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TVC > SEC Filings for TVC > Form 10-K on 16-Nov-2012All Recent SEC Filings

Show all filings for TENNESSEE VALLEY AUTHORITY

Form 10-K for TENNESSEE VALLEY AUTHORITY


16-Nov-2012

Annual Report


ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
(Dollars in millions except where noted)

The following Management's Discussion and Analysis of Financial Condition and Results of Operations ("MD&A") is intended to help the reader understand the Tennessee Valley Authority ("TVA"), its operations and its present business environment. MD&A is provided as a supplement to - and should be read in conjunction with - TVA's consolidated financial statements and the accompanying notes thereto contained in Item 8, Financial Statements and Supplementary Data of this report. This MD&A includes the following sections:

• TVA's Business and Vision - a general description of its business, its objective, its strategic priorities, and its core capabilities;

• Executive Overview - a general overview of activities and effects on operations for 2012;

• Results of Operations - an analysis of TVA's consolidated results of operations for the three years presented in its consolidated financial statements;

• Liquidity and Capital Resources - an analysis of cash flows; off-balance sheet arrangements and aggregate contractual obligations; and overview of financial position;

• Key Initiatives and Challenges - a discussion of current and future challenges facing TVA;

• Critical Accounting Policies and Estimates - a discussion of accounting policies that require critical judgments and estimates; and

• Other Matters - a discussion of governance and certain risks facing TVA.

TVA's Business and Vision

Business

TVA operates the nation's largest public power system. At September 30, 2012, TVA provided electricity to approximately 50 large industrial customers, six federal agency customers, and 155 distributor customers that serve over nine million people in parts of seven southeastern states. TVA generates virtually all of its revenues from the sale of electricity, and in 2012 revenues from the sale of electricity totaled $11.1 billion. As a wholly-owned agency and instrumentality of the United States, however, TVA differs from other electric utilities in a number of ways:

1. TVA is a government corporation.

2. The area in which TVA sells power is limited by the Tennessee Valley Authority Act of 1933, as amended, 16 U.S.C. §§ 831-831ee (as amended, the "TVA Act") under a provision known as the "fence"; however, another provision of federal law known as the "anti-cherrypicking" provision generally protects TVA from being forced to provide access to its transmission lines to others for the purpose of delivering power to customers within substantially all of TVA's defined service area.

3. The rates TVA charges for power are set solely by the TVA Board of Directors (the "TVA Board") and are not set or reviewed by another entity, such as a public utility commission. In setting rates, however, the TVA Board is charged by the TVA Act to have due regard for the primary objectives of the TVA Act, including the objective that power be sold at rates as low as feasible.

4. TVA is not authorized to raise capital by issuing equity securities. TVA relies primarily on cash from operations and proceeds from power program borrowings to fund its operations and is authorized by the TVA Act to issue bonds, notes, or other evidences of indebtedness ("Bonds") in an amount not to exceed $30.0 billion outstanding at any given time. Although TVA's operations were originally funded primarily with appropriations from Congress, TVA has not received any appropriations from Congress for any activities since 1999 and, as directed by Congress, has funded essential stewardship activities primarily with power revenues.

TVA's Renewed Vision

While TVA's mission has not changed since it was established in 1933, the environment in which TVA does business continues to evolve. Facing challenging economic conditions, tougher new environmental standards, an aging generating fleet, and changing customer needs, TVA has recognized a need to refine its strategic vision for the future.


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TVA's renewed vision is to be one of the nation's leading providers of low-cost and cleaner energy by 2020. More specifically, TVA intends to be:

•The nation's leader in improving air quality;

•The nation's leader in increased nuclear production; and

•The Southeast's leader in increased energy efficiency.

The three priorities of TVA's renewed vision define a path forward for TVA's energy future in which every TVA initiative and the functions of every TVA employee will be linked to at least one of six focus areas:

• Low rates

• High reliability

• Responsibility

• Cleaner air

• Greater energy efficiency

• More nuclear generation

In 2011, the TVA Board accepted the Integrated Resource Plan ("IRP"), which recommends a strategic direction focusing on a diverse mix of electricity generation sources, including nuclear power, renewable energy, and natural gas, as well as traditional coal and hydroelectric power. TVA is increasing its low or no emission generation. TVA considers fuel mix in making decisions about generation, and is expected to rely on nuclear, natural gas-fired capacity, and energy efficiency as the primary means to meet future electricity needs.

In support of its renewed vision of more generation with low or no emissions, TVA has invested $5.4 billion since 1977 to reduce emissions of sulfur dioxide and nitrogen oxide at its coal-fired plants. These emissions have been reduced approximately 90 percent from their peak levels. During 2012, TVA completed construction of the John Sevier Combined-Cycle Facility ("John Sevier CCF"), a natural-gas fired plant located in northeastern Tennessee. John Sevier CCF began commercial operations on April 30, 2012. See Item 1, Business - Current Power Supply.

Linking the Vision to Performance

During 2012, TVA set measures and evaluated its operational performance by focusing on three key indicators. The first measure was the variance of net cash flow to plan. Net cash flow is defined as cash flow from operations plus net cash flow used in investing activities less net cash flow from change in the fuel cost adjustment deferral account. The other two measures were nuclear equivalent availability factor and fossil seasonal equivalent forced outage rate, which measure the availability of TVA's generation units within the nuclear and fossil-fueled fleets. The 2012 results compared with targets for these key indicators are reflected in the following chart.

Corporate Measure                               Target     Stretch       Actual
Net cash flow compared to plan                $0 Million $200 Million $1.1 Billion
Nuclear equivalent availability factor          90.1%       92.2%        93.0%
Fossil seasonal equivalent forced outage rate    6.8%        5.1%         2.9%

TVA exceeded its target for net cash flow by $899 million primarily due to lower than expected expenditures resulting from savings initiatives discussed in the Executive Overview section below.

TVA also exceeded its operating goals for nuclear equivalent availability factor and fossil seasonal equivalent forced outage rate. While nuclear outages ran seven days higher than planned, nuclear operations experienced fewer forced outage days and was able to increase output by over 10 percent versus 2011 generation. The fossil seasonal forced outage rate, which measures generating assets availability for the fossil fuel-fired generation units, was at a historical low in 2012, Assets were available when needed and took outages in periods where TVA could purchase in the market at lower prices.

Net cash flow is not a measure of financial performance under accounting principles generally accepted in the United States of America ("GAAP"). Accordingly, it should not be considered as a substitute for cash flow data prepared in accordance


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with GAAP. However, TVA uses net cash flow as an indicator of TVA's ability to meet its debt service obligations and the availability of funds for capacity expansion and other business requirements.

The following reconciles the net cash flow to net cash provided by operating activities.

                          Non-GAAP Reconciliation
                   For the year ended September 30, 2012

Net cash flow provided by operating activities                     $ 2,574
Plus: Net cash flow used in investing activities                    (2,513 )
Less: Net cash flow from change in fuel cost adjustment deferral       (61 )
Planned cash flow                                                  $  (977 )
Net cash flow                                                      $ 1,099

Executive Overview

Weather was the primary driver affecting TVA's results of operations for the year ended September 30, 2012, as compared with the same period of 2011. TVA had net income for the year ended September 30, 2012 of $60 million as compared with net income of $162 million for the same period of 2011.

The southeastern United States experienced one of the warmest winters on record in 2012, which contributed to a six percent decrease in sales of electricity for the first two quarters of 2012 as compared with the same period of the prior year. Although sales of electricity increased during the last two quarters of 2012, as compared with the same period of 2011, the increase was not large enough to fully offset the impact of lower sales and revenue in the first two quarters of 2012. TVA anticipates continuing slow growth for 2013 due to the sluggish economic recovery and, to a lesser extent, the effects of energy efficiency initiatives by individuals and companies.

Planned operating revenues for 2012 were $12.1 billion, including the estimated impact of fuel cost recovery. Total operating revenues were seven percent below the planned amount. In response to overall lower sales and revenues, TVA undertook cost savings initiatives beginning in the second quarter of 2012. Actions initiated include reductions in discretionary spending, deferred program spending, and identification of productivity enhancements to improve the overall cost effectiveness of existing programs and projects. In addition, TVA eliminated certain layers of management and reduced contractor and consultant services.

TVA experienced some short-term challenges with respect to its electricity generation during 2012. See Key Initiatives and Challenges - Generation Resources. Over the long-term, TVA faces challenges related to, among other things, compliance with current and emergent environmental laws and regulations, which may include installation of clean air equipment on coal-fired units and replacement of generating capacity of idled coal-fired units with nuclear and natural gas-fired units. Meeting these challenges will require significant capital expenditures on TVA's part. TVA is constrained by the TVA Act, which allows TVA to issue Bonds in an amount not to exceed $30.0 billion outstanding at any one time. Without a legislative solution, this limitation may require TVA to seek alternative financing arrangements. See Liquidity and Capital Resources
- Sources of Liquidity and Key Initiatives and Challenges.


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Results of Operations

Sales of Electricity

Sales of electricity accounted for virtually all of TVA's operating revenues in 2012, 2011, and 2010. TVA sells power at wholesale rates to distributor customers, consisting of municipalities and cooperatives that resell the power to their customers at retail rates. TVA also sells power to directly served customers, consisting primarily of federal agencies and customers with large or unusual loads. In addition, power that exceeds the needs of the TVA system is sold under exchange power arrangements with other power systems.

The following table compares TVA's energy sales statistics for the year ended September 30, 2012, and 2011:

                                              Sales of Electricity
                                        For the years ended September 30
                                               (millions of kWh)
                                    2012        Percent Change        2011        Percent Change        2010
Municipalities and cooperatives    131,885           (3.8 )%         137,042           (3.1 )%         141,448
Industries directly served          30,446            6.6  %          28,563           (5.1 )%          30,099
Federal agencies and other           2,924           37.6  %           2,125            0.5  %           2,115
Total sales of electricity         165,255           (1.5 )%         167,730           (3.4 )%         173,662

Weather affects both demand and market prices for electricity. TVA uses degree days to measure the impact of weather on its power operations. Degree days measure the extent to which average temperatures in the five largest cities in TVA's service area vary from 65 degrees Fahrenheit.

                                                              Degree Days
                                                Percent                                 Percent
                      2012      Normal(1)      Variation      2011      Normal(1)      Variation      2012      2011     Percent Change

Heating Degree Days  2,598         3,381       (23.2 )%      3,418         3,381          1.1 %      2,598     3,418          (24.0 )%

Cooling Degree Days  2,116         1,863        13.6  %      2,123         1,863         14.0 %      2,116     2,123           (0.3 )%

Note
(1) This calculation is updated every five years in order to incorporate the then most recent 30 years. It was last updated in 2011.

2012 Compared to 2011

Sales of electricity decreased 2.5 billion kilowatt hours ("kWh") for the year ended September 30, 2012, compared to the year ended September 30, 2011, primarily due to a decrease in demand by municipalities and cooperatives. The reduced demand was largely the result of the milder than normal winter during 2012, as compared to the relatively normal winter during 2011. Heating degree days were 23.2 percent below normal during 2012, compared to 1.1 percent above normal during 2011. The customers of municipalities and cooperatives are largely residential and commercial customers whose usage of electricity is typically more temperature-sensitive than that of industrial customers. The decrease in sales of electricity to municipalities and cooperatives during this same period was partially offset by increased demand from industries directly served, primarily by TVA's largest directly served industrial customer, and increased sales to off-system customers.

2011 Compared to 2010

Sales of electricity decreased 5.9 billion kWh for the year ended September 30, 2011, as compared to the year ended September 30, 2010, primarily due to a decrease in demand by municipalities and cooperatives. The 4.4 billion kWh decrease in sales to municipalities and cooperatives was primarily due to a 7.6 percent decrease in heating degree days and a 9.2 percent decrease in cooling degree days as a result of a warmer winter and cooler summer in 2011 compared to 2010. Heating degree days were 1.1 percent above normal during 2011, compared to 9.4 percent above normal during 2010. Cooling degree days were 14.0 percent above normal for 2011, compared to 25.5 percent above normal for 2010. Decreased demand by directly served industrial customers, primarily by TVA's largest directly served industrial customer, accounted for the remaining 1.5 billion kWh decrease in total sales of electricity.


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Financial Results

The following table compares operating results for 2012, 2011 and 2010:

     Summary Consolidated Statements of Operations
                          2012        2011        2010
Operating revenues     $  11,220    $ 11,841    $ 10,874
Operating expenses         9,920      10,404       8,632
Operating income           1,300       1,437       2,242
Other income, net             33          30          24
Net interest expense       1,273       1,305       1,294
Net income (loss)      $      60    $    162    $    972

Operating Revenues. Operating revenues for 2012, 2011 and 2010 consisted of the following:

                                           Operating Revenues
                           2012         Percent Change        2011        Percent Change        2010
Sales of electricity
Municipalities and
cooperatives           $     9,506           (6.3 )%      $    10,144            9.4  %     $     9,275
Industries directly
served                       1,442            0.1  %            1,440            9.0  %           1,321
Federal agencies and
other                          138           (0.7 )%              139           18.8  %             117
Total sales of
electricity                 11,086           (5.4 )%           11,723            9.4  %          10,713
Other revenue                  134           13.6  %              118          (26.7 )%             161
Total operating
revenues               $    11,220           (5.2 )%      $    11,841            8.9  %     $    10,874

In April 2011, TVA implemented a revised wholesale rate structure. The rate structure provides price signals intended to encourage distributor and end-use customers to shift energy usage from high-cost generation periods to less expensive generation periods. Under the revised wholesale structure, weather can positively or negatively impact both volume and average rates, while only volume was impacted under the former wholesale structure. This is because the wholesale structure includes two components: a demand charge and an energy charge. The demand charge is based on the customer's peak monthly usage and increases as the peak increases. The energy charge is based on the kWhs used by the customer. In conjunction with the change, the rate structure was also revised to establish a separate fuel rate that includes the costs of natural gas, fuel oil, purchased power, coal, emission allowances, nuclear fuel and other fuel-related commodities; realized gains and losses on derivatives purchased to hedge the costs of such commodities; and tax equivalents associated with the fuel cost adjustments.

A summary of changes in revenue components consisted of the following:

                    Variance 2012 vs. 2011       Variance 2011 vs. 2010
Fuel cost recovery $               (355 )      $               1,211
Base revenue                       (294 )                       (210 )
Other                                28                          (34 )
Total              $               (621 )      $                 967

2012 Compared to 2011

Operating revenues decreased $621 million for the year ended September 30, 2012, compared to the year ended September 30, 2011. The change was primarily due to a $355 million decrease in fuel cost recovery and a $294 million decrease in base revenue. Partially offsetting these decreases was a slight increase in other revenue sources. Of the $355 million decrease in fuel cost recovery, $269 million was due to lower fuel rates and $86 million was due to lower sales of electricity. Lower demand as a result of milder weather conditions was the primary driver of the decrease in base revenues and accounted for $209 million of the change.

See Sales of Electricity above for further discussion of the change in the volume of sales of electricity and Operating


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Expenses below for further discussion of the change in fuel expense.

2011 Compared to 2010

Operating revenues increased $967 million for the year ended September 30, 2011, compared to the year ended September 30, 2010. The change was primarily due to a $1.2 billion increase in fuel cost recovery. Partially offsetting this increase was a $210 million decrease in base revenue and a $34 million decrease in other revenue sources. Of the increase in fuel cost recovery, $1.3 billion was due to the unusually low fuel rate in 2010, which resulted from the liquidation of the fuel cost adjustment liability. This fuel cost adjustment liability was the product of over collection of fuel costs in 2009 through the fuel cost adjustment formula. Prior to October 2009, the fuel cost adjustment formula was updated quarterly resulting in the potential for larger positive and negative swings. Starting in 2010, the TVA Board revised the operation of this formula so that it was updated monthly and the TVA Board also approved the liquidation of the remaining liability through rates charged to rate payers over the nine-month period from October 1, 2009 to June 30, 2010, thereby decreasing the fuel rate charged to customers for that period. If not for this decrease to the fuel rate, 2010 revenues would have been $822 million higher. The increase in fuel cost recovery was partially offset by a $100 million decrease due to lower sales of electricity. Lower demand as a result of milder weather conditions was the primary driver of the $210 million decrease in base revenues and accounted for $259 million of the change.

See Sales of Electricity above for further discussion of the change in the volume of sales of electricity and Operating Expenses below for further discussion of the change in fuel expense.

Operating Expenses. The majority of the operating expenses associated with Fuel expense and Purchased power expense are recovered through the fuel cost recovery mechanism while all other operating costs, including certain non-eligible fuel costs ("Non-eligible Fuel Costs"), are recovered through base rates. (References to Fuel expense and Purchased power expense recovered by the fuel cost recovery mechanism do not refer to the recovery of the Non-eligible Fuel Costs, which are recovered in base rates.) The fuel cost recovery mechanism adjustment provides a means to adjust rates monthly in order to reflect changing fuel and purchased power costs, including realized gains and losses relating to fuel commodity hedging transactions under TVA's Financial Trading Program ("FTP"). See Note 14
- Derivatives Not Receiving Hedge Accounting Treatment - Derivatives Under 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 the operation of the fuel cost recovery mechanism adjustment. This difference is recorded as a regulatory asset or liability and represents over-collected revenues (regulatory liabilities) or under- collected revenues (regulatory assets). As a result of this treatment, fuel expenses are matched to the related revenues. Non-eligible Fuel Costs for 2012, 2011, and 2010 were $333 million, $426 million, and $355 million, respectively.

Operating expenses for 2012, 2011 and 2010 consisted of the following:

                                           Operating Expenses
                                    For the years ended September 30
                           2012        Percent Change        2011         Percent Change        2010
Fuel                   $     2,680           (8.4 )%     $     2,926             39.9 %     $     2,092
Purchased power              1,189          (16.7 )%           1,427             26.6 %           1,127
Operating and
maintenance                  3,510           (3.0 )%           3,617             11.9 %           3,232
Depreciation and
amortization                 1,919            8.3  %           1,772              2.8 %           1,724
Tax equivalents                622           (6.0 )%             662             44.9 %             457
Total operating
expenses               $     9,920           (4.7 )%     $    10,404             20.5 %     $     8,632

2012 Compared to 2011

Fuel expense decreased $246 million for the year ended September 30, 2012 as compared to the prior year. Overall favorable fuel rates, as a result of the change in the mix of generation resources, accounted for $235 million of the decrease. Coal-fired generation decreased 21 percent while natural gas-fired generation was 145 percent higher as compared to the prior year. This increase was primarily due to greater capacity as a result of the acquisition of the Magnolia Combined-Cycle Gas Plant ("Magnolia") and the completion of the John Sevier CCF and was also due to the increased use of natural gas-fired generation as a result of lower gas prices. The average Henry Hub natural gas spot price in 2012 was $2.73 per mmBtu, which was 34 percent lower than the average price for the prior year. Nuclear generation also helped offset the reduction in coal-fired generation as it increased 11 percent compared to the prior year due to fewer refueling outages. Lower sales of electricity led to a decrease in overall generation which accounted for the remaining $11 million of the decrease in fuel expense.

Purchased power expense decreased $238 million in 2012 from 2011 primarily due to a decrease in the average price of purchased power of 11 percent, which was largely the result of favorable natural gas prices. Lower natural gas prices reduced purchased power expense by $140 million. In addition, purchased power volume decreased by seven percent,


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primarily as a result of TVA using its own sources of generation as opposed to purchasing power. This reduced purchased power expense by $98 million in 2012 as compared to the prior year.

Operating and maintenance expense decreased $107 million in 2012 from 2011. The primary drivers of this decrease were a reduction of $53 million in nuclear operation expenses due to fewer nuclear refueling outages in 2012, as compared to the prior year, and a decrease in contractor and consultant services of $37 million. The decrease in contractor and consultant expense was primarily the result of cost savings initiatives undertaken in 2012 in order to offset lower sales and revenues. Other cost saving initiatives undertaken during the year include the identification of productivity enhancements to improve the overall cost effectiveness of existing programs and projects as well as project prioritization and reductions in discretionary spending.

Depreciation and amortization expense increased $147 million in 2012 over 2011 primarily due to additional depreciation of $308 million on certain idled coal-fired units and due to depreciation expense on net plant additions. These increases were partially offset by a $155 million decrease in amortization expense due to the treatment of certain regulatory assets as a result of the approval of Bellefonte Unit 1 in August 2011. See Note 1 - Property, Plant, and Equipment, and Depreciation.

Tax equivalents expense decreased $40 million. This change is primarily attributable to the increase in the fuel cost-related tax equivalent regulatory liability in 2011 as compared to 2010. The fuel cost-related tax equivalent regulatory liability, which is equal to five percent of the fuel-cost related . . .

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