A summary of our retail electric sales in GWh for CL&P, PSNH and WMECO and firm natural gas sales in million cubic feet for Yankee Gas for the third quarter and first nine months of 2009 and 2008 is as follows:
| | | | | | | | | | | | |
| | For the Three Months Ended September 30, |
| | Electric | | Firm Natural Gas |
| |
2009
| | 2008 | | Percentage
Increase/
(Decrease) | | 2009 | | 2008 | | Percentage
Increase |
Residential | | 3,768 | | 3,837 | | (1.8)% | | 1,107 | | 1,024 | | 8.1% |
Commercial | | 3,828 | | 3,978 | | (3.8)% | | 1,341 | | 1,313 | | 2.2% |
Industrial | | 1,190 | | 1,389 | | (14.3)% | | 3,038 | | 2,849 | | 6.6% |
Other | | 80 | | 79 | | 1.4 % | | - | | - | | - |
Total* | | 8,866 | | 9,282 | | (4.5)% | | 5,486 | | 5,185 | | 5.8% |
| | | | | | | | | | | | |
| | For the Nine Months Ended September 30, |
| | Electric | | Firm Natural Gas |
| |
2009
| | 2008 | | Percentage
Decrease | | 2009 | | 2008 | | Percentage
Increase |
Residential | | 10,883 | | 10,947 | | (0.6)% | | 9,263 | | 8,930 | | 3.7% |
Commercial | | 10,930 | | 11,335 | | (3.6)% | | 9,708 | | 8,890 | | 9.2% |
Industrial | | 3,318 | | 3,914 | | (15.2)% | | 10,791 | | 9,684 | | 11.4% |
Other | | 244 | | 246 | | (0.7)% | | - | | - | | - |
Total* | | 25,376 | | 26,442 | | (4.0)% | | 29,762 | | 27,504 | | 8.2% |
*Amounts may not total due to rounding of GWh or million cubic feet.
Similar to second quarter of 2009, our third quarter 2009 actual retail electric sales were significantly impacted by the weather and economic conditions and were lower than the same period in 2008. The negative trend in our sales continues to be most prevalent in the industrial class where many customers have been negatively impacted by the economic conditions of our region and nation. We believe the reduction in industrial sales is primarily driven by a reduced number of shifts and days of operations.
Our residential sales in the third quarter of 2009 for CL&P and PSNH were lower than in the third quarter of 2008, and WMECO's residential sales in the third quarter of 2009 were unchanged from the third quarter of 2008. On a weather normalized basis, residential sales in the third quarter of 2009 for all three electric distribution companies were higher than the same period in 2008. The significant difference between actual and weather normalized residential sales in the third quarter of 2009 reflects the fact that the amount of cooling degree days for this time period was approximately 20 percent and 12 percent lower than the same period last year for Connecticut/Western Massachusetts and New Hampshire, respectively. The cool and rainy weather in June 2009 continued through much of the third quarter and decreased the amount of air conditioning load. For the first nine months of 2009, residential
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sales for all three electric distribution companies were lower than the same period in 2008, but on a weather normalized basis, residential sales were higher than they were in 2008.
Recovery of our distribution revenues, however, varies between customer classes. As compared to other customer classes, a greater portion of residential revenues is recovered through volumetric charges. In contrast to residential rates, a much smaller portion of commercial and industrial revenues is recovered through volumetric charges. Distribution rates for certain large businesses are structured so that we recover 100 percent of the distribution revenues through non-volumetric charges. In this regard, rate design has significantly mitigated the impact of the declining commercial and industrial sales on distribution revenues and earnings.
Actual and weather normalized firm natural gas sales in the third quarter of 2009 and for the first nine months of 2009 were higher than the same periods in 2008. The 2009 results for the commercial and industrial sectors have benefitted substantially from the addition of new large gas-fired distributed generation in Yankee Gas's service region during the last twelve to fifteen months. Yankee Gas recovers almost half of its total distribution revenues through non-usage charges, and thus, similar to our electric distribution companies, changes in sales have less of an impact on revenues.
Our expense related to uncollectible receivable balances (or uncollectibles expense) is influenced by the economic conditions of our region. The weak economic conditions in the Northeast continue to have a negative effect on our customers. For the third quarter of 2009, our total uncollectibles expense was approximately $12.8 million higher than the same period in 2008. For the first nine months of 2009, our total uncollectibles expense was approximately $23.6 million higher than the same period in 2008. These increases in our 2009 uncollectibles expense were partially mitigated from an earnings perspective because a portion of the total uncollectibles expense for each of the electric distribution companies is allocated to the respective company's energy supply rate and recovered through its tariffs. Additionally, for CL&P and Yankee Gas, write-offs of uncollectible receivable balances attributable to qualified customers under financial or medical dures s (or hardship customers) are fully recovered through their respective tariffs. Of the $12.8 million and $23.6 million increase in uncollectibles expense for the third quarter and first nine months of 2009, approximately $7.2 million and $10.2 million, respectively, was not recovered and impacted earnings.
Competitive Businesses: NU Enterprises, which continues to manage to completion Select Energy Inc.'s (Select Energy) remaining wholesale marketing contracts and to manage its energy services activities, earned $0.3 million in the third quarter of 2009 and $11.6 million in the first nine months of 2009, compared with earnings of $4.6 million in the third quarter of 2008 and $8.7 million in the first nine months of 2008. Competitive business earnings for the third quarter of 2009 included an after-tax mark-to-market loss of $0.9 million associated with Select Energy's wholesale marketing contracts, as compared to an after-tax mark-to-market gain of $3.6 million in the third quarter of 2008. Earnings for the first nine months of 2009 and 2008 included after-tax mark-to-market gains of $3.7 million and $2.7 million, respectively. Results for the first nine months of 2008 included a net after-tax charge of $2.8 million associated with the implementation of acco unting guidance for fair value measurements. Results for NU Enterprises are not expected to continue at the 2008 and 2009 earnings levels. The margins Select Energy earns on its remaining contracts are expectedto decline in future years.
NU Parent and Other Companies: NU parent and other companies recorded net expenses of $0.8 million in the third quarter of 2009 and $6.3 million in the first nine months of 2009, compared with net expenses of $3.3 million in the third quarter of 2008 and $38.3 million in the first nine months of 2008. The net expenses in the first nine months of 2008 included a $29.8 million after-tax charge resulting from the payment of $49.5 million made in March 2008 associated with a litigation settlement. The decrease in net expenses for the third quarter of 2009 was the result of a decrease in net interest costs for NU parent due primarily to lower interest expense related to an interest rate swap on its fixed rate long-term debt, as well as interest earned on significantly higher cash balances after the sale of common shares in March 2009, which resulted in net proceeds of $370.8 million.
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Future Outlook
EPS Guidance: We continue to project consolidated 2009 earnings of between $1.80 per share and $1.90 per share. A summary of our projected 2009 and 2010 EPS by segment, which also reconciles consolidated fully diluted EPS to the non-GAAP financial measures of EPS by segment, is as follows:
| | | | | | | | | | | | |
| | 2009 EPS Range | | 2010 EPS Range |
(Approximate amounts) | | | Low | | | High | | | Low | | | High |
Fully Diluted EPS (GAAP) | | $ | 1.80 | | $ | 1.90 | | $ | 1.80 | | $ | 2.00 |
| | | | | | | | | | | | |
Regulated companies: | | | | | | | | | | | | |
Distribution segment | | $ | 0.90 | | $ | 1.00 | | $ | 0.95 | | $ | 1.05 |
Transmission segment | | | 0.90 | | | 0.90 | | | 0.90 | | | 0.95 |
Total regulated companies | | | 1.80 | | | 1.90 | | | 1.85 | | | 2.00 |
Competitive businesses | | | 0.05 | | | 0.05 | | | 0.00 | | | 0.05 |
NU parent and other companies | | | (0.05) | | | (0.05) | | | (0.05) | | | (0.05) |
Fully Diluted EPS (GAAP) | | $ | 1.80 | | $ | 1.90 | | $ | 1.80 | | $ | 2.00 |
We have included estimated impacts from current economic conditions in the assumptions that were used to develop our earnings guidance. The 2010 distribution segment guidance reflects a one percent annual decrease in total retail electric sales, as well as uncertainty around the outcomes of the PSNH distribution rate case that was filed in mid-2009 and a CL&P distribution rate case that we expect to file in late 2009 or early 2010. A Yankee Gas rate case is also being considered but additional earnings from such a filing are not included in the above projections. Both the PSNH and CL&P rate case decisions are expected around mid-2010.
Long-Term Growth Rate: We project that we will achieve a compound average annual EPS growth rate for the five-year period of 2010 to 2014 of between 6 percent and 9 percent, using 2009 projected EPS of between $1.80 and $1.90 as the base level. This EPS growth rate assumes Regulatory ROEs of approximately 12.25 percent for the transmission segment and an average of approximately 10 percent for the distribution segment (including generation). We believe this growth will be achieved if our capital program is completed in accordance with our plans, distribution rate case orders enable us to earn fair Regulatory ROEs and FERC's current transmission policies remain consistent and enable us to achieve projected transmission ROEs. In addition to the assumptions above, there are certain items that will likely impact this earnings growth rate. These items include, but are not limited to, sales levels; operating expense levels, including maintenance, pe nsion and uncollectibles expense; and lower margins that NU Enterprises expects to earn on its remaining contracts.
Liquidity
Consolidated: We had $249 million of cash and cash equivalents on hand as of September 30, 2009, compared with $89.8 million as of December 31, 2008. During the first nine months of 2009 our cash position increased primarily as a result of the issuance of 18,975,000 common shares by NU on March 20, 2009, which yielded gross proceeds of approximately $380 million, and the issuance of $250 million of first mortgage bonds by CL&P on February 13, 2009.
On October 5, 2009, the NHPUC approved an application by PSNH to issue $150 million of first mortgage bonds and increase its short-term debt limit to $60 million above the statutory limit of 10 percent of net plant, which represents approximately $157 million. A request for rehearing on the NHPUC's decision has been filed, however, we currently expect PSNH to issue the bonds by the end of 2009. No other long-term debt or equity financings are planned by NU parent or its subsidiaries in 2009. Our planned financings for 2010 total approximately $340 million of new long-term debt comprised of $170 million at PSNH, $90 million at WMECO and $80 million at Yankee Gas. We have only annual sinking fund requirements of $4.3 million continuing in 2010 through 2012, the mandatory tender of $62 million of tax-exempt Pollution Control Revenue Bonds (PCRBs) by CL&P in 2010, which CL&P expects will be remarketed in the ordinary course, and no debt maturities until April 1, 2012.
The proceeds from our 2009 and 2010 financings were or will be used primarily to repay short-term borrowings and fund our capital programs. The combined borrowings and letters of credit (LOCs) outstanding on our revolving credit facilities totaled $397.2 million as of September 30, 2009, compared with approximately $706 million as of December 31, 2008.
We had cash flows provided by operating activities, after RRB payments included in financing activities, in the first nine months of 2009 of $577.9 million, compared with $252.2 million in the first nine months of 2008. The improved cash flows were due primarily to the increase in operating results from higher transmission revenues at CL&P after significant projects were placed in service in late 2008 as well as NU cost management efforts; a shift in accounts receivable and unbilled revenue balances of approximately $159 million; a decrease in regulatory underrecoveries of approximately $141 million related primarily to CL&P's Federally Mandated Congestion Charge (FMCC), Generation Service Charge (GSC), and reserve for Conservation and Load Management (C&LM)
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included in customer rates; a favorable change in fuel, materials and supplies balances of approximately $78 million due primarily to the lower cost of gas being stored by Yankee Gas for the winter heating season; and the absence in 2009 of the litigation settlement payment of $49.5 million made in March 2008. These favorable factors were partially offsetby a negative shift in timing of cash disbursements from accounts payable of approximately $184 million.
We project consolidated cash flows provided by operating activities of approximately $700 million in 2009, after RRB payments of approximately $244 million. Consolidated cash flows provided by operating activities after RRB payments are expected to total approximately $4 billion from 2010 through 2014, ranging from approximately $700 million in 2010, after RRB payments of approximately $260 million, to approximately $1.1 billion in 2014, assuming our capital projects are completed as expected and we receive fair regulatory treatment on related expenditures. We expect the vast majority of our capital program to be funded through cash flows provided by operating activities and new debt issuances, and currently anticipate a single NU common equity issuance in the next five years of approximately $300 million, which is expected no earlier than 2012.
A summary of the current credit ratings and outlooks by Moody's Investors Service (Moody's), Standard & Poor's (S&P) and Fitch Ratings (Fitch) for senior unsecured debt of NU parent and WMECO and senior secured debt of CL&P and PSNH is as follows:
| | | | | | | | | | | | |
| | Moody's | | S&P | | Fitch |
| | Current | | Outlook | | Current | | Outlook | | Current | | Outlook |
NU parent | | Baa2 | | Stable | | BBB- | | Stable | | BBB | | Stable |
CL&P | | A2 | | Stable | | BBB+ | | Stable | | A- | | Stable |
PSNH | | A3 | | Stable | | BBB+ | | Stable | | BBB+ | | Stable |
WMECO | | Baa2 | | Stable | | BBB | | Stable | | BBB+ | | Stable |
On October 9, 2009, Fitch concluded its annual review of NU parent and its electric utilities by reaffirming all of its existing credit ratings and stable outlooks. On October 27, 2009, Moody's published credit opinions on CL&P and WMECO in which it reaffirmed the companies' ratings and stable outlooks.
If NU parent's senior unsecured debt ratings were to be reduced to below investment grade level by either Moody's or S&P, a number of Select Energy's supply contracts would require Select Energy to post additional collateral in the form of cash or LOCs. If such an event had occurred as of September 30, 2009, Select Energy, under its remaining contracts, would have been required to provide additional cash or LOCs in an aggregate amount of $29.1 million to various unaffiliated counterparties and additional cash or LOCs in the aggregate amount of $2 million to an independent system operator. NU parent would have been and remains able to provide that collateral on behalf of Select Energy.
If unsecured debt ratings for CL&P or PSNH were to be reduced by either Moody's or S&P, certain supply contracts could require CL&P and PSNH to post additional collateral in the form of cash or LOCs with various unaffiliated counterparties. As of September 30, 2009, CL&P only had one supply contract requiring collateral posting for which $1 million of cash collateral has been posted for the out-of-the-money position. No additional collateral would have been required of CL&P under its supply contracts if its unsecured debt ratings had been reduced. If PSNH's unsecured debt ratings had been reduced by one level, PSNH would have been required to post additional collateral of $1.8 million as of September 30, 2009. If these ratings had been reduced by two levels or below investment grade, the amount of additional collateral required to be posted by PSNH would have been $14.8 million as of September 30, 2009. PSNH would have been and rema ins able to provide these collateral amounts.
On July 1, 2009, WMECO filed an application with the DPU to issue and sell up to $150 million of senior secured or unsecured long-term debt. If WMECO decides to issue first mortgage bonds, WMECO will be obligated to secure its $195 million of currently outstanding senior unsecured notes equally and ratably with such first mortgage bonds.
We paid common dividends of $120.6 million in the first nine months of 2009, compared with $95.8 million in the first nine months of 2008. The increase is the result of a 6.3 percent increase in our common dividend rate that took effect in the third quarter of 2008, an additional 11.8 percent increase that took effect in the first quarter of 2009, and a higher number of shares outstanding in the second and third quarters of 2009. On October 13, 2009, our Board of Trustees declared a common dividend of $0.2375 per share, payable on December 31, 2009 to shareholders of record as of December 1, 2009.
We target paying out approximately 50 percent of consolidated earnings in the form of common dividends. Our ability to pay common dividends is subject to approval by our Board of Trustees and our future earnings and cash flow requirements and may be limited by certain state statutes, the leverage restrictions in our revolving credit agreement and the ability of our subsidiaries to pay common dividends. The Federal Power Act limits the payment of dividends by CL&P, PSNH and WMECO to their respective retained earnings balances unless a higher amount is approved by FERC, and PSNH is required to reserve an additional amount of retained earnings under its FERC hydroelectric license conditions. In addition, relevant state statutes may impose additional limitations on the payment of dividends by the regulated companies. CL&P, PSNH, WMECO and Yankee Gas also are parties to a revolving credit agreement that imposes leverage restrictions.
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In general, the regulated companies pay approximately 60 percent of their cash earnings to NU parent in the form of common dividends. In the first nine months of 2009, CL&P, PSNH, WMECO, and Yankee Gas paid $85.4 million, $30.6 million, $14.7 million, and $19.1 million, respectively, in common dividends to NU parent. In the first nine months of 2009, NU parent made cash equity contributions of $116.6 million and $68.9 million to CL&P and PSNH, respectively. NU parent made minimal cash equity contributions to WMECO and Yankee Gas for the nine months ended September 30, 2009.
Cash capital expenditures included on the accompanying unaudited condensed consolidated statements of cash flows and described in the Liquidity section of this Management's Discussion and Analysis do not include amounts incurred on capital projects but not yet paid, cost of removal, the allowance for funds used during construction (AFUDC) related to equity funds, and the capitalized portions of pension and postretirement benefits other than pension (PBOP) expense or income. A summary of our cash capital expenditures by company for the first nine months of 2009 and 2008 is as follows:
| | | | | | |
| | For the Nine Months Ended September 30, |
(Millions of Dollars) | | | 2009 | | | 2008 |
CL&P | | $ | 331.6 | | $ | 678.6 |
PSNH | | | 169.4 | | | 164.8 |
WMECO | | | 63.7 | | | 49.6 |
Yankee Gas | | | 39.1 | | | 39.1 |
Other | | | 30.6 | | | 19.7 |
Totals | | $ | 634.4 | | $ | 951.8 |
The decrease in our total cash capital expenditures was primarily the result of lower transmission segment capital expenditures, particularly at CL&P (refer to "Business Development and Capital Expenditures" for further discussion).
As a result of Lehman Brothers Commercial Bank (LBCB) declining to fund its commitment of approximately $56 million under our credit facilities in 2008 as referred to below, our aggregate borrowing capacity under our credit facilities was reduced from $900 million to $844 million. We believe this borrowing capacity, when combined with our access to other funding sources, provides operating flexibility to maintain adequate liquidity.
NU parent has a credit facility in a nominal aggregate amount of $500 million, $482.3 million excluding the commitment of LBCB, which expires on November 6, 2010. As of September 30, 2009, NU parent had $72 million of LOCs issued for the benefit of certain subsidiaries (primarily PSNH) and $146.6 million of borrowings outstanding under this facility. The weighted-average interest rate on these short-term borrowings as of September 30, 2009 was 0.625 percent, which is based on a variable rate plus an applicable margin based on NU parent's credit ratings. NU parent had approximately $263.7 million of borrowing availability on this facility as of September 30, 2009, excluding LBCB's commitment, as compared to $101.3 million of availability as of December 31, 2008.
The regulated companies maintain a joint credit facility in a nominal aggregate amount of $400 million, $361.8 million excluding the commitment of LBCB, which also expires on November 6, 2010. There were $178.6 million of borrowings outstanding under this facility as of September 30, 2009 ($33 million for CL&P, $45.2 million for PSNH, $75.1 million for WMECO, and $25.3 million for Yankee Gas). The weighted-average interest rate on these short-term borrowings as of September 30, 2009 was 0.64 percent, which is based on a variable rate plus an applicable margin based on the borrower's credit ratings. The regulated companies had approximately $183.2 million of aggregate borrowing availability on this facility as of September 30, 2009, excluding LBCB's commitment and subject to each individual company's borrowing limits, as compared to $56.5 million of availability as of December 31, 2008.
Our credit facilities and bond indentures require that NU parent and certain of its subsidiaries, including CL&P, PSNH and WMECO, comply with certain financial and non-financial covenants as are customarily included in such agreements, including a consolidated debt to capitalization ratio. All such companies currently are, and expect to, remain in compliance with these covenants. Refer to Note 2, "Short-Term Debt," and Note 11, "Long-Term Debt," to our consolidated financial statements included in the 2008 Form 10-K for further discussion of material terms and conditions of these agreements.
Impact of Financial Market Conditions: While the impact of continued market volatility and the extent and impacts of the current economic downturn cannot be predicted, we believe that we currently have operating flexibility and access to funding sources to maintain adequate liquidity. The credit outlooks for NU parent and its regulated companies are all stable. Our companies have low risk of calls for collateral due to our business model, as described further below, and we have no long-term debt maturing until April 2012. An estimated cash contribution to our pension plan of $50 million is expected to be made in the third quarter of 2010, as further described below, and we project capital expenditures for 2010 of approximately $1.1 billion. However, we project cash flows provided by operating activities for 2010 of approximately $700 million, and, based on our successful financings in 2009, we do not anticipate any difficulty in accessing the capital markets in 2010 for our total planned debt issuances of approximately $340 million.
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Our regulated standard offer type contracts do not require us to post collateral. In the event of an energy supplier's default under these contracts we could be required to provide standard offer type services directly to customers until a substitute supplier could be arranged. Such an event would require us to post additional collateral with the New England Independent System Operator (ISO-NE). Our suppliers currently are performing on these contracts, and any additional costs we would incur from a supplier default would be recoverable from customers. In other regulated contracts that do contain collateral posting requirements, the counterparties are generally exposed to us at this time, and when we have been exposed to them, these counterparties have been posting the necessary collateral. As of September 30, 2009 and December 31, 2008, PSNH had posted $56 million and $75 million, respectively, in related collateral in the form of NU parent LOCs with count erparties. PSNH had an additional $10 million of LOCs posted with ISO-NE at September 30, 2009 and December 31, 2008. Also, the ongoing collateral requirements for Select Energy's few remaining wholesale contracts are not material as it continues to wind down this business. Select Energy has not experienced any significant performance difficulties with suppliers on its remaining sourcing contracts. As of September 30, 2009, Select Energy had posted $30.2 million in collateral due to the exposure of counterparties to us, including collateral posted with counterparties under master netting agreements, as compared to $26.3 million as of December 31, 2008. Refer to "NU Enterprises Contracts - Counterparty Credit" in this Management's Discussion and Analysis for further discussion.
As of January 1, 2008 our pension plan funded ratio (the value of plan assets divided by the funding target in accordance with the requirement of the Pension Protection Act or PPA) was 111 percent. We have not been required to make a contribution to the plan since 1991. As of January 1, 2009, due primarily to the negative financial market conditions experienced in 2008, the fair value of our pension plan assets dropped by approximately $900 million to $1.56 billion. On October 7, 2009, the Internal Revenue Service issued final regulations on the PPA funding rules, which allows us to maximize our funding flexibility by using the October 2008 yield curve rate for the January 1, 2009 valuation of pension plan liabilities. Using the October 2008 yield curve rate, our pension plan funded ratio was 100 percent as of January 1, 2009. We currently estimate that a contribution of approximately $50 million will be made in the third quarter of 2010 for the purpose of satisfying benefit obligations accrued during 2009, and that contributions totaling approximately $200 to $250 million will be made in 2011. PSNH is currently expected to fund approximately $30 million and $157 million of the 2010 and 2011 contributions, respectively. The actual amount of future contributions will depend on many factors, including the performance of existing plan assets, valuation of the plan's liabilities, and long-term discount rates.
Business Development and Capital Expenditures
Consolidated: Our consolidated capital expenditures, including amounts incurred but not paid, cost of removal, AFUDC, and the capitalized portions of pension and PBOP expense or income (all of which are non-cash factors), totaled $650.6 million in the first nine months of 2009, compared with $946.6 million in the first nine months of 2008. These amounts included $34.4 million and $14.7 million in the first nine months of 2009 and 2008, respectively, that related to our corporate service companies that support the regulated companies.
Regulated Companies: Capital expenditures for the regulated companies are expected to total approximately $960 million ($429 million for CL&P) in 2009, which includes planned spending of approximately $52 million for our corporate service companies that support the regulated companies.
Transmission Segment: Transmission segment capital expenditures decreased by $375.5 million in the first nine months of 2009, as compared with the same period in 2008, due primarily to reduced expenditures at CL&P, which completed three major transmission projects in southwest Connecticut in the second half of 2008. Capital expenditures for the consolidated transmission segment are expected to total approximately $275 million ($148 million for CL&P) in 2009. A summary of transmission segment capital expenditures by company in the first nine months of 2009 and 2008 is as follows:
| | | | | | | |
| | For the Nine Months Ended September 30, |
(Millions of Dollars) | | | 2009 | | | 2008 |
CL&P | | $ | 112.9 | | $ | 486.4 | |
PSNH | | | 41.8 | | | 58.6 | |
WMECO | | | 44.3 | | | 27.9 | |
HWP | | | - | | | 1.6 | * |
Totals | | $ | 199.0 | | $ | 574.5 | |
*
Represents capital additions of Holyoke Water Power Company (HWP), which were transferred to WMECO in December 2008.
In October 2008, we commenced state siting filings for our current series of major transmission projects, New England East-West Solutions (NEEWS). That series of projects involves our construction of new overhead 345 kilovolt (KV) lines in Massachusetts and Connecticut as well as associated substation work and 115 KV rebuilds. One of the projects will connect to a new transmission line that National Grid USA plans to build in Rhode Island and Massachusetts. On September 24, 2008, ISO-NE issued its technical approval of the NEEWS projects, which was a precursor to the siting application process. We estimate that CL&P's and WMECO's
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total capital expenditures for these projects will be $1.49 billion through 2014. ISO-NE is currently performing an evaluation of all projects in its regional system plan, including NEEWS, and assessing the presently estimated need dates for these projects. The timing and amount of our projected annual capital spending could be affected if receipt of siting approvals is delayed or if the need dates for these projects change through ISO-NE's regional system planning process. Since inception of the project through September 30, 2009, CL&P and WMECO have capitalized approximately $56.6 million and $58.8 million, respectively, in costs associated with NEEWS, of which $23.3 million and $24.4 million, respectively, were capitalized in the first nine months of 2009.
The first of the NEEWS projects, Greater Springfield Reliability Project (GSRP), which involves the construction of a 115 KV/345 KV line from Ludlow, Massachusetts to North Bloomfield, Connecticut, is the largest and most complicated project within NEEWS. ISO-NE has reaffirmed the need and need date for GSRP. This project is expected to cost approximately $714 million if built according to our preferred route configuration. CL&P filed its application to build the Connecticut portion of the GSRP with the Connecticut Siting Council (CSC) on October 20, 2008. WMECO filed its application to build its portion of the project with the Massachusetts Energy Facilities Siting Board (MAEFSB) on October 27, 2008. Public hearings before the MAEFSB and CSC began in May 2009 and September 2009, respectively. Evidentiary hearings before the CSC began in July 2009 and are expected to conclude in the fourth quarter of 2009. A joint hearing between the CS C and MAEFSB on topics common to both states' proceedings was held in September 2009. Evidentiary hearings before the MAEFSB commenced on November 2, 2009 and are expected to be completed in the fourth quarter of 2009. The CSC is considering other applications in parallel with the GSRP application to ascertain which projects satisfy the reliability needs identified by ISO-NE. Following decisions by the state siting boards, which are expected by early to mid-2010, we expect to commence construction in mid- to late 2010 and to place the project in service in 2013.
Our second major NEEWS project is the Interstate Reliability Project, which is being designed and built in coordination with National Grid USA. CL&P's share of this project includes an approximately 40-mile, 345 KV line from Lebanon, Connecticut to the Connecticut-Rhode Island border where it would connect with enhancements National Grid USA is designing. We estimate CL&P's share of the costs of this project will be approximately $250 million. Municipal consultations concluded in November 2008, and CL&P plans to file its siting application with Connecticut regulators in mid-2010, following the completion by ISO-NE of its evaluation of the need date for this project as part of its regional system planning process expected by the end of 2009 or in early 2010. We currently expect the project to be placed in service in late 2013.
The third part of NEEWS is the Central Connecticut Reliability Project, which involves construction of a new line from Bloomfield, Connecticut to Watertown, Connecticut. This line would provide another 345 KV connection to move power across the state of Connecticut. The timing of this project would be six to twelve months behind the Interstate Reliability Project, and CL&P currently expects to file the siting application in late 2010. ISO-NE continues to evaluate the need date for this project as part of its regional system planning process, with expected completion by the end of 2009 or in early 2010. This project is currently expected to be placed in service in mid- to late 2014 after the other two projects, at an estimated cost of approximately $315 million. Included as part of NEEWS are approximately $211 million of associated reliability related expenditures, some of which may be incurred in advance of the three major projects.
During the siting approval process, state regulators may require changes in configuration (including placing some lines underground) to address local concerns that could increase construction costs. Our current design for NEEWS does not contemplate any underground lines. Building any lines underground, particularly 345 KV lines, would increase total costs of the project beyond those reflected above.
NU, NSTAR, and Hydro-Québec (HQ), a large Canadian utility, are engaged in planning a 1,200 MW high voltage direct current (HVDC) transmission line from Canada to New Hampshire to deliver and sell low carbon energy in New England. FERC granted conceptual approval of the project in May 2009 and we expect to file a Transmission Service Agreement (TSA) in late 2009 or early 2010. In July 2009, FERC granted rehearing on two third-party requests but has not indicated when an order on rehearing will be issued.
Critical components of the HQ project include the location of the southern terminus of the new line, the negotiation of power purchase agreements (PPAs) between H.Q. Energy Services (U.S.) Inc. (HQUS), New England utilities and other entities for terms that are expected to be at least 20 years, and the TSA. Final determination of the location of the southern HVDC terminus is viewed by both NU/NSTAR and HQUS as a critical path decision, and final studies are being completed to make that determination. We anticipate that the PPAs can be successfully negotiated with HQUS and NSTAR and filed with respective state commissions in 2010. Among other permits and approvals, this transmission project would require state and federal siting approvals and technical approval from ISO-NE as appropriate. We believe that the approval process will be initiated in 2010, with construction to commence upon receipt of all necessary permits, at an estimated cost to NU of $675 million, a nd transmission of power over the new line could commence in late 2014 to early 2015.
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Distribution Segment: Distribution segment capital expenditures increased by $59.8 million in the first nine months of 2009, as compared with the same period in 2008, primarily due to increased generation business capital expenditures at PSNH related to its Clean Air Project further described below and the absence in 2009 of a $17.5 million capital cost recovery by Yankee Gas related to a legal settlement in February 2008. We currently expect capital expenditures for the consolidated distribution segment to total approximately $633 million in 2009 ($281 million for CL&P and $147 million for the PSNH generation business).
A summary of distribution segment capital expenditures by company in the first nine months of 2009 and 2008 is as follows:
| | | | | | |
| | | For the Nine Months Ended September 30, |
(Millions of Dollars) | | | 2009 | | | 2008 |
CL&P | | $ | 203.8 | | $ | 202.4 |
PSNH | | | 65.4 | | | 65.3 |
WMECO | | | 24.6 | | | 24.9 |
Totals - Electric distribution (excluding generation) | | | 293.8 | | | 292.6 |
Yankee Gas | | | 39.2 | | | 24.9 |
Other | | | 0.3 | | | 0.4 |
Total distribution | | | 333.3 | | | 317.9 |
PSNH generation | | | 83.9 | | | 39.5 |
Total distribution segment | | $ | 417.2 | | $ | 357.4 |
PSNH's Clean Air Project is currently expected to cost $457 million, which will be recovered through PSNH's generation rates under New Hampshire law. Construction is ahead of schedule and on budget, and PSNH currently expects to complete the project by mid-2012. Since inception of the project, PSNH has capitalized approximately $98.6 million associated with this project, of which $71.1 million was capitalized in the first nine months of 2009. We expect this project to be approximately 33 percent complete by the end of 2009.
Smart Grid and Other Strategic Initiatives: We continue to evaluate certain development projects that would benefit our customers, such as investments in AMI systems and other projects that are detailed below:
On August 6, 2009, CL&P, PSNH and WMECO filed an application with the DOE for federal stimulus funding for 50 percent of our approximate $253 million investment in a project involving, among other things, the installation of smart grid technology in Connecticut, New Hampshire and Massachusetts, as well as expanded access to AMI systems for over 200,000 of their customers. The DOE elected not to approve this application in October 2009. We continue to proceed with the smart meter initiatives at CL&P and WMECO further described below.
On August 12, 2009, the DPU approved a stipulation agreement between WMECO and the AG concerning WMECO's proposal, under the Massachusetts Green Communities Act of 2007 (GCA), to install 6 MW of solar energy generation in its service territory at an estimated cost of $41 million. Under the agreement, no more than 3 MW will be commissioned in any one year between 2010 and 2012, the ROE on these assets will be 9 percent, and the benefits of renewable energy and tax credits will be used to reduce the impact on customer bills. WMECO will need to file an additional application with the DPU if it seeks to develop more than the initial 6 MW under the GCA, which allows for electric utility ownership of up to 50 MW of solar energy generating facilities.
On August 31, 2009, CL&P completed a three-month dynamic pricing smart meter pilot program that involved nearly 3,000 customers. The pilot tested nearly 1,500 residential and 1,500 commercial and industrial customers' interest in and response to dynamic pricing rates, coupled with smart meters. CL&P is required to file a report on the results of the pilot with the DPUC on December 1, 2009. The cost of this pilot program is expected to be approximately $13 million and is being recovered through CL&P rates. In the first quarter of 2010, CL&P expects to file an AMI deployment recommendation with the DPUC.
On October 16, 2009, WMECO filed its proposal for a dynamic pricing smart meter pilot program with the DPU. The program proposes to involve 1,750 customers in WMECO's service region for a term of six months beginning in April 2011. The total cost of the project is projected to be $7 million, which would be recovered through WMECO rates. A decision is expected from the DPU in the first half of 2010.
The estimated capital expenditures discussed below include expenditures for the WMECO solar program.
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Projected Capital Expenditures and Rate Base Estimates: A summary of the projected capital expenditures for the regulated companies' transmission segment and the distribution and generation segment by company for 2009 and 2010 through 2014, including our corporate service companies' capital expenditures on behalf of regulated companies, is as follows:
| | | | | | | | | | | | | | | | | | | | | |
| | Year | | |
(Millions of Dollars)
| |
2009
| | 2010 | | 2011 | | 2012 | | 2013 | |
2014
| | 2010-2014
Totals |
CL&P transmission | | $ | 148 | | $ | 136 | | $ | 203 | | $ | 281 | | $ | 286 | | $ | 155 | | $ | 1,061 |
PSNH transmission | | | 58 | | | 55 | | | 118 | | | 107 | | | 74 | | | 22 | | | 376 |
WMECO transmission | | | 67 | | | 66 | | | 256 | | | 328 | | | 156 | | | 6 | | | 812 |
HQ tie line | | | 2 | | | 16 | | | 49 | | | 90 | | | 236 | | | 282 | | | 673 |
Total transmission | | | 275 | | | 273 | | | 626 | | | 806 | | | 752 | | | 465 | | | 2,922 |
CL&P distribution | | | 281 | | | 305 | | | 313 | | | 306 | | | 305 | | | 317 | | | 1,546 |
PSNH distribution | | | 106 | | | 113 | | | 111 | | | 115 | | | 121 | | | 134 | | | 594 |
WMECO distribution | | | 38 | | | 33 | | | 39 | | | 36 | | | 35 | | | 36 | | | 179 |
Total electric distribution | | | 425 | | | 451 | | | 463 | | | 457 | | | 461 | | | 487 | | | 2,319 |
PSNH generation | | | 147 | | | 187 | | | 117 | | | 82 | | | 68 | | | 26 | | | 480 |
WMECO generation | | | - | | | 20 | | | 14 | | | 7 | | | - | | | - | | | 41 |
Total generation | | | 147 | | | 207 | | | 131 | | | 89 | | | 68 | | | 26 | | | 521 |
Yankee Gas distribution | | | 61 | | | 112 | | | 104 | | | 80 | | | 82 | | | 83 | | | 461 |
Corporate service companies | | | 52 | | | 48 | | | 25 | | | 22 | | | 25 | | | 14 | | | 134 |
Totals | | $ | 960 | | $ | 1,091 | | $ | 1,349 | | $ | 1,454 | | $ | 1,388 | | $ | 1,075 | | $ | 6,357 |
Actual capital expenditures could vary from the projected amounts for the companies and periods above. The continuation of weak economic conditions in the Northeast could impact the timing of our major transmission projects. Most of these capital investment projections, including those for the HQ tie line, assume timely regulatory approval, which in some cases requires extensive review. Delays in or denials of those approvals could reduce the levels of expenditures, associated rate base, and anticipated EPS growth. The capital program for 2010 through 2014 represents a decrease of approximately $600 million, primarily in the PSNH transmission segment, from our previously announced capital program for 2009 through 2013. This decrease is due primarily to the completion of the remainder of our southwest Connecticut projects a year ahead of schedule and the reduction in costs of two projects in New Hampshire, which involved an upgrade in the east to west flow o f power in southern New Hampshire and a new renewable transmission line in northern New Hampshire. The capital expenditures for these projects were reduced as a result of lower peak demand projections, short-term and lower cost solutions to address current reliability concerns, and the elimination from the ISO-NE generation capacity queue of 150 MW of wind generation in northern New Hampshire.
Based on the above estimated expenditures, projected transmission, distribution, and generation rate base at December 31 of each year are as follows:
| | | | | | | | | | | | | | | | | | |
| | Year |
(Millions of Dollars) | | 2009 | | 2010 | | 2011 | | 2012 | | 2013 | | 2014 |
CL&P transmission | | $ | 2,125 | | $ | 2,105 | | $ | 2,134 | | $ | 2,318 | | $ | 2,545 | | $ | 2,563 |
PSNH transmission | | | 318 | | | 335 | | | 433 | | | 530 | | | 608 | | | 584 |
WMECO transmission | | | 191 | | | 240 | | | 429 | | | 665 | | | 889 | | | 851 |
HQ tie line | | | - | | | - | | | - | | | - | | | - | | | 675 |
Total transmission | | | 2,634 | | | 2,680 | | | 2,996 | | | 3,513 | | | 4,042 | | | 4,673 |
CL&P distribution | | | 2,179 | | | 2,333 | | | 2,497 | | | 2,629 | | | 2,778 | | | 2,911 |
PSNH distribution | | | 764 | | | 849 | | | 941 | | | 1,030 | | | 1,090 | | | 1,156 |
WMECO distribution | | | 394 | | | 413 | | | 434 | | | 447 | | | 456 | | | 461 |
Total electric distribution | | | 3,337 | | | 3,595 | | | 3,872 | | | 4,106 | | | 4,324 | | | 4,528 |
PSNH generation | | | 381 | | | 404 | | | 414 | | | 848 | | | 874 | | | 857 |
WMECO generation | | | - | | | - | | | 29 | | | 31 | | | 28 | | | 25 |
Total generation | | | 381 | | | 404 | | | 443 | | | 879 | | | 902 | | | 882 |
Yankee Gas distribution | | | 717 | | | 764 | | | 843 | | | 892 | | | 932 | | | 974 |
Totals | | $ | 7,069 | | $ | 7,443 | | $ | 8,154 | | $ | 9,390 | | $ | 10,200 | | $ | 11,057 |
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Transmission Rate Matters
Transmission - Wholesale Rates: NU's transmission rates recover total transmission revenue requirements, ensuring that we recover all regional and local revenue requirements. These rates provide for annual true-ups to actual costs. The financial impacts of differences between actual and projected costs are deferred for future recovery from or refund to customers. As of September 30, 2009, NU was in a total underrecovery position of $12.2 million ($7.5 million for CL&P).
Legislative Matters
2009 Federal Legislation: On February 17, 2009, President Obama signed into law The American Recovery and Reinvestment Act of 2009. We are benefiting from the Act's extension of tax rules allowing the accelerated deduction of depreciation, which we project will positively impact cash flow by approximately $80 million in 2009. We also expect to benefit from the Act's solar credit provisions. We are continuing to evaluate further opportunities but cannot estimate at this time the ultimate impact that the Act will have on our earnings.
It is possible that the United States Environmental Protection Agency will adopt regulations and/or Congress will enact legislation addressing climate change and carbon constraints. Any such regulations or laws will likely impact PSNH's generating plants and possibly the prices that CL&P and WMECO pay for generation service. Until regulations are adopted or legislation is enacted, we are unable to determine the actual impacts on any of our companies. We would anticipate recovering related costs from customers.
Regulatory Developments and Rate Matters
Connecticut - CL&P:
Distribution Rates: CL&P implemented new distribution rates in 2009 to reflect the DPUC's 2008 decision allowing a $20.1 million annualized increase in distribution rates, effective February 1, 2009. CL&P expects to file a new distribution rate case in either late 2009 or early 2010.
Standard Service and Last Resort Service Rates: CL&P's residential and small commercial customers who do not choose competitive suppliers are served under Standard Service (SS) rates, and large commercial and industrial customers who do not choose competitive suppliers are served under Last Resort Service (LRS) rates. Effective July 1, 2009, the DPUC approved total average SS rates that did not change from the previous rates, though the energy supply portion of the rates increased from 12.316 cents per kilowatt-hour (kWh) to 12.516 cents per kWh. The DPUC also approved a decrease to CL&P's total average LRS rates of approximately 2.3 percent, which was primarily the result of the energy supply portion decreasing to 7.944 cents per kWh. Effective October 1, 2009, the DPUC approved an increase to CL&P's total average LRS rates of approximately 5.8 percent, which was primarily the result of the energy supply portion increasing to 8.657 cents per k Wh. CL&P is fully recovering from customers the costs of its SS and LRS services.
CTA and SBC Reconciliation: On March 31, 2009, CL&P filed with the DPUC its 2008 Competitive Transition Assessment (CTA) and Systems Benefit Charge (SBC) reconciliation, which compared CTA and SBC revenues to revenue requirements. For the 12 months ended December 31, 2008, total CTA revenues exceeded CTA revenue requirements by $84.9 million, which was recorded as a decrease to Regulatory assets. For the 12 months ended December 31, 2008, the SBC revenues exceeded SBC cost of service by $2.5 million, which was recorded as a decrease to Regulatory assets. On September 30, 2009, the DPUC issued a final decision in this docket that approved the 2008 CTA and SBC reconciliations as filed. The final decision also stated that the DPUC will review the CTA and SBC Regulatory asset or liability balances later in 2009 to determine if rate changes are warranted effective January 1, 2010.
FMCC Filing: On February 6, 2009, CL&P filed with the DPUC its semi-annual FMCC filing, which reconciled actual FMCC revenues and charges and GSC revenues and expenses, for the period July 1, 2008 through December 31, 2008, and also included the previously filed revenues and expenses for the January 1, 2008 through June 30, 2008 period. The filing identified an underrecovery for the full year totaling approximately $31.9 million. On November 5, 2009, the DPUC issued a draft decision accepting CL&P's calculations as filed. A final decision is expected in the fourth quarter of 2009. On August 3, 2009, CL&P filed with the DPUC its semi-annual FMCC filing for the period January 1, 2009 through June 30, 2009, which identified a net underrecovery of $7.1 million for that period. A final decision is also expected in the fourth quarter of 2009. Both underrecoveries have been recorded as Regulatory assets on the accompan ying unaudited condensed consolidated balance sheets. We do not expect the outcome of the DPUC's review of these filings to have a material adverse impact on CL&P's earnings, financial position or cash flows.
2008 Management Audit: An audit by a consulting firm hired by the DPUC, which is required to be conducted every six years by statute and requires a diagnostic review of all functions of CL&P, has been completed and a final report was received by CL&P on September 1, 2009. The outcome of this audit did not have an impact on CL&P's earnings, financial position or cash flows.
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C2 Prudency Audit: On September 3, 2009, a consulting firm hired by the DPUC to perform a prudency audit of certain costs incurred in the implementation of a new customer service system (C2) at CL&P provided its final audit report. This report concluded that the overall project was properly managed by CL&P and the cost was no greater than the alternatives. To date, the DPUC has not opened a docket to review the results of the prudency audit, as it indicated it might do in the 2007 CL&P rate case decision. We continue to believe that our C2 expenses were prudent and will be recovered in rates and that the review of this audit will not have a material adverse impact on CL&P's earnings, financial position or cash flows.
New Hampshire:
Distribution Rates: Pursuant to an application filed by PSNH in April 2009, the NHPUC issued an order on July 31, 2009 approving a temporary increase of $25.6 million in distribution rates on an annualized basis, effective August 1, 2009. Included in the $25.6 million temporary increase is $6 million to begin the recovery of PSNH's $49.2 million deferral of storm costs incurred in December 2008.
On June 30, 2009, PSNH filed an application with the NHPUC requesting a permanent increase in distribution rates of approximately $51 million on an annualized basis to be effective on August 1, 2009, and another $17 million effective July 1, 2010. The case is currently in the discovery phase. Hearings before the NHPUC are scheduled for April 2010 and PSNH expects a decision in mid-2010. Any differences between temporary and permanent rates will be reconciled back to August 1, 2009.
ES, SCRC, and TCAM Rates: On July 23, 2009 and July 24, 2009, the NHPUC approved stranded cost recovery charge (SCRC) and default energy service (ES) rates of 1.14 cents and 9.03 cents per kWh, respectively, which are effective August 1, 2009 through December 31, 2009. On July 24, 2009, the NHPUC approved a transmission cost adjustment mechanism (TCAM) rate of 1.195 cents per kWh, which is effective August 1, 2009 through June 30, 2010.
On September 24, 2009, PSNH filed petitions with the NHPUC requesting changes in both its ES and SCRC annual rates for the period January 1, 2010 through December 31, 2010. Consistent with previous annual rate filings, PSNH is requesting that the NHPUC review and approve the underlying data in these filings, not a specific ES or SCRC rate. PSNH expects to petition the NHPUC using updated information in late November 2009 for specific 2010 ES and SCRC rates.
ES and SCRC Reconciliation: On an annual basis, PSNH files with the NHPUC an ES/SCRC reconciliation filing for the preceding year. On May 1, 2009, PSNH filed its 2008 ES/SCRC reconciliation with the NHPUC, whose evaluation includes a prudence review of PSNH's generation activities. During 2008, ES revenues exceeded ES costs by $20.7 million, and SCRC costs exceeded SCRC revenues by $6.4 million, resulting in an ES regulatory liability for refunds to customers and a SCRC regulatory asset for costs that will be recovered from customers. Hearings before the NHPUC are scheduled for late November 2009. We do not expect the outcome of the NHPUC review to have a material adverse impact on PSNH's earnings, financial position or cash flows.
Massachusetts:
Customer Rates: On October 30, 2009, WMECO filed with the DPU for rate changes effective January 1, 2010. This proposal was made in accordance with WMECO's transmission and transition rates and various tracking mechanisms, and included an overall increase in customer rates of 0.313 cents per kWh, or 2.3 percent. We expect a decision by the DPU before the end of 2009.
Basic Service Rates: Effective July 1, 2009, the rates for all basic service customers decreased due to the decline in the cost of energy, as reflected in WMECO's basic service solicitations. Basic service rates for residential customers decreased from 11.805 cents per kWh to 8.554 cents per kWh, small commercial and industrial customers decreased from 12.074 cents per kWh to 9.179 cents per kWh and rates for medium and large commercial and industrial customers decreased from 7.679 cents per kWh to 7.256 cents per kWh. Effective October 1, 2009, the basic service rates for medium and large commercial and industrial customers increased from 7.256 cents per kWh to 8.210 cents per kWh.
Transition Cost Reconciliation: On July 2, 2009, WMECO filed the 2008 cost reconciliation for transition, transmission, basic/default service, basic/default service adder, and capital projects scheduling list. An evidentiary hearing has been scheduled for late November 2009. We do not expect the outcome of the DPU's review of this filing to have a material adverse impact on WMECO's earnings, financial position or cash flows.
Pension Factor Reconciliation Filing: On July 2, 2009, WMECO filed the 2008 reconciliation for its pension factor revenues and expenses. There is currently no timeline for the DPU's review of this filing. We do not expect the outcome of the DPU's review of this filing to have a material adverse impact on WMECO's earnings, financial position or cash flows.
67
NU Enterprises Divestitures
We have exited most of our competitive businesses. NU Enterprises continues to manage to completion its remaining wholesale marketing contracts and to manage its energy services activities.
Wholesale Marketing: During the first nine months of 2009, Select Energy continued to manage its long-term wholesale sales contract with the New York Municipal Power Agency (NYMPA), an agency comprised of municipalities, that expires in 2013, and related supply contracts. In addition to the NYMPA portfolio, Select Energy has a contract to operate and purchase the output of a certain generating facility in New England through mid-2012.
Energy Services: Most of NU Enterprises' energy services businesses were sold in 2005 and 2006. Certain other businesses were wound down in 2007, and we continue to wind down minimal activity at the other energy services businesses other than E.S. Boulos Company (Boulos), an electrical contractor based in Maine that we are continuing to own and manage.
NU Enterprises Contracts
Wholesale Derivative Contracts: NU Enterprises' wholesale derivative liabilities (through its subsidiary Select Energy) are subject to mark-to-market accounting. Numerous factors could either positively or negatively affect the realization of the wholesale derivative net fair value amounts in cash. These factors include the volatility of commodity prices until the derivative contracts result in deliveries, are exited or expire, differences between expected and actual volumes, the performance of counterparties, and other factors.
Select Energy has policies and procedures requiring all of its wholesale derivative energy positions to be valued daily and segregating responsibilities between the individuals actually transacting (front office) and those confirming the trades (middle office). The middle office is responsible for determining the portfolio's fair value independent from the front office.
The methods Select Energy used to determine the fair value of its wholesale derivative contracts are identified and segregated in the table of fair value of wholesale derivative contracts as of September 30, 2009 and December 31, 2008. A description of each method is as follows: 1) prices actively quoted primarily represent NYMEX futures and swaps that are marked to closing exchange prices; and 2) prices provided by external sources primarily include over-the-counter forwards and options, including bilateral contracts for the purchase or sale of electricity, and are marked to the mid-point of bid and ask market prices. The mid-points of market prices are adjusted to include all applicable market information, such as historical experience with intra-month price volatility and exit pricing assumptions. Currently, a portion of the NYMPA contract's fair value related to intra-month volatility and an exit price premium are determined based upon a model.
Generally, valuations of short-term derivative contracts derived from quotes or other external sources are more reliable should there be a need to liquidate the contracts, while valuations for longer-term derivative contracts are less certain. Accordingly, there is a risk that derivative contracts will not be realized at the amounts recorded.
The tables below disaggregate the estimated fair value of the wholesale derivative contracts. Valuations of individual contracts are broken into their component parts based upon prices actively quoted, prices provided by external sources and model-based amounts. Under accounting guidance for fair value measurements, contracts are classified in their entirety according to the lowest level for which there is at least one input that is significant to the valuation. Therefore, all of these contracts are classified as Level 3 under this guidance. As of September 30, 2009 and December 31, 2008, the sources of the fair value of wholesale derivative contracts are included in the following tables:
| | | | | | | | | | | | |
| | Fair Value of Wholesale Contracts as of September 30, 2009 |
(Millions of Dollars)
Sources of Fair Value | | Maturity Less
than One Year | | Maturity of One
to Four Years | | Maturity in
Excess
of Four Years | |
Total Fair
Value
|
Prices actively quoted | | $ | (5.3) | | $ | (16.6) | | $ | (0.8) | | $ | (22.7) |
Prices provided by external sources | | | (1.1) | | | (10.3) | | | (1.5) | | | (12.9) |
Model-based | | | (1.8) | | | (7.2) | | | (0.8) | | | (9.8) |
Totals* | | $ | (8.2) | | $ | (34.1) | | $ | (3.1) | | $ | (45.4) |
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| | | | | | | | | | | | |
| | Fair Value of Wholesale Contracts as of December 31, 2008 |
(Millions of Dollars)
Sources of Fair Value | | Maturity Less
than One Year | | Maturity of One
to Four Years | | Maturity in
Excess
of Four Years | |
Total Fair
Value
|
Prices actively quoted | | $ | (10.1) | | $ | (7.3) | | $ | (1.2) | | $ | (18.6) |
Prices provided by external sources | | | (2.7) | | | (21.2) | | | (10.0) | | | (33.9) |
Model-based | | | (1.7) | | | (6.7) | | | (3.0) | | | (11.4) |
Totals | | $ | (14.5) | | $ | (35.2) | | $ | (14.2) | | $ | (63.9) |
*
Excludes cash collateral posted under master netting agreements that is required to be netted against fair value positions under GAAP.
For the three and nine months ended September 30, 2009, the changes in fair value of these contracts are included in the following table:
| | | | | | |
| | For the Three Months
Ended September 30, 2009 | | For the Nine Months
Ended September 30, 2009 |
(Millions of Dollars)
| | Total Portfolio
Fair Value | | Total Portfolio
Fair Value |
Fair value of wholesale contracts outstanding at the beginning of the period | | $ | (44.7) | | $ | (63.9) |
Contracts realized or otherwise settled during the period(1) | | | 0.7 | | | 12.4 |
Change in unrealized gains included in pre-tax earnings | | | (1.4) | | | 6.1 |
Fair value of wholesale contracts outstanding at the end of the period | | $ | (45.4) | | $ | (45.4) |
(1)
Amount includes purchases, issuances and settlements of $0.8 million and $12.1 million for the three and nine months ended September 30, 2009, and realized intra-month (losses)/gains of $(0.1) million and $0.3 million for the three and nine months ended September 30, 2009.
For further information regarding Select Energy's derivative contracts, see Note 2, "Derivative Instruments," to the unaudited condensed consolidated financial statements.
Counterparty Credit: Counterparty credit risk relates to the risk of loss that Select Energy would incur because of non-performance by counterparties pursuant to the terms of their contractual obligations. Select Energy has established credit policies with regard to its counterparties to minimize overall credit risk. These policies require an evaluation of potential counterparties' financial condition (including credit ratings), collateral requirements under certain circumstances (including cash advances, LOCs, and parent guarantees), and the use of standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty. This evaluation results in Select Energy establishing credit limits prior to entering into contracts. The appropriateness of these limits is subject to continuing review. Concentrations among these counterparties may affect Select Energy's overall exposure to credit risk, eith er positively or negatively, in that the counterparties may be similarly affected by changes in economic, regulatory or other conditions. As of September 30, 2009, approximately 98 percent of Select Energy's counterparty credit exposure to wholesale counterparties was non-rated, and approximately 2 percent was collateralized. All of the non-rated credit exposure is comprised of one counterparty, which is a non-rated public entity that we have assessed as creditworthy. To date, this counterparty has met all of its contractual obligations.
Off-Balance Sheet Arrangements
Letters of Credit: NU parent provides standby LOCs for the benefit of its subsidiaries under its revolving credit agreement. PSNH posts such LOCs as collateral with counterparties and ISO-NE. As of September 30, 2009, PSNH had posted $70 million in such NU parent LOCs, which includes $10 million with ISO-NE. In addition, Select Energy had posted a $2 million NU parent LOC with ISO-NE as of September 30, 2009.
Competitive Businesses: We have various guarantees and indemnification obligations outstanding on behalf of former subsidiaries in connection with the exit from our competitive businesses. See Note 5C, "Commitments and Contingencies - Guarantees and Indemnifications," to the unaudited condensed consolidated financial statements for information regarding the maximum exposure and amounts recorded under these guarantees and indemnification obligations.
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Critical Accounting Policies and Estimates Update
The preparation of financial statements in conformity with GAAP requires management to make estimates, assumptions and at times difficult, subjective or complex judgments. Changes in these estimates, assumptions and judgments, in and of themselves, could materially impact our financial position or results of operations. Our management communicates to and discusses with our Audit Committee of the Board of Trustees all critical accounting policies and estimates. The accounting policies and estimates that we believed were the most critical in nature were reported in the 2008 Form 10-K. There have been no material changes with regard to these critical accounting policies and estimates.
Other Matters
Accounting Standards Issued But Not Yet Adopted and Accounting Standards Recently Adopted: For information regarding new accounting standards, see Note 1B, "Summary of Significant Accounting Policies - Accounting Standards Issued But Not Yet Adopted," and Note 1C, "Summary of Significant Accounting Policies - Accounting Standards Recently Adopted," to the unaudited condensed consolidated financial statements.
Contractual Obligations and Commercial Commitments: For updated information regarding our contractual obligations and commercial commitments as of September 30, 2009, see Note 5A, "Commitments and Contingencies - Long-Term Contractual Arrangements," to the unaudited condensed consolidated financial statements.
Web Site: Additional financial information is available through our web site atwww.nu.com.
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RESULTS OF OPERATIONS - NU
The following table provides the variances in income statement line items for the unaudited condensed consolidated statements of income for NU included in this Quarterly Report on Form 10-Q for the three and nine months ended September 30, 2009:
| | | | | | | | | | | |
| Income Statement Variances
(Millions of Dollars)
2009 over/(under) 2008 | |
| Third
Quarter | | Percent | | | Nine
Months | | Percent | |
Operating Revenues | $ | (201) | | (13) | % | | $ | (228) | | (5) | % |
| | | | | | | | | | | |
Operating Expenses: | | | | | | | | | | | |
Fuel, purchased and net interchange power | | (189) | | (24) | | | | (252) | | (11) | |
Other operation | | 18 | | 8 | | | | (23) | | (3) | |
Maintenance | | (10) | | (14) | | | | (32) | | (16) | |
Depreciation | | 7 | | 11 | | | | 26 | | 13 | |
Amortization of regulatory assets, net | | (51) | | (83) | | | | (113) | | (85) | |
Amortization of rate reduction bonds | | 4 | | 7 | | | | 9 | | 6 | |
Taxes other than income taxes | | 7 | | 10 | | | | 17 | | 8 | |
Total operating expenses | | (214) | | (16) | | | | (368) | | (9) | |
| | | | | | | | | | | |
Operating Income | | 13 | | 9 | | | | 140 | | 33 | |
| | | | | | | | | | | |
Interest expense, net | | (1) | | (2) | | | | 6 | | 3 | |
Other income, net | | (8) | | (46) | | | | (16) | | (37) | |
Income before income tax expense | | 6 | | 7 | | | | 118 | | 45 | |
Income tax expense | | 14 | | 66 | | | | 62 | | 90 | |
Net Income | | (8) | | (11) | | | | 56 | | 29 | |
Preferred dividends of subsidiary | | - | | - | | | | - | | - | |
Net Income attributable to controlling interest | $ | (8) | | (11) | % | | $ | 56 | | 30 | % |
Net income attributable to controlling interests was $56 million higher for the first nine months of 2009 as compared to the same period in 2008 due primarily to the absence in 2009 of a first quarter 2008 $29.8 million after-tax litigation settlement charge and higher transmission and distribution earnings.
Comparison of the Third Quarter of 2009 to the Third Quarter of 2008
Operating Revenues
| | | | | | | | | |
| | For the Three Months Ended September 30, |
(Millions of Dollars) | | 2009 | | 2008 | | Variance |
Electric distribution | | $ | 1,082 | | $ | 1,284 | | $ | (202) |
Gas distribution | | | 61 | | | 92 | | | (31) |
Total distribution | | | 1,143 | | | 1,376 | | | (233) |
Transmission | | | 149 | | | 110 | | | 39 |
Regulated companies | | | 1,292 | | | 1,486 | | | (194) |
Competitive businesses | | | 19 | | | 23 | | | (4) |
Other & eliminations | | | (5) | | | (2) | | | (3) |
NU | | $ | 1,306 | | $ | 1,507 | | $ | (201) |
Operating revenues decreased $201 million in 2009 due primarily to lower distribution revenues from the regulated companies ($233 million) as a result of the recovery of a lower level of electric and gas distribution fuel and other expenses passed through to customers through regulatory tracking mechanisms and lower CL&P wholesale revenues as a result of decreased market revenue related to sales of independent power producers (IPP) purchased generation output to ISO-NE.
Electric distribution revenues decreased $202 million due primarily to a decrease in the portion of electric distribution revenues that does not impact earnings ($209 million), partially offset by an increase in the component of revenues that impacts earnings ($7 million). The portion of electric distribution segment revenues that impacts earnings increased $7 million due primarily to higher CL&P and PSNH retail rates, partially offset by lower retail electric sales. Retail electric sales for the regulated companies decreased
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4.5 percent. Gas distribution revenues decreased $31 million due primarily to decreased recovery of fuel costs primarily as a result of lower prices, partially offset by higher sales volumes. Firm natural gas sales increased 5.8 percent in the third quarter of 2009 compared with the same period of 2008.
The $209 million decrease in electric distribution revenues that does not impact earnings consists of the portions of distribution revenues that are included in regulatory commission approved tracking mechanisms that recover certain incurred costs ($207 million) and revenues that are eliminated in consolidation ($2 million). The distribution revenue tracking components decreased $207 million due primarily to lower recovery of generation service and related congestion charges ($157 million), lower CL&P wholesale revenues as a result of decreased market revenue related to sales of IPP purchased generation output to ISO-NE ($51 million), and lower CL&P delivery-related FMCC ($11 million), partially offset by higher retail transmission revenues ($12 million) mainly as a result of the higher 2009 retail rates. The tracking mechanisms allow for rates to be changed periodically with overcollections refunded to customers or undercollections recovered from customers in future periods.
Transmission segment revenues increased $39 million due primarily to a higher transmission investment base as a result of the completion of our southwest Connecticut projects in 2008. Competitive businesses' revenues decreased $4 million due primarily to lower Boulos revenues as a result of less work on transmission projects and a lower level of work in other areas.
Fuel, Purchased and Net Interchange Power
Fuel, purchased and net interchange power expenses decreased $189 million in 2009 due to lower costs at the regulated companies ($196 million), partially offset by higher competitive business expenses ($7 million). Fuel and purchased power expense from the regulated companies decreased primarily at CL&P ($103 million) mainly due to a decrease in GSC supply costs as a result of lower sales and additional customer migration to third-party suppliers. The decreases for PSNH, Yankee Gas, and WMECO are $39 million, $32 million and $22 million, respectively. The higher competitive business expense is due primarily to the Select Energy mark-to-market expense related to the remaining wholesale contracts.
Other Operation
Other operation increased $18 million in 2009 due primarily to higher regulated companies' distribution and transmission segment expenses ($21 million), partially offset by lower competitive businesses' expenses ($4 million).
Higher regulated companies' distribution and transmission segment expenses of $21 million were due primarily to higher electric distribution segment expenses ($13 million), higher costs that are recovered through distribution tracking mechanisms and have no earnings impact ($7 million), higher Yankee Gas expenses ($4 million), and higher transmission segment expenses ($2 million), partially offset by transmission segment intercompany billings to the distribution segment that are eliminated in consolidation and further intercompany costs that are eliminated on an NU consolidated basis ($6 million).
Competitive businesses' expenses were lower by $4 million due primarily to lower Boulos expenses as a result of a lower level of work.
Maintenance
Maintenance expenses decreased $10 million in 2009 due primarily to lower regulated companies' distribution expenses. Distribution expenses were $10 million lower due primarily to lower PSNH generation expenses ($4 million), lower repair and maintenance of distribution lines ($3 million) and equipment ($1 million).
Depreciation
Depreciation increased $7 million in 2009 due primarily to higher regulated transmission ($5 million) and distribution ($3 million) plant balances resulting from completed construction projects placed into service.
Amortization of Regulatory Assets, Net
Amortization of regulatory assets, net decreased $51 million in 2009 for the distribution segment due primarily to lower amortization at CL&P resulting from a lower recovery of transition costs ($50 million) as a result of lower CL&P retail CTA revenues and higher transition costs.
Amortization of Rate Reduction Bonds
Amortization of RRBs increased $4 million in 2009, which corresponded to the reduction in principal of the RRBs.
Taxes Other than Income Taxes
Taxes other than income taxes increased $7 million in 2009 due primarily to higher property taxes at CL&P, PSNH, and WMECO.
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Interest Expense, Net
Interest expense, net decreased $1 million in 2009 due primarily to lower RRB interest resulting from lower principal balances outstanding ($4 million), partially offset by higher long-term debt interest ($3 million) resulting from the issuance of new long-term debt in 2009.
Other Income, Net
Other income, net decreased $8 million in 2009 due primarily to the absence of interest income related to a federal tax settlement in 2008 ($10 million) and lower AFUDC equity income ($6 million) as a result of lower eligible construction work in progress (CWIP) balances, partially offset by higher investment income due primarily to improved results from NU's supplemental benefit trust ($9 million).
Income Tax Expense
Income tax expense increased $14 million due primarily to higher pre-tax earnings ($6 million) and lower tax benefits associated with lower amounts of capital expenditures.
Comparison of the First Nine Months of 2009 to the First Nine Months of 2008
Operating Revenues
| | | | | | | | | |
| | For the Nine Months Ended September 30, |
(Millions of Dollars) | | 2009 | | 2008 | | Variance |
Electric distribution | | $ | 3,335 | | $ | 3,581 | | $ | (246) |
Gas distribution | | | 333 | | | 405 | | | (72) |
Total distribution | | | 3,668 | | | 3,986 | | | (318) |
Transmission | | | 419 | | | 306 | | | 113 |
Regulated companies | | | 4,087 | | | 4,292 | | | (205) |
Competitive businesses | | | 61 | | | 87 | | | (26) |
Other & eliminations | | | (24) | | | (27) | | | 3 |
NU | | $ | 4,124 | | $ | 4,352 | | $ | (228) |
Operating revenues decreased $228 million in 2009 due primarily to lower distribution revenues from the regulated companies ($318 million) as a result of the recovery of a lower level of electric and gas distribution fuel and other expenses passed through to customers through regulatory tracking mechanisms and lower CL&P wholesale revenues as a result of decreased market revenue related to sales of IPP purchased generation output to ISO-NE.
Electric distribution revenues decreased $246 million due primarily to a decrease in the portion of electric distribution revenues that does not impact earnings ($265 million), partially offset by an increase in the component of revenues that impacts earnings ($20 million). The portion of electric distribution segment revenues that impacts earnings increased $20 million due primarily to increases in CL&P and PSNH retail rates, partially offset by lower sales volumes. Retail electric sales for the regulated companies decreased 4 percent. Gas distribution revenues decreased $72 million due primarily to decreased recovery of fuel costs, partially offset by higher sales volumes. Firm natural gas sales increased 8.2 percent in 2009 compared with 2008.
The $265 million decrease in electric distribution revenues that does not impact earnings consists of the portions of distribution revenues that are included in regulatory commission approved tracking mechanisms that recover certain incurred costs ($230 million) and revenues that are eliminated in consolidation ($35 million). The distribution revenue tracking components decreased $230 million due primarily to lower recovery of generation service and related congestion charges ($204 million) and lower CL&P wholesale revenues as a result of decreased market revenue related to sales of IPP purchased generation output to ISO-NE ($148 million), partially offset by higher retail transmission revenues ($88 million) mainly as a result of the higher 2009 retail rates, higher PSNH SCRC revenues ($18 million) and higher CL&P delivery-related FMCC ($14 million). The tracking mechanisms allow for rates to be changed periodically with overcollections refunded to customers or under collections recovered from customers in future periods.
Transmission segment revenues increased $113 million due primarily to a higher transmission investment base as a result of the completion of our southwest Connecticut projects in 2008. Competitive businesses' revenues decreased $26 million due primarily to lower Boulos revenues as a result of less work on transmission projects and a lower level of work in other areas.
Fuel, Purchased and Net Interchange Power
Fuel, purchased and net interchange power expenses decreased $252 million in 2009 due to lower costs at the regulated companies. Fuel and purchased power expense from the regulated companies decreased primarily at CL&P ($97 million) mainly due to lower GSC supply costs as a result of lower sales, and Yankee Gas ($82 million) due to a decrease in gas prices this year as compared to last year. The decreases for PSNH and WMECO are $48 million and $26 million, respectively.
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Other Operation
Other operation decreased $23 million in 2009 due primarily to lower NU parent and other companies' expenses ($49 million) and lower competitive businesses' expenses ($31 million), partially offset by higher regulated companies' distribution and transmission segment expenses ($58 million).
NU parent and other companies' expenses were lower by $49 million in 2009 due primarily to the absence of the $49.5 million payment resulting from the settlement of litigation made in March 2008. Competitive businesses' expenses were lower by $31 million due primarily to lower Boulos expenses as a result of a lower level of work.
Higher regulated companies' distribution and transmission segment expenses of $58 million were due primarily to higher electric distribution segment expenses ($29 million), higher costs that are recovered through distribution tracking mechanisms and have no earnings impact ($14 million), higher Yankee Gas expenses ($10 million), and higher transmission segment expenses ($9 million), partially offset by transmission segment intercompany billings to the distribution segment that are eliminated in consolidation and further intercompany costs that are eliminated on an NU consolidated basis ($5 million).
Maintenance
Maintenance expenses decreased $32 million in 2009 due primarily to lower regulated companies' distribution expenses ($31 million) and lower transmission line expenses ($2 million). Distribution expenses were lower due primarily to lower repair and maintenance of distribution lines ($23 million), including lower storm-related expenses, lower PSNH generation expenses ($8 million) and lower equipment maintenance expenses ($3 million), partially offset by higher vegetation management expenses ($5 million).
Depreciation
Depreciation increased $26 million in 2009 due primarily to higher regulated transmission ($19 million) and distribution ($9 million) plant balances resulting from completed construction projects placed into service.
Amortization of Regulatory Assets, Net
Amortization of regulatory assets, net decreased $113 million in 2009 for the distribution segment due primarily to lower amortization at CL&P resulting from a lower recovery of transition costs ($121 million) as a result of lower retail CTA revenues and higher transition costs, partially offset by higher amortization of the SBC balance ($11 million).
Amortization of Rate Reduction Bonds
Amortization of RRBs increased $9 million in 2009, which corresponded to the reduction in principal of the RRBs.
Taxes Other than Income Taxes
Taxes other than income taxes increased $17 million in 2009 due primarily to higher Connecticut gross earnings taxes recoverable in rates ($11 million), mainly as a result of higher CL&P revenues that are subject to gross earnings tax, and higher property taxes at CL&P, PSNH, and WMECO ($11 million), partially offset by the resolution of various routine tax issues ($8 million).
Interest Expense, Net
Interest expense, net increased $6 million in 2009 due primarily to higher long-term debt interest ($26 million) resulting from the issuance of new long-term debt in 2008 and 2009, partially offset by lower RRB interest resulting from lower principal balances outstanding ($10 million) and lower other interest ($10 million) mostly related to the resolution of various routine tax issues.
Other Income, Net
Other income, net decreased $16 million in 2009 due primarily to lower AFUDC equity income ($17 million) as a result of lower eligible CWIP balances, the absence of interest income related to the federal tax settlement in 2008 ($10 million), and lower Energy Independence Act incentives ($5 million), partially offset by higher investment income due primarily to improved results from NU's supplemental benefit trust ($15 million).
Income Tax Expense
Income tax expense increased $62 million due primarily to higher pre-tax earnings ($38 million) and lower tax benefits associated with less capital expenditures.
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THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
Management's Discussion and Analysis of
Financial Condition and Results of Operations
CL&P is a wholly owned subsidiary of NU parent. This discussion should be read in conjunction with NU's Management's Discussion and Analysis of Financial Condition and Results of Operations, unaudited condensed consolidated financial statements and footnotes in this Form 10-Q, the 2009 Forms 10-Q and the 2008 Form 10-K.
RESULTS OF OPERATIONS
The following table provides the variances in income statement line items for the unaudited condensed consolidated statements of income for CL&P included in this Quarterly Report on Form 10-Q for the three and nine months ended September 30, 2009:
| | | | | | | | | | | |
| Income Statement Variances
(Millions of Dollars)
2009 over/(under) 2008 | |
| Third
Quarter | | Percent | | | Nine
Months | | Percent | |
Operating Revenues | $ | (121) | | (12) | % | | $ | (89) | | (3) | % |
| | | | | | | | | | | |
Operating Expenses: | | | | | | | | | | | |
Fuel, purchased and net interchange power | | (103) | | (20) | | | | (97) | | (7) | |
Other operation | | 8 | | 6 | | | | 18 | | 4 | |
Maintenance | | (5) | | (13) | | | | (12) | | (12) | |
Depreciation | | 6 | | 14 | | | | 20 | | 17 | |
Amortization of regulatory assets, net | | (47) | | (86) | | | | (107) | | (81) | |
Amortization of rate reduction bonds | | 3 | | 7 | | | | 8 | | 7 | |
Taxes other than income taxes | | 5 | | 10 | | | | 15 | | 11 | |
Total operating expenses | | (133) | | (15) | | | | (155) | | (6) | |
| | | | | | | | | | | |
Operating Income | | 12 | | 12 | | | | 66 | | 24 | |
| | | | | | | | | | | |
Interest expense, net | | 3 | | 7 | | | | 7 | | 6 | |
Other income, net | | (6) | | (46) | | | | (17) | | (48) | |
Income before income tax expense | | 3 | | 4 | | | | 42 | | 21 | |
Income tax expense | | 12 | | 70 | | | | 32 | | 58 | |
Net Income | $ | (9) | | (16) | % | | $ | 10 | | 7 | % |
Comparison of the Third Quarter of 2009 to the Third Quarter of 2008
Operating Revenues
Operating revenues decreased $121 million due to lower distribution segment revenues ($150 million), partially offset by higher transmission segment revenues ($29 million).
The distribution segment revenues decreased $150 million due primarily to a decrease in the portion of distribution revenues that does not impact earnings ($153 million), primarily as a result of the inclusion of these distribution revenues in regulatory tracking mechanisms, partially offset by an increase in the portion of revenues that impacts earnings ($3 million).
The $153 million decrease in distribution segment revenues that does not impact earnings was due primarily to a decrease in the portions of retail revenues that are included in DPUC approved tracking mechanisms that track the recovery of certain incurred costs through CL&P's tariffs ($150 million). The distribution revenues included in DPUC approved tracking mechanisms decreased $150 million due primarily to a decrease in revenues associated with the recovery of GSC and supply-related FMCC ($86 million), lower wholesale revenues as a result of decreased market revenue generated from the sale of CL&P's purchased IPP generation output to ISO-NE due to a decrease in the market price of energy ($51 million), lower delivery-related FMCC ($11 million) and transition cost recoveries ($8 million), partially offset by higher retail transmission revenues ($5 million). The lower GSC and supply-related FMCC revenue was due primarily to lower retail sales and additional customer migration to third-party suppliers in 2009 as compared to 2008. The lower delivery-related FMCC revenue was due primarily to changes in projections for certain delivery-related FMCC costs for 2009 that significantly lowered the delivery-related FMCC rate in the third quarter of 2009 as compared to 2008. The tracking mechanisms allow for rates to be changed periodically with overcollections refunded to customers or undercollections recovered from customers in future periods.
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The portion of revenues that impacts earnings increased $3 million primarily as a result of rate changes, partially offset by lower retail sales. Retail sales as compared to the same period in 2008 decreased 17.7 percent for the industrial, 4 percent for the commercial, and 2.4 percent for the residential classes. Total retail sales decreased overall by 5 percent.
Transmission segment revenues increased $29 million due primarily to a higher transmission investment base as a result of the completion of our southwest Connecticut projects in 2008.
Fuel, Purchased and Net Interchange Power
Fuel, purchased and net interchange power expense decreased $103 million due primarily to a decrease in GSC supply costs ($119 million) and other purchased power costs ($10 million), partially offset by higher deferred fuel ($25 million), all of which are included in DPUC approved tracking mechanisms. The $119 million decrease in GSC supply costs was due primarily to lower retail sales and additional customer migration to third-party suppliers. These GSC supply costs are the contractual amounts CL&P must pay to various suppliers that have been awarded the right to supply SS and LRS load through a competitive solicitation process. The $25 million increase in deferred fuel costs was due primarily to the combined effect of a third quarter 2008 net underrecovery of GSC and FMCC expenses as compared to third quarter 2009 net overrecovery of these expenses.
Other Operation
Other operation expenses increased $8 million due primarily to higher distribution segment expenses ($11 million) due primarily to pension and expenses related to uncollectible receivable balances and transmission segment expenses that are tracked and recorded through FERC rate tariffs ($2 million), partially offset by lower costs that are recovered through distribution tracking mechanisms and have no earnings impact ($2 million) and transmission segment intracompany billings to the distribution segment that are eliminated in consolidation ($2 million).
Maintenance
Maintenance expenses decreased $5 million in 2009 due primarily to lower repair and maintenance of overhead distribution lines ($3 million) including lower storm expenses and lower distribution substation equipment expenses ($1 million).
Depreciation
Depreciation expense increased $6 million due primarily to higher utility plant balances resulting from completed construction projects placed into service in the transmission segment ($5 million) and the distribution segment ($2 million).
Amortization of Regulatory Assets, Net
Amortization of regulatory assets, net decreased $47 million due primarily to lower amortization related to the recovery of transition charges ($50 million) as a result of lower retail CTA revenue and higher transition costs, partially offset by a higher amortization of the SBC balance ($2 million) and increased amortization of deferred taxes ($1 million).
Amortization of Rate Reduction Bonds
Amortization of RRBs increased $3 million in 2009, which corresponded to the reduction in principal of the RRBs.
Taxes Other Than Income Taxes
Taxes other than income taxes increased $5 million due primarily to higher property taxes as a result of higher plant balances and increased municipal tax rates primarily for the transmission segment.
Interest Expense, Net
Interest expense, net, increased $3 million due primarily to higher long-term debt interest ($5 million) resulting primarily from the $250 million debt issuance in February 2009, partially offset by lower RRB interest resulting from lower principal balances outstanding ($3 million).
Other Income, Net
Other income, net, decreased $6 million due primarily to the absence in 2009 of interest income related to a federal tax settlement in 2008 ($6 million), and a lower AFUDC equity income ($5 million) as a result of lower eligible CWIP due to large transmission projects being completed and placed in-service in 2008 and lower capital expenditures in 2009, partially offset by higher interest and investment income ($5 million) due primarily to improved results from the NU supplemental benefit trust.
Income Tax Expense
Income tax expense increased $12 million due primarily to higher pre-tax earnings ($3 million) and lower tax benefits as a result of lower capital expenditures ($7 million).
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Comparison of the First Nine Months of 2009 to the First Nine Months of 2008
Operating Revenues
Operating revenues decreased $89 million due to lower distribution segment revenues ($186 million), partially offset by higher transmission segment revenues ($97 million).
The distribution segment revenues decreased $186 million due primarily to a decrease in the portion of distribution revenues that does not impact earnings ($202 million), primarily as a result of the inclusion of these distribution revenues in regulatory tracking mechanisms and intracompany revenues that are eliminated in consolidation, partially offset by an increase in the portion of revenues that impacts earnings ($16 million).
The $202 million decrease in distribution segment revenues that does not impact earnings was due primarily to a decrease in the portions of retail revenues that are included in DPUC approved tracking mechanisms that track the recovery of certain incurred costs through CL&P's tariffs ($180 million) and transmission segment intracompany billings to the distribution segment that are eliminated in consolidation ($22 million). The distribution revenues included in DPUC approved tracking mechanisms decreased $180 million due primarily to lower wholesale revenues as a result of decreased market revenue generated from the sale of CL&P's purchased IPP generation output to ISO-NE due to a decrease in the market price of energy ($148 million) and a decrease in revenues associated with the recovery of GSC and supply-related FMCC ($119 million), partially offset by higher retail transmission revenues ($68 million) and delivery-related FMCC ($14 million). The lower GSC and supply- related FMCC revenue was due primarily to lower retail sales and additional customer migration to third-party suppliers in 2009 as compared to 2008. The higher delivery-related FMCC revenue was due primarily to a larger prior year overrecovery being refunded to customers in 2008 as compared to 2009, partially offset by lower reliability must run costs built into the 2009 rate as compared to 2008. The tracking mechanisms allow for rates to be changed periodically with overcollections refunded to customers or undercollections recovered from customers in future periods.
The portion of revenues that impacts earnings increased $16 million primarily as a result of rate changes, partially offset by lower retail sales. The 2009 retail sales as compared to the same period in 2008 decreased 18.1 percent for the industrial, 3.3 percent for the commercial, and 0.5 percent for the residential classes. Total retail sales decreased overall by 3.9 percent.
Transmission segment revenues increased $97 million due primarily to a higher transmission investment base as a result of the completion of our southwest Connecticut projects in 2008.
Fuel, Purchased and Net Interchange Power
Fuel, purchased and net interchange power expense decreased $97 million due primarily to lower GSC supply costs ($160 million) and other purchased power costs ($32 million), partially offset by an increase in deferred fuel costs ($95 million), all of which are included in DPUC approved tracking mechanisms. The $160 million decrease in GSC supply costs was due primarily to lower retail sales and additional customer migration to third-party suppliers. These GSC supply costs are the contractual amounts CL&P must pay to various suppliers that have been awarded the right to supply SS and LRS load through a competitive solicitation process. The $95 million increase in deferred fuel costs was due primarily to the combined effect of the first nine months of 2008 net underrecovery of GSC and FMCC expenses as compared to the first nine months of 2009 net overrecovery of these expenses.
Other Operation
Other operation expenses increased $18 million due primarily to higher distribution segment expenses ($17 million) due primarily to pension and expenses related to uncollectible receivable balances and higher transmission segment expenses, which are tracked and recorded through FERC rate tariffs ($9 million), partially offset by lower transmission segment intracompany billing to the distribution segment that are eliminated in consolidation ($6 million) and lower costs that are recovered through distribution tracking mechanisms and have no earnings impact ($3 million).
Maintenance
Maintenance expenses decreased $12 million in 2009 due primarily to lower repair and maintenance of distribution lines ($6 million), including lower storm expenses, lower transmission segment expenses ($2 million) and lower distribution substation equipment expenses ($2 million).
Depreciation
Depreciation expense increased $20 million due primarily to higher utility plant balances resulting from completed construction projects placed into service in the transmission segment ($17 million) and the distribution segment ($5 million).
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Amortization of Regulatory Assets, Net
Amortization of regulatory assets, net decreased $107 million due primarily to lower amortization related to the recovery of transition charges ($121 million) as a result of lower retail CTA revenue and higher transition costs, partially offset by higher amortization of the SBC balance ($11 million) and increased amortization of deferred taxes ($2 million).
Amortization of Rate Reduction Bonds
Amortization of RRBs increased $8 million in 2009, which corresponded to the reduction in principal of the RRBs.
Taxes Other Than Income Taxes
Taxes other than income taxes increased $15 million due primarily to higher gross earnings taxes recoverable in rates as a result of higher distribution and transmission revenues that are subject to gross earnings tax ($12 million with transmission being $5 million), higher property taxes as a result of higher plant balances and increased municipal tax rates ($6 million) and higher payroll taxes ($1 million), partially offset by the resolution of various routine tax issues ($4 million).
Interest Expense, Net
Interest expense, net, increased $7 million due primarily to higher long-term debt interest ($22 million) resulting from the $300 million debt issuance in May 2008 and the $250 million debt issuance in February 2009, partially offset by lower other interest ($8 million) mostly related to the resolution of various routine tax issues and lower RRB interest resulting from lower principal balances outstanding ($7 million).
Other Income, Net
Other income, net, decreased $17 million due primarily to lower AFUDC equity income ($16 million) as a result of lower eligible CWIP due to large transmission projects being completed and placed in-service in 2008 and lower capital expenditures in 2009, the absence in 2009 of interest income related to a federal tax settlement in 2008 ($6 million), and lower Energy Independence Act incentives ($5 million), partially offset by higher interest and investment income ($9 million) due primarily to improved results from the NU supplemental benefit trust.
Income Tax Expense
Income tax expense increased $32 million due primarily to higher pre-tax earnings ($13 million) and less tax benefits as a result of lower capital expenditures ($11 million).
LIQUIDITY
CL&P had cash flows from operating activities, after RRB payments included in financing activities, in the first nine months of 2009 of $343.8 million, compared with $202.2 million in the first nine months of 2008. The improvement in 2009 cash flows was primarily due to higher operating results as a result of increased transmission revenues after significant projects were placed in service in late 2008; a shift in accounts receivable and unbilled revenue balances of $147 million; and a decrease in the negative cash flow impact from regulatory underrecoveries of $151 million, primarily related to the FMCC, GSC and C&LM charges included in customer rates. These factors were partially offset by increases of $96 million and $58 million in the negative cash flow effect of our accounts payable balances related to operating activities and the change in the amount of income tax refunds or payments, respectively. We project cash flows provided by operating activities at CL&P of approximately $450 million in 2009, after approximately $183 million of RRB payments.
In 2009, CL&P reduced its borrowings under the $400 million credit facility it shares with the other regulated companies by $155 million to $33 million as of September 30, 2009. CL&P can borrow up to $200 million under this facility. Other financing activities for the first nine months of 2009 included the $250 million bond issuance in February 2009, the remarketing of $62 million of tax-exempt PCRBs and cash capital contributions from NU parent of $116.6 million, offset by $102.7 million in repayment of NU Money Pool borrowings and $85.4 million in common dividends paid to NU parent.
Cash capital expenditures included on the accompanying unaudited condensed consolidated statements of cash flows do not include amounts incurred on capital projects but not yet paid, cost of removal, the AFUDC related to equity funds, and the capitalized portions of pension and PBOP expense or income. CL&P's cash capital expenditures totaled $331.6 million in the first nine months of 2009, compared with $678.6 million in the first nine months of 2008. This decrease was primarily the result of lower transmission segment capital expenditures in 2009 due to the completion in 2008 of three major transmission projects in southwest Connecticut. Other investing activities for the first nine months of 2009 included lendings to the NU Money Pool of $90 million.
We project capital expenditures at CL&P of $441 million in 2010, as compared to our current projection of $429 million for 2009. We also project cash flows provided by operating activities at CL&P of approximately $440 million in 2010, after RRB payments.
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While the impact of continued market volatility and the extent and impacts of the current economic downturn cannot be predicted, we believe that CL&P currently has operating flexibility and access to funding sources to maintain adequate liquidity. On October 9, 2009, Fitch concluded its annual review of NU parent and its electric utilities, including CL&P, by reaffirming all of its existing credit ratings and stable outlooks. Other agencies' credit outlooks for CL&P are also stable. CL&P has low risk of calls for collateral due to its business model, as described under "Liquidity-Impact of Financial Market Conditions" in this "Management's Discussion and Analysis of Financial Condition and Results of Operations." Capital contributions from NU parent and other internal sources of funding are provided to CL&P as necessary. CL&P has the mandatory tender of $62 million in 2010, which it plans to remarket in the ordina ry course, but does not have any long-term debt maturing until 2014, and there are no CL&P debt issuances planned for 2010.
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PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES
Management's Discussion and Analysis of
Financial Condition and Results of Operations
PSNH is a wholly owned subsidiary of NU parent. This discussion should be read in conjunction with NU's Management's Discussion and Analysis of Financial Condition and Results of Operations, unaudited condensed consolidated financial statements and footnotes in this Form 10-Q, the 2009 Forms 10-Q and the 2008 Form 10-K.
RESULTS OF OPERATIONS
The following table provides the variances in income statement line items for the unaudited condensed consolidated statements of income for PSNH included in this Quarterly Report on Form 10-Q for the three and nine months ended September 30, 2009:
| | | | | | | | | | | |
| Income Statement Variances
(Millions of Dollars)
2009 over/(under) 2008 | |
| Third
Quarter | | Percent | | | Nine
Months | | Percent | |
Operating Revenues | $ | (26) | | (9) | % | | $ | (21) | | (2) | % |
| | | | | | | | | | | |
Operating Expenses: | | | | | | | | | | | |
Fuel, purchased and net interchange power | | (39) | | (24) | | | | (49) | | (11) | |
Other operation | | 9 | | 19 | | | | 21 | | 14 | |
Maintenance | | (4) | | (17) | | | | (17) | | (23) | |
Depreciation | | 1 | | 9 | | | | 5 | | 11 | |
Amortization of regulatory assets/(liabilities), net | | - | | - | | | | 8 | | 82 | |
Amortization of rate reduction bonds | | 1 | | 6 | | | | 1 | | 3 | |
Taxes other than income taxes | | 1 | | 12 | | | | 3 | | 10 | |
Total operating expenses | | (31) | | (11) | | | | (28) | | (4) | |
| | | | | | | | | | | |
Operating Income | | 5 | | 16 | | | | 7 | | 8 | |
| | | | | | | | | | | |
Interest expense, net | | (2) | | (13) | | | | (3) | | (7) | |
Other income, net | | (1) | | (17) | | | | 1 | | 22 | |
Income before income tax expense | | 6 | | 32 | | | | 11 | | 18 | |
Income tax expense | | 4 | | 94 | | | | 5 | | 32 | |
Net Income | $ | 2 | | 13 | % | | $ | 6 | | 12 | % |
Comparison of the Third Quarter of 2009 to the Third Quarter of 2008
Operating Revenues
Operating revenues decreased $26 million in 2009 due to lower distribution segment revenues ($32 million), partially offset by higher transmission segment revenues ($6 million).
The distribution segment revenues decreased $32 million due primarily to a decrease in the portion of electric distribution revenues that does not impact earnings ($35 million) as a result of the inclusion of these distribution revenues in regulatory tracking mechanisms. The component of revenues that impacts earnings increased $3 million primarily as a result of higher retail rates, partially offset by lower retail sales volumes. Retail sales decreased 3.8 percent in 2009 compared to the same period in 2008.
The $35 million decrease in distribution revenues that does not impact earnings is due to the portion of retail revenues that is included in NHPUC approved tracking mechanisms that recover certain incurred costs through PSNH's tariffs. The decrease was due primarily to lower energy supply costs ($49 million), partially offset by an increase in the SCRC ($8 million), higher retail transmission revenues ($3 million) and higher Northern Wood Power Plant renewable energy certificate revenues ($3 million). The tracking mechanisms allow for rates to be changed periodically with overcollections refunded to customers or undercollections recovered from customers in future periods.
Transmission segment revenues increased $6 million due primarily to a higher transmission investment base.
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Fuel, Purchased and Net Interchange Power
Fuel, purchased and net interchange power costs decreased $39 million due primarily to an increased level of migration of ES customers to competitive supply and lower retail sales.
Other Operation
Other operation expenses increased $9 million due primarily to higher retail transmission expenses that are recovered through a tracking mechanism ($5 million) and higher distribution segment expenses ($4 million) mainly as a result of higher administrative and general expenses, including higher pension costs, and higher expenses related to uncollectible receivable balances.
Maintenance
Maintenance expenses decreased $4 million due primarily to generation expenses incurred in 2008 primarily as a result of the Merrimack Station maintenance outages ($3 million) and hydro expenses incurred primarily as a result of two major dam resurfacing projects ($1 million).
Depreciation
Depreciation expense increased $1 million due primarily to higher utility plant balances resulting from completed construction projects placed into service in the transmission segment.
Amortization of Rate Reduction Bonds
Amortization of RRBs increased $1 million in 2009, which corresponded to the reduction in principal of the RRBs.
Taxes Other Than Income Taxes
Taxes other than income taxes increased $1 million due primarily to higher property taxes as a result of higher net plant balances and increased local municipal tax rates.
Interest Expense, Net
Interest expense, net decreased $2 million due primarily to lower long-term debt interest ($1 million), resulting from lower interest rates on a variable rate PCRB, and lower RRB interest resulting from lower principal balances outstanding ($1 million).
Other Income, Net
Other income, net decreased $1 million in 2009 due primarily to the absence of interest income related to a 2008 federal tax settlement, partially offset by higher investment income due primarily to improved results from the NU supplemental benefit trust.
Income Tax Expense
Income tax expense increased $4 million due primarily to higher pre-tax earnings ($2 million) and depreciation deduction adjustments ($2 million).
Comparison of the First Nine Months of 2009 to the First Nine Months of 2008
Operating Revenues
Operating revenues decreased $21 million in 2009 due to lower distribution segment revenues ($31 million), partially offset by higher transmission segment revenues ($9 million).
The distribution segment revenues decreased $31 million due primarily to a decrease in the portion of electric distribution revenues that does not impact earnings ($33 million) as a result of the inclusion of these distribution revenues in regulatory tracking mechanisms and transmission segment intracompany billings to the distribution segment that are eliminated in consolidation. The component of revenues that impacts earnings increased $2 million primarily as a result of higher retail rates, partially offset by lower retail sales volumes. Retail sales decreased 3.8 percent in 2009 compared to the same period in 2008.
The $33 million decrease in distribution revenues that does not impact earnings is due to the portion of retail revenues that is included in NHPUC approved tracking mechanisms that recover certain incurred costs through PSNH's tariffs ($24 million) and intracompany revenues that are eliminated in consolidation ($9 million). The distribution revenues included in NHPUC approved tracking mechanisms decreased $24 million due primarily to lower energy supply costs ($58 million), partially offset by an increase in the SCRC ($18 million), higher retail transmission revenues ($9 million), higher Northern Wood Power Plant renewable energy certificate revenues ($7 million), and higher wholesale revenue ($1 million). The tracking mechanisms allow for rates to be changed periodically with overcollections refunded to customers or undercollections recovered from customers in future periods.
Transmission segment revenues increased $9 million due primarily to a higher transmission investment base.
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Fuel, Purchased and Net Interchange Power
Fuel, purchased and net interchange power costs decreased $49 million due primarily to an increased level of migration of ES customers to competitive supply and lower retail sales, partially offset by higher forward energy market prices.
Other Operation
Other operation expenses increased $21 million due primarily to higher distribution segment expenses ($14 million) mainly due to higher administrative and general expenses, including higher pension costs, and higher expenses related to uncollectible receivable balances, higher generation business costs that are recovered through distribution tracking mechanisms ($5 million) and higher retail transmission expenses that are also recovered through distribution tracking mechanisms ($4 million).
Maintenance
Maintenance expenses decreased $17 million due primarily to lower distribution maintenance ($12 million), including lower storm costs, and generation expenses incurred in 2008 primarily as a result of the Merrimack Station maintenance outages ($7 million) and hydro expenses incurred primarily as a result of two major dam resurfacing projects ($1 million), partially offset by higher vegetation management expenses ($4 million).
Depreciation
Depreciation expense increased $5 million due primarily to higher utility plant balances resulting from completed construction projects placed into service in the distribution segment ($3 million) and the transmission segment ($2 million).
Amortization of Regulatory Assets/(Liabilities), Net
Amortization of regulatory assets/(liabilities), net increased $8 million due primarily to an increase in net deferrals associated with PSNH's SCRC tracking mechanism, partially offset by a decrease in net deferrals associated with the ES and TCAM tracking mechanisms.
Amortization of Rate Reduction Bonds
Amortization of RRBs increased $1 million in 2009, which corresponded to the reduction in principal of the RRBs.
Taxes Other Than Income Taxes
Taxes other than income taxes increased $3 million due primarily to higher property taxes as a result of higher net plant balances and increased local municipal tax rates ($4 million), partially offset by lower sales taxes as a result of the resolution of various routine tax issues ($1 million).
Interest Expense, Net
Interest expense, net decreased $3 million due primarily to lower RRB interest resulting from lower principal balances outstanding ($2 million) and lower other interest ($1 million), mainly related to the favorable resolution of various routine tax issues.
Other Income, Net
Other income, net increased $1 million due primarily to higher investment income related to improved results from the NU supplemental benefit trust and higher interest income related to the return on the December 2008 ice storm, partially offset by lower interest income as a result of the absence in 2009 of the 2008 federal tax settlement and lower AFUDC equity income due to higher short-term debt, which results in a lower rate based on borrowing costs.
Income Tax Expense
Income tax expense increased $5 million due primarily to higher pre-tax earnings ($3 million) and depreciation deduction adjustments ($2 million).
LIQUIDITY
PSNH had cash flows provided by operating activities in the first nine months of 2009 of $66.7 million, compared with $64.7 million in the first nine months of 2008, both after RRB payments. The increase in 2009 cash flows was due to improved operating results excluding non-cash factors, such as depreciation expense, insurance settlement proceeds for the recovery of major storm costs and a decrease in the negative cash flow impact from various other working capital items, such as accrued income taxes of $25 million. These factors were offset by an increase of $76.5 million in the negative cash flow effect of accounts payable balances as a result of, among other things, costs related to the major storm in December 2008 that were paid to vendors in 2009 and deferred. These costs began to be recovered from customers on August 1, 2009 at an annual rate of $6 million pursuant to the temporary rate case settlement. This level of recovery could be modified once PSN H's permanent rate case is decided.
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WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY
Management's Discussion and Analysis of
Financial Condition and Results of Operations
WMECO is a wholly owned subsidiary of NU parent. This discussion should be read in conjunction with NU's Management's Discussion and Analysis of Financial Condition and Results of Operations, unaudited condensed consolidated financial statements and footnotes in this Form 10-Q, the 2009 Forms 10-Q and the 2008 Form 10-K.
RESULTS OF OPERATIONS
The following table provides the variances in income statement line items for the unaudited condensed consolidated statements of income for WMECO included in this Quarterly Report on Form 10-Q for the three and nine months ended September 30, 2009:
| | | | | | | | | | | |
| Income Statement Variances
(Millions of Dollars)
2009 over/(under) 2008 | |
| Third
Quarter | | Percent | | | Nine
Months | | Percent | |
Operating Revenues | $ | (16) | | (14) | % | | $ | (22) | | (7) | % |
| | | | | | | | | | | |
Operating Expenses: | | | | | | | | | | | |
Fuel, purchased and net interchange power | | (22) | | (34) | | | | (26) | | (14) | |
Other operation | | 3 | | 17 | | | | 7 | | 12 | |
Maintenance | | (1) | | (11) | | | | (2) | | (15) | |
Depreciation | | 1 | | 8 | | | | 1 | | 7 | |
Amortization of regulatory (liabilities)/assets, net | | (4) | | (a) | | | | (14) | | (a) | |
Amortization of rate reduction bonds | | - | | - | | | | 1 | | 7 | |
Taxes other than income taxes | | 1 | | 27 | | | | 1 | | 9 | |
Total operating expenses | | (22) | | (22) | | | | (32) | | (11) | |
| | | | | | | | | | | |
Operating Income | | 6 | | 59 | | | | 10 | | 28 | |
| | | | | | | | | | | |
Interest expense, net | | - | | - | | | | - | | - | |
Other income, net | | (1) | | (88) | | | | (1) | | (47) | |
Income before income tax expense | | 5 | | 69 | | | | 9 | | 40 | |
Income tax expense | | 2 | | 87 | | | | 3 | | 45 | |
Net Income | $ | 3 | | 63 | % | | $ | 6 | | 38 | % |
(a) Percent greater than 100.
Comparison of the Third Quarter of 2009 to the Third Quarter of 2008
Operating Revenues
Operating revenues decreased $16 million in 2009 due to lower distribution segment revenues ($20 million), partially offset by higher transmission segment revenues ($4 million).
The distribution segment revenues decreased $20 million due primarily to a decrease in the portion of distribution revenues that does not impact earnings ($22 million), primarily as a result of the inclusion of these distribution revenues in regulatory tracking mechanisms, partially offset by an increase in the portions of revenues that impacts earnings ($2 million).
The $22 million distribution segment revenue decrease that does not impact earnings was due to a decrease in the portions of retail revenues that are included in DPU approved tracking mechanisms that track the recovery of certain incurred costs through WMECO's tariffs due primarily to lower energy supply costs ($22 million), lower transition cost recoveries ($2 million), and lower wholesale revenues ($2 million), partially offset by higher retail transmission revenues ($4 million). The tracking mechanisms allow for rates to be changed periodically with overcollections refunded to customers or undercollections recovered from customers in future periods.
The portion of revenues that impacts earnings increased $2 million due primarily to the absence in 2009 of a 2008 service quality (SQ) performance assessment charge, partially offset by lower retail sales. WMECO became subject to a SQ performance assessment charge in the third quarter of 2008 as a result of its reliability performance against the SQ metrics primarily as a result of significant
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storm activity. The 2009 retail sales as compared to the same period in 2008 decreased 9.3 percent for the industrial, 2.1 percent for the commercial, and was flat for the residential classes. Total retail sales decreased overall by 2.7 percent.
Transmission segment revenues increased $4 million due primarily to a higher transmission investment base.
Fuel, Purchased and Net Interchange Power
Fuel, purchased and net interchange power expense decreased $22 million due primarily to lower Basic/Default Service supply costs resulting from lower supplier contract rates and reduced load volumes ($28 million). This decrease was partially offset by higher deferral of excess Basic/Default Service revenue over Basic/Default Service expense ($7 million). The Basic/Default Service supply costs are the contractual amounts we must pay to various suppliers that serve Basic/Default Service load after winning a competitive solicitation process. To the extent that these costs do not match the revenues collected from customers, the DPU allows the difference to be deferred for future collection or refund.
Other Operation
Other operation expenses increased $3 million due primarily to higher retail transmission costs that are recovered through distribution tracking mechanisms and have no earnings impact ($4 million), partially offset by lower distribution segment expenses ($1 million) mainly as a result of lower administrative and general expenses.
Maintenance
Maintenance expenses decreased $1 million due primarily to lower repair and maintenance of distribution lines including lower storm expenses.
Depreciation
Depreciation expense increased $1 million due primarily to higher utility plant balances resulting from completed construction projects placed into service.
Amortization of Regulatory (Liabilities)/Assets, Net
Amortization of regulatory (liabilities)/assets, net decreased $4 million in 2009 due primarily to the deferral of allowed distribution segment transition costs that are in excess of transition revenues, resulting from a decrease in the transition cost portion rate and lower IPP revenue than previous years.
Taxes Other Than Income Taxes
Taxes other than income taxes increased $1 million due primarily to higher property taxes as a result of higher plant balances and increased municipal tax rates.
Other Income, Net
Other income, net, decreased $1 million due primarily to lower interest income as a result of a 2009 tax refund adjustment and the absence in 2009 of interest income related to a federal tax settlement in 2008.
Income Tax Expense
Income tax expense increased $2 million due primarily to higher pre-tax earnings.
Comparison of the First Nine Months of 2009 to the First Nine Months of 2008
Operating Revenues
Operating revenues decreased $22 million in 2009 due to lower distribution segment revenues ($29 million), partially offset by higher transmission segment revenues ($6 million).
The distribution segment revenues decreased $29 million due primarily to a decrease in the portion of distribution revenues that does not impact earnings ($30 million), primarily as a result of the inclusion of these distribution revenues in regulatory tracking mechanisms and intracompany revenues that are eliminated in consolidation, partially offset by an increase in the portions of revenues that impacts earnings ($2 million).
The $29 million distribution segment revenue decrease that does not impact earnings was due primarily to a decrease in the portions of retail revenues that are included in DPU approved tracking mechanisms that track the recovery of certain incurred costs through WMECO's tariffs ($26 million) and transmission segment intracompany billings to the distribution segment that are eliminated in consolidation ($4 million). The distribution revenues included in DPU approved tracking mechanisms decreased $26 million due primarily to lower energy supply costs ($27 million), lower transition cost recoveries ($7 million), and lower wholesale revenues ($5 million), partially offset by higher retail transmission revenues ($11 million). The tracking mechanisms allow for rates to be changed periodically with overcollections refunded to customers or undercollections recovered from customers in future periods.
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The portion of revenues that impacts earnings increased $2 million due primarily to the absence in 2009 of a SQ performance assessment charge as further described above, partially offset by lower retail sales. The 2009 retail sales as compared to the same period in 2008 decreased 13.5 percent for the industrial, 5.2 percent for the commercial, and 1.3 percent for the residential classes. Total retail sales decreased overall by 5.3 percent.
Transmission segment revenues increased $6 million due primarily to a higher transmission investment base.
Fuel, Purchased and Net Interchange Power
Fuel, purchased and net interchange power expense decreased $26 million due primarily to lower Basic/Default Service supply costs ($30 million) and lower other purchased power costs ($2 million), partially offset by higher deferral of excess Basic/Default Service revenue over Basic/Default Service expense ($6 million). The Basic/Default Service supply costs are the contractual amounts we must pay to various suppliers that serve Basic/Default Service load after winning a competitive solicitation process. These costs decreased as a result of lower supplier contract rates and reduced load volumes. To the extent that these costs do not match the revenues collected from customers, the DPU allows the difference to be deferred for future collection or refund. Lower other purchased power costs are due primarily to a decrease in costs associated with customer generation and IPPs.
Other Operation
Other operation expenses increased $7 million due primarily to higher retail transmission and other costs that are recovered through distribution tracking mechanisms and have no earnings impact ($8 million) and higher transmission segment expenses ($1 million), partially offset by lower distribution segment expenses ($2 million) mainly as a result of lower administrative and general expenses.
Maintenance
Maintenance expenses decreased $2 million due primarily to lower repair and maintenance of distribution lines including lower storm expenses.
Depreciation
Depreciation expense increased $1 million due primarily to higher utility plant balances resulting from completed construction projects placed into service.
Amortization of Regulatory (Liabilities)/Assets, Net
Amortization of regulatory (liabilities)/assets, net decreased $14 million in 2009 due primarily to the deferral of allowed distribution segment transition costs that are in excess of transition revenues, resulting from a decrease in the transition cost portion rate and lower IPP revenue than previous years.
Amortization of Rate Reduction Bonds
Amortization of RRBs increased $1 million in 2009, which corresponded to the reduction in principal of the RRBs.
Taxes Other Than Income Taxes
Taxes other than income taxes increased $1 million due primarily to higher property taxes as a result of higher plant balances and increased municipal tax rates.
Other Income, Net
Other income, net, decreased $1 million due primarily to a 2009 tax refund adjustment to interest income ($1 million), the absence in 2009 of interest income related to a federal tax settlement in 2008 ($1 million), and lower AFUDC equity income ($1 million). Although CWIP has increased over the prior year due to the NEEWS transmission project, there has been no 2009 equity AFUDC as CWIP has been fully funded by short-term debt for the last seven months. These factors were partially offset by higher investment income ($2 million) due primarily to improved results from the NU supplemental benefit trust.
Income Tax Expense
Income tax expense increased $3 million due primarily to higher pre-tax earnings.
LIQUIDITY
WMECO had cash flows provided by operating activities in the first nine months of 2009 of $27.7 million, compared with $29.2 million in the first nine months of 2008, both after RRB payments. The decrease in 2009 cash flows was due to an increase of $31.6 million in the negative cash flow effect of accounts payable balances partially as a result of costs related to the major storm in December 2008 that were paid to vendors in 2009. These costs were deferred and are expected to be recovered from customers. WMECO anticipates filing a distribution rate case in mid-2010, which would include a request for more timely recovery of the December 2008 storm costs. The above timing impact was offset by a decrease in the negative cash flow impact from various other
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working capital items, such as accrued income taxes or taxes receivable of $14 million and accounts receivable and unbilled revenues of $7.8 million, and improved operating results excluding non-cash factors, such as depreciation expense.
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ITEM 3.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Market Risk Information
Commodity Price Risk Management: We have no contracts entered into for trading purposes. Our regulated companies enter into energy contracts to serve our customers, and the economic impacts of those contracts are passed on to our customers. Accordingly, the regulated companies have no exposure to loss of future earnings or fair values due to these market risk-sensitive instruments, and the sensitivity analyses below do not include these contracts. The wholesale portfolio held by Select Energy includes contracts that are market-risk sensitive, including a wholesale sales contract with NYMPA through 2013 with approximately 0.4 million remaining megawatt-hours (MWh) of supply contract volumes, net of related sales volumes. Select Energy also has a non-derivative contract that expires in mid-2012 to purchase output from a generation facility, which is less exposed to market price volatility and is not included in the sensitivity analysis below. &n bsp;As Select Energy's contract volumes are winding down, and as the NYMPA contract is substantially hedged against price risks, we have somewhat limited exposure to commodity price risks.
For Select Energy's wholesale portfolio derivatives, we utilize the sensitivity analysis methodology to disclose quantitative information for our commodity price risks (including, where applicable, capacity and ancillary components). Sensitivity analysis provides a presentation of the potential loss of future pre-tax earnings and fair values from our market risk-sensitive contracts due to one or more hypothetical changes in commodity price components, or other similar price changes. Under the sensitivity analysis, the fair value of the derivatives is a function of the underlying commodity components, contract prices and market prices represented by each derivative contract. For swaps, forward contracts and options, fair value reflects our best estimates considering over-the-counter quotations, time value and volatility factors of the underlying commitments. Exchange-traded futures and options are recorded at fair value based on closing exchange prices. A po rtion of the fair value of the NYMPA contract is based on a model.
Select Energy's Wholesale Portfolio: When conducting sensitivity analyses of the change in the fair value of the wholesale portfolio, which includes several derivative contracts, which would result from a hypothetical change in the future market price of electricity, the fair values of the contracts are determined from models that take into consideration estimated future market prices of electricity, the volatility of the market prices in each period, as well as the time value factors of the underlying commitments.
Hypothetical changes in the fair value of derivative contracts in the wholesale portfolio were determined using a 30 percent assumed change in forward market prices. As of September 30, 2009, we determined the following hypothetical changes and calculated the nominal adjusted impact on pre-tax earnings:
| | | | | | |
| | 30% Price Increase | | 30% Price Decrease |
(Millions of Dollars)
Commodity | | Nominal Impact
on Pre-Tax Earnings | | Nominal Impact
on Pre-Tax Earnings |
Energy | | $ | 0.2 | | $ | (4.3) |
Capacity | | | (2.0) | | | 2.0 |
Ancillaries | | | (1.6) | | | 1.6 |
| | $ | (3.4) | | $ | (0.7) |
The impact of a change in electricity prices on wholesale derivative transactions as of September 30, 2009 are not necessarily representative of the results that will be realized if such a change were to occur. Energy, capacity and ancillaries have different market volatilities. The method we use to determine the fair value of these contracts includes discounting expected future cash flows using a LIBOR swap curve. As such, the wholesale portfolio is also exposed to interest rate volatility. This exposure is not modeled in sensitivity analyses, and we do not believe that such exposure is material. The derivative contracts in the wholesale portfolio are accounted for at fair value, and changes in market prices impact earnings.
Other Risk Management Activities
Interest Rate Risk Management: We manage our interest rate risk exposure in accordance with our written policies and procedures by maintaining a mix of fixed and variable rate long-term debt. As of September 30, 2009, approximately 93 percent (87 percent including the long-term debt subject to the fixed-to-floating interest rate swap as variable rate long-term debt) of our long-term debt, including fees and interest due for spent nuclear fuel disposal costs, was at a fixed interest rate. The remaining long-term debt is at variable interest rates and is subject to interest rate risk that could result in earnings volatility. Assuming a one percentage point increase in our variable interest rate, annual interest expense would have increased by a pre-tax amount of $3.3 million. As of September 30, 2009, we maintained a fixed-to-floating interest rate swap at NU parent to manage the interest rate risk associated with $263 million of its fixed-rate long-term deb t.
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Credit Risk Management: Credit risk relates to the risk of loss that we would incur as a result of non-performance by counterparties pursuant to the terms of our contractual obligations. We serve a wide variety of customers and suppliers that include IPPs, industrial companies, gas and electric utilities, oil and gas producers, financial institutions, and other energy marketers. Margin accounts exist within this diverse group, and we realize interest receipts and payments related to balances outstanding in these margin accounts. This wide customer and supplier mix generates a need for a variety of contractual structures, products and terms that, in turn, require us to manage the portfolio of market risk inherent in those transactions in a manner consistent with the parameters established by our risk management process.
Credit risks and market risks at NU Enterprises are monitored regularly by a Risk Oversight Council. The Risk Oversight Council is comprised of members of management from other areas of NU that do not create these risk exposures and functions to ensure compliance with our stated risk management policies.
We track and re-balance the risk in our portfolio in accordance with fair value and other risk management methodologies that utilize forward price curves in the energy markets to estimate the size and probability of future potential exposure.
The NYMEX traded futures and option contracts cleared off the NYMEX exchange are ultimately guaranteed by NYMEX to Select Energy. Select Energy has established written credit policies with regard to its counterparties to minimize overall credit risk on all types of transactions. These policies require an evaluation of potential counterparties' financial condition (including credit ratings), collateral requirements under certain circumstances (including cash in advance, LOCs, and parent guarantees), and the use of standardized agreements, which allow for the netting of positive and negative exposures associated with a single counterparty in the event of default. This evaluation results in establishing credit limits prior to Select Energy entering into energy contracts. The appropriateness of these limits is subject to continuing review. Concentrations among these counterparties may impact Select Energy's overall exposure to credit risk, either positively or negatively, in that the counterparties may be similarly affected by changes to economic, regulatory or other conditions.
Due to the exposure of counterparties to Select Energy, Select Energy had cash collateral balances deposited with its NYMEX broker of $29.3 million and $26.3 million as of September 30, 2009 and December 31, 2008, respectively, which are included in Current assets - prepayments and other on the accompanying unaudited condensed consolidated balance sheets. As of September 30, 2009, Select Energy also had $0.9 million of collateral posted with counterparties under a master netting agreement. This collateral is netted against the fair value of derivatives. Select Energy held no collateral balances from counterparties at either period end. In addition, Select Energy had posted a $2 million NU parent LOC as of September 30, 2009 in favor of ISO-NE.
Our regulated companies are subject to credit risk from certain long-term or high-volume supply contracts with energy marketing companies. Our regulated companies manage the credit risk with these counterparties in accordance with established credit risk practices and maintain an oversight group that monitors contracting risks, including credit risk. As of September 30, 2009, CL&P had $1 million in cash collateral deposited with counterparties that has been netted against the fair value of the related derivative. As of December 31, 2008, our regulated companies neither held cash collateral nor deposited collateral with counterparties. NU parent provides standby LOCs for the benefit of its subsidiaries under its revolving credit agreement. PSNH posts such LOCs as collateral with counterparties and ISO-NE. As of September 30, 2009, PSNH had posted $70 million in such NU parent LOCs.
We have implemented an Enterprise Risk Management (ERM) methodology for identifying the principal risks of the Company. ERM involves the application of a well-defined, enterprise-wide methodology that enables our Risk and Capital Committee, comprised of our senior officers, to oversee the identification, management and reporting of the principal risks of the business. However, there can be no assurances that the ERM process will identify or manage every risk or event that could impact our financial condition or results of operations. The findings of this process are periodically discussed with our Board of Trustees.
Additional quantitative and qualitative disclosures about market risk are set forth in Part I, Item 2, "Management's Discussion and Analysis of Financial Condition and Results of Operations," included in this Quarterly Report on Form 10-Q.
ITEM 4.
CONTROLS AND PROCEDURES
Management, on behalf of NU, CL&P, PSNH, and WMECO, evaluated the design and operation of the disclosure controls and procedures as of September 30, 2009 to determine whether they are effective in ensuring that the disclosure of required information is made timely and in accordance with the Securities Exchange Act of 1934 and the rules and regulations of the SEC. This evaluation was made under management's supervision and with management's participation, including the principal executive officers and principal financial officer as of the end of the period covered by this Quarterly Report on Form 10-Q. There are inherent limitations of disclosure controls and procedures, including the possibility of human error and the circumventing or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives. The principal executive officers and principa l financial officer have concluded, based on their review, that the disclosure controls and procedures of NU, CL&P, PSNH, and WMECO are effective to ensure that information required to be
88
disclosed by us in reports filed under the Securities Exchange Act of 1934 (i) is recorded, processed, summarized, and reported within the time periods specified in SEC rules and regulations and (ii) is accumulated and communicated to management, including the principal executive officers and principal financial officer, as appropriate to allow timely decisions regarding required disclosures.
There have been no changes in internal controls over financial reporting for NU, CL&P, PSNH, and WMECO during the quarter ended September 30, 2009 that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting.
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PART II. OTHER INFORMATION
ITEM 1.
LEGAL PROCEEDINGS
We are parties to various legal proceedings. We have identified these legal proceedings in Part I, Item 3, "Legal Proceedings," and elsewhere in our Annual Report on Form 10-K for the year ended December 31, 2008, and updated them in our Quarterly Report on From 10-Q for the quarter ended June 30, 2009, all of which disclosures are incorporated herein by reference. There have been no material changes with regard to the legal proceedings previously disclosed in our most recent Annual Report on Form 10-K and Quarterly Reports on Form 10-Q.
ITEM 1A.
RISK FACTORS
We are subject to a variety of significant risks in addition to the matters set forth under "Forward Looking Statements," in "Management's Discussion and Analysis of Financial Condition and Results of Operations," of this Quarterly Report on Form 10-Q. We have identified a number of these risk factors in our Annual Report on Form 10-K for the year ended December 31, 2008 and our Quarterly Reports on Form 10-Q for the quarters ended March 31, 2009 and June 30, 2009, all of which risk factors are incorporated herein by reference. These risk factors should be considered carefully in evaluating our risk profile. There have been no additional risk factors identified and no material changes with regard to the risk factors previously disclosed in our most recent Annual Report on Form 10-K and Quarterly Reports on Form 10-Q.
ITEM 2.
UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
There were no purchases made by or on behalf of NU or any "affiliated purchaser" (as defined in Rule 10b-18(a)(3) under the Securities Exchange Act of 1934) of NU common shares during the quarter ended September 30, 2009.
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ITEM 6.
EXHIBITS
Exhibit No.
Description
Listing of Exhibits (NU)
12
Ratio of Earnings to Fixed Charges
15
Deloitte & Touche LLP Letter Regarding Unaudited Financial Information
31
Certification of Charles W. Shivery, Chairman, President and Chief Executive Officer of Northeast Utilities, required by Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated November 6, 2009
31.1
Certification of David R. McHale, Executive Vice President and Chief Financial Officer of Northeast Utilities, required by Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated November 6, 2009
32
Certification of Charles W. Shivery, Chairman, President and Chief Executive Officer of Northeast Utilities and David R. McHale, Executive Vice President and Chief Financial Officer of Northeast Utilities, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated November 6, 2009
Listing of Exhibits (CL&P)
12
Ratio of Earnings to Fixed Charges
31
Certification of Leon J. Olivier, Chief Executive Officer of The Connecticut Light and Power Company, required by Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated November 6, 2009
31.1
Certification of David R. McHale, Executive Vice President and Chief Financial Officer of The Connecticut Light and Power Company, required by Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated November 6, 2009
32
Certification of Leon J. Olivier, Chief Executive Officer of The Connecticut Light and Power Company and David R. McHale, Executive Vice President and Chief Financial Officer of The Connecticut Light and Power Company, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated November 6, 2009
Listing of Exhibits (PSNH)
12
Ratio of Earnings to Fixed Charges
31
Certification of Leon J. Olivier, Chief Executive Officer of Public Service Company of New Hampshire, required by Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated November 6, 2009
31.1
Certification of David R. McHale, Executive Vice President and Chief Financial Officer of Public Service Company of New Hampshire, required by Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated November 6, 2009
32
Certification of Leon J. Olivier, Chief Executive Officer of Public Service Company of New Hampshire and David R. McHale, Executive Vice President and Chief Financial Officer of Public Service Company of New Hampshire, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated November 6, 2009
91
Listing of Exhibits (WMECO)
12
Ratio of Earnings to Fixed Charges
31
Certification of Leon J. Olivier, Chief Executive Officer of Western Massachusetts Electric Company, required by Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated November 6, 2009
31.1
Certification of David R. McHale, Executive Vice President and Chief Financial Officer of Western Massachusetts Electric Company, required by Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated November 6, 2009
32
Certification of Leon J. Olivier, Chief Executive Officer of Western Massachusetts Electric Company and David R. McHale, Executive Vice President and Chief Financial Officer of Western Massachusetts Electric Company, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated November 6, 2009
92
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.
| | | |
| | | NORTHEAST UTILITIES |
| | | (Registrant) |
| | | |
| | | |
| | | |
| | | |
Date: November 6, 2009 | | By | /s/ David R. McHale |
| | | David R. McHale |
| | | Executive Vice President and Chief Financial Officer |
| | | (for the Registrant and as Principal Financial Officer) |
____________________________________________________________________________________
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.
| | | |
| | | THE CONNECTICUT LIGHT AND POWER COMPANY |
| | | (Registrant) |
| | | |
| | | |
| | | |
| | | |
Date: November 6, 2009 | | By | /s/ David R. McHale |
| | | David R. McHale |
| | | Executive Vice President and Chief Financial Officer |
| | | (for the Registrant and as Principal Financial Officer) |
93
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.
| | | |
| | | PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE |
| | | (Registrant) |
| | | |
| | | |
| | | |
| | | |
Date: November 6, 2009 | | By | /s/ David R. McHale |
| | | David R. McHale |
| | | Executive Vice President and Chief Financial Officer |
| | | (for the Registrant and as Principal Financial Officer) |
____________________________________________________________________________________
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.
| | | |
| | | WESTERN MASSACHUSETTS ELECTRIC COMPANY |
| | | (Registrant) |
| | | |
| | | |
| | | |
| | | |
Date: November 6, 2009 | | By | /s/ David R. McHale |
| | | David R. McHale |
| | | Executive Vice President and Chief Financial Officer |
| | | (for the Registrant and as Principal Financial Officer) |
94
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