purchased power expense increased $370 million due to:
A $301 million increase in purchased power expense related to the fuel cost mechanism which matches the recognition of purchased power expense with the period it is collected in revenue.
A $69 million increase in purchased power expense primarily because of an increase in purchased power volume of 1.0 billion kWh, or five percent, which increased purchased power expense by $50 million. The increase in purchased power volume was largely due to Browns Ferry being offline for nearly a month as a result of the storms on April 27, 2011, and April 28, 2011. Additionally, the average price of purchased power increased two percent, which increased purchased power expense by $19 million.
Operating and maintenance expense increased $410 million. The primary driver for the increase was a $172 million increase in operating and maintenance expense at nuclear plants due to the timing and duration of refueling outages, maintenance projects to increase plant reliability, and increased security costs due to regulatory requirements. Additional items contributing to the increase in Operating and maintenance expense included a $76 million increase in pension and postretirement benefit expense, a $34 million increase at coal-fired and combustion turbine plants due to an increase in base maintenance costs to address material condition and regulatory requirements and increased costs associated with Lagoon Creek which began commercial operations in September 2010, a $24 million increase related to ash remediation activities as TVA is in the process of converting from wet storage to dry storage facilities, a $22 million increase to support economic development initiatives, a $22 million increase in costs to support energy efficiency and demand response initiatives, a $16 million increase due to capital project write-offs, a $12 million increase in costs for reagents used in coal-fired emission controls, a $10 million increase in other employee benefits, and a $10 million increase due to the Environmental Agreements.
Depreciation and amortization expense increased $56 million primarily because of an increase in net plant additions and acceleration of depreciation on certain coal-fired units due to the decision to idle those units.
Tax equivalents expense increased $144 million. This increase primarily reflects an increase in the accrued tax equivalent expense related to the FCA. The accrued tax equivalent expense is equal to five percent of the FCA revenues and increased for the nine months ended June 30, 2011, since the FCA revenues were higher than in the nine-month
period ended June 30, 2010.
Interest Expense. Interest expense and interest rates for the three and nine months ended June 30,December 31, 2011, and 2010, were as follows:
Interest Expense | |
| | | For the three months ended June 30 | | | For the nine months ended June 30 | |
| | | 2011 | | | 2010 | | | Percent Change | | | 2011 | | | 2010 | | | Percent Change | |
| | | | | | | | | | | | | | | | | | | |
| Interest expense | | $ | 358 | | | $ | 343 | | | | 4.4 | % | | $ | 1,072 | | | $ | 1,026 | | | | 4.5 | % |
| Allowance for funds used during construction and nuclear fuel expenditures | | | (32 | ) | | | (22 | ) | | | 45.5 | % | | | (93 | ) | | | (53 | ) | | | 75.5 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Net interest expense | | $ | 326 | | | $ | 321 | | | | 1.6 | % | | $ | 979 | | | $ | 973 | | | | 0.6 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | 2011 | | | | 2010 | | | | | | | 2011 | | | | 2010 | | | | |
| Interest rates (average) | | | | | | | | | | | | | | | | | | | | | | | | |
Long-term(1) | | | 5.76 | | | | 5.92 | | | | (2.7 | %) | | | 5.81 | | | | 5.90 | | | | (1.5 | %) |
| Discount notes | | | 0.01 | | | | 0.12 | | | | (91.7 | %) | | | 0.09 | | | | 0.07 | | | | 28.6 | % |
Blended(1) | | | 5.72 | | | | 5.67 | | | | 0.9 | % | | | 5.75 | | | | 5.66 | | | | 1.6 | % |
Note (1) The average interest rates on long-term debt for the three and nine months ended June 30, 2011, reflected in the table above are calculated using an average of long-term debt balances at the end of each month in the period presented, and interest expense for those periods. Interest expense is interest on long-term debt, including amortization of debt discounts, issue, and reacquisition costs, net. Average long-term interest rates reported for the three and nine months ended June 30, 2010, were calculated using the average balance of debt based at the beginning and end of the period. The calculation was changed so that the average rate reflects fluctuations in the balance of long-term debt throughout the periods and the impact on interest expense. |
|
| | | | | | | | | | |
| Interest Expense |
| | Three Months Ended December 31 |
| | 2011 | | 2010 | | Percent Change |
| Interest expense | $ | 358 |
| | $ | 358 |
| | — | % |
| Allowance for funds used during construction and nuclear fuel expenditures | (39 | ) | | (29 | ) | | 34.5 | % |
| Net interest expense | $ | 319 |
| | $ | 329 |
| | (3.0 | )% |
| | | | | | |
| | 2011 | | 2010 | | Percent Change |
| Interest rates (average) | |
| | |
| | |
|
Long-term(1) | 5.75 |
| | 5.87 |
| | (2.0 | )% |
| Discount notes | — |
| | 0.08 |
| | (100.0 | )% |
Blended(1) | 5.65 |
| | 5.86 |
| | (3.6 | )% |
Note (1) The average interest rates on long-term debt reflected in the table above are calculated using an average of long-term debt balances at the end of each month in the fiscal years depicted and interest expense for those periods. Interest expense is interest on long-term debt, including amortization of debt discounts, issue, and reacquisition costs, net. |
The $5$10 million increase decrease in net interest expense for the three months ended June 30, 2011, was primarily attributablerelated to an increase in interest on debt as a result of an increase in the average balance of long-term debt for the three months ended June 30, 2011, compared to the three months ended June 30, 2010. This increase was partially offset by a greater amountamounts of capitalized interest due to an increase in the construction work in progress base used to calculate allowance for funds used during construction (“AFUDC”("AFUDC") as a result of ongoing construction activities at Watts Bar Unit 2.
The $6 million increase in net interest expense for the nine months ended June 30, 2011, was primarily attributable to an increase in interest on debt as a result of an increase in the average balance of long-term debt for the nine months ended June 30, 2011, compared to the nine months ended June 30, 2010. This increase was partially offset by a greater amount of capitalized interest due to an increase in the construction work in progress base used to calculate AFUDC as a result of ongoing construction activities at Watts Bar Unit 2.
The preparation of financial statements requires TVA to estimate the effects of various matters that are inherently uncertain as of the date of the financial statements. Although the financial statements are prepared in conformity with accounting principles generally accepted in the United States of America, (“GAAP”), TVA is required to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities, and the amounts of revenues and expenses reported during the reporting period. Each of these estimates varies in regard to the level of judgment involved and its potential impact on TVA’sTVA's financial results. Estimates are deemed critical either when a different estimate could have reasonably been used, or where changes in the estimate are reasonably likely to occur from period to period, and such use or change would materially impact TVA’sTVA's financial condition, results of operations, or cash flows. TVA’sTVA's critical accounting policies are discussed in Item 7, Management’sManagement's Discussion and Analysis of Financial Condition and Results of Operations — Critical Accounting Policies and Estimates and Note 1 of the Notes to the Financial Statements in the Annual Report.
On April 1, 2011, TVA implemented new pricing structures for wholesale service toFor distributor customers, and TVA’s retail service to directly served customers. Wholesale service to distributor customersthe default rate structure is on a time-of-use rate structuretime of use ("TOU") with an option forto elect a seasonal demand and energy structure. The TVA rate throughstructures provide that all distributor customers are to be on a TOU wholesale structure by no later than October 2012. By October 2012, TVA is proposing to have all distributor customers on a wholesale time-of-use rate structure. However,2012; however, TVA will continue to have discussions with distributors on other alternative wholesalerate structures.
The TVA Board of Directors approved a rate adjustment at its August 18, 2011 meeting that went into effect in October 2011. The rate adjustment resulted in an increase in wholesale base rates of two percent.
TVA faces several challenges in implementing TOU rates. Although metering is in place today to facilitate implementation at the wholesale level, additional metering and infrastructure will be needed to pass through the TOU pricing signals at the retail level. TVA is working with distributors to explore how additional metering and infrastructure resources can best be acquired in a cost-effective manner. There will also be additional administration costs associated with implementing the
rate structures. TVA is offering a default time-of-use rate structure with the option of a seasonal demandTOU rates. Billing, metering, communication, and energy rate structuredata management systems will have to directly served customersbe modified (and in some cases acquired) to read, communicate, and distributor-served
customers with contract demands in excess of five MW. The new rate structures are designed to provide pricing signals intended to incentivize wholesale (distributor) and retail customers to shift energy usage from higher cost periods to less expensive periods. These new rates are also intended to provide TVA with the same overall revenue as was generated prior to the rate restructuring; however, individual distributors and retail customers may see some effects on their bills depending on their usage characteristics (demand and energy usage on-peak versus off-peak).
ultimately generate customer bills.
For a discussion of TVA’s new accounting standards and interpretations, see Note 2,, which discussion is incorporated into this Item 2, Management’s Discussion and Analysis of Financial Condition and Results of Operations.
Corporate Governance
Corporate GovernanceOn December 21, 2011, William R. McCollum, Jr., TVA's Chief Operating Officer, announced that he would be retiring, effective June 30, 2012.
On April 14, 2011, the TVA Board selectedThe service of Dennis C. Bottorff, to continue to serve as Chairman of the TVA Board after his term in office expired on May 18, 2011. The terms of Robert M. Duncan, and Thomas C. Gilliland alsoas members of TVA's Board of Directors ended January 3, 2012, with the adjournment of the first session of the 112th Congress. Their terms of office, which began in 2006 for Mr. Bottorff and Mr. Duncan and 2008 for Mr. Gilliland, expired on May 18, 2011. Even though the terms of Chairman Bottorff and Directors Duncan and Gilliland have expired, they mayThe TVA Act permitted them to continue to serve on the TVA Boardas directors until the end of the currentthen-current session of Congress or until a successor takes office. On April 14, 2011, the TVA Board also selected William B. Sansom to serve as Vice Chairman.
On July 13, 2011, Richard Howorth was sworn in as a member of the TVA Board. Mr. Howorth, age 60, is a resident of Oxford, Mississippi. He is the owner of Square Books, an Oxford independent bookstore he founded in 1979. Mr. Howorth served two terms as the mayor of Oxford, from 2001 to 2009, during which time he was chairman of the authority overseeing the Oxford Electric Department. From 2001 to 2009, he also served as a director and officer of the North Mississippi Industrial Development Association, an economic development consortium. Mr. Howorth’s term will expire in 2015.Congress.
On August 3, 2011, Ashok Bhatnagar, TVA’s Senior Vice President of Nuclear Generation Development and Construction (“NGDC”), informed senior management that he would retire. His retirement is effective October 1, 2011. Mike Skaggs, currently Site Vice President at TVA’s Sequoyah Nuclear Plant, will replace Mr. Bhatnagar as Senior Vice President of NGDC.
Environmental Matters
laws and regulations.
