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| TVC > SEC Filings for TVC > Form 10-Q on 3-Aug-2012 | All Recent SEC Filings |
3-Aug-2012
Quarterly Report
Management's Discussion and Analysis of Financial Condition and Results of Operations ("MD&A") explains the results of operations and general financial condition of the Tennessee Valley Authority ("TVA"). The MD&A should be read in conjunction with the accompanying unaudited consolidated financial statements and TVA's Annual Report on Form 10-K for the fiscal year ended September 30, 2011 (the "Annual Report").
Executive Overview
Weather continued to be the primary driver affecting TVA's net income for the three and nine month periods ended June 30, 2012, as compared with the same periods of 2011. TVA had net losses for the three and nine months ended June 30, 2012, of $23 million and $290 million, respectively, as compared with net losses of $240 million and $35 million for the same periods of 2011.
The southeastern United States experienced the fourth warmest winter on record, 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 quarter ended June 30, 2012, as compared with the same period of 2011, the increase was not large enough for TVA to fully offset the impact of lower sales and revenue in the first two quarters of 2012.
Planned revenue for 2012 was $12.1 billion, including the estimated impact of fuel cost recovery. During the first nine months of 2012, total operating revenues were seven percent below the planned amount. Despite a six percent increase in sales during the third quarter of 2012, TVA still expects Total operating revenues to be seven percent less than planned for 2012. In response to overall lower sales and revenues, TVA undertook cost savings initiatives in the second quarter of 2012 that are beginning to take effect. Actions initiated include reductions in discretionary spending, deferring program spending, and identification of productivity enhancements to improve the overall cost effectiveness of existing programs and projects. In addition, TVA has eliminated certain layers of management and reduced contractor and consultant services. Nonetheless, TVA expects to record a net loss for 2012.
TVA has experienced some short-term challenges with respect to its electricity generation during 2012. See 2012 Key Initiatives and Challenges - Generation Resources. Longer term, it faces challenges related to 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 cleaner-emissions nuclear and gas-fired units. Meeting these needs will require significant capital expenditures on TVA's part, but TVA is constrained by the TVA Act which authorizes TVA to issues bonds, notes and other evidences of indebtedness ("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.
Results of Operations
Sales of Electricity
The following table compares TVA's energy sales statistics for the three and
nine months ended June 30, 2012, and 2011:
Sales of Electricity
(millions of kWh)
Three Months Ended June 30 Nine Months Ended June 30
Percent
2012 2011 Change Change 2012 2011 Change Percent Change
Municipalities and
cooperatives 32,609 32,129 480 1.5 % 94,335 98,822 (4,487 ) (4.5 )%
Industries directly
served 7,531 6,240 1,291 20.7 % 23,872 22,513 1,359 6.0 %
Federal agencies and
other 967 486 481 99.0 % 1,993 1,549 444 28.7 %
Total sales of
electricity 41,107 38,855 2,252 5.8 % 120,200 122,884 (2,684 ) (2.2 )%
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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
Three months ended
June 30 130 228 (43.0 )% 199 228 (12.7 )% 130 199 (34.7 )%
Nine months ended
June 30 2,585 3,364 (23.2 )% 3,405 3,343 1.9 % 2,585 3,405 (24.1 )%
Cooling Degree Days
Three months ended
June 30 757 586 29.2 % 761 586 29.9 % 757 761 (0.5 )%
Nine months ended
June 30 875 666 31.4 % 831 666 24.8 % 875 831 5.3 %
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Note
(1) This is based on the most recent 30 years of weather history. Every five
years this calculation is updated in order to incorporate the most recent 30
years. The most recent update, to incorporate CYs 2006-2010, occurred during the
second quarter of 2011.
Sales of electricity increased 2.3 billion kilowatt hour ("kWh") for the three months ended June 30, 2012, as compared to the three months ended June 30, 2011. Increased demand by directly served industrial customers, primarily by TVA's largest directly served industrial customer, accounted for over half of the increase in total sales of electricity. Sales to off-system customers and increased demand by municipalities also contributed to the increase for the same period.
Sales of electricity decreased 2.7 billion kWh for the nine months ended June 30, 2012, compared to the nine months ended June 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 the nine months ended June 30, 2012, as compared to the relatively normal winter during the nine months ended June 30, 2011. Heating degree days were 23.2 percent below normal during the nine months ended June 30, 2012, compared to 1.2 percent above normal during the nine months ended June 30, 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.
Financial Results
The following table compares operating results for the three and nine months
ended June 30, 2012, and 2011:
Summary Consolidated Statements of Operations
Three Months Ended June 30 Nine Months Ended June 30
2012 2011 Percent Change 2012 2011 Percent Change
Operating revenues $ 2,777 $ 2,657 4.5 % $ 7,949 $ 8,453 (6.0 )%
Operating expenses (2,499 ) (2,575 ) (3.0 )% (7,288 ) (7,534 ) (3.3 )%
Operating income 278 82 239.0 % 661 919 (28.1 )%
Other income, net 21 4 425.0 % 16 25 (36.0 )%
Interest expense, net (322 ) (326 ) (1.2 )% (967 ) (979 ) (1.2 )%
Net income (loss) $ (23 ) $ (240 ) (90.4 )% $ (290 ) $ (35 ) 728.6 %
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Operating Revenues. Operating revenues for the three and nine months ended June 30, 2012, and 2011, consisted of the following:
Operating Revenues
Three Months Ended June 30 Nine Months Ended June 30
Percent
2012 2011 Change 2012 2011 Percent Change
Sales of electricity
Municipalities and
cooperatives $ 2,339 $ 2,287 2.3 % $ 6,643 $ 7,190 (7.6 )%
Industries directly
served 366 310 18.1 % 1,115 1,077 3.5 %
Federal agencies and
other 36 31 16.1 % 92 95 (3.2 )%
Total sales of
electricity 2,741 2,628 4.3 % 7,850 8,362 (6.1 )%
Other revenue 36 29 24.1 % 99 91 8.8 %
Total operating revenues $ 2,777 $ 2,657 4.5 % $ 7,949 $ 8,453 (6.0 )%
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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 periods to less expensive periods. Under the 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:
Three Month Change Nine Month Change
Base revenue $ 90 $ (296 )
Fuel cost recovery 15 (220 )
Other 15 12
Total $ 120 $ (504 )
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Operating revenues increased $120 million for the three months ended June 30, 2012, compared to the three months ended June 30, 2011, primarily due to a $90 million increase in base revenue. Contributing to the increase in base revenue was a $57 million increase due to the volume of electricity sold, which increased base revenue as a result of higher peak demand charges, and a $33 million increase due to the average effective rate (total revenues divided by total kWh). The increase in the volume of electricity sold was primarily due to increased demand by directly served industrial customers.
Operating revenues decreased $504 million for the nine months ended June 30, 2012, compared to the nine months ended June 30, 2011. The change was primarily due to a $296 million decrease in base revenue and a $220 million decrease in fuel cost recovery. Partially offsetting the decrease was a slight increase in other revenue sources. Lower demand as a result of warmer weather conditions was the primary driver of the decrease in base revenues and accounted for $189 million of the change. Warmer weather conditions also contributed to a decrease in the average effective rate of electricity sold (total revenues divided by total kWh) by decreasing peak demand charges. The decrease in the average effective rate reduced base revenue by $107 million. Of the $220 million decrease in fuel cost recovery, $143 million was due to more favorable fuel rates and $77 million was due to lower sales of electricity.
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. Most 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 regularly adjust rates 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 13
- 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 overcollected revenues (regulatory liabilities) or undercollected revenues (regulatory assets). As a result of this treatment, fuel expenses are matched to the related revenues. Non-eligible Fuel Costs for the three and nine months ended June 30, 2012, were $75 million and $251 million, respectively, and for the three and nine months ended June 30, 2011, were $102 million and $294 million, respectively.
Operating expenses for the three and nine months ended June 30, 2012, and 2011, consisted of the following:
Operating Expenses
Three Months Ended June 30 Nine Months Ended June 30
Percent Percent
2012 2011 Change 2012 2011 Change
Fuel $ 683 $ 584 17.0 % $ 1,847 $ 2,071 (10.8 )%
Purchased power 277 387 (28.4 )% 925 1,026 (9.8 )%
Operating and
maintenance 882 994 (11.3 )% 2,625 2,677 (1.9 )%
Depreciation and
amortization 505 436 15.8 % 1,439 1,296 11.0 %
Tax equivalents 152 174 (12.6 )% 452 464 (2.6 )%
Total operating
expenses $ 2,499 $ 2,575 (3.0 )% $ 7,288 $ 7,534 (3.3 )%
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Operating expenses decreased $76 million in the three months ended June 30, 2012, and decreased $246 million for the nine months ended June 30, 2012, compared to the same periods in 2011.
Fuel expense increased $99 million in the three months ended June 30, 2012, as
compared to the same period of
the prior year. An increase in generation by TVA to meet the higher demand for
electricity by customers accounted for $96 million of this increase. Gas-fired
generation increased by 150 percent due to greater capacity as a result of the
Magnolia Combined Cycle Plant ("Magnolia") acquisition and the completion of the
John Sevier Combined Cycle Facility ("John Sevier CCF") and due to lower natural
gas prices. The average Henry Hub natural gas spot price for the three months
ended June 30, 2012, was $2.27 per million British thermal units ("mmBtu"),
which was 48 percent lower than the average price for the same period of the
prior year. The 38 percent increase in nuclear generation was a result of having
one refueling outage during the third quarter of 2012 as compared to two
refueling outages during the same period of 2011. These increases in generation
were offset by a decrease of 56 percent in conventional hydroelectric generation
primarily due to rainfall being 50 percent lower and runoff being 71 percent
lower and a decrease in coal-fired generation of nine percent as a result of the
lower prices for natural gas as compared to the same period of the prior year.
Purchased power expense decreased $110 million during the three months ended June 30, 2012, as compared to the same period of the prior year, primarily due to a decrease in the average price of purchased power of 19 percent. As natural gas-fired generation is TVA's primary source of purchased power, natural gas price changes were the main source of the decrease. The lower natural gas prices reduced purchased power expense by $65 million. In addition, purchased power volume decreased by 12 percent, as compared to the same period of the prior year, primarily as a result of TVA using its own sources of generation, which reduced purchased power expense by $45 million.
Operating and maintenance expense decreased $112 million in the three months ended June 30, 2012, as compared to the same period of the prior year. The primary driver of the decrease in operating and maintenance expense was a $63 million decrease related to nuclear routine maintenance and nuclear refueling outages. Nuclear operations had fewer outages in the three months ended June 30, 2012, compared to the same period of the prior year and incurred additional expenses in the same period of the prior year related to a forced outage experienced at Browns Ferry Nuclear Plant ("Browns Ferry") due to a series of storms in April 2011. Additionally, contract labor decreased $31 million primarily due to an emphasis on cost saving initiatives, including project prioritization and a reduction in TVA contractors overall. These items were partially offset by a $36 million increase in pension and post-retirement benefits as a result of the use of a lower assumed discount rate in the actuarial calculation of post-retirement liabilities.
Depreciation and amortization expense increased $69 million for the three months ended June 30, 2012, as compared to the same period of the prior year, primarily due to accelerated depreciation of $100 million on certain idled coal-fired units and to depreciation expense on net plant additions. These increases were partially offset by a $38 million decrease in amortization expense due to the treatment of certain regulatory assets as a result of the approval of Bellefonte Nuclear Plant ("Bellefonte") Unit 1 in August 2011. See Note 1 - Depreciation.
Tax equivalents expense decreased $22 million in the three months ended June 30, 2012, as compared to the same period of the prior year. This change is primarily attributable to the increase in the 2011 fuel-cost related tax equivalent regulatory liability as compared to 2010. The fuel-cost related tax equivalent regulatory liability, which is equal to five percent of the fuel-cost related revenues, saw an increase in 2011 due to the wholesale rate structure implemented on April 1, 2011. Tax
equivalent expense related to fuel-cost revenues is recognized in the same period the revenues are recognized. Tax equivalents related to all other revenues are recognized in the year paid.
TVA calculates tax equivalent expense by subtracting the prior year fuel cost-related tax equivalent regulatory asset or liability from the tax equivalent payments made to the states and counties and then adds back the current year fuel cost-related tax equivalent regulatory asset or liability.
Fuel expense decreased $224 million in the nine months ended June 30, 2012, as compared to the same period of the prior year. Overall favorable fuel rates, as a result of the change in the mix of generation resources, accounted for $183 million of the decrease. Coal-fired generation decreased 27 percent while gas-fired generation helped offset the reduction in coal-fired generation, as gas-fired generation was 138 percent higher as compared to the same period of the prior year. This increase was primarily due to greater capacity as a result of the Magnolia acquisition and the completion of the John Sevier CCF and due to lower gas prices. The average Henry Hub natural gas spot price for the nine months ended June 30, 2012, was $2.68 per mmBtu, which was 35 percent lower than the average price for the same period of the prior year. Nuclear generation also helped offset the reduction in coal-fired generation as it increased 17 percent as compared to the same period of the prior year due to fewer plant outages. Lower sales of electricity led to a decrease in generation which accounted for the remaining $41 million of the decrease in fuel expense.
Purchased power expense decreased $101 million during the nine months ended June 30, 2012, as compared to the same period of the prior year, primarily due to a decrease in the average price of purchased power of seven percent, which was largely the result of changes in gas prices. Lower natural gas prices reduced purchased power expense by $72 million. In addition, purchased power volume decreased by three percent, primarily as a result of TVA using its own sources of generation. This reduced purchased power expense by $29 million as compared to the same period of the prior year.
Operating and maintenance expense decreased $52 million in the nine months ended June 30, 2012, as compared to the same period of the prior year. The primary driver of the decrease in operating and maintenance expense was a $99 million decrease related to nuclear operation expenses due to fewer nuclear refueling outages as compared to the same period of the prior year. Additionally, contract labor decreased $32 million primarily due to an emphasis on cost saving initiatives, including project prioritization and a reduction in TVA contractors overall. These items were partially offset by an increase of $107 million in pension and post-retirement benefits as a result of the use of a lower assumed discount rate in the actuarial calculation of post-retirement liabilities.
Depreciation and amortization expense increased $143 million for the nine months ended June 30, 2012, as compared to the same period of the prior year, primarily due to accelerated depreciation of $236 million on certain idled coal-fired units and to depreciation expense on net plant additions. These increases were partially offset by a $116 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 - Depreciation.
Tax equivalents expense decreased $12 million in the nine months ended June 30, 2012, as compared to the same period of the prior year. This change is primarily attributable to the increase in the 2011 fuel cost-related tax equivalent regulatory liability as compared to 2010. The fuel cost-related tax equivalent regulatory liability, which is equal to five percent of the fuel-cost related revenues, saw an increase in 2011 due to the wholesale rate structure implemented on April 1, 2011. Tax equivalent expense related to fuel-cost revenues is recognized in the same period the revenues are recognized. Tax equivalents related to all other revenues are recognized in the year paid.
Interest Expense. Interest expense and interest rates for the three and nine months ended June 30, 2012, and 2011, were as follows:
Interest Expense
Three Months Ended June 30 Nine Months Ended June 30
Percent Percent
2012 2011 Change 2012 2011 Change
Interest Expense(1)
Interest expense $ 366 $ 358 2.2 % $ 1,092 $ 1,072 1.9 %
Allowance for funds used
during construction and
nuclear fuel expenditures (44 ) (32 ) 37.5 % (125 ) (93 ) 34.4 %
Net interest expense $ 322 $ 326 (1.2 )% $ 967 $ 979 (1.2 )%
Percent Percent
2012 2011 Change 2012 2011 Change
Interest Rates (average)
Long-term outstanding power
bonds(2) 6.090 5.755 5.8 % 5.859 5.814 0.8 %
Long-term debt of VIE 4.819 - N/A 4.824 - N/A
Discount notes 0.084 0.011 663.6 % 0.063 0.088 (28.4 )%
Blended 5.549 5.722 (3.0 )% 5.640 5.750 (1.9 )%
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Notes
(1) Interest expense includes interest on long-term debt obligations, including
amortization of debt discounts, issuance, and reacquisition costs, net.
(2) The average interest rates on long-term debt obligations reflected in the
table above are calculated using an average of long-term debt balances at the
end of each month in the periods depicted and interest expense for those
periods.
Net interest expense decreased $4 million for the three months ended June 30, 2012. The decrease was primarily due to a $12 million increase in allowance for funds used during construction ("AFUDC") due to greater amounts of capitalized interest caused by an increase in the construction work in progress base used to calculate AFUDC as a result of ongoing construction activities at Watts Bar Nuclear Plant ("Watts Bar") Unit 2. This was partially offset by an $8 million increase in interest expense, primarily due to an increase of $12 million related to the financing of the John Sevier CCF. See Note 7 and Note 11 - Debt Securities Activity - Secured Debt of VIEs.
Net interest expense decreased $12 million for the nine months ended June 30,
2012. This was primarily related to a $32 million increase in AFUDC due to
ongoing construction activities at Watts Bar Unit 2. This was partially offset
by a $20 million increase in interest expense primarily due to an increase of
$22 million related to the financing of the John Sevier CCF. See Note 7 and Note
11 - Debt Securities Activity - Secured Debt of VIEs.
. . .
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